42 U.S.C. 7601 and 7651
(a)
(b)
The terms used in this part, in parts 73, 74, 75, 76, 77 and 78 of this chapter shall have the meanings set forth in the Act, including sections 302 and 402 of the Act, and in this section as follows:
(1) For purposes of sulfur dioxide emissions:
(i) The tonnage equivalent of the allowances authorized to be allocated to an affected unit for use in a calendar year under section 404(a)(1), (a)(3), and (h) of the Act, or the basic Phase II allowance allocations authorized to be allocated to an affected unit for use in a calendar year, or the allowances authorized to be allocated to an opt-in source under section 410 of the Act for use in a calendar year;
(ii) As adjusted:
(A) By allowances allocated by the Administrator pursuant to section 403, section 405 (a)(2), (a)(3), (b)(2), (c)(4), (d)(3), and (h)(2), and section 406 of the Act;
(B) By allowances allocated by the Administrator pursuant to subpart D of this part; and thereafter
(C) By allowance transfers to or from the compliance subaccount for that unit that were recorded or properly submitted for recordation by the allowance transfer deadline as provided in § 73.35 of this chapter, after deductions and other adjustments are made pursuant to § 73.34(c) of this chapter; and
(2) For purposes of nitrogen oxides emissions, the applicable limitation under part 76 of this chapter.
“Months not on line” is the number of months during January 1985 through
(1) For calendar years 2000 through 2009 inclusive, allocations of allowances made by the Administrator pursuant to section 403 and section 405 (b)(1), (3), and (4); (c)(1), (2), (3), and (5); (d)(1), (2), (4), and (5); (e); (f); (g)(1), (2), (3), (4), and (5); (h)(1); (i); and (j).
(2) For each calendar year beginning in 2010, allocations of allowances made by the Administrator pursuant to section 403 and section 405 (b)(1), (3), and (4); (c)(1), (2), (3), and (5); (d)(1), (2), (4), and (5); (e); (f); (g)(1), (2), (3), (4), and (5); (h)(1) and (3); (i); and (j).
(1) The response of gaseous monitor to a calibration gas and the known concentration of the calibration gas;
(2) The response of a flow monitor to a reference signal and the known value of the reference signal; or
(3) The response of a continuous opacity monitoring system to an attenuation filter and the known value of the filter after a stated period of operation during which no unscheduled maintenance, repair, or adjustment took place.
(1) A standard reference material;
(2) A standard reference material-equivalent compressed gas primary reference material;
(3) A NIST traceable reference material;
(4) NIST/EPA-approved certified reference materials;
(5) A gas manufacturer's intermediate standard;
(6) An EPA protocol gas;
(7) Zero air material; or
(8) A research gas mixture.
(1) For a corporation, a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function, or any other person who performs similar policy or decision-making functions for the corporation;
(2) For partnership or sole proprietorship, a general partner or the proprietor, respectively; and
(3) For a local government entity or State, Federal, or other public agency, either a principal executive officer or ranking elected official.
(1) For purposes of the requirements of part 75 of this chapter, a unit is “coal-fired” independent of the percentage of coal or coal-derived fuel consumed in any calendar year (expressed in mmBtu); and
(2) For all other purposes under the Acid Rain Program, except for purposes of applying part 76 of this chapter, a unit is “coal-fired” if it uses coal or coal-derived fuel as its primary fuel (expressed in mmBtu);
(1)
(2)
(1) Sulfur dioxide pollutant concentration monitor;
(2) Flow monitor;
(3) Nitrogen oxides pollutant concentration monitors;
(4) Diluent gas monitor (oxygen or carbon dioxide);
(5) A continuous moisture monitor when such monitoring is required by part 75 of this chapter; and
(6) A data acquisition and handling system.
(1) Opacity monitor; and
(2) A data acquisition and handling system.
(1) To improve the efficiency of consumption of electricity from a utility by customers of the utility; or
(2) To reduce the amount of consumption of electricity from a utility by customers of the utility without increasing the use by the customer of fuel other than: Biomass (i.e., combustible energy-producing materials from biological sources, which include wood, plant residues, biological wastes, landfill gas, energy crops, and eligible components of municipal solid waste), solar, geothermal, or wind resources; or industrial waste gases where the party making the submission involved certifies that there is no net increase in sulfur dioxide emissions from the use of such gases. “Demand-side measure” includes the measures listed in part 73, appendix A, section 1 of this chapter.
(1) The operation of high-voltage lines, substations, and related equipment; and
(2) The scheduling of generation for the purpose of supplying electricity to other utilities over interconnecting transmission lines.
(1) For purposes of the requirements for a fuel flowmeter used in an excepted monitoring system under appendix D or E of part 75 of this chapter, the fuel identified by the designated representative in the unit's monitoring plan as the fuel which is combusted only during emergencies where the primary fuel is not available; or
(2) For purposes of the requirement for stack testing for an excepted monitoring system under appendix E of part 75 of this chapter, the fuel identified in the State, local, or Federal permit for a plant and is identified by the designated representative in the unit's monitoring plan as the fuel which is combusted only during emergencies where the primary fuel is not available, as established in a petition under § 75.66 of this chapter.
(1) Communication between EPA employees other than between EPA trial staff and a member of the decisional body; or
(2) Communication between the decisional body and interested persons outside the Agency, or EPA trial staff, where all parties to the proceeding have received prior written notice of the proposed communication and are given an opportunity to be present and to participate therein.
(1) Any tonnage of sulfur dioxide emitted by an affected unit during a calendar year that exceeds the Acid Rain emissions limitation for sulfur dioxide for the unit; and
(2) Any tonnage of nitrogen oxide emitted by an affected unit during a calendar year that exceeds the annual tonnage equivalent of the Acid Rain emissions limitation for nitrogen oxides applicable to the affected unit taking into account the unit's heat input for the year.
(1) For all purposes under the Acid Rain Program, except for part 75 of this chapter, the combustion of:
(i) Natural gas or other gaseous fuel (including coal-derived gaseous fuel), for at least 90.0 percent of the unit's average annual heat input during the previous three calendar years and for at least 85.0 percent of the annual heat input in each of those calendar years; and
(ii) Any fuel, except coal or solid or liquid coal-derived fuel, for the remaining heat input, if any.
(2) For purposes of part 75 of this chapter, the combustion of:
(i) Natural gas or other gaseous fuel (including coal-derived gaseous fuel) for at least 90.0 percent of the unit's average annual heat input during the previous three calendar years and for at least 85.0 percent of the annual heat input in each of those calendar years; and
(ii) Fuel oil, for the remaining heat input, if any.
(3) For purposes of part 75 of this chapter, a unit may initially qualify as gas-fired if the designated representative demonstrates to the satisfaction of the Administrator that the requirements of paragraph (2) of this definition are met, or will in the future be met, through one of the following submissions:
(i) For a unit for which a monitoring plan has not been submitted under § 75.62 of this chapter, the designated representative submits either:
(A) Fuel usage data for the unit for the three calendar years immediately preceding the date of initial submission of the monitoring plan for the unit under § 75.62; or
(B) If a unit does not have fuel usage data for one or more of the three calendar years immediately preceding the date of initial submission of the monitoring plan for the unit under § 75.62, the unit's designated fuel usage; all available fuel usage data (including the percentage of the unit's heat input derived from the combustion of gaseous fuels), beginning with the date on which the unit commenced commercial operation; and the unit's projected fuel usage.
(ii) For a unit for which a monitoring plan has already been submitted under § 75.62, that has not qualified as gas-fired under paragraph (3)(i) of this definition, and whose fuel usage changes, the designated representative submits either:
(A) Three calendar years of data following the change in the unit's fuel usage, showing that no less than 90.0 percent of the unit's average annual heat input during the previous three calendar years, and no less than 85.0 percent of the unit's annual heat input during any one of the previous three calendar years, is from the combustion of gaseous fuels and the remaining heat input is from the combustion of fuel oil; or
(B) A minimum of 720 hours of unit operating data following the change in the unit's fuel usage, showing that no less than 90.0 percent of the unit's heat
(iii) If a unit qualifies as gas-fired under paragraph (3)(i) or (ii) of this definition, the unit is classified as gas-fired as of the date of the submission under such paragraph.
(4) For purposes of part 75 of this chapter, a unit that initially qualifies as gas-fired under paragraph (3)(i) or (ii) of this definition must meet the criteria in paragraph (2) of this definition each year in order to continue to qualify as gas-fired. If such a unit combusts only gaseous fuel and fuel oil but fails to meet such criteria for a given year, the unit no longer qualifies as gas-fired starting January 1 of the year after the first year for which the criteria are not met. If such a unit combusts fuel other than gaseous fuel or fuel oil and fails to meet such criteria in a given year, the unit no longer qualifies as gas-fired starting the day after the first day for which the criteria are not met. If a unit failing to meet the criteria in paragraph (2) of this definition initially qualified as a gas-fired unit under paragraph (3) of this definition, the unit may qualify as a gas-fired unit for a subsequent year only if the designated representative submits the data specified in paragraph (3)(ii)(A) of this definition.
(1) Is nonrecourse project financed, as defined by the Secretary of Energy at 10 CFR part 715;
(2) Is used for the generation of electricity, eighty percent or more of which is sold at wholesale; and
(3) Is a new unit required to hold allowances under Title IV of the Clean
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period equal to or greater than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit was built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
(1) Commences commercial operation on or after November 15, 1990;
(2) Is nonrecourse project-financed, as defined in 10 CFR part 715;
(3) Sells 80% of electricity generated at wholesale; and
(4) Does not sell electricity to any affiliate or, if it does, demonstrates it cannot obtain the required allowances from such an affiliate.
(1) For all purposes under the Acid Rain Program, except part 75 of this chapter, the combustion of:
(i) Fuel oil for more than 10.0 percent of the average annual heat input during the previous three calendar years or for more than 15.0 percent of the annual heat input during any one of those calendar years; and
(ii) Any solid, liquid or gaseous fuel (including coal-derived gaseous fuel), other than coal or any other coal-derived solid or liquid fuel, for the remaining heat input, if any.
(2) For purposes of part 75 of this chapter, combustion of only fuel oil and gaseous fuels, provided that the unit involved does not meet the definition of gas-fired.
(1) Beginning with the hour corresponding to the completion of a daily calibration error, linearity check, or quality assurance audit that indicates that the instrument is not measuring and recording within the applicable performance specifications; and
(2) Ending with the hour corresponding to the completion of an additional calibration error, linearity check, or quality assurance audit following corrective action that demonstrates that the instrument is measuring and recording within the applicable performance specifications.
(1) Any holder of any portion of the legal or equitable title in an affected
(2) Any holder of a leasehold interest in an affected unit or in a combustion source or process source; or
(3) Any purchaser of power from an affected unit or from a combustion source or process source under a life-of-the-unit, firm power contractual arrangement as the term is defined herein and used in section 408(i) of the Act. However, unless expressly provided for in a leasehold agreement, owner shall not include a passive lessor, or a person who has an equitable interest through such lessor, whose rental payments are not based, either directly or indirectly, upon the revenues or income from the affected unit; or
(4) With respect to any Allowance Tracking System general account, any person identified in the submission required by § 73.31(c) of this chapter that is subject to the binding agreement for the authorized account representative to represent that person's ownership interest with respect to allowances.
(1) A unit that has:
(i) An average capacity factor of no more than 10.0 percent during the previous three calendar years and
(ii) A capacity factor of no more than 20.0 percent in each of those calendar years.
(2) For purposes of part 75 of this chapter, a unit may initially qualify as a peaking unit if the designated representative demonstrates to the satisfaction of the Administrator that the requirements of paragraph (1) of this definition are met, or will in the future be met, through one of the following submissions:
(i) For a unit for which a monitoring plan has not been submitted under § 75.62, the designated representative submits either:
(A) Capacity factor data for the unit for the three calendar years immediately preceding the date of initial submission of the monitoring plan for the unit under § 75.62; or
(B) If a unit does not have capacity factor data for one or more of the three calendar years immediately preceding the date of initial submission of the monitoring plan for the unit under § 75.62, all available capacity factor data, beginning with the date on which the unit commenced commercial operation; and projected capacity factor data.
(ii) For a unit for which a monitoring plan has already been submitted under § 75.62, that has not qualified as a peaking unit under paragraph (2)(i) of this definition, and where capacity factor changes, the designated representative submits either:
(A) Three calendar years of data following the change in the unit's capacity factor showing an average capacity factor of no more than 10.0 percent during the three previous calendar years and a capacity factor of no more than 20.0 percent in each of those calendar years; or
(B) One calendar year of data following the change in the unit's capacity factor showing a capacity factor of no more than 10.0 percent and a statement that this changed pattern of operation resulting in a capacity factor less than 10.0 percent is considered permanent and is projected to continue for the foreseeable future.
(3) For purposes of part 75 of this chapter, a unit that initially qualifies as a peaking unit must meet the criteria in paragraph (1) of this definition each year in order to continue to qualify as a peaking unit. If such a unit fails to meet such criteria for a given year, the unit no longer qualifies as a peaking unit starting January 1 of the year after the year for which the criteria are not met. If a unit failing to
(1) When the Administrator is responsible for administering Acid Rain permits under subpart G of this part, the Administrator or a delegatee agency authorized by the Administrator; or
(2) The State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to administer Acid Rain permits under subpart G of this part and part 70 of this chapter.
(1) A power sales agreement;
(2) A state regulatory authority order requiring a utility to:
(i) Enter into a power sales agreement with the facility;
(ii) Purchase from the facility; or
(iii) Enter into arbitration concerning the facility for the purpose of establishing terms and conditions of the utility's purchase of power;
(3) A letter of intent or similar instrument committing to purchase power (actual electrical output or generator output capacity) from the source at a previously offered or lower price and a power sales agreement applicable to the source is executed within the time frame established by the terms of the letter of intent but no later than November 15, 1993 or, where the letter of intent does not specify a time frame, a power sale agreement applicable to the source is executed on or before November 15, 1993; or
(4) A utility competitive bid solicitation that has resulted in the selection of the qualifying facility or independent power production facility as the winning bidder.
(1) The identity of the electric output purchaser; or
(2) The identity of the steam purchaser and the location of the facility, remain unchanged as of the date the facility commences commercial operation; and
(3) The terms and conditions of the power purchase commitment are not changed in such a way as to allow the costs of compliance with the Acid Rain Program to be shifted to the purchaser.
(1) Replacement of an existing coal-fired boiler with one of the following clean coal technologies: Atmospheric or pressurized fluidized bed combustion, integrated gasification combined cycle, magnetohydrodynamics, direct and indirect coal-fired turbines, integrated gasification fuel cells, or as determined by the Administrator, in consultation with the Secretary of Energy, a derivative of one or more of these technologies, and any other technology capable of controlling multiple combustion emissions simultaneously with improved boiler or generation efficiency and with significantly greater waste reduction relative to the performance of technology in widespread commercial use as of the date of enactment of the Clean Air Act Amendments of 1990; or
(2) Any oil- or gas-fired unit that has been awarded clean coal technology demonstration funding as of January 1, 1991, by the Department of Energy.
(1) Within the performance specifications set forth in part 75, appendix A of this chapter and the quality assurance/quality control procedures set forth in part 75, appendix B of this chapter, without unscheduled maintenance, repair, or adjustment; and
(2) In accordance with § 75.10(d), (e), and (f) of this chapter.
(1) In person;
(2) By United States Postal Service; or
(3) By other equivalent means of dispatch, or transmission, and delivery. Compliance with any “submission”, “service”, or “mailing” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
(1) The total electrical generation (MWe) for use within the plant and for sale; or
(2) In the case of a unit or source that uses part of its heat input for purposes other than electrical generation, the total steam pressure (psia) produced by the unit or source.
(1) That serves a generator in any State that produces electricity for sale, or
(2) That during 1985, served a generator in any State that produced electricity for sale.
(3) Notwithstanding paragraphs (1) and (2) of this definition, a unit that was in operation during 1985, but did not serve a generator that produced electricity for sale during 1985, and did not commence commercial operation on or after November 15, 1990 is not a utility unit for purposes of the Acid Rain Program.
(4) Notwithstanding paragraphs (1) and (2) of this definition, a unit that cogenerates steam and electricity is not a utility unit for purposes of the Acid Rain Program, unless the unit is constructed for the purpose of supplying, or commences construction after November 15, 1990 and supplies, more than one-third of its potential electrical output capacity and more than 25 MWe output to any power distribution system for sale.
(1) A fuel with a total sulfur content no greater than 0.05 percent sulfur by weight;
(2) Natural gas or pipeline natural gas, as defined in this section; or
(3) Any gaseous fuel with a total sulfur content no greater than 20 grains of sulfur per 100 standard cubic feet.
(1) A calibration gas certified by the gas vendor not to contain concentrations of SO
(2) Ambient air conditioned and purified by a CEMS for which the CEMS manufacturer or vendor certifies that the particular CEMS model produces conditioned gas that does not contain concentrations of SO
(3) For dilution-type CEMS, conditioned and purified ambient air provided by a conditioning system concurrently supplying dilution air to the CEMS; or
(4) A multicomponent mixture certified by the supplier of the mixture that the concentration of the component being zeroed is less than or equal to the applicable concentration specified in paragraph (1) of this definition, and that the mixture's other components do not interfere with the CEM readings.
Measurements, abbreviations, and acronyms used in this part are defined as follows:
(a) The Administrator reserves all authority under sections 112(r)(9), 113, 114, 120, 301, 303, 304, 306, and 307(a) of the Act, including, but not limited to, the authority to:
(1) Secure information needed for the purpose of developing, revising, or implementing, or of determining whether any person is in violation of, any standard, method, requirement, or prohibition of the Act, this part, parts 73, 74, 75, 76, 77, and 78 of this chapter;
(2) Make inspections, conduct tests, examine records, and require an owner or operator of an affected unit to submit information reasonably required for the purpose of developing, revising, or implementing, or of determining whether any person is in violation of, any standard, method, requirement, or prohibition of the Act, this part, parts 73, 74, 75, 76, 77, and 78 of this chapter.
(3) Issue orders, call witnesses, and compel the production of documents.
(b) The Administrator reserves the right under title IV of the Act to take any action necessary to protect the orderly and competitive functioning of the allowance system, including actions to prevent fraud and misrepresentation.
Consistent with section 116 of the Act, the provisions of the Acid Rain Program shall not be construed in any manner to preclude any State from adopting and enforcing any other air quality requirement (including any continuous emissions monitoring) that is not less stringent than, and does not alter, any requirement applicable to an affected unit or affected source under the Acid Rain Program;
(a) Each of the following units shall be an affected unit, and any source that includes such a unit shall be an affected source, subject to the requirements of the Acid Rain Program:
(1) A unit listed in table 1 of § 73.10(a) of this chapter.
(2) A unit that is listed in table 2 or 3 of § 73.10 of this chapter and any other existing utility unit, except a unit under paragraph (b) of this section.
(3) A utility unit, except a unit under paragraph (b) of this section, that:
(i) Is a new unit; or
(ii) Did not serve a generator with a nameplate capacity greater than 25 MWe on November 15, 1990 but serves such a generator after November 15, 1990.
(iii) Was a simple combustion turbine on November 15, 1990 but adds or uses auxiliary firing after November 15, 1990;
(iv) Was an exempt cogeneration facility under paragraph (b)(4) of this section but during any three calendar year period after November 15, 1990 sold, to a utility power distribution system, an annual average of more
(v) Was an exempt qualifying facility under paragraph (b)(5) of this section but, at any time after the later of November 15, 1990 or the date the facility commences commercial operation, fails to meet the definition of qualifying facility;
(vi) Was an exempt IPP under paragraph (b)(6) of this section but, at any time after the later of November 15, 1990 or the date the facility commences commercial operation, fails to meet the definition of independent power production facility; or
(vii) Was an exempt solid waste incinerator under paragraph (b)(7) of this section but during any three calendar year period after November 15, 1990 consumes 20 percent or more (on a Btu basis) fossil fuel.
(b) The following types of units are not affected units subject to the requirements of the Acid Rain Program:
(1) A simple combustion turbine that commenced commercial operation before November 15, 1990.
(2) Any unit that commenced commercial operation before November 15, 1990 and that did not, as of November 15, 1990, and does not currently, serve a generator with a nameplate capacity of greater than 25 MWe.
(3) Any unit that, during 1985, did not serve a generator that produced electricity for sale and that did not, as of November 15, 1990, and does not currently, serve a generator that produces electricity for sale.
(4) A cogeneration facility which:
(i) For a unit that commenced construction on or prior to November 15, 1990, was constructed for the purpose of supplying equal to or less than one-third its potential electrical output capacity or equal to or less than 219,000 MWe-hrs actual electric output on an annual basis to any utility power distribution system for sale (on a gross basis). If the purpose of construction is not known, the Administrator will presume that actual operation from 1985 through 1987 is consistent with such purpose. However, if in any three calendar year period after November 15, 1990, such unit sells to a utility power distribution system an annual average of more than one-third of its potential electrical output capacity and more than 219,000 MWe-hrs actual electric output (on a gross basis), that unit shall be an affected unit, subject to the requirements of the Acid Rain Program; or
(ii) For units which commenced construction after November 15, 1990, supplies equal to or less than one-third its potential electrical output capacity or equal to or less than 219,000 MWe-hrs actual electric output on an annual basis to any utility power distribution system for sale (on a gross basis). However, if in any three calendar year period after November 15, 1990, such unit sells to a utility power distribution system an annual average of more than one-third of its potential electrical output capacity and more than 219,000 MWe-hrs actual electric output (on a gross basis), that unit shall be an affected unit, subject to the requirements of the Acid Rain Program.
(5) A qualifying facility that:
(i) Has, as of November 15, 1990, one or more qualifying power purchase commitments to sell at least 15 percent of its total planned net output capacity; and
(ii) Consists of one or more units designated by the owner or operator with total installed net output capacity not exceeding 130 percent of the total planned net output capacity. If the emissions rates of the units are not the same, the Administrator may exercise discretion to designate which units are exempt.
(6) An independent power production facility that:
(i) Has, as of November 15, 1990, one or more qualifying power purchase commitments to sell at least 15 percent of its total planned net output capacity; and
(ii) Consists of one or more units designated by the owner or operator with total installed net output capacity not exceeding 130 percent of its total planned net output capacity. If the emissions rates of the units are not the same, the Administrator may exercise discretion to designate which units are exempt.
(7) A solid waste incinerator, if more than 80 percent (on a Btu basis) of the
(8) A non-utility unit.
(9) A unit for which an exemption under § 72.7, § 72.8, or § 72.14 is in effect. Although such a unit is not an affected unit, the unit shall be subject to the requirements of § 72.7, § 72.8, or § 72.14, as applicable to the exemption.
(c) A certifying official of an owner or operator of any unit may petition the Administrator for a determination of applicability under this section.
(1)
(2)
(3)
(4)
(5)
(6)
(a)
(1) Serves during the entire year (except for any period before the unit commenced commercial operation) one or more generators with total nameplate capacity of 25 MWe or less;
(2) Burns fuel that does not include any coal or coal-derived fuel (except coal-derived gaseous fuel with a total sulfur content no greater than natural gas); and
(3) Burns gaseous fuel with an annual average sulfur content of 0.05 percent or less by weight (as determined under paragraph (d) of this section) and nongaseous fuel with an annual average sulfur content of 0.05 percent or less by weight (as determined under paragraph (d) of this section).
(b)(1) Any new utility unit that meets the requirements of paragraph (a) of this section and that is not allocated any allowances under subpart B of part 73 of this chapter shall be exempt from the Acid Rain Program, except for the provisions of this section, §§ 72.2 through 72.6, and §§ 72.10 through 72.13.
(2) The exemption under paragraph (b)(1) of this section shall be effective on January 1 of the first full calendar year for which the unit meets the requirements of paragraph (a) of this section. By December 31 of the first year for which the unit is to be exempt
(3) After receipt of the statement under paragraph (b)(2) of this section, the permitting authority shall amend under § 72.83 the operating permit covering the source at which the unit is located, if the source has such a permit, to add the provisions and requirements of the exemption under paragraphs (a), (b)(1), (d), and (f) of this section.
(c)(1) Any new utility unit that meets the requirements of paragraph (a) of this section and that is allocated one or more allowances under subpart B of part 73 of this chapter shall be exempt from the Acid Rain Program, except for the provisions of this section, §§ 72.2 through 72.6, and §§ 72.10 through 72.13, if each of the following requirements are met:
(i) The designated representative (authorized in accordance with subpart B of this part) or, if no designated representative has been authorized, a certifying official of each owner of the unit submits to the permitting authority otherwise responsible for administering a Phase II Acid Rain permit for the unit a statement (in a format prescribed by the Administrator) that:
(A) Identifies the unit and states the nameplate capacity of each generator served by the unit and the fuels currently burned or expected to be burned by the unit and their sulfur content by weight;
(B) States that the owners and operators of the unit will comply with paragraph (f) of this section;
(C) Surrenders allowances equal in number to, and with the same or earlier compliance use date as, all of those allocated to the unit under subpart B of part 73 of this chapter for the first year that the unit is to be exempt under this section and for each subsequent year; and
(D) Surrenders any proceeds for allowances under paragraph (c)(1)(i)(C) or this section withheld from the unit under § 73.10 of this chapter. If the Administrator is not the permitting authority, a copy of the statement shall be submitted to the Administrator.
(ii) The Administrator deducts from the unit's Allowance Tracking System account allowances under paragraph (c)(1)(i)(C) of this section and receives proceeds under paragraph (c)(1)(i)(D) of this section. Within 5 business days of receiving a statement in accordance with paragraph (c)(1)(i) of this section, the Administrator shall either deduct the allowances under paragraph (c)(1)(i)(C) of this section or notify the owners and operators that there are insufficient allowances to make such deductions. Upon completion of such deductions and receipt of such proceeds, the Administrator will close the unit's Allowance Tracking System account and notify the designated representative (or certifying official) and, if the Administrator is not the permitting authority otherwise responsible for administering a Phase II Acid Rain permit for the unit, the permitting authority.
(2) The exemption under paragraph (c)(1) of this section shall be effective on January 1 of the first full calendar year for which the requirements of paragraphs (a) and (c)(1) of this section are met. After notification by the Administrator under the third sentence of paragraph (c)(1)(ii) of this section, the permitting authority shall amend under § 72.83 the operating permit covering the source at which the unit is located, if the source has such a permit, to add the provisions and requirements of the exemption under paragraphs (a), (c)(1), (d), and (f) of this section.
(d) Compliance with the requirement that fuel burned during the year have an annual average sulfur content of 0.05 percent by weight or less shall be determined as follows using a method of determining sulfur content that provides information with reasonable precision, reliability, accessibility, and timeliness:
(1) For gaseous fuel burned during the year, if natural gas is the only gaseous fuel burned, the requirement is assumed to be met;
(2) For gaseous fuel burned during the year where other gas in addition to or besides natural gas is burned, the requirement is met if the annual average sulfur content is equal to or less than 0.05 percent by weight. The annual average sulfur content, as a percentage by weight, for the gaseous fuel burned shall be calculated as follows:
(3) For nongaseous fuel burned during the year, the requirement is met if the annual average sulfur content is equal to or less than 0.05 percent by weight. The annual average sulfur content, as a percentage by weight, shall be calculated using the equation in paragraph (d)(2) of this section. In lieu of the factor, volume times density (V
(e)(1) A utility unit that was issued a written exemption under this section and that meets the requirements of paragraph (a) of this section shall be exempt from the Acid Rain Program, except for the provisions of this section, §§ 72.2 through 72.6, and §§ 72.10 through 72.13 and shall be subject to the requirements of paragraphs (a), (d), (e)(2), and (f) of this section in lieu of the requirements set forth in the written exemption. The permitting authority shall amend under § 72.83 the operating permit covering the source at which the unit is located, if the source has such a permit, to add the provisions and requirements of the exemption under this paragraph (e)(1) and paragraphs (a), (d), (e)(2), and (f) of this section.
(2) If a utility unit under paragraph (e)(1) of this section is allocated one or more allowances under subpart B of part 73 of this chapter, the designated representative (authorized in accordance with subpart B of this part) or, if no designated representative has been authorized, a certifying official of each owner of the unit shall submit to the permitting authority that issued the written exemption a statement (in a format prescribed by the Administrator) meeting the requirements of paragraph (c)(1)(i)(C) and (D) of this section. The statement shall be submitted by June 31, 1998 and, if the Administrator is not the permitting authority, a copy shall be submitted to the Administrator.
(f)
(i) Comply with the requirements of paragraph (a) of this section for all periods for which the unit is exempt under this section; and
(ii) Comply with the requirements of the Acid Rain Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect.
(2) For any period for which a unit is exempt under this section, the unit is not an affected unit under the Acid Rain Program and parts 70 and 71 of this chapter and is not eligible to be an opt-in source under part 74 of this chapter. As an unaffected unit, the unit shall continue to be subject to any other applicable requirements under parts 70 and 71 of this chapter.
(3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under this section shall retain at the source that includes the unit records demonstrating that the requirements of paragraph (a) of this section are met. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the Administrator or the permitting authority.
(i) Such records shall include, for each delivery of fuel to the unit or for fuel delivered to the unit continuously by pipeline, the type of fuel, the sulfur content, and the sulfur content of each sample taken.
(ii) The owners and operators bear the burden of proof that the requirements of paragraph (a) of this section are met.
(4) Loss of exemption. (i) On the earliest of the following dates, a unit exempt under paragraphs (b), (c), or (e) of this section shall lose its exemption and become an affected unit under the Acid Rain Program and parts 70 and 71 of this chapter:
(A) The date on which the unit first serves one or more generators with total nameplate capacity in excess of 25 MWe;
(B) The date on which the unit burns any coal or coal-derived fuel except for coal-derived gaseous fuel with a total sulfur content no greater than natural gas; or
(C) January 1 of the year following the year in which the annual average sulfur content for gaseous fuel burned at the unit exceeds 0.05 percent by weight (as determined under paragraph (d) of this section) or for nongaseous fuel burned at the unit exceeds 0.05 percent by weight (as determined under paragraph (d) of this section).
(ii) Notwithstanding § 72.30(b) and (c), the designated representative for a unit that loses its exemption under this section shall submit a complete Acid Rain permit application on the later of January 1, 1998 or 60 days after the first date on which the unit is no longer exempt.
(iii) For the purpose of applying monitoring requirements under part 75 of this chapter, a unit that loses its exemption under this section shall be treated as a new unit that commenced commercial operation on the first date on which the unit is no longer exempt.
(a) This section applies to any affected unit (except for an opt-in source) that is permanently retired.
(b)(1) Any affected unit (except for an opt-in source) that is permanently retired shall be exempt from the Acid Rain Program, except for the provisions of this section, §§ 72.2 through 72.6, §§ 72.10 through 72.13, and subpart B of part 73 of this chapter.
(2) The exemption under paragraph (b)(1) of this section shall become effective on January 1 of the first full calendar year during which the unit is permanently retired. By December 31 of the first year that the unit is to be exempt under this section, the designated representative (authorized in accordance with subpart B of this part), or, if no designated representative has been authorized, a certifying official of each owner of the unit shall submit a statement to the permitting authority otherwise responsible for administering a Phase II Acid Rain permit for the unit. If the Administrator is not the permitting authority, a copy of the statement shall be submitted to the Administrator. The statement shall state (in a format prescribed by the Administrator) that the unit is permanently retired and will comply with the requirements of paragraph (d) of this section.
(3) After receipt of the notice under paragraph (b)(2) of this section, the permitting authority shall amend
(c) A unit that was issued a written exemption under this section and that is permanently retired shall be exempt from the Acid Rain Program, except for the provisions of this section, §§ 72.2 through 72.6, §§ 72.10 through 72.13, and subpart B of part 73 of this chapter, and shall be subject to the requirements of paragraph (d) of this section in lieu of the requirements set forth in the written exemption. The permitting authority shall amend under § 72.83 the operating permit covering the source at which the unit is located, if the source has such a permit, to add the provisions and requirements of the exemption under this paragraph (c) and paragraph (d) of this section.
(d)
(2) A unit exempt under this section shall not resume operation unless the designated representative of the source that includes the unit submits a complete Acid Rain permit application under § 72.31 for the unit not less than 24 months prior to the later of January 1, 2000 or the date on which the unit is first to resume operation.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under this section shall comply with the requirements of the Acid Rain Program concerning all periods for which the exemption is not in effect, even if such requirements arise, or must be complied with, after the exemption takes effect.
(4) For any period for which a unit is exempt under this section, the unit is not an affected unit under the Acid Rain Program and parts 70 and 71 of this chapter and is not eligible to be an opt-in source under part 74 of this chapter. As an unaffected unit, the unit shall continue to be subject to any other applicable requirements under parts 70 and 71 of this chapter.
(5) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under this section shall retain at the source that includes the unit records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the Administrator or the permitting authority. The owners and operators bear the burden of proof that the unit is permanently retired.
(6) Loss of exemption. (i) On the earlier of the following dates, a unit exempt under paragraph (b) or (c) of this section shall lose its exemption and become an affected unit under the Acid Rain Program and parts 70 and 71 of this chapter:
(A) The date on which the designated representative submits an Acid Rain permit application under paragraph (d)(2) of this section; or
(B) The date on which the designated representative is required under paragraph (d)(2) of this section to submit an Acid Rain permit application.
(ii) For the purpose of applying monitoring requirements under part 75 of this chapter, a unit that loses its exemption under this section shall be treated as a new unit that commenced commercial operation on the first date on which the unit resumes operation.
(a)
(i) Submit a complete Acid Rain permit application (including a compliance plan) under this part in accordance with the deadlines specified in § 72.30;
(ii) Submit in a timely manner a complete reduced utilization plan if required under § 72.43; and
(iii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review an Acid Rain permit application and issue or deny an Acid Rain permit.
(2) The owners and operators of each affected source and each affected unit at the source shall:
(i) Operate the unit in compliance with a complete Acid Rain permit application or a superseding Acid Rain permit issued by the permitting authority; and
(ii) Have an Acid Rain Permit.
(b)
(2) The emissions measurements recorded and reported in accordance with part 75 of this chapter shall be used to determine compliance by the unit with the Acid Rain emissions limitations and emissions reduction requirements for sulfur dioxide and nitrogen oxides under the Acid Rain Program.
(3) The requirements of part 75 of this chapter shall not affect the responsibility of the owners and operators to monitor emissions of other pollutants or other emissions characteristics at the unit under other applicable requirements of the Act and other provisions of the operating permit for the source.
(c)
(i) Hold allowances, as of the allowance transfer deadline, in the unit's compliance subaccount (after deductions under § 73.34(c) of this chapter) not less than the total annual emissions of sulfur dioxide for the previous calendar year from the unit; and
(ii) Comply with the applicable Acid Rain emissions limitation for sulfur dioxide.
(2) Each ton of sulfur dioxide emitted in excess of the Acid Rain emissions limitations for sulfur dioxide shall constitute a separate violation of the Act.
(3) An affected unit shall be subject to the requirements under paragraph (c)(1) of this section as follows:
(i) Starting January 1, 1995, an affected unit under § 72.6(a)(1);
(ii) Starting on or after January 1, 1995 in accordance with §§ 72.41 and 72.43, an affected unit under § 72.6(a) (2) or (3) that is a substitution or compensating unit;
(iii) Starting January 1, 2000, an affected unit under § 72.6(a)(2) that is not a substitution or compensating unit; or
(iv) Starting on the later of January 1, 2000 or the deadline for monitor certification under part 75 of this chapter, an affected unit under § 72.6(a)(3) that is not a substitution or compensating unit.
(4) Allowances shall be held in, deducted from, or transferred among Allowance Tracking System accounts in accordance with the Acid Rain Program.
(5) An allowance shall not be deducted, in order to comply with the requirements under paragraph (c)(1)(i) of this section, prior to the calendar year for which the allowance was allocated.
(6) An allowance allocated by the Administrator under the Acid Rain Program is a limited authorization to emit sulfur dioxide in accordance with the Acid Rain Program. No provision of the Acid Rain Program, the Acid Rain permit application, the Acid Rain permit, or an exemption under §§ 72.7, 72.8, or 72.14 and no provision of law shall be construed to limit the authority of the United States to terminate or limit such authorization.
(7) An allowance allocated by the Administrator under the Acid Rain Program does not constitute a property right.
(d)
(e)
(2) The owners and operators of an affected unit that has excess emissions in any calendar year shall:
(i) Pay without demand the penalty required, and pay upon demand the interest on that penalty, as required by part 77 of this chapter; and
(ii) Comply with the terms of an approved offset plan, as required by part 77 of this chapter.
(f)
(i) The certificate of representation for the designated representative for the source and each affected unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation, in accordance with § 72.24;
(ii) All emissions monitoring information, in accordance with part 75 of this chapter;
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the Acid Rain Program.
(iv) Copies of all documents used to complete an Acid Rain permit application and any other submission under the Acid Rain Program or to demonstrate compliance with the requirements of the Acid Rain Program.
(2) The designated representative of an affected source and each affected unit at the source shall submit the reports and compliance certifications required under the Acid Rain Program, including those under subpart I of this part and part 75 of this chapter.
(g)
(2) Any person who knowingly makes a false, material statement in any record, submission, or report under the Acid Rain Program shall be subject to criminal enforcement pursuant to section 113(c) of the Act and 18 U.S.C. 1001.
(3) No permit revision shall excuse any violation of the requirements of the Acid Rain Program that occurs prior to the date that the revision takes effect.
(4) Each affected source and each affected unit shall meet the requirements of the Acid Rain Program.
(5) Any provision of the Acid Rain Program that applies to an affected source (including a provision applicable to the designated representative of an affected source) shall also apply to the owners and operators of such source and of the affected units at the source.
(6) Any provision of the Acid Rain Program that applies to an affected unit (including a provision applicable to the designated representative of an affected unit) shall also apply to the owners and operators of such unit. Except as provided under § 72.41 (substitution plans), § 72.42 (Phase I extension plans), § 72.43 (reduced utilization plans), § 72.44 (Phase II repowering extension plans), § 74.47 of this chapter (thermal energy plans), and § 76.11 of this chapter (NO
(7) Each violation of a provision of this part, parts 73, 74, 75, 76, 77, and 78 of this chapter, by an affected source or affected unit, or by an owner or operator or designated representative of such source or unit, shall be a separate violation of the Act.
(h)
(1) Except as expressly provided in title IV of the Act, exempting or excluding the owners and operators and, to the extent applicable, the designated representative of an affected source or affected unit from compliance with any other provision of the Act, including the provisions of title I of the Act relating to applicable National Ambient Air Quality Standards or State Implementation Plans.
(2) Limiting the number of allowances a unit can hold;
(3) Requiring a change of any kind in any State law regulating electric utility rates and charges, affecting any State law regarding such State regulation, or limiting such State regulation, including any prudence review requirements under such State law.
(4) Modifying the Federal Power Act or affecting the authority of the Federal Energy Regulatory Commission under the Federal Power Act.
(5) Interfering with or impairing any program for competitive bidding for power supply in a State in which such program is established.
The availability to the public of information provided to, or otherwise obtained by, the Administrator under the Acid Rain Program shall be governed by part 2 of this chapter.
(a) Unless otherwise stated, any time period scheduled, under the Acid Rain Program, to begin on the occurrence of an act or event shall begin on the day the act or event occurs.
(b) Unless otherwise stated, any time period scheduled, under the Acid Rain Program, to begin before the occurrence of an act or event shall be computed so that the period ends on the day before the act or event occurs.
(c) Unless otherwise stated, if the final day of any time period, under the Acid Rain Program, falls on a weekend or a Federal holiday, the time period shall be extended to the next business day.
(d) Whenever a party or interested person has the right, or is required, to act under the Acid Rain Program within a prescribed time period after service of notice or other document upon him or her by mail, 3 days shall be added to the prescribed time.
The procedures for appeals of decisions of the Administrator under this part are contained in part 78 of this chapter.
The materials listed in this section are incorporated by reference in the corresponding sections noted. These incorporations by reference were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they existed on the date of approval, and a notice of any change in these materials will be published in the
(a) The following materials are available for purchase from the following addresses: American Society for Testing and Material (ASTM), 1916 Race Street, Philadelphia, Pennsylvania 19103; and the University Microfilms
(1) ASTM D388-92, Standard Classification of Coals by Rank for § 72.2 of this chapter.
(2) ASTM D396-90a, Standard Specification for Fuel Oils, for § 72.2 of this chapter.
(3) ASTM D975-91, Standard Specification for Diesel Fuel Oils, for § 72.2 of this chapter.
(4) ASTM D2880-90a, Standard Specification for Gas Turbine Fuel Oils, for § 72.2 of this part.
(b) [Reserved]
(a)
(1) Starting on the date of the signing of the interconnection agreement under paragraph (a)(2) of this section and thereafter, there has been no owner or operator of the unit, division or subsidiary or affiliate or parent company of an owner or operator of the unit, or combination thereof whose principalbusiness is the sale, transmission, or distribution of electricity or that is a public utility under the jurisdiction of a State or local utility regulatory authority;
(2) On or before March 23, 1993, the owners or operators of the unit entered into an interconnection agreement and any related power purchase agreement with a person whose principal business is the sale, transmission, or distribution of electricity or that is a public utility under the jurisdiction of a State or local utility regulatory authority, requiring the generator or generators served by the unit to produce electricity for sale only for incidental electricity sales to such person;
(3) The unit served or serves one or more generators that, in 1985 or any year thereafter, actually produced electricity for sale only for incidental electricity sales required under the interconnection agreement and any related power purchase agreement under paragraph (a)(2) of this section or a successor agreement under paragraph (d)(4)(ii) of this section; and
(4) Incidental electricity sales, under this section, are total annual sales of electricity produced by a generator that do not exceed 10 percent of the nameplate capacity of that generator times 8,760 hours per year and do not exceed 10 percent of the actual annual electric output of that generator.
(b)
(1) Identification of the unit;
(2) A statement that the unit is not a cogeneration unit;
(3) A list of the current owners and operators of the unit and any other owners and operators of the unit, starting on the date of the signing of the interconnection agreement under paragraph (a)(2) of this section, and a statement that, starting on that date, there has been no owner or operator of the unit, division or subsidiary or affiliate or parent company of an owner or operator of the unit, or combination thereof whose principal business is the sale, transmission, or distribution of electricity or that is a public utility under the jurisdiction of a State or local utility regulatory authority;
(4) A summary of the terms of the interconnection agreement and any related power purchase agreement under paragraph (a)(2) of this section and any successor agreement under paragraph (d)(4)(ii) of this section, including the date on which the agreement was signed, the amount of electricity that may be required to be produced for sale
(5) A copy of the interconnection agreement and any related power purchase agreement under paragraph (a)(2) of this section and any successor agreement under paragraph (d)(4)(ii) of this section;
(6) The nameplate capacity of each generator served by the unit;
(7) For each year starting in 1985, the actual annual electrical output of each generator served by the unit, the total amount of electricity produced for sales to any customer by each generator, and the total amount of electricity produced and sold as required by the interconnection agreement and any related power purchase agreement under paragraph (a)(2) of this section or any successor agreement under paragraph (d)(4)(ii) of this section;
(8) A statement that each generator served by the unit actually produced electricity for sale only for incidental electricity sales (in accordance with paragraph (a)(4) of this section) required under the interconnection agreement and any related power purchase agreement under paragraph (a)(2) of this section or any successor agreement under paragraph (d)(4)(ii) of this section; and
(9) The special provisions of paragraph (d) of this section.
(c)
(ii) If a petition for exemption is submitted for a unit but the designated representative fails to demonstrate that the requirements of paragraph (a) of this section are met, the permitting authority shall deny an exemption under this section.
(2) In issuing or denying an exemption under paragraph (c)(1) of this section, the permitting authority shall treat the petition for exemption as a permit application and apply the procedures used for issuing or denying draft, proposed (if the Administrator is not the permitting authority otherwise responsible for administering a Phase II Acid Rain permit for the unit), and final Acid Rain permits.
(3) An exemption issued under paragraph (c)(1)(i) of this section shall become effective on January 1 of the first full year the unit meets the requirements of paragraph (a) of this section.
(4) An exemption issued under paragraph (c)(1)(i) of this section shall be effective until the date on which the unit loses the exemption under paragraph (d)(4) of this section.
(5) After issuance of the exemption under paragraphs (c)(1) and (2) of this section, the permitting authority shall amend under § 72.83 the operating permit covering the source at which the unit is located, if the source has such a permit, to add the provisions and requirements of the exemption under paragraphs (c)(1)(i) and (d) of this section.
(d)
(2) For any period for which a unit is exempt under this section, the unit is not an affected unit under the Acid Rain Program and parts 70 and 71 of this chapter and is not eligible to be an opt-in source under part 74 of this chapter. As an unaffected unit, the unit shall continue to be subject to any other applicable requirements under parts 70 and 71 of this chapter.
(3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under this section shall retain at the source that includes the unit records demonstrating that the requirements of paragraph (a) of this section are met. The owners and operators bear the burden of proof that the requirements of this section are met. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the Administrator or the permitting
(i) A copy of the interconnection agreement and any related power purchase agreement under paragraph (a)(2) of this section and any successor agreement under paragraph (d)(4)(ii) of this section;
(ii) The nameplate capacity of each generator served by the unit; and
(iii) For each year starting in 1985, the actual annual electrical output of each generator served by the unit, the total amount of electricity produced for sales to any customer by each generator, and the total amount of electricity produced and sold as required by the interconnection agreement and any related power purchase agreement under paragraph (a)(2) of this section or any successor agreement under paragraph (d)(4)(ii) of this section.
(4) Loss of exemption. (i) On the earliest of the following dates, a unit exempt under this section shall lose its exemption and become an affected unit under the Acid Rain Program and parts 70 and 71 of this chapter:
(A) The first date on which there is an owner or operator of the unit, division or subsidiary or affiliate or parent company of an owner or operator of the unit, or combination thereof, whose principal business is the sale, transmission, or distribution of electricity or that is a public utility under the jurisdiction of a State or local utility regulatory authority.
(B) If any generator served by the unit actually produces any electricity for sale other than for sale to the person specified as the purchaser in the interconnection agreement or any related power purchase agreement under paragraph (a)(2) of this section or a successor agreement under paragraph (d)(4)(ii) of this section, then the day after the date on which such electricity is sold.
(C) If any generator served by the unit actually produces any electricity for sale to the person specified as the purchaser in the interconnection agreement or any related power purchase agreement under paragraph (a)(2) of this section or a successor agreement under paragraph (d)(4)(ii) of this section where such sale is not required under that interconnection agreement or related power purchase agreement or successor agreement or where such sale will result in total sales for a calendar year exceeding 10 percent of the nameplate capacity of that generator times 8,769 hours per year, then the day after the date on which such sale is made.
(D) If any generator served by the unit actually produces any electricity for sale to the person specified as the purchaser in the interconnection agreement or related power purchase agreement under paragraph (a)(2) of this section or a successor agreement under paragraph (d)(4)(ii) of this section where such sale results in total sales for a calendar year exceeding 10 percent of the actual electric output of the generator for that year, then January 1 of the year after such year.
(E) If the interconnection agreement or related power purchase agreement under paragraph (a)(2) of this section expires or is terminated, no successor agreement under paragraph (d)(4)(ii) of this section is in effect, and any generator served by the unit actually produces any electricity for sale, then the day after the date on which such electricity is sold.
(ii) A “successor agreement” is an agreement that:
(A) Modifies, replaces or supersedes the interconnection agreement or related power purchase agreement under paragraph (a)(2) of this section;
(B) Is between the owners and operators of the unit and a person that is contractually obligated to sell electricity to the owners and operators of the unit and either whose principal business is the sale, transmission, or distribution of electricity or that is a public utility under the jurisdiction of a State or local utility regulatory authority; and
(C) Requires the generator served by the unit to produce electricity for sale to the person under paragraph (d)(4)(ii)(B) of this section and only for incidental electricity sales, such that the total amount of electricity that such generator is required to produce for sale under the interconnection agreement or related power purchase agreement (to the extent they are still in effect) and the successor agreement shall not exceed the total amount of
(iii) Notwithstanding § 72.30(b) and (c), the designated representative for a unit that loses its exemption under this section shall submit a complete Acid Rain permit application on the later of January 1, 1998 or 60 days after the first date on which the unit is no longer exempt.
(iv) For the purpose of applying monitoring requirements under part 75 of this chapter, a unit that loses its exemption under this section shall be treated as a new unit that commenced commercial operation on the first date on which the unit is no longer exempt.
(a) Except as provided under § 72.22, each affected source, including all affected units at the source, shall have one and only one designated representative, with regard to all matters under the Acid Rain Program concerning the source or any affected unit at the source.
(b) Upon receipt by the Administrator of a complete certificate of representation, the designated representative of the source shall represent and, by his or her actions, inactions, or submissions, legally bind each owner and operator of the affected source represented and each affected unit at the source in all matters pertaining to the Acid Rain Program, not withstanding any agreement between the designated representative and such owners and operators. The owners and operators shall be bound by any order issued to the designated representative by the Administrator, the permitting authority, or a court.
(c) The designated representative shall be selected and act in accordance with the certifications set forth in § 72.24(a) (4), (5), (7), and (9).
(d) No Acid Rain permit shall be issued to an affected source, nor shall any allowance transfer be recorded for an Allowance Tracking System account of an affected unit at a source, until the Administrator has received a complete certificate of representation for the designated representative of the source and the affected units at the source.
(a) Each submission under the Acid Rain Program shall be submitted, signed, and certified by the designated representative for all sources on behalf of which the submission is made.
(b) In each submission under the Acid Rain Program, the designated representative shall certify, by his or her signature:
(1) The following statement, which shall be included verbatim in such submission: “I am authorized to make this submission on behalf of the owners and operators of the affected source or affected units for which the submission is made.”
(2) The following statement, which shall be included verbatim in such submission: “I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(c) The Administrator and the permitting authority shall accept or act on a submission made on behalf of owners or operators of an affected source and an affected unit only if the submission has been made, signed, and certified in accordance with paragraphs (a) and (b) of this section.
(d)(1) The designated representative of a source shall serve notice on each owner and operator of the source and of an affected unit at the source:
(i) By the date of submission, of any Acid Rain Program submissions by the designated representative and
(ii) Within 10 business days of receipt of a determination, of any written determination by the Administrator or the permitting authority,
(iii) Provided that the submission or determination covers the source or the unit.
(2) The designated representative of a source shall provide each owner and operator of an affected unit at the source a copy of any submission or determination under paragraph (d)(1) of this section, unless the owner or operator expressly waives the right to receive such a copy.
(e) The provisions of this section shall apply to a submission made under parts 73, 74, 75, 76, 77, and 78 of this chapter only if it is made or signed or required to be made or signed, in accordance with parts 73, 74, 75, 76, 77, and 78 of this chapter, by:
(1) The designated representative; or
(2) The authorized account representative or alternate authorized account representative of a unit account.
(a) The certificate of representation may designate one and only one alternate designated representative, who may act on behalf of the designated representative. The agreement by which the alternate designated representative is selected shall include a procedure for the owners and operators of the source and affected units at the source to authorize the alternate designated representative to act in lieu of the designated representative.
(b) Upon receipt by the Administrator of a complete certificate of representation that meets the requirements of § 72.24 (including those applicable to the alternate designated representative), any action, representation, or failure to act by the alternate designated representative shall be deemed to be an action, representation, or failure to act by the designated representative.
(c) In the event of a conflict, any action taken by the designated representative shall take precedence over any action taken by the alternate designated representative if, in the Administrator's judgement, the actions are concurrent and conflicting.
(d) Except in this section, § 72.23, and § 72.24, whenever the term “designated representative” is used under the Acid Rain Program, the term shall be construed to include the alternate designated representative.
(e)(1) Notwithstanding paragraph (a) of this section, the certification of representation may designate two alternate designated representatives for a unit if:
(i) The unit and at least one other unit, which are located in two or more of the contiguous 48 States or the District of Columbia, each have a utility system that is a subsidiary of the same company; and
(ii) The designated representative for the units under paragraph (e)(1)(i) of this section submits a NO
(2) Except in this paragraph (e), whenever the term “alternate designated representative” is used under the Acid Rain Program, the term shall be construed to include either of the alternate designated representatives authorized under this paragraph (e). Except in this section, § 72.23, and § 72.24, whenever the term “designated representative” is used under the Acid Rain Program, the term shall be construed to include either of the alternate designated representatives authorized under this paragraph (e).
(a)
(b)
(c)
(2) Within 30 days following any change in the owners and operators of an affected unit, including the addition of a new owner or operator, the designated representative or any alternative designated representative shall submit a revision to the certificate of representation amending the list of owners and operators to include the change.
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the affected source and each affected unit at the source for which the certificate of representation is submitted.
(2) The name, address, and telephone and facsimile numbers of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the affected source and of each affected unit at the source.
(4) The following statement: “I certify that I was selected as the ‘designated representative’ or ‘alternate designated representative,’ as applicable, by an agreement binding on the owners and operators of the affected source and each affected unit at the source.”
(5) The following statement: “I certify that I have given notice of the agreement, selecting me as the ‘designated representative’ for the affected source and each affected unit at the source identified in this certificate of representation, in a newspaper of general circulation in the area where the source is located or in a State publication designed to give general public notice.”
(6) The following statement: “I certify that I have all necessary authority to carry out my duties and responsibilities under the Acid Rain Program on behalf of the owners and operators of the affected source and of each affected unit at the source and that each such owner and operator shall be fully bound by my actions, inactions, or submissions.”
(7) The following statement: “I certify that I shall abide by any fiduciary responsibilities imposed by the agreement by which I was selected as ‘designated representative’ or ‘alternate designated representative’, as applicable.”
(8) The following statement: “I certify that the owners and operators of the affected source and of each affected unit at the source shall be bound by any order issued to me by the Administrator, the permitting authority, or a court regarding the source or unit.”
(9) The following statement: “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, an affected unit, or where a utility or industrial customer purchases
(i) “I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by which I was selected to each owner and operator of the affected source and of each affected unit at the source; and
(ii) “Allowances and proceeds of transactions involving allowances will be deemed to be held or distributed in proportion to each holder's legal, equitable, leasehold, or contractual reservation or entitlement or, if such multiple holders have expressly provided for a different distribution of allowances by contract, that allowances and the proceeds of transactions involving allowances will be deemed to be held or distributed in accordance with the contract.”
(10) If an alternate designated representative is authorized in the certificate of representation, the following statement: “The agreement by which I was selected as the alternate designated representative includes a procedure for the owners and operators of the source and affected units at the source to authorize the alternate designated representative to act in lieu of the designated representative.”
(11) The signature of the designated representative and any alternate designated representative who is authorized in the certificate of representation and the date signed.
(b) Unless otherwise required by the Administrator or the permitting authority, documents of agreement or notice referred to in the certificate of representation shall not be submitted to the Administrator or the permitting authority. Neither the Administrator nor the permitting authority shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(a) Once a complete certificate of representation has been submitted in accordance with § 72.24, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate is received by the Administrator.
(b) Except as provided in § 72.23, no objection or other communication submitted to the Administrator or the permitting authority concerning the authorization, or any submission, action or inaction, of the designated representative shall affect any submission, action, or inaction of the designated representative, or the finality of any decision by the Administrator or permitting authority, under the Acid Rain Program. In the event of such communication, the Administrator and the permitting authority are not required to stay any allowance transfer, any submission, or the effect of any action or inaction under the Acid Rain Program.
(c) Neither the Administrator nor any permitting authority will adjudicate any private legal dispute concerning the authorization or any submission, action, or inaction of any designated representative, including private legal disputes concerning the proceeds of allowance transfers.
(a)
(b)
(A) Any source with such a unit under § 72.6(a)(1); and
(B) Any source with such a unit under § 72.6(a) (2) or (3) that is designated a substitution or compensating
(ii) Notwithstanding paragraph (b)(1)(i) of this section, if a unit at a source not previously permitted is designated a substitution or compensating unit in a submission requesting revision of an existing Acid Rain permit, the designated representative of the unit shall submit a complete Acid Rain permit application on the date that the submission requesting the revision is made.
(2)
(ii) For any source with a new unit under § 72.6(a)(3)(i), the designated representative shall submit a complete Acid Rain permit application governing such unit to the permitting authority at least 24 months before the later of January 1, 2000 or the date on which the unit commences operation.
(iii) For any source with a unit under § 72.6(a)(3)(ii), the designated representative shall submit a complete Acid Rain permit application governing such unit to the permitting authority at least 24 months before the later of January 1, 2000 or the date on which the unit begins to serve a generator with a nameplate capacity greater than 25 MWe.
(iv) For any source with a unit under § 72.6(a)(3)(iii), the designated representative shall submit a complete Acid Rain permit application governing such unit to the permitting authority at least 24 months before the later of January 1, 2000 or the date on which the auxiliary firing commences operation.
(v) For any source with a unit under § 72.6(a)(3)(iv), the designated representative shall submit a complete Acid Rain permit application governing such unit to the permitting authority before the later of January 1, 1998 or March 1 of the year following the three calendar year period in which the unit sold to a utility power distribution system an annual average of more than one-third of its potential electrical output capacity and more than 219,000 MWe-hrs actual electric output (on a gross basis).
(vi) For any source with a unit under § 72.6(a)(3)(v), the designated representative shall submit a complete Acid Rain permit application governing such unit to the permitting authority before the later of January 1, 1998 or March 1 of the year following the calendar year in which the facility fails to meet the definition of qualifying facility.
(vii) For any source with a unit under § 72.6(a)(3)(vi), the designated representative shall submit a complete Acid Rain permit application governing such unit to the permitting authority before the later of January 1, 1998 or March 1 of the year following the calendar year in which the facility fails to meet the definition of an independent power production facility.
(viii) For any source with a unit under § 72.6(a)(3)(vii), the designated representative shall submit a complete Acid Rain permit application governing such unit to the permitting authority before the later of January 1, 1998 or March 1 of the year following the three calendar year period in which the incinerator consumed 20 percent or more fossil fuel (on a Btu basis).
(c)
(d) The original and three copies of all permit applications for Phase I and where the Administrator is the permitting authority, for Phase II, shall be submitted to the EPA Regional Office for the Region where the affected source is located. The original and three copies of all permit applications for Phase II, where the Administrator is not the permitting authority, shall be submitted to the State permitting
(e) Where two or more affected units are located at a source, the permitting authority may, in its sole discretion, allow the designated representative of the source to submit, under paragraph (a) or (c) of this section, two or more Acid Rain permit applications covering the units at the source,
A complete Acid Rain permit application shall include the following elements in a format prescribed by the Administrator:
(a) Identification of the affected source for which the permit application is submitted;
(b) Identification of each Phase I unit at the source for which the permit application is submitted for Phase I or each affected unit (except for an opt-in source) at the source for which the permit application is submitted for Phase II;
(c) A complete compliance plan for each unit, in accordance with subpart D of this part;
(d) The standard requirements under § 72.9; and
(e) If the Acid Rain permit application is for Phase II and the unit is a new unit, the date that the unit has commenced or will commence operation and the deadline for monitor certification.
(a) Once a designated representative submits a timely and complete Acid Rain permit application, the owners and operators of the affected source and the affected units covered by the permit application shall be deemed in compliance with the requirement to have an Acid Rain permit under § 72.9(a)(2) and § 72.30(a);
(b) Prior to the date on which an Acid Rain permit is issued or denied, an affected unit governed by and operated in accordance with the terms and requirements of a timely and complete Acid Rain permit application shall be deemed to be operating in compliance with the Acid Rain Program.
(c) A complete Acid Rain permit application shall be binding on the owners and operators and the designated representative of the affected source and the affected units covered by the permit application and shall be enforceable as an Acid Rain permit from the date of submission of the permit application until the issuance or denial of an Acid Rain permit covering the units.
(d) If agency action concerning a permit is appealed under part 78 of this chapter, issuance or denial of the permit shall occur when the Administrator takes final agency action subject to judicial review.
(a) Every Phase I unit shall be treated as part of a dispatch system for purposes of §§ 72.91 and 72.92 in accordance with this section.
(b)(1) The designated representatives of all affected units in a group of all units and generators that are interconnected and centrally dispatched and that are included in the same utility system, holding company, or power pool, may jointly submit to the Administrator a complete identification of dispatch system.
(2) Except as provided in paragraph (f) of this section, each unit or generator may be included in only one dispatch system.
(3) Any identification of dispatch system must be submitted by January 30 of the first year for which the identification is to be in effect. A designated representative may request, and the Administrator may grant at his or her discretion, an exemption allowing the
(c) A complete identification of dispatch system shall include the following elements in a format prescribed by the Administrator:
(1) The name of the dispatch system.
(2) The list of all units and generators (including sulfur-free generators) in the dispatch system.
(3) The first calendar year for which the identification is to be in effect.
(4) The following statement: “I certify that, except as otherwise required under a petition as approved under 40 CFR 72.33(f), the units and generators listed herein are and will continue to be interconnected and centrally dispatched, and will be treated as a dispatch system under 40 CFR 72.91 and 72.92, during the period that this identification of dispatch system is in effect. During such period, all information concerning these units and generators and contained in any submissions under 40 CFR 72.91 and 72.92 by me and the other designated representatives of these units shall be consistent and shall conform with the data in the dispatch system data reports under 40 CFR 72.92(b). I am aware of, and will comply with, the requirements imposed under 40 CFR 72.33(e)(2).”
(5) The signatures of the designated representative for each affected unit in the dispatch system.
(d) In order to change a unit's current dispatch system, complete identifications of dispatch system shall be submitted for the unit's current dispatch system and the unit's new dispatch system, reflecting the change.
(e)(1) Any unit or generator not listed in a complete identification of dispatch system that is in effect shall treat its utility system as its dispatch system and, if such unit or generator is listed in the NADB, shall treat the utility system reported under the data field “UTILNAME” of the NADB as its utility system.
(2) During the period that the identification of dispatch system is in effect all information that concerns the units and generators in a given dispatch system and that is contained in any submissions under §§ 72.91 and 72.92 by designated representative of these units shall be consistent and shall conform with the data in the dispatch system data reports under § 72.92(b). If this requirement is not met, the Administrator may reject all such submissions and require the designated representatives to make the submissions under §§ 72.91 and 72.92 (including the dispatch system data report) treating the utility system of each unit or generator as its respective dispatch system and treating the identification of dispatch system as no longer in effect.
(f)(1) Notwithstanding paragraph (e)(1) of this section or any submission of an identification of dispatch system under paragraphs (b) or (d) of this section, the designated representative of a Phase I unit with two or more owners may petition the Administrator to treat, as the dispatch system for an owner's portion of the unit, the dispatch system of another unit.
(i) The owner's portion of the unit shall be based on one of the following apportionment methods:
(A)
(B)
(ii) The annual or actual utilization of a unit shall be attributed, under paragraph (f)(1)(i) of this section, to an owner of the unit using accounting procedures consistent with those used to determine the owner's share of the fuel costs in the operation of the unit during the period for which the annual or actual utilization is being attributed.
(iii) Upon submission of the petition, the designated representative may not
(2) The petition under paragraph (f)(1) of this section shall be submitted by January 30 of the first year for which the dispatch system proposed in the petition will take effect, if approved. A complete petition shall include the following elements in a format prescribed by the Administrator:
(i) The election of the apportionment method under paragraph (f)(1)(i) of this section.
(ii) The baseline of the owner's portion of the unit and the baseline of any other owner's portion of the unit for which a petition under paragraph (f)(1) of this section has been approved or has been submitted (and not disapproved) and a demonstration that the sum of such baselines and the baseline of any remaining portion of the unit equals 100 percent of the baseline of the unit. The designated representative shall also submit, upon request, either:
(A) Where the unit is to be apportioned under paragraph (f)(1)(i)(A) of this section, documentation of the average of the owner's percentage ownership of the capacity of the unit for each year during 1985-1987; or
(B) Where the unit is to be apportioned under paragraph (f)(1)(i)(B) of this section, documentation showing the attribution of the unit's utilization in 1985, 1986, and 1987 among the portions of the unit and the calculation of the annual average utilization for 1985-1987 for the portions of the unit.
(iii) The name of the proposed dispatch system and a list of all units (including portions of units) and generators in that proposed dispatch system and, upon request, documentation demonstrating that the owner's portion of the unit, along with the other units in the proposed dispatch system, are a group of all units and generators that are interconnected and centrally dispatched by a single utility company, the service company of a single holding company, or a single power pool.
(iv) The following statement, signed by the designated representatives of all units in the proposed dispatch system: “I certify that the units and generators in the dispatch system proposed in this petition are and will continue to be interconnected and centrally dispatched, and will be treated as a dispatch system under 40 CFR 72.91 and 72.92, during the period that this petition, as approved, is in effect.”
(v) The following statement, signed by the designated representatives of all units in all dispatch systems that will include any portion of the unit if the petition is approved: “During the period that this petition, if approved, is in effect, all information that concerns the units and generators in any dispatch system including any portion of the unit apportioned under the petition and that is contained in any submissions under 40 CFR 72.91 and 72.92 by me and the other designated representatives of these units shall be consistent and shall conform to the data in the dispatch system data reports under 40 CFR 72.92(b). I am aware of, and will comply with, the requirements imposed under 40 CFR 72.33(f) (4) and (5).”
(3)(i) The Administrator will approve in whole, in part, or with changes or conditions, or deny the petition under paragraph (f)(1) of this section within 90 days of receipt of the petition. The Administrator will treat the petition, as changed or conditioned upon approval, as amending any identification of dispatch system that is submitted prior to the approval and includes any portion of the unit for which the petition is approved. Where any portion of a unit is not covered by an approved petition, that remaining portion of the unit shall continue to be part of the unit's dispatch system.
(ii) In approving the petition, the Administrator will determine, on a case-by-case basis, the proper calculation and treatment, for purposes of the reports required under §§ 72.91 and 72.92, of plan reductions and compensating generation provided to other units.
(4) The designated representative for the unit for which a petition is approved under paragraph (f)(3) of this section and the designated representatives of all other units included in all
(i) The baseline of each portion of the unit for which a petition is approved shall be determined under paragraphs (f)(1) (i) and (ii) of this section. The baseline of the remaining portion of such unit shall equal the baseline of the unit less the sum of the baselines of any portions of the unit for which a petition is approved.
(ii) The actual utilization of each portion of the unit for which a petition is approved shall be determined under paragraphs (f)(l) (i) and (ii) of this section. The actual utilization of the remaining portion of such unit shall equal the actual utilization of the unit less the sum of the actual utilizations of any portions of the unit for which a petition is approved. Upon request, the designated representative of the unit shall demonstrate in the annual compliance certification report that the requirements concerning calculation of actual utilization under paragraph (f)(1)(ii) and any requirements established under paragraph (f)(3) of this section are met.
(iii) Except as provided in paragraph (f)(5) of this section, the designated representative shall surrender for deduction the number of allowances calculated using the formula in § 72.92(c) and treating, as a separate Phase I unit, each portion of unit for which a petition is approved under paragraph (f)(3) of this section and the remaining portion of the unit.
(5) In the event that the designated representatives fail to make all the proper attributions, apportionments, calculations, and demonstrations under paragraph (f)(4) of this section and §§ 72.91 and 72.92, the Administrator may require that:
(i) All portions of the unit be treated as part of the dispatch system of the unit in accordance with paragraph (e)(1) of this paragraph and any identification of dispatch system submitted under paragraph (b) or (d) of this section;
(ii) The designated representatives make all submissions under §§ 72.91 and 72.92 (including the dispatch system data report), treating the entire unit as a single Phase I unit, in accordance with paragraph (e)(1) of this paragraph and any identification of dispatch system submitted under paragraph (b) or (d) of this section; and
(iii) The designated representative surrender for deduction the number of allowances calculated, consistent with the reports under paragraph (f)(5)(ii) of this section and §§ 72.91 and 72.92, using the formula in § 72.92(c) and treating the entire unit as a single Phase I unit.
(6) The designated representative may submit a notification to terminate an approved petition by January 30 of the first year for which the termination is to take effect. The notification must be signed and certified by the designated representatives of all units included in all dispatch systems that include any portion of the unit apportioned under the petition. Upon receipt of the notification meeting the requirements of the prior two sentences by the Administrator, the approved petition is no longer in effect for that year and the remaining years in Phase I and the designated representatives shall make all submissions under §§ 72.91 and 72.92 treating the petition as no longer in effect for all such years.
(7) Except as expressly provided in paragraphs (f)(1) through (6) of this section or the Administrator's approval of the petition, all provisions of the Acid Rain Program applicable to an affected source or an affected unit shall apply to the entire unit regardless of whether a petition has been submitted or approved, or reports have been submitted,
(a) For each affected unit included in an Acid Rain permit application, a complete compliance plan shall:
(1) For sulfur dioxide emissions, certify that, as of the allowance transfer deadline, the designated representative will hold allowances in the unit's compliance subaccount (after deductions under § 73.34(c) of this chapter), or in the compliance subaccount of another affected unit at the same source to the extent provided in § 73.35(b)(3), not less than the total annual emissions of sulfur dioxide from the unit. The compliance plan may also specify, in accordance with this subpart, one or more of the Acid Rain compliance options.
(2) For nitrogen oxides emissions, certify that the unit will comply with the applicable emission limitation under § 76.5, § 76.6, or § 76.7 of this chapter or shall specify one or more Acid Rain compliance options, in accordance with part 76 of this chapter.
(b)
(i) Such plan is signed and certified by the designated representative for each source with an affected unit governed by such plan; and
(ii) A complete permit application is submitted covering each unit governed by such plan.
(2) A permitting authority's approval of a plan under paragraph (b)(1) of this section that includes units in more than one State shall be final only after every permitting authority with jurisdiction over any such unit has approved the plan with the same modifications or conditions, if any.
(c)
(1) To activate a conditionally-approved Acid Rain compliance option, the designated representative shall notify the permitting authority in writing that the conditionally-approved compliance option will actually be pursued beginning January 1 of a specified year. If the conditionally approved compliance option includes a plan described in paragraph (b)(1) of this section, the designated representative of each source governed by the plan shall sign and certify the notification. Such notification shall be subject to the limitations on activation under subpart D of this part and part 76 of this chapter.
(2) The notification under paragraph (c)(1) of this section shall specify the first calendar year and the last calendar year for which the conditionally approved Acid Rain compliance option is to be activated. A conditionally approved compliance option shall be activated, if at all, before the date of any enforceable milestone applicable to the compliance option. The date of activation of the compliance option shall not be a defense against failure to meet the requirements applicable to that compliance option during each calendar year for which the compliance option is activated.
(3) Upon submission of a notification meeting the requirements of paragraphs (c) (1) and (2) of this section, the conditionally-approved Acid Rain compliance option becomes binding on the
(4) A notification meeting the requirements of paragraphs (c) (1) and (2) of this section will revise the unit's permit in accordance with § 72.83 (administrative permit amendment).
(d)
(2) The notification under paragraph (d)(1) of this section shall specify the calendar year for which the termination will take effect.
(3) Upon submission of a notification meeting the requirements of paragraphs (d) (1) and (2) of this section, the termination becomes binding on the owners and operators and the designated representative of any unit governed by the Acid Rain compliance option to be terminated.
(4) A notification meeting the requirements of paragraphs (d) (1) and (2) of this section will revise the unit's permit in accordance with § 72.83 (administrative permit amendment).
(a)
(1) Any unit listed in table 1 of § 73.10(a) of this chapter; and
(2) Any other existing utility unit that is an affected unit under this part, provided that this section shall not apply to a unit under section 410 of the Act.
(b)(1) The designated representative may include, in the Acid Rain permit application for a unit under paragraph (a)(1) of this section, a substitution plan under which one or more units under paragraph (a)(2) of this section are designated as substitution units, provided that:
(i) Each unit under paragraph (a)(2) of this section is under the control of the owner or operator of each unit under paragraph (a)(1) of this section that designates the unit under paragraph (a)(2) of this section as a substitution unit; and
(ii) In accordance with paragraph (c)(3) of this section, the emissions reductions achieved under the plan shall be the same or greater than would have been achieved by all units governed by the plan without such plan.
(2) The designated representative of each source with a unit designated as a substitution unit in any plan submitted under paragraph (b)(1) of this section shall incorporate in the permit application each such plan.
(3) The designated representative may submit a substitution plan not later than 6 months (or 90 days if submitted in accordance with § 72.82), or a notification to activate a conditionally approved plan in accordance with § 72.40(c) not later than 60 days, before the allowance transfer deadline applicable to the first year for which the plan is to take effect.
(c)
(1) Identification of each unit under paragraph (a)(1) of this section and each substitution unit to be governed by the substitution plan. A unit shall not be a substitution unit in more than one substitution plan.
(2) Except where the designated representative requests conditional approval of the plan, the first calendar year and, if known, the last calendar year in which the substitution plan is to be in effect. Unless the designated representative specifies an earlier calendar year, the last calendar year will be deemed to be 1999.
(3) Demonstration that the total emissions reductions achieved under the substitution plan will be equal to
(i) For each substitution unit:
(A) The unit's baseline.
(B) Each of the following: the unit's 1985 actual SO
(C) The lesser of: the unit's 1985 actual SO
(D) The product of the baseline in paragraph (c)(3)(i)(A) of this section and the emissions rate in paragraph (c)(3)(i)(C) of this section, divided by 2000 lbs/ton. Where the most stringent emissions limitation is not the same for every year during 1995-1999, the product in the prior sentence shall be calculated separately for each year using the emissions rate determined for that year in paragraph (c)(3)(i)(C) of this section.
(ii)(A) The sum of the amounts in paragraph (c)(3)(i)(D) of this section for all substitution units to be governed by the plan. Except as provided in paragraph (c)(3)(ii)(B) of this section, this sum is the total number of allowances available each year under the substitution plan.
(B) Where the most stringent unit-specific federally enforceable or State enforceable SO
(iii) Where, as of November 15, 1990, a non-unit-specific federally enforceable or State enforceable SO
(4) Distribution of substitution allowances. (i) A statement that the allowances in paragraph (c)(3)(ii) of this section are not to be distributed to any units under paragraph (a)(1) of this section that are to be governed by the plan; or
(ii) A list showing any annual distribution of the allowances in paragraph (c)(3)(ii) of this section from a substitution unit to a unit under paragraph (a)(1) of this section that, under the plan, designates the substitution unit.
(5) A demonstration that the substitution plan meets the requirement that each unit under paragraph (a)(2) of this section is under the control of the owner or operator of each unit under paragraph (a)(1) of this section that designates the unit under paragraph (a)(2) of this section as a substitution unit. The demonstration shall be one of the following:
(i) If the unit under paragraph (a)(1) of this section has one or more owners or operators that have an aggregate percentage ownership interest of 50 percent or more in the capacity of the unit under paragraph (a)(2) of this section or the units have a common operator, a statement identifying such owners or operators and their aggregate percentage ownership interest in the capacity of the unit under paragraph (a)(2) of this section or identifying the units’ common operator. The
(ii) If the unit under paragraph (a)(1) of this section has one or more owners or operators that have an aggregate percentage ownership interest of at least 10 percent and less than 50 percent in the capacity of the unit under paragraph (a)(2) of this section and the units do not have a common operator, a statement identifying such owners or operators and their aggregate percentage ownership interest in the capacity of the unit under paragraph (a)(2) of this seciton and stating that each such owner or operator has the contractual right to direct the dispatch of the electricity that, because of its ownership interest, it has the right to receive from the unit under paragraph (a)(2) of this section. The fact that the electricity that such owner or operator has the right to receive is centrally dispatched through a power pool will not be the basis for determining that the owner or operator does not have the contractual right to direct the dispatch of such electricity. The designated representative shall submit supporting documentation upon request by the Administrator.
(iii) A copy of an agreement that is binding on the owners and operators of the unit under paragraph (a)(2) of this section and the owners and operators of the unit under paragraph (a)(1) of this section, provides each of the following elements, and is supported by documentation meeting the requirements of paragraph (c)(6) of this section:
(A) The owners and operators of the unit under paragraph (a)(2) of this section must not allow the unit to emit sulfur dioxide in excess of a maximum annual average SO
(B) The maximum annual average SO
(C) For each year that the actual SO
(D) The unit under paragraph (a)(2) of this section and the unit under paragraph (a)(1) of this section shall designate a common designated representative during the period that the substitution plan is in effect. Having a common alternate designated representative shall not satisfy the requirement in the prior sentence.
(E) Except as provided in paragraph (c)(6)(i) of this section, the actual SO
(6) A demonstration under paragraph (c)(5)(iii) of this section shall include the following supporting documentation:
(i) The calculation of the average actual SO
(ii) A description of the actions that will be taken in order for the unit under paragraph (a)(2) of this section to comply with the maximum annual average SO
(iii) A description of any contract for implementing the actions described in paragraph (c)(6)(ii) of this section that was executed before the date on which the agreement under paragraph (c)(5)(iii) of this section is executed. The designated representative shall state the execution date of each such contract and state whether the contract is expressly contingent on the agreement under paragraph (c)(5)(iii) of this section.
(iv) A showing that the actions described under paragraph (c)(6)(ii) of this section will not be implemented during Phase I unless the unit is approved as a substitution unit.
(7) The special provisions in paragraph (e) of this section.
(d)
(2) In no event shall allowances be allocated to a substitution unit, under an approved substitution plan, for any year in excess of the sum calculated and applicable to that year under paragraph (c)(3)(ii) of this section, as adjusted by the Administrator in approving the plan.
(3) Where, as of November 15, 1990, a non-unit-specific federally enforceable or State enforceable SO
(e)
(ii) Each unit under paragraph (a)(1) of this section, and each substitution unit, governed by an approved substitution plan shall be subject to the Acid Rain emissions limitations for nitrogen oxides in accordance with part 76 of this chapter.
(iii) Where an approved substitution plan includes a demonstration under paragraphs (c)(5)(iii) and (c)(6) of this section.
(A) The owners and operators of the substitution unit covered by the demonstration shall implement the actions described under paragraph (c)(6)(ii) of this section, as adjusted by the Administrator in approving the plan or in revising the permit. The designated representative may submit proposed permit revisions changing the description of the actions to be taken in order for the substitution unit to achieve the maximum annual average SO
(B) The designated representative of the unit under paragraph (a)(1) of this section shall surrender allowances, and theAdministrator will deduct allowances, in accordance with paragraph (c)(5)(iii)(C) of this section. The surrender and deduction of allowances as required under the prior sentence shall be the only remedy under the Act for a failure to meet the maximum annual average SO
(2)
(3)
(ii) To terminate a substitution plan for a given calendar year prior to the last year for which the plan was approved:
(A) A notification to terminate in accordance with § 72.40(d) shall be submitted no later than 60 days before the allowance transfer deadline applicable to the given year; and
(B) In the notification to terminate, the designated representative of each unit governed by the plan shall state that he or she surrenders for deduction from the unit's Allowance Tracking System account allowances equal in
(iii) If the requirements of paragraph (e)(3)(ii) of this section are met and upon revision of the permit to terminate the substitution plan, the Administrator will deduct the allowances specified in paragraph (e)(3)(ii)(B) of this section. No substitution plan shall be terminated, and no unit shall be de-designated as a Phase I unit, unless such deduction is made.
(iv)(A) If there is a change in the ownership interest of the owners or operators of any unit under a substitution plan approved as meeting the requirements of paragraph (c)(5)(i) or (ii) of this section or a change in such owners’ or operators’ right to direct dispatch of electricity from a substitution unit under such a plan and the demonstration under paragraph (c)(5)(i) or (ii) of this section cannot be made, then the designated representatives of the units governed by this plan shall submit a notification to terminate the plan so that the plan will terminate as of January 1 of the calendar year during which the change is made.
(B) Where a substitution plan is approved as meeting the requirements of paragraph (c)(5)(iii) of this section, if there is a change in the agreement under paragraph (c)(5)(iii) of this section and a demonstration that the agreement, as changed, meets the requirements of paragraph (c)(5)(iii) cannot be made, then the designated representative of the units governed by the plan shall submit a notification to terminate the plan so that the plan will terminate as of January 1 of the calendar year during which the change is made. Where a substitution plan is approved as meeting the requirements of paragraph (c)(5)(iii) of this section, if the requirements of the first sentence of paragraph (e)(1)(iii)(A) of this section are not met during a calendar year, then the designated representative of the units governed by the plan shall submit a notification to terminate the plan so that the plan will terminate as of January 1 of such calendar year.
(C) If the plan is not terminated in accordance with paragraphs (e)(3)(iv)(A) or (B) of this section, the Administrator, on his or her own motion, will terminate the plan and deduct the allowances required to be surrendered under paragraph (e)(3)(ii) of this section.
(D) Where a substitution unit and the Phase I unit designating the substitution unit in an approved substitution plan have a common owner, operator, or designated representative during a year, the plan shall not be terminated under paragraphs (e)(3)(iv)(A), (B), or (C) of this section with regard to the substitution unit if the year is as specified in paragraph (e)(3)(iv)(D)(
(
(
(
(a)
(i) A unit listed in table 1 of § 73.10(a) of this chapter;
(ii) A unit designated as a substitution unit in accordance with § 72.41; or
(iii) A unit designated as a compensating unit in accordance with § 72.43, except a compensating unit that is a new unit.
(2) A unit for which a Phase I extension is sought shall be either:
(i) A control unit, which shall be a unit under paragraph (a)(1) of this section and at which qualifying Phase I technology shall commence operation on or after November 15, 1990 but not later than December 31, 1996; or
(ii) A transfer unit, which shall be a unit under paragraph (a)(1)(i) of this section and whose Phase I emissions reduction obligation shall be transferred in whole or in part to one or more control units.
(3) A Phase I extension does not exempt the owner or operator for any unit governed by the Phase I extension plan from the requirement to comply with such unit's Acid Rain emissions limitations for sulfur dioxide.
(b) To apply for a Phase I extension:
(1) The designated representative for each source with a control unit may submit an early ranking application for a Phase I extension plan in person, beginning on the 40th day after publication of this subpart in the
(2) By February 15, 1993:
(i) The designated representative for each source with a control unit shall submit a Phase I extension plan as a part of the Acid Rain permit application for the source, and
(ii) The designated representative for each source with a unit designated as a transfer unit in any plan submitted under paragraph (b)(2)(i) of this section shall incorporate in the Acid Rain permit application each such plan.
(c)
(1) Identification of each control unit. All control units in an application must be located at the same source. If the control unit is not a unit under paragraph (a)(1)(i) of this section, a substitution plan or a reduced utilization plan governing the unit shall be submitted by the deadline for submitting a Phase I permit application.
(2) Identification of each transfer unit. A unit shall not be a transfer unit in more than one early ranking application.
(3) For each control and transfer unit, the total tonnage of sulfur dioxide emitted in 1988 plus the total tonnage of sulfur dioxide emitted in 1989, divided by 2. The 1988 and 1989 tonnage figures shall be consistent with the data filed on EIA form 767 for those years and the conversion methodology specified in appendix B of this part.
(4) For each control and transfer unit:
(i) The projected annual utilization (in mmBtu) for 1995 multiplied by the projected uncontrolled emissions rate (i.e., the emissions rate in the absence of title IV of the Act) for 1995 (in lbs/mmBtu), divided by 2000 lbs/ton.
(ii) The projected annual utilization (in mmBtu) for 1996 multiplied by the projected uncontrolled emissions rate (i.e., the emissions rate in the absence of title IV of the Act) for 1996 (in lbs/mmBtu), divided by 2000 lbs/ton.
(5) For each control and transfer unit, the number of Phase I extension reserve allowances requested for 1995 and for 1996, not to exceed the difference between:
(i) The lesser of the value for the unit under paragraph (c)(3) of this section and the value for the unit for that year under paragraph (c)(4) of this section, and
(ii) Each unit's baseline multiplied by 2.5 lb/mmBtu, divided by 2000 lbs/ton.
(6) Documentation that the annual emissions reduction obligations transferred from all transfer units to all control units do not exceed those authorized under this section, as follows:
(i) For each control unit, the difference, calculated separately for 1995 and 1996, between:
(A) The control unit's allowance allocation in table 1 of § 73.10(2) of this chapter, the allocation under § 72.41 if the control unit is a substitution unit, or the allocation under § 72.43 if the control unit is a compensating unit; and
(B) The projected emissions resulting from 90% control after installing the qualifying Phase I technology, i.e., 10% of the projected uncontrolled emissions for the control unit for the year in accordance with paragraph (c)(4) of this section.
(ii) The sum, by year, of the results under paragraph (c)(6)(i) of this section for all control units.
(iii) The sum, by year, of Phase I extension reserve allowances requested for all transfer units.
(iv) A showing that, for each year, the sum under paragraph (c)(6)(ii) of this section is greater than or equal to the sum under paragraph (c)(6)(iii) of this section.
(7) For each control and transfer unit, the projected controlled emissions for 1997, for 1998, and for 1999 calculated as follows:
Projected annual utilization (in mmBtu) multiplied by the projected controlled emission rate (in lbs/mmBtu), divided by 2000 lbs/ton.
(8) For each control unit, the number of Phase I extension reserve allowances requested for 1997, for 1998, and for 1999, calculated as follows:
The unit's baseline multiplied by 1.2 lbs/mmBtu and divided by 2000 lbs/ton, minus the projected controlled emissions (in tons/yr) under paragraph (c)(7) of this section for the given year.
(9) The total of Phase I extension reserve allowances requested for all units in the plan for 1995 through 1999.
(10) With regard to each executed contract for the design engineering and construction of qualifying Phase I technology at each control unit governed by the early ranking application, either a copy of the contract or a certification that the contract is on site at the source and will be submitted to the Administrator upon written request. The contract or contracts may be contingent on the Administrator approving the Phase I extension plan.
(11) For each contract for which a certification is submitted under paragraph (c)(10) of this section, a binding letter agreement, signed and dated by each party and specifying:
(i) The type of qualifying Phase I technology to which the contract applies;
(ii) The parties to the contract;
(iii) The date each party executed the contracts;
(iv) The unit to which the contract applies;
(v) A brief list identifying each provision of the contract;
(vi) Any dates to which the parties agree, including construction completion date; and
(vii) The total dollar amount of the contract.
(12) A vendor certification of the sulfur dioxide removal efficiency guaranteed to be achievable by the qualifying Phase I technology for the type and
(13) The date (not later than December 31, 1996) on which the owners and operators plan to commence operation of the qualifying Phase I technology.
(14) The special provisions of paragraph (f) of this section.
(d)
(1) Identification of each unit in the plan.
(2)(i) A statement that the elements in the Phase I extension plan are identical to those in the previously submitted early ranking application for the plan and that such early ranking application is incorporated by reference; or
(ii) All elements that are different from those in the previously submitted early ranking application for the plan and a statement that the early ranking application is incorporated by reference as modified by the newly submitted elements;
(iii) All elements required for an early ranking application and a statement that no early ranking application for the plan was submitted.
(e)
(ii) The Administrator will act on each early ranking application in the order of receipt.
(iii) The Administrator will determine the order of receipt by the following procedures:
(A) Hand-delivered submissions and mailed submissions will be deemed to have been received on the date they are received by the Administrator;
(B) All submissions received by the Administrator on the same day will be deemed to have been received simultaneously.
(C) The order of receipt of all submissions received simultaneously will be determined by a public lottery if allocation of Phase I extension reserve allowances to each of the simultaneous submissions would result in oversubscription of the Phase I extension reserve.
(iv) Based on the allowances requested under paragraph (c)(9) of this section, as adjusted by the Administrator in approving the early ranking application, the Administrator will award Phase I extension reserve allowances for each complete early ranking application to the extent that allowances that have not been awarded remain in the Phase I extension reserve at the time the Administrator acts on the application. The allowances will be awarded in accordance with the procedures set forth the allocation of reserve allowances in paragraph (e)(3) of this section.
(v) The Administrator's action on an early ranking application shall be conditional on the Administrator's action on a timely and complete Acid Rain permit application that includes a complete Phase I extension plan and, where the plan includes a unit under paragraph (a)(1) (ii) and (iii) of this section, a complete substitution plan or reduced utilization plan, as appropriate.
(vi) Not later than 15 days after receipt of each early ranking application, the Administrator will notify, in writing, the designated representative of each application of the date that the early ranking application was received and one of the following:
(A) The award of allowances if the application was complete and the Phase I extension reserve as not oversubscribed;
(B) A determination that the application was incomplete and is disapproved; or
(C) If the Phase I extension reserve was oversubscribed, a list of the applications received on that date, the number of Phase I extension allowances requested in each application, and the date, time, and location of a lottery to determine the order of receipt for all applications received on that date.
(vii) The date of a lottery for all applications received on a given day will not be earlier than 15 days after the Administrator notifies each designated representative whose applications were received on that date.
(viii) Any early ranking application may be withdrawn from the lottery if a letter signed by the designated representative of each unit governed by the application and requesting withdrawal is received by the Administrator before the lottery takes place.
(2)
(ii) Based on the allowances requested under paragraph (c)(9) of this section, as adjusted under paragraph (d) of this section and by the Administrator in approving the Phase I extension plan, the Administrator will allocate Phase I extension reserve allowances to the Allowance Tracking System account of each control and transfer unit upon issuance of an Acid Rain permit containing the approved Phase I extension plan. The allowances will be allocated using the procedures set forth in paragraph (e)(3) of this section.
(iii) The Administrator will not approve a Phase I extension plan, even if it meets the requirements of this section, unless unallocated allowances remain in the Phase I extension reserve at the time the Administrator acts on the plan.
(3)
(i) For 1995, to each control unit in the order in which it is listed in the plan and then to each transfer unit in the order in which it is listed.
(ii) For 1996, to each control unit in the order in which it is listed in the plan and then to each transfer unit in the order in which it is listed.
(iii) For 1997, to each control unit in the order in which it is listed in the plan, then likewise for 1998, and then likewise for 1999.
(iv) The Administrator will allocate any Phase I extension reserve allowances returned to the Administrator to the next Phase I extension plan, in the rank order established under paragraph (e)(1)(iii) of this section, that continues to meet the requirements of this section and this part.
(f)
(B) Failure to demonstrate at least a 90% reduction of sulfur dioxide in 1997, 1998, or 1999 in accordance with part 75 of this chapter at a control unit governed by an approved Phase I extension plan shall be a violation of this section. In the event of any such violation, in addition to any other liability under the Act, the Administrator will deduct allowances from the control unit's compliance subaccount for the year of the violation. The deduction will be calculated as follows:
(ii)
(A) Beginning on January 1, 1997, each control and transfer unit shall be subject to the Acid Rain emissions limitations for nitrogen oxides.
(B) Notwithstanding paragraph (f)(1)(ii)(A) of this section, a transfer unit shall be subject to the Acid Rain emissions limitations for nitrogen oxides, under section 407 of the Act and regulations implementing section 407 of the Act, beginning on January 1 of any year for which a transfer unit is allocated fewer Phase I extension reserve allowances than the maximum amount that the designated representative could have requested in accordance with paragraph (c)(5) of this section (as adjusted under paragraph (d) of this section and by the Administrator in approving the Phase I extension plan) unless the transfer unit is the last unit allocated Phase I extension reserve allowances under the plan.
(2)
(3)
(4)
(5)
(a)
(1) Any Phase I unit, including:
(i) Any unit listed in table 1 of § 73.10(a) of this chapter; and
(ii) Any other unit that becomes a Phase I unit (including any unit designated as a compensating unit under this section or a substitution unit under § 72.41).
(2) Any affected unit that:
(i) Is not otherwise subject to any Acid Rain emissions limitation or emissions reduction requirements during Phase I; and
(ii) Meets the requirement, as set forth in paragraphs (c)(4)(ii) and (d) of this section, that for each year for which the unit is to be covered by the reduced utilization plan, the unit's baseline divided by 2,000 lbs/ton and multiplied by the lesser of the unit's 1985 actual SO
(A) The lesser of 10 percent of the amount under paragraph (a)(2)(ii) of this section or 200 tons, plus
(B) The unit's baseline divided by 2,000 lbs/ton and multiplied by the lesser of: The greater of the unit's 1989 or 1990 actual SO
(b)(1) The designated representative of any unit under paragraph (a)(1) of this section shall include in the Acid Rain permit application for the unit a reduced utilization plan, meeting the requirements of this section, when the owners and operators of the unit plan to:
(i) Reduce utilization of the unit below the unit's baseline to achieve compliance, in whole or in part, with the unit's Phase I Acid Rain emissions limitations for sulfur dioxide; and
(ii) Accomplish such reduced utilization through one or more of the following:
(A) Shifting generation of the unit to a unit under paragraph (a)(2) of this section or to a sulfur-free generator; or
(B) Using one or more energy conservation measures or improved unit efficiency measures.
(2)(i) Energy conservation measures shall be either demand-side measures implemented after December 31, 1987 in the residence or facility of a customer to whom the unit's utility system sells electricity or supply-side measures implemented after December 31, 1987 in facilities of the unit's utility system.
(ii) The utility system shall pay in whole or in part for the energy conservation measures either directly or, in the case of demand-side measures, through payment to another person who purchases the measure.
(iii) Energy conservation measures shall not include:
(A) Conservation programs that are exclusively informational or educational in nature;
(B) Load management measures that lead to reduction of electric energy demands during a utility's peak generating period, unless kilowatt hour savings can be verified under § 72.91(b); or
(C) Utilization of industrial waste gases, unless the designated representative certifies that there is no net increase in sulfur dioxide emissions from such utilization.
(iv) For calendar years when the unit's utility system is a subsidiary of a holding company and the unit's dispatch system is or includes all units that are interconnected and centrally dispatched and included in that holding company, then:
(A) Energy conservation measures shall be either demand-side measures implemented in the residence or facility of a customer to whom any utility system in the holding company sells electricity or supply-side measures implemented in facilities of any utility system in the holding company. Such utility system shall pay in whole or in part for the measures either directly or, in the case of demand-side measures, through payment to another person who purchases the measures.
(B) The limitations in paragraph (b)(2)(iii) of this section shall apply.
(3)(i) Improved unit efficiency measures shall be implemented in the unit after December 31, 1987. Such measures include supply-side measures listed in appendix A, section 2.1 of part 73 of this chapter.
(ii) The utility system shall pay in whole or in part for the improved unit efficiency measures.
(4) The requirement to submit a reduced utilization plan shall apply in the event that the owners and operators of a Phase I unit decide, at any time during any Phase I calendar year, to rely on the method of compliance in paragraph (b)(1) of this section. In that case, the designated representative shall submit a reduced utilization plan not later than 6 months (or 90 days if sumitted in accordance with § 72.82 or § 72.83), or a notification to activate a conditionally approved plan in accordance with § 72.40(c) not later than 60 days, before the allowance transfer deadline applicable to the first year for which the plan is to take effect.
(5) The designated representative of each source with a unit designated as a compensating unit in any plan submitted under paragraphs (b) (1) or (4) of this section shall incorporate by reference in the permit application each such plan.
(c)
(1) Identification of each Phase I unit for which the owners and operators plan reduced utilization.
(2) Except where the designated representative requests conditional approval of the plan, the first calendar year and, if known, the last calendar year in which the reduced utilization plan is to be in effect. Unless the designated representative specifies an earlier calendar year, the last calendar year shall be deemed to be 1999.
(3) A statement whether the plan designates a compensating unit or relies on sulfur-free generation, any energy conservation measure, or any improved unit efficiency measure to account for any amount of reduced utilization.
(4) If the plan designates a compensating unit, or relies on sulfur-free generation, to account for any amount of reduced utilization:
(i) Identification of each compensating unit or sulfur-free generator.
(ii) For each compensating unit. (A) Each of the following: The unit's 1985 actual SO
(B) The unit's baseline divided by 2,000 lbs/ton and multiplied by the lesser of the unit's 1985 actual SO
(C) The unit's baseline divided by 2000 lbs/ton and multiplied by the lesser of: The greater of the unit's 1989 or 1990 actual SO
(D) The difference between the amount under paragraph (c)(4)(ii)(B) of this section and the amount under paragraph (c)(4)(ii)(C) of this section. If the difference calculated in the prior sentence for any year exceeds the lesser of 10 percent of the amount under paragraph (c)(4)(ii)(B) of this section or 200 tons, the unit shall not be designated as a compensating unit for the year. Where the most stringent unit-specific federally enforceable or State enforceable SO
(E) The allowance allocation calculated as the amount under paragraph (c)(4)(ii)(B) of this section. If the compensating unit is a new unit, it shall be deemed to have a baseline of zero and shall be allocated no allowances.
(F) Where, as of November 15, 1990, a non-unit-specific federally enforceable or State enforceable SO
(iii) For each sulfur-free generator, identification of any other Phase I units that designate the same sulfur-free generator in another plan submitted under paragraph (b) (1) or (4) of this section.
(iv) For each compensating unit or sulfur-free generator not in the dispatch system of the unit reducing utilization under the plan, the system directives or power purchase agreements or other contractual agreements governing the acquisition, by the dispatch system, of the electrical energy that is generated by the compensating unit or sulfur-free generator and on which the plan relies to accomplish reduced utilization. Such contractual agreements shall identify the specific compensating unit or sulfur-free generator from which the dispatch system acquires such electrical energy.
(5) The special provisions in paragraph (f) of this section.
(d)
(2) Where, as of November 15, 1990, a non-unit-specific federally enforceable or State enforceable emissions limitation covers the unit for any year during 1995-1999, the Administrator will
(e)
(f)
(ii) The designated representative of any Phase I unit (including a unit governed by a reduced utilization plan relying on energy conservation, improved unit efficiency, sulfur-free generation, or a compensating unit) shall surrender allowances, and the Administrator will deduct or return allowances, in accordance with paragraph (d)(2) of this section and subpart I of this part.
(2)
(3)
(4)
(ii) To terminate a reduced utilization plan for a given calendar year prior to its last year for which the plan was approved:
(A) A notification to terminate in accordance with § 72.40(d) shall be submitted no later than 60 days before the allowance transfer deadline applicable to the given year; and
(B) In the notification to terminate, the designated representative of any compensating unit governed by the plan shall state that he or she surrenders for deduction from the unit's Allowance Tracking System account allowances equal in number to, and with the same or an earlier compliance use date as, those allocated under paragraph (d) of this section to each compensating unit for the calendar years for which the plan is to be terminated. The designated representative may
(iii) If the requirements of paragraph (f)(3)(ii) are met and upon revision of the permit to terminate the reduced utilization plan, the Administrator will deduct the allowances specified in paragraph (f)(3)(ii)(B) of this section. No reduced utilization plan shall be terminated, and no unit shall be de-designated as a Phase I unit, unless such deduction is made.
(a)
(i) Any existing affected unit that is a coal-fired unit and has a 1985 actual SO
(ii) Any new unit that will be a replacement unit, as provided in paragraph (b)(2) of this section, for a unit meeting the requirements of paragraph (a)(1)(i) of this section.
(iii) Any oil and/or gas-fired unit that has been awarded clean coal technology demonstration funding as of January 1, 1991 by the Secretary of Energy.
(2) A repowering extension does not exempt the owner or operator for any unit governed by the repowering plan from the requirement to comply with such unit's Acid Rain emissions limitations for sulfur dioxide.
(b) The designated representative of any unit meeting the requirements of paragraph (a)(1)(i) of this section may include in the unit's Phase II Acid Rain permit application a repowering extension plan that includes a demonstration that:
(1) The unit will be repowered with a qualifying repowering technology in order to comply with the Phase II emissions limitations for sulfur dioxide; or
(2) The unit will be replaced by a new utility unit that has the same designated representative and that is located at a different site using a qualified repowering technology and the existing unit will be permanently retired from service on or before the date on which the new utility unit commences commercial operation.
(c) In order to apply for a repowering extension, the designated representative of a unit under paragraph (a) of this section shall:
(1) Submit to the permitting authority, by January 1, 1996, a complete repowering extension plan;
(2) Submit to the Administrator, before June 1, 1997, a complete petition for approval of repowering technology; and
(3) If the repowering extension plan is submitted for conditional approval, submit by December 31, 1997, a notification to activate the plan in accordance with § 72.40(c).
(d)
(i) Identification and description of the technology.
(ii) Vendor certification of the guaranteed performance characteristics of the technology, including:
(A) Percent removal and emission rate of each pollutant being controlled;
(B) Overall generation efficiency; and
(C) Information on the state, chemical constituents, and quantities of solid waste generated (including information on land-use requirements for disposal) and on the availability of a market to which any by-products may be sold.
(iii) If the repowering technology is not listed in the definition of a qualified repowering technology in § 72.2, a vendor certification of the guaranteed performance characteristics that demonstrate that the technology meets the criteria specified for non-listed technologies in § 72.2;
(2) The Administrator may request any supplemental information that is deemed necessary to review the petition for approval of repowering technology.
(3) The Administrator shall review the petition for approval of repowering technology and, in consultation with the Secretary of Energy, shall make a conditional determination of whether the technology described in the petition is a qualifying repowering technology.
(4) Based on the petition for approval of repowering technology and the information provided under paragraph (d)(2) of this section and § 72.94(a), the Administrator will make a final determination of whether the technology described in the petition is a qualifying repowering technology.
(e)
(1) Identification of the existing unit governed by the plan.
(2) The unit's federally-approved State Implementation Plan sulfur dioxide emissions limitation.
(3) The unit's 1995 actual SO
(4) A schedule for construction, installation, and commencement of operation of the repowering technology approved or submitted for approval under paragraph (d) of this section, with dates for the following milestones:
(i) Completion of design engineering;
(ii) For a plan under paragraph (b)(1) of this section, removal of the existing unit from operation to install the qualified repowering technology;
(iii) Commencement of construction;
(iv) Completion of construction;
(v) Start-up testing;
(vi) For a plan under paragraph (b)(2) of this section, shutdown of the existing unit; and
(vii) Commencement of commercial operation of the repowering technology.
(5) For a plan under paragraph (b)(2) of this section:
(i) Identification of the new unit. A new unit shall not be included in more than one repowering extension plan.
(ii) Certification that the new unit will replace the existing unit.
(iii) Certification that the new unit has the same designated representative as the existing unit.
(iv) Certification that the existing unit will be permanently retired from service on or before the date the new unit commences commercial operation.
(6) The special provisions of paragraph (h) of this section.
(f)
(2)
(A) The approved repowering extension plan; and
(B) A schedule of compliance with enforceable milestones for construction, installation, and commencement of operation of the repowering technology and other requirements necessary to ensure that Phase II emission reduction requirements under this section will be met.
(ii) Except as otherwise provided in paragraph (g) of this section, the repowering extension shall be in effect starting January 1, 2000 and ending on the day before the date (specified in the Acid Rain permit) on which the existing unit will be removed from operation to install the qualifying re-pow-er-ing technology or will be permanently removed from service for replacement by a new unit with such technology;
(iii) The portion of the operating permit specifying the repowering extension and other requirements under paragraph (f)(2)(i) of this section shall be subject to the Administrator's final determination, under paragraph (d)(4) of this section, that the technology to be used in the repowering extension plan is a qualifying repowering technology.
(3)
(i) To the existing unit under the approved plan, in accordance with § 73.21 of this chapter during the repowering extension under paragraph (f)(2)(ii) of this section; and
(ii) To the existing unit under the approved plan under paragraph (b)(1) of this section or, in lieu of any further allocations to the existing unit, to the new unit under the approved plan under paragraph (b)(2) of this section, in accordance with § 73.21 of this chapter, after the repowering extension under paragraph (f)(2)(ii) of this section ends.
(g)
(ii) Regardless of whether notification under paragraph (g)(1)(i) of this section is given, the repowering extension will end beginning on the earlier of the date of such notification or the date by which the designated representative was required to give such notification under § 72.94(d). The Administrator will deduct allowances (including a pro rata deduction for any fraction of a year) from the Allowance Tracking System account of the existing unit to the extent necessary to ensure that, beginning the day after the extension ends, allowances are allocated in accordance with § 73.21(c)(1) of this chapter.
(2) If the designated representative of a unit governed by an approved re-pow-er-ing extension plan demonstrates to the satisfaction of the Administrator, in a requested permit modification, that the repowering technology specified in the plan was properly constructed and tested on such unit but was unable to achieve the emissions reduction limitations specified in the plan and that it is economically or technologically infeasible to modify the technology to achieve such limits, the unit shall not be deemed in violation of the Act because of such failure to achieve the emissions reduction limitations. If the Administrator is not the permitting authority, a copy of the requested permit modification shall be sumitted to the Administrator. In order to be properly constructed and tested, the repowering technology shall be constructed at least to the extent necessary for direct testing of the multiple combustion emissions (including sulfur dioxide and nitrogen oxides) from such unit while operating the technology at nameplate capacity. Where the preceding requirements of this paragraph are met:
(i) The permitting authority shall revise the Acid Rain portion of the operating permit in accordance with paragraphs (g)(2) (ii) and (iii) and § 72.81 (permit modification).
(ii) The existing unit may be retrofitted or repowered with another clean coal or other available control technology.
(iii) The repowering extension will continue in effect until the earlier of the date the existing unit commences commercial operation with such control technology or December 31, 2003. The Administrator will allocate or deduct allowances as necessary to ensure that allowances are allocated in accordance with paragraph (f)(3) of this section applying the repowering extension under this paragraph.
(h)
(ii)
(iii) No existing unit governed by an approved repowering extension plan shall be eligible for a waiver under section 111(j) of the Act.
(iv) No new unit governed by an approved repowering extension plan shall receive an exemption from the requirements imposed under section 111 of the Act.
(2)
(3)
(ii) The units governed by the plan under paragraph (b)(2) of this section shall continue to have a common designated representative until the existing unit is permanently retired under the plan.
(4)
(a) Each Acid Rain permit (including any draft or proposed Acid Rain permit) will contain the following elements in a format prescribed by the Administrator:
(1) All elements required for a complete Acid Rain permit application under § 72.31 of this part, as approved or adjusted by the permitting authority;
(2) The applicable Acid Rain emissions limitation for sulfur dioxide; and
(3) The applicable Acid Rain emissions limitation for nitrogen oxides.
(b) Each Acid Rain permit is deemed to incorporate the definitions of terms under § 72.2 of this part.
Each affected unit operated in accordance with the Acid Rain permit that governs the unit and that was issued in compliance with title IV of the Act, as provided in this part and parts 73, 74, 75, 76, 77, and 78 of this chapter shall be deemed to be operating in compliance with the Acid Rain Program, except as provided in § 72.9(g)(6).
(a)
(1) Notwithstanding the provisions of part 71 of this chapter, the provisions of subparts C, D, E, F, and H of this part and of parts 74, 76, and 78 of this chapter shall govern the following requirements for Acid Rain permit applications and permits: submission, content, and effect of permit applications; content and requirements of compliance plans and compliance options; content of permits and permit shield; procedures for determining completeness of permit applications; issuance of draft permits; administrative record; public notice and comment and public hearings on draft permits; response to comments on draft permits; issuance and effectiveness of permits; permit revisions; and administrative appeal procedures. The provisions of part 71 of this chapter concerning Indian tribes, delegation of a part 71 program, affected State review of draft permits, and public petitions to reopen a permit for cause shall apply to Acid Rain permit applications and permits.
(2) The procedures in this subpart do not apply to the issuance of Acid Rain permits by State permitting authorities with operating permit programs approved under part 70 of this chapter, except as expressly provided in subpart G of this part.
(b)
(c)
(a)
(b)
(2)(i) Within a reasonable period determined by the Administrator, the designated representative shall submit the information required under paragraph (b)(1) of this section.
(ii) If the designated representative fails to submit the supplemental information within the required time period, the Administrator may disapprove that portion of the Acid Rain permit application for the review of which the information was necessary and may deny the source an Acid Rain permit.
(3) Any designated representative who fails to submit any relevant information or who has submitted incorrect information in a permit application shall, upon becoming aware of such
(a) After the Administrator receives a complete Acid Rain permit application and any supplemental information, the Administrator will issue a draft permit that incorporates in whole, in part, or with changes or conditions as appropriate, the permit application or deny the source a draft permit.
(b) The draft permit will be based on the information submitted by the designated representative of the affected source and other relevant information.
(c) The Administrator will serve a copy of the draft permit and the statement of basis on the designated representative of the affected source.
(d) The Administrator will provide a 30-day period for public comment, and opportunity to request a public hearing, on the draft permit or denial of a draft permit, in accordance with the public notice required under § 72.65(a)(1)(i) of this part.
(a)
(1) The permit application and any supporting or supplemental data submitted by the designated representative;
(2) The draft permit;
(3) The statement of basis;
(4) Copies of any documents cited in the statement of basis and any other documents relied on by the Administrator in issuing or denying the draft permit (including any records of discussions or conferences with owners, operators, or the designated representative of affected units at the source or interested persons regarding the draft permit), or, for any such documents that are readily available, a statement of their location;
(5) Copies of all written public comments submitted on the draft permit or denial of a draft permit;
(6) The record of any public hearing on the draft permit or denial of a draft permit;
(7) The Acid Rain permit; and
(8) Any response to public comments submitted on the draft permit or denial of a draft permit and copies of any documents cited in the response and any other documents relied on by the Administrator to issue or deny the Acid Rain permit, or, for any such documents that are readily available, a statement of their location.
(b) [Reserved]
(a) The statement of basis will briefly set forth significant factual, legal, and policy considerations on which the Administrator relied in issuing or denying the draft permit.
(b) The statement of basis will include:
(1) The reasons, and supporting authority, for approval or disapproval of any compliance options requested in the permit application, including references to applicable statutory or regulatory provisions and to the administrative record; and
(2) The name, address, and telephone, and facsimile numbers of the EPA office processing the issuance or denial of the draft permit.
(a)(1) The Administrator will give public notice of the following:
(i) The draft permit or denial of a draft permit and the opportunity for public review and comment and to request a public hearing; and
(ii) Date, time, location, and procedures for any scheduled hearing on the draft permit or denial of a draft permit.
(2) Any public notice given under this section may be for the issuance or denial of one or more draft permits.
(b)
(1) Serving written notice on the following persons (except where such person has waived his or her right to receive such notice):
(i) The designated representative;
(ii) The air pollution control agencies of affected States; and
(iii) Any interested person.
(2) Giving notice by publication in the
(c)
(1) Identification of the EPA office processing the issuance or denial of the draft permit for which the notice is being given.
(2) Identification of the designated representative for the affected source.
(3) Identification of each unit covered by the Acid Rain permit application and the draft permit.
(4) Any compliance options proposed for approval in the draft permit or for disapproval and the total allowances (including any under the compliance options) allocated to each unit if the Acid Rain permit application is approved.
(5) The address and office hours of a public location where the administrative record is available for public inspection and a statement that all information submitted by the designated representative and not protected as confidential under section 114(c) of the Act is available for public inspection as part of the administrative record.
(6) For public notice under paragraph (a)(1)(i) of this section, a brief description of the public comment procedures, including:
(i) A 30-day period for public comment beginning the date of publication of the notice or, in the case of an extension or reopening of the public comment period, such period as the Administrator deems appropriate;
(ii) The address where public comments should be sent;
(iii) Required formats and contents for public comment;
(iv) An opportunity to request a public hearing to occur not earlier than 15 days after public notice is given and the location, date, time, and procedures of any scheduled public hearing; and
(v) Any other means by which the public may participate.
(d)
(a)
(b)
(2) The submission shall clearly indicate the draft permit issuance or denial to which the comments apply.
(3) The submission shall clearly indicate the name of the person commenting, his or her interest in the matter, and his or her affiliation, if any, to owners and operators of any unit covered by the Acid Rain permit application.
(c)
(1) Any standard requirement under § 72.9;
(2) Issues that are not relevant, such as:
(i) The environmental effects of acid rain, acid deposition, sulfur dioxide, or nitrogen oxides generally; and
(ii) Permit issuance procedures, or actions on other permit applications, that are not relevant to the draft permit issuance or denial in question.
(d) Persons who do not wish to raise issues concerning the issuance or denial of the draft permit, but who wish to be notified of any subsequent actions concerning such matter may so indicate in writing during the public comment period or at any other time. The Administrator will place their names on a list of interested persons.
(a) During the public comment period, any person may request a public hearing. A request for a public hearing shall be made in writing and shall state the issues proposed to be raised in the hearing.
(b) On the Administrator's own motion or on the request of any person, the Administrator may, at his or her discretion, hold a pubic hearing whenever the Administrator finds that such a hearing will contribute to the decision-making process by clarifying one or more significant issues affecting the draft permit or denial of a draft permit. Public hearings will not be held on issues under § 72.66(c) (1) and (2).
(c) During a public hearing under this section, any person may submit oral or written comments concerning the draft permit or denial of a draft permit. The Administrator may set reasonable limits on the time allowed for oral statements and will require the submission of a written summary of each oral statement.
(d) The Administrator will assure that a record is made of the hearing.
(a) The Administrator will consider comments on the draft permit or denial of a draft permit that are received during the public comment period and any public hearing. The Administrator is not required to consider comments otherwise received.
(b) In issuing or denying an Acid Rain permit, the Administrator will:
(1) Identify any permit provision or portion of the statement of basis that has been changed and the reasons for the change; and
(2) Briefly describe and respond to relevant comments under paragraph (a) of this section.
(a) After the close of the public comment period, the Administrator will issue or deny an Acid Rain permit. The Administrator will serve a copy of any Acid Rain permit and the response to comments on the designated representative for the source covered by the issuance or denial and serve written notice of the issuance or denial on the air pollution control agencies of affected States and any interested person. The Administrator will also give notice in the
(b)(1) The term of every Acid Rain permit shall be 5 years commencing on its effective date.
(2) Every Acid Rain permit for Phase I shall take effect on January 1, 1995.
(a)
(b)
(a) Each State shall submit, to the Administrator for review and acceptance, a State Acid Rain program meeting the requirements of §§ 72.72 and 72.73.
(b) The Administrator will review each State Acid Rain program or portion of a State Acid Rain program and accept, by notice in the
(c)(1) Except as provided in paragraph (c)(2) of this section, the Administrator will issue all Acid Rain permits for Phase I. The Administrator reserves the right to delegate the remaining administration and enforcement of Acid Rain permits for Phase I to approved State operating permit programs.
(2) The State permitting authority will issue an opt-in permit for a combustion or process source subject to its jurisdiction if, on the date on which the combustion or process source submits an opt-in permit application, the State permitting authority has opt-in regulations accepted under paragraph (b) of this section and an approved operating permits program under part 70 of this chapter.
A State operating permit program (including a State Acid Rain program) shall meet the following criteria. Any aspect of a State operating permits program or any implementation of a State operating permit program that fails to meet these criteria shall be grounds for nonacceptance or withdrawal of all or part of the Acid Rain portion of an approved State operating permit program by the Administrator or for disapproval or withdrawal of approval of the State operating permit program by the Administrator.
(a)
(1) Prohibitions, inconsistent with the Acid Rain Program, on the acquisition or transfer of allowances by an affected unit under the jurisdiction of the State permitting authority;
(2) Restrictions, inconsistent with the Acid Rain Program, on an affected unit's ability to sell or otherwise obligate its allowances;
(3) Requirements that an affected unit maintain a balance of allowances in excess of the level determined to be prudent by any utility regulatory authority with jurisdiction over the owners of the affected unit;
(4) Failing to notify the Administrator of any State administrative or judicial appeals of, or decisions covering, Acid Rain permit provisions that
(5) Issuing an order, inconsistent with the Acid Rain Program, interpreting Acid Rain Program requirements as not applicable to an affected source or an affected unit in whole or in part or otherwise adjusting the requirements;
(6) Withholding approval of any compliance option that meets the requirements of the Acid Rain Program; or
(7) Any other aspect of implementation that the Administrator determines would hinder the operation of the Acid Rain Program.
(b) The State operating permit program shall require the following provisions, which are adopted to the extent that this paragraph (b) is incorporated by reference or is otherwise included in the State operating permit program.
(1)
(i)
(
(B)
(ii)
(B) Prior to issuance of a draft permit for a combustion or process source, the State permitting authority shall provide the designated representative of a combustion or process source an opportunity to confirm its intention to opt-in, in accordance with § 74.14 of this chapter.
(iii)
(iv)
(v)
(vi)
(vii)
(viii) Each Acid Rain permit (including a draft or proposed permit) shall contain all applicable Acid Rain requirements, shall be a complete and segregable portion of the operating permit, and shall not incorporate information contained in any other documents, other than documents that are readily available.
(ix) No Acid Rain permit (including a draft or proposed permit) shall be issued unless the Administrator has received a certificate of representation for the designated representative of the source in accordance with subpart B of this part.
(x) Except as provided in § 72.73(b) and, with regard to combustion or process sources, in § 74.14(c)(6) of this chapter, the State permitting authority shall issue or deny an Acid Rain permit within 18 months of receiving a complete Acid Rain permit application submitted in accordance with § 72.21 or such lesser time approved under part 70 of this chapter.
(2)
(3)
(4)
(5)
(ii) [Reserved]
(iii) The State permitting authority shall serve written notice on the Administrator of any State administrative or judicial appeal concerning as Acid Rain provision of any operating permit or denial of an Acid Rain portion of any operating permit within 30 days of the filing of the appeal.
(iv) Any State administrative permit appeals procedures shall ensure that the Administrator may intervene as a matter of right in any permit appeal involving an Acid Rain permit provision or denial of an Acid Rain permit.
(v) The State permitting authority shall serve written notice on the Administrator of any determination or
(vi) A failure of the State permitting authority to issue an Acid Rain permit in accordance with § 72.73(b)(1) or, with regard to combustion or process sources, § 74.14(b)(6) of this chapter shall be ground for filing an appeal.
(6)
(a)
(i) That are located in the geographic area covered by the operating permits program; and
(ii) To the extent that the accepted State Acid Rain program is applicable.
(2) In administering and enforcing Acid Rain permits, the State permitting authority shall comply with the procedures for issuance, revision, renewal, and appeal of Acid Rain permits under this subpart.
(b)
(i) On or before December 31, 1997, issue an Acid Rain permit for Phase II covering the affected units (other than opt-in sources) at each source in the geographic area for which the program is approved;
(ii) On or before January 1, 1999, for each unit subject to an Acid Rain NO
(2) Each Acid Rain permit issued in accordance with this section shall have a term of 5 years commencing on its effective date;
(a)(1) The Administrator will be responsible for administering and enforcing Acid Rain permits for Phase II for any affected sources to the extent that a State permitting authority is not responsible, as of January 1, 1997 or such later date as the Administrator may establish, for administering and enforcing Acid Rain permits for such sources under § 72.73(a).
(2) After and to the extent the State permitting authority becomes responsible for administering and enforcing Acid Rain permits under § 72.73(a), the Administrator will suspend federal administration of Acid Rain permits for Phase II for sources and units to the extent that they are subject to the accepted State Acid Rain program, except as provided in paragraph (b)(4) of this section.
(b)(1) The Administrator will administer and enforce Acid Rain permits effective in Phase II for sources and units during any period that the Administrator is administering and enforcing an operating permit program under part 71 of this chapter for the geographic area in which the sources and units are located.
(2) The Administrator will administer and enforce Acid Rain permits effective in Phase II for sources and units otherwise subject to a State Acid Rain program under § 72.73(a) if:
(i) The Administrator determines that the State permitting authority is not adequately administering or enforcing all or a portion of the State Acid Rain program, notifies the State permitting authority of such determination and the reasons therefore, and publishes such notice in the
(ii) The State permitting authority fails either to correct the deficiencies within a reasonable period (established by the Administrator in the notice under paragraph (b)(2)(i) of this section) after issuance of the notice or to take significant action to assure adequate administration and enforcement of the program within a reasonable period (established by the Administrator in the notice) after issuance of the notice; and
(iii) The Administrator publishes in the
(3) When the Administrator administers and enforces Acid Rain permits under paragraph (b)(1) or (b)(2) of this section, the Administrator will administer and enforce each Acid Rain permit issued under the State Acid Rain program or portion of the program until, and except to the extent that, the permit is replaced by a permit issued under this section. After the later of the date for publication of a notice in the
(4) After the State permitting authority becomes responsible for administering and enforcing Acid Rain permits effective in Phase II under § 72.73(a), the Administrator will continue to administer and enforce each Acid Rain permit issued under paragraph (a)(1), (b)(1), or (b)(2) of this section until, and except to the extent that, the permit is replaced by a permit issued under the State Acid Rain program. The State permitting authority may replace an Acid Rain permit issued under paragraph (a)(1), (b)(1), or (b)(2) of this section by issuing a permit under the State Acid Rain program by the expiration of the permit under paragraph (a)(1), (b)(1), or (b)(2) of this section. The Administrator may retain jurisdiction over the Acid Rain permits issued under paragraph (a)(1), (b)(1), or (b)(2) of this section for which the administrative or judicial review process is not complete and will address such retention of jurisdiction in a notice in the
(c)
(ii) Each Acid Rain permit issued in accordance with this section shall have a term of 5 years commencing on its effective date. Each Acid Rain permit issued in accordance with paragraph (c)(1)(i) of this section shall take effect by the later of January 1, 2000 or, where a permit governs a unit under § 72.6(a)(3), the deadline for monitor certification under part 75 of this chapter.
(2)
(d)
(2) The Administrator may delegate all or part of his or her responsibility, under this section, for administering and enforcing Phase II Acid Rain permits or opt-in permits to a State. Such delegation will be made consistent with the requirements of this part and the provisions governing delegation of a part 71 program under part 71 of this chapter.
(a) This subpart shall govern revisions to any Acid Rain permit issued by the Administrator and to the Acid Rain portion of any operating permit issued by a State permitting authority.
(b) Notwithstanding the operating permit revision procedures specified in parts 70 and 71 of this chapter, the provisions of this subpart shall govern revision of any Acid Rain Program permit provision.
(c) A permit revision may be submitted for approval at any time. No permit revision shall affect the term of the Acid Rain permit to be revised. No permit revision shall excuse any violation of an Acid Rain Program requirement that occurred prior to the effective date of the revision.
(d) The terms of the Acid Rain permit shall apply while the permit revision is pending, except as provided in § 72.83 for administrative permit amendments.
(e) The standard requirements of § 72.9 shall not be modified or voided by a permit revision.
(f) Any permit revision involving incorporation of a compliance option that was not submitted for approval and comment during the permit issuance process or involving a change in a compliance option that was previously submitted, shall meet the requirements for applying for such compliance option under subpart D of this part and parts 74 and 76 of this chapter.
(g) Any designated representative who fails to submit any relevant information or who has submitted incorrect information in a permit revision shall, upon becoming aware of such failure or incorrect submittal, promptly submit such supplementary information or corrected information to the permitting authority.
(h) For permit revisions not described in §§ 72.81 and 72.82 of this part, the permitting authority may, in its
(a) Permit revisions that shall follow the permit modification procedures are:
(1) Relaxation of an excess emission offset requirement after approval of the offset plan by the Administrator;
(2) Incorporation of a final nitrogen oxides alternative emission limitation following a demonstration period;
(3) Determinations concerning failed repowering projects under § 72.44(g)(1)(i) and (2) of this part.
(b) The following permit revisions shall follow, at the option of the designated representative submitting the permit revision, either the permit modification procedures or the fast-track modification procedures under § 72.82 of this part:
(1) Consistent with paragraph (a) of this section, incorporation of a compliance option that the designated representative did not submit for approval and comment during the permit issuance process; except that incorporation of a reduced utilization plan that was not submitted during the permit issuance process, that does not designate a compensating unit, and that meets the requirements of § 72.43 of this part, may use the administrative permit amendment procedures under § 72.83 of this part;
(2) Changes in a substitution plan or reduced utilization plan that result in the addition of a new substitution unit or a new compensating unit under the plan;
(3) Addition of a nitrogen oxides averaging plan to a permit;
(4) Changes in a Phase I extension plan, repowering plan, nitrogen oxides averaging plan, or nitrogen oxides compliance deadline extension; and
(5) Changes in a thermal energy plan that result in any addition or subtraction of a replacement unit or any change affecting the number of allowances transferred for the replacement of thermal energy.
(c)(1) Permit modifications shall follow the permit issuance requirements of:
(i) Subparts E, F, and G of this part, where the Administrator is the permitting authority; or
(ii) Subpart G of this part, where the State is the permitting authority.
(2) For purposes of applying paragraph (c)(1) of this section, a requested permit modification shall be treated as a permit application, to the extent consistent with § 72.80 (c) and (d).
The following procedures shall apply to all fast-track modifications.
(a) If the Administrator is the permitting authority, the designated representative shall serve a copy of the fast-track modification on the Administrator and any person entitled to a written notice under § 72.65(b)(1)(ii) and (iii). If a State is the permitting authority, the designated representative shall serve such a copy on the Administrator, the permitting authority, and any person entitled to receive a written notice of a draft permit under the approved State operating permit program. Within 5 business days of serving such copies, the designated representative shall also give public notice by publication in a newspaper of general circulation in the area where the sources are located or in a State publication designed to give general public notice.
(b) The public shall have a period of 30 days, commencing on the date of publication of the notice, to comment on the fast-track modification. Comments shall be submitted in writing to the permitting authority and to the designated representative.
(c) The designated representative shall submit the fast-track modification to the permitting authority on or before commencement of the public comment period.
(d) Within 30 days of the close of the public comment period if the Administrator is the permitting authority or within 90 days of the close of the public comment period if a State is the permitting authority, the permitting authority shall consider the fast-track modification and the comments received and approve, in whole or in part
(a) Acid Rain permit revisions that shall follow the administrative permit amendment procedures are:
(1) Activation of a compliance option conditionally approved by the permitting authority;
(2) Changes in the designated representative or alternative designated representative;
(3) Correction of typographical errors;
(4) Changes in names, addresses, or telephone or facsimile numbers;
(5) Changes in the owners or operators;
(6)(i) Termination of a compliance option in the permit; provided that all requirements for termination under subpart D of this part are met and this procedure shall not be used to terminate a repowering plan after December 31, 1999 or a Phase I extension plan;
(ii) For opt-in sources, termination of a compliance option in the permit; provided that all requirements for termination under § 74.47 of this chapter are met.
(7) Changes in a substitution or reduced utilization plan that do not result in the addition of a new substitution unit or a new compensating unit under the plan;
(8) Changes in the date, specified in a unit's Acid Rain permit, of commencement of operation of qualifying Phase I technology,
(9) Changes in the date, specified in a new unit's Acid Rain permit, of commencement of operation or the deadline for monitor certification,
(10) The addition of or change in a nitrogen oxides alternative emissions limitation demonstration period,
(11) Changes in a thermal energy plan that do not result in the addition or subtraction of a replacement unit or any change affecting the number of allowances transferred for the replacement of thermal energy.
(12) The addition of a NO
(13) The addition of an exemption for which the requirements have been met under § 72.7 or § 72.8 or which was approved by the permitting authority under § 72.14; and
(14) Incorporation of changes that the Administrator has determined to be similar to those in paragraphs (a)(1) through (13) of this section.
(b)(1) The permitting authority will take final action on an administrative permit amendment within 60 days, or, for the addition of an alternative emissions limitation demonstration period, within 90 days, of receipt of the requested amendment and may take such action without providing prior public notice. The source may implement any changes in the administrative permit amendment immediately upon submission of the requested amendment,
(2) The permitting authority may, on its own motion, make an administrative permit amendment under paragraph (a)(3), (a)(4), (a)(12), or (a)(13) of this section at least 30 days after providing notice to the designated representative of the amendment and without providing any other prior public notice.
(c) The permitting authority will designate the permit revision under paragraph (b) of this section as having been made as an administrative permit amendment. Where a State is the permitting authority, the permitting authority shall submit the revised portion of the permit to the Administrator.
(d) An administrative amendment shall not be subject to the provisions
The following permit revisions shall be deemed to amend automatically, and become a part of the affected unit's Acid Rain permit by operation of law without any further review:
(a) Upon recordation by the Administrator under part 73 of this chapter, all allowance allocations to, transfers to, and deductions from an affected unit's Allowance Tracking System account; and
(b) Incorporation of an offset plan that has been approved by the Administrator under part 77 of this chapter.
(a) The permitting authority shall reopen an Acid Rain permit for cause whenever:
(1) Any additional requirement under the Acid Rain Program becomes applicable to any affected unit governed by the permit;
(2) The permitting authority determines that the permit contains a material mistake or that an inaccurate statement was made in establishing the emissions standards or other terms or conditions of the permit, unless the mistake or statement is corrected in accordance with § 72.83; or
(3) The permitting authority determines that the permit must be revised or revoked to assure compliance with Acid Rain Program requirements.
(b) In reopening an Acid Rain permit for cause, the permitting authority shall issue a draft permit changing the provisions, or adding the requirements, for which the reopening was necessary. The draft permit shall be subject to the requirements of subparts E, F, and G of this part.
(c) As provided in §§ 72.73(b)(1) and 72.74(c)(2), the permitting authority shall reopen an Acid Rain permit to incorporate nitrogen oxides requirements, consistent with part 76 of this chapter.
(d) Any reopening of an Acid Rain permit shall not affect the term of the permit.
(a)
(b)
(1) Identification of the unit;
(2) For all Phase I units, the information in accordance with §§ 72.91(a) and 72.92(a) of this part;
(3) If the unit is governed by an approved Phase I extension plan, then the information in accordance with § 72.93 of this part;
(4) At the designated representative's option, the total number of allowances to be deducted for the year, using the formula in § 72.95 of this part, and the serial numbers of the allowances that are to be deducted;
(5) At the designated representative's option, for units that share a common stack and whose emissions of sulfur dioxide are not monitored separately or apportioned in accordance with part 75 of this chapter, the percentage of the total number of allowances under paragraph (b)(4) of this section for all such units that is to be deducted from each unit's compliance subaccount; and
(6) The compliance certification under paragraph (c) of this section.
(c)
(1) Whether the unit was operated in compliance with the applicable Acid Rain emissions limitations, including whether the unit held allowances, as of the allowance transfer deadline, in its compliance subaccount (after accounting for any allowance deductions under § 73.34(c) of this chapter) not less than the unit's total sulfur dioxide emissions during the calendar year covered by the annual report;
(2) Whether the monitoring plan that governs the unit has been maintained to reflect the actual operation and monitoring of the unit and contains all information necessary to attribute monitored emissions to the unit;
(3) Whether all the emissions from the unit, or a group of units (including the unit) using a common stack, were monitored or accounted for through the missing data procedures and reported in the quarterly monitoring reports, including whether conditionally valid data, as defined in § 72.2, were reported in the quarterly report. If conditionally valid data were reported, the owner or operator shall indicate whether the status of all conditionally valid data has been resolved and all necessary quarterly report resubmissions have been made.
(4) Whether the facts that form the basis for certification of each monitor at the unit or a group of units (including the unit) using a common stack or for using an Acid Rain Program excepted monitoring method or approved alternative monitoring method, if any, has changed; and
(5) If a change is required to be reported under paragraph (c)(4) of this section, specify the nature of the change, the reason for the change, when the change occurred, and how the unit's compliance status was determined subsequent to the change, including what method was used to determine emissions when a change mandated the need for monitor recertification.
(a)
(1) “Baseline” is as defined in § 72.2 of this part.
(2) “Actual utilization” is the actual annual heat input (in mmBtu) of the unit for the calendar year determined in accordance with part 75 of this chapter.
(3) “Plan reductions” are the reductions in actual utilization, for the calendar year, below the baseline that are accounted for by an approved reduced utilization plan. The designated representative for the unit shall calculate the “plan reductions” (in mmBtu) using the following formula and converting all values in Kwh to mmBtu using the actual annual average heat rate (Btu/Kwh) of the unit (determined in accordance with part 75 of this chapter) before the employment of any improved unit efficiency measures under an approved plan:
(i) “Reduction from energy conservation” is a good faith estimate of the expected kilowatt hour savings during the calendar year from all conservation measures under the reduced utilization plan and the corresponding reduction
(ii) “Reduction from improved unit efficiency” is a good faith estimate of the expected improvement in heat rate during the calendar year and the corresponding reduction in heat input (in mmBtu) at the Phase I unit as a result of all improved unit efficiency measures under the reduced utilization plan. The verified amount of such reduction shall be submitted in accordance with paragraph (b) of this section.
(iii) “Shifts to designated sulfur-free generators” is the reduction in utilization (in mmBtu), for the calendar year, that is accounted for by all sulfur-free generators designated under the reduced utilization plan in effect for the calendar year. This term equals the sum, for all such generators, of the “shift to sulfur-free generator.” “Shift to sulfur-free generator” shall equal the amount, to the extent documented under paragraph (a)(6) of this section, calculated for each generator using the following formula:
(A) “Actual sulfur-free utilization” is the actual annual generation (in Kwh) of the designated sulfur-free generator for the calendar year converted to mmBtus.
(B) “Average 1985-87 sulfur-free utilization” is the sum of annual generation (in Kwh) for 1985, 1986, and 1987 for the designated sulfur-free generator, divided by three and converted to mmBtus.
(C) “Percentage change in dispatch system sales” is calculated as follows:
If the result of the formula for percentage change in dispatch system sales is less than or equal to zero, then percentage change in dispatch system sales shall be treated as zero only for purposes of paragraph (a)(3)(iii) of this section.
(D) If the result of the formula for “shift to sulfur-free generator” is less than or equal to zero, then “shift to sulfur-free generator” is zero.
(iv) “Shifts to designated compensating units” is the reduction in utilization (in mmBtu) for the calendar year that is accounted for by increased generation at compensating units designated under the reduced utilization plan in effect for the calendar year. This term equals the heat rate, under paragraph (a)(3) of this section, of the unit reducing utilization multiplied by the sum, for all such compensating units, of the “shift to compensating unit” for each compensating unit. “Shift to compensating unit” shall equal the amount of compensating generation (in Kwh), to the extent documented under paragraph (a)(6) of this section, that the designated representatives of the unit reducing utilization and the compensating unit have certified (in their respective annual compliance certification reports) as the amount that will be converted to mmBtus and used, in accordance with paragraph (a)(4) of this section, in calculating the adjusted utilization for the compensating unit.
(4) “Compensating generation provided to other units” is the total amount of utilization (in mmBtu) necessary to provide the generation (if any) that was shifted to the unit as a designated compensating unit under any other reduced utilization plans that were in effect for the unit and for the calendar year. This term equals the heat rate, under paragraph (a)(3) of this section, of such unit multiplied by the
(5) Notwithstanding paragraphs (a)(3) (i), (ii), and (iii) of this section, where two or more Phase I units include in “plan reductions”, in their annual compliance certification reports for the calendar year, expected kilowatt hour savings or reduction in heat rate from the same specific conservation or improved unit efficiency measures or increased utilization of the same sulfur-free generator:
(i) The designated representatives of all such units shall submit with their annual reports a certification signed by all such designated representatives. The certification shall apportion the total kilowatt hour savings, reduction in heat rate, or increased utilization among such units.
(ii) Each designated representative shall include in the annual report only the respective unit's share of the total kilowatt hour savings, reduction in heat rate, or increased utilization, in accordance with the certification under paragraph (a)(5)(i) of this section.
(6)(i) Where a unit includes in “plan reductions” under paragraph (a)(3) of this section the increase in utilization of any sulfur-free generator, the designated representative of the unit shall submit, with the annual compliance certification report, documentation demonstrating that an amount of electrical energy at least equal to the “shift to sulfur-free generator” attributed to the sulfur-free generator in the annual report was actually acquired by the unit's dispatch system from the sulfur-free generator.
(ii) Where a unit includes in “plan reductions” under paragraph (a)(3) of this section utilization of any compensating unit, the designated representative of the unit shall submit with the annual compliance certification report, documentation demonstrating that an amount of electrical energy at least equal to the “shift to compensating unit” attributed to the compensating unit in the annual report was actually acquired by the unit's dispatch system from the compensating unit.
(7) Notwithstanding paragraphs (a)(3) (i), (ii), (iii), and (iv), (a)(4), and (a)(5) of this section, “plan reductions” minus “compensating generation provided to other units” shall not exceed “baseline” minus “actual utilization.”
(b)
(i) The verified kilowatt hour savings from each such energy conservation measure and the verified corresponding reduction in the unit's heat input resulting from each measure during the calendar year covered by the annual report. For purposes of this paragraph (b), all values in Kwh shall be converted to mmBtu using the actual annual heat rate (Btu/Kwh) of the unit (determined in accordance with part 75 of this chapter) before the employment of any improved unit efficiency measures under an approved reduced utilization plan.
(ii) The verified reduction in the heat rate achieved by each improved unit efficiency measure and the verified corresponding reduction in the unit's heat input resulting from such measure.
(iii) For each figure under paragraphs (b)(1) (i) and (ii) of this section:
(A) Documentation (which may follow the EPA Conservation Verification Protocol) verifying specified figures to the satisfaction of the Administrator; or
(B) Certification, by a State utility regulatory authority that has ratemaking jurisdiction over the utility system that paid for the measures in accordance with § 72.43(b)(2) of this part and over rates reflecting any of the amount paid for such measures, or that meets the criteria in § 73.82(c)(1) (i) and
(C) Certification, by a utility regulatory authority that has ratemaking jurisdiction over the utility system that paid for the measures in accordance with § 72.43(b)(2) of this part and over rates reflecting any of the amount paid for such measures, that such authority verified specified figures related to supply-side measures, except measures relating to generation efficiency.
(iv) The sum of the verified reductions in a unit's heat input from all measures implemented at the unit to reduce the unit's heat rate (whether the measures are treated as supply-side measures or improved unit efficiency measures) shall not exceed the generation (in kwh) attributed to the unit for the calendar year times the difference between the unit's heat rate for 1987 and the unit's heat rate for the calendar year.
(2) Notwithstanding paragraph (b)(1)(i) of this section, where two or more Phase I units include in the confirmation report the verified kilowatt hour savings or reduction in heat rate from the same specific conservation or improved unit efficiency measures:
(i) The designated representatives of all such units shall submit with their confirmation reports a certification signed by all such designated representatives. The certification shall apportion the total kilowatt hour savings or reduction in heat rate among such units.
(ii) Each designated representative shall include in the confirmation report only the respective unit's share of the total savings or reduction in heat rate in accordance with the certification under paragraph (b)(2)(i) of this section.
(3) If the total, included in the confirmation report, of the amounts of verified reduction in the unit's heat input from energy conservation and improved unit efficiency measures equals the total estimated in the unit's annual compliance certification report from such measures for the calendar year, then the designated representatives shall include in the confirmation report a statement indicating that is true.
(4) If the total, included in the confirmation report, of the amounts of verified reduction in the unit's heat input from energy conservation and improved unit efficiency measures is greater than the total estimated in the unit's annual compliance certification report from such measures for the calendar year, then the designated representative shall include in the confirmation report the number of allowances to be credited to the unit's compliance subaccount calculated using the following formula:
(i) “Verified heat input reduction” is the total of the amounts of verified reduction in the unit's heat input (in mmBtu) from energy conservation and improved unit efficiency measures included in the confirmation report.
(ii) “Estimated heat input reduction” is the total of the amounts of reduction in the unit's heat input (in mmBtu) accounted for by energy conservation and improved efficiency measures as estimated in the unit's annual compliance certification report for the calendar year.
(iii) “Emissions rate” is the “emissions rate” under § 72.92(c)(2)(v) of this part.
(iv) The allowances credited shall not exceed the total number of allowances deducted from the unit's compliance subaccount for the calendar year in accordance with §§ 72.92(a) and (c) and 73.35(b) of this chapter.
(5) If the total, included in the confirmation report, of the amount of verified reduction in the unit's heat input for energy conservation and improved unit efficiency measures is less than the total estimated in the unit's annual compliance certification report for such measures for the calendar year, then the designated representative shall include in the confirmation report the number of allowances to be deducted from the unit's compliance subaccount calculated in accordance with this paragraph (b)(5).
(i) If any allowances were deducted from the unit's compliance subaccount for the calendar year in accordance with §§ 72.92(a) and (c) and 73.35(b) of this chapter, then the number of allowances to be deducted under paragraph (b)(5) of this section equals the absolute value of the result of the formula for allowances credited under paragraph (b)(4) of this section (excluding paragraph (b)(4)(iv) of this section).
(ii) If no allowances were deducted from the unit's compliance subaccount for the calendar year in accordance with §§ 72.92(a) and (c) and 73.35(b) of this chapter:
(A) The designated representative shall recalculate the unit's adjusted utilization in accordance with paragraph (a) of this section, replacing the amounts for reduction from energy conservation and reduction from improved unit efficiency by the amount for verified heat input reduction. “Verified heat input reduction” is the total of the amounts of verified reduction in the unit's heat input (in mmBtu) from energy conservation and improved unit efficiency measures included in the confirmation report.
(B) After recalculating the adjusted utilization under paragraph (b)(5)(ii)(A) of this section for all Phase I units that are in the unit's dispatch system and to which paragraph (b)(5) of this section is applicable, the designated representative shall calculate the number of allowances to be surrendered in accordance with § 72.92(c)(2) using the recalculated adjusted utilizations of such Phase I units.
(C) The allowances to be deducted under paragraph (b)(5) of this section shall equal the amount under paragraph (b)(5)(ii)(B) of this section,
(6) The Administrator will determine the amount of allowances that would have been included in the unit's compliance subaccount and the amount of excess emissions of sulfur dioxide that would have resulted if the deductions made under § 73.35(b) of this chapter had been based on the verified, rather than the estimated, reduction in the unit's heat input from energy conservation and improved unit efficiency measures.
(7) The Administrator will determine whether the amount of excess emissions of sulfur dioxide under paragraph (b)(6) of this section differs from the amount of excess emissions determined under § 73.35(b) of this chapter based on the annual compliance certification report. If the amounts differ, the Administrator will determine: The number of allowances that should be deducted to offset any increase in excess emissions or returned to account for any decrease in excess emissions; and the amount of excess emissions penalty (excluding interest) that should be paid or returned to account for the change in excess emissions. The Administrator will deduct immediately from the unit's compliance subaccount the amount of allowances that he or she determines is necessary to offset any increase in excess emissions or will return immediately to the unit's compliance subaccount the amount of allowances that he or she determines is necessary to account for any decrease in excess emissions. The designated representative may identify the serial numbers of the allowances to be deducted or returned. In the absence of such identification, the deduction will be on a first-in, first-out basis under § 73.35(b)(2) of this chapter and the return will be at the Administrator's discretion.
(8) If the designated representative of a unit fails to submit on a timely basis a confirmation report (in accordance with paragraph (b) of this section) with regard to the estimate of expected kilowatt hour savings or improvement in heat rate from any energy conservation or improved unit efficiency measure under the reduced utilization plan, then the Administrator will reject such estimate and correct it to equal zero in the unit's annual compliance certification report that includes that estimate. The Administrator will deduct immediately, on a first-in, first-out basis under § 73.35(c)(2) of this chapter, the amount of allowances that he or she determines is necessary to offset
(a)
(b)
(2)(i) If any Phase I unit in a dispatch system is governed during the calendar year by an approved reduced utilization plan relying on sulfur-free generation, then the designated representatives of all affected units in such dispatch system shall jointly submit, within 60 days of the end of the calendar year, a dispatch system data report that includes the following elements in a format prescribed by the Administrator:
(A) The name of the dispatch system as reported under § 72.33;
(B) The calculation of “percentage change in dispatch system sales” under § 72.91(a)(3)(iii)(C);
(C) A certification that each designated representative will use this figure, as appropriate, in its annual compliance certification report and will submit upon request the data supporting the calculation; and
(D) The signatures of all the designated representatives.
(ii) If any Phase I unit in a dispatch system has adjusted utilization greater than zero for the calendar year, then the designated representatives of all Phase I units in such dispatch system shall jointly submit, within 60 days of the end of the calendar year, a dispatch system data report that includes the following elements in a format prescribed by the Administrator:
(A) The name of the dispatch system as reported under § 72.33;
(B) The calculation of “percentage change in dispatch system sales” under § 72.91(a)(3)(iii)(C);
(C) The calculation of “dispatch system adjusted utilization” under paragraph (c)(2)(i) of this section;
(D) The calculation of “dispatch system aggregate baseline” under paragraph (c)(2)(ii) of this section;
(E) The calculation of “fraction of generation within dispatch system” under paragraph (c)(2)(v)(A) of this section;
(F) The calculation of “dispatch system emissions rate” under paragraph (c)(2)(v)(B) of this section;
(G) The calculation of “fraction of generation from non-utility generators” under paragraph (c)(2)(v)(C) of this section;
(H) The calculation of “non-utility generator average emissions rate “ under paragraph (c)(2)(v)(F) of this section;
(I) A certification that each designated representative will use these figures, as appropriate, in its annual compliance certification report and will submit upon request the data supporting these calculations; and
(J) The signatures of all the designated representatives.
(c)
(i) Allowances are not surrendered for deduction for the portion of adjusted utilization accounted for by:
(A) Shifts in generation from the unit to other Phase I units;
(B) A dispatch-system-wide sales decline;
(C) Plan reductions under a reduced utilization plan as calculated under § 72.91; and
(D) Foreign generation.
(ii) Allowances are surrendered for deduction for the portion of adjusted utilization that is not accounted for under paragraph (c)(1)(i) of this section.
(2) The designated representative shall surrender for deduction the number of allowances calculated using the following formula:
If the result of the formula for “allowances surrendered” is less than or equal to zero, then no allowances are surrendered.
(i)
(ii)
(iii)
(iv)
(A) U
(B) U
(C) m = all Phase I units in the dispatch system having an adjusted utilization greater than 0 for the calendar year.
(v)
(A) “Fraction of generation within dispatch system” is the fraction of the dispatch system's total sales accounted for by generation from units and generators within the dispatch system, other than generation from non-utility generators. This term equals the total generation (in Kwh) by all units and generators within the dispatch system for the calendar year minus the total non-utility generation from non-utility generators within the dispatch system for the calendar year and divided by the total sales (in Kwh) by the dispatch system for the calendar year.
(B) Dispatch system emissions rate” is the weighted average rate (in lbs/mmBtu) for the dispatch system calculated as follows:
Dispatch system emissions rate =
(C) “Fraction of generation from non-utility generators” is the fraction of the dispatch system's total sales accounted for by generation acquired from non-utility generators within or outside the dispatch system. This term equals the total non-utility generation from non-utility generators (within or outside the dispatch system) for the calendar year divided by the total sales (in Kwh) by the dispatch system for the calendar year.
(D) “Non-utility generator” is a power production facility (within or outside the dispatch system) that is not an affected unit or a sulfur-free generator and that has a “non-utility generator emissions rate” for the calendar year under paragraph (c)(2)(v)(F) of this section.
(E) “Non-utility generation” is the generation (in Kwh) that the dispatch system acquired from a non-utility generator during the calendar year as required by Federal or State law or an order of a utility regulatory authority or under a contract awarded as the result of a power purchase solicitation required by Federal or State law or an order of a utility regulatory authority.
(F) “Non-utility generator average emissions rate” is the weighted average rate (in lbs/mmBtu) for the non-utility generators calculated as follows:
Non-utility generator average emissions rate =
(
(
(
(G) “Fraction of generation outside dispatch system” = 1−fraction of generation within dispatch system−fraction of generation from non-utility generators.
(H) “Fraction of non-Phase I and non-foreign generation in NERC region” is the portion of the NERC region's total sales generated by units and generators other than Phase I units or foreign sources in the unit's NERC region in 1985, as set forth in table 1 of this section.
(I) “NERC region emissions rate” is the weighted average emission rate (in lbs/mmBtu) for the unit's NERC region in 1985, as set forth in table 1 of this section.
(a)
(1) Satisfactory documentation of a preliminary design and engineering effort.
(2) A binding letter agreement for the executed and binding contract (or for each in a series of executed and binding contracts) for the majority of the equipment to repower the unit using the technology conditionally approved by the Administrator under § 72.44(d)(3).
(3) The letter agreement under paragraph (a)(2) of this section shall be signed and dated by each party and specify:
(i) The parties to the contract;
(ii) The date each party executed the contract;
(iii) The unit to which the contract applies;
(iv) A brief list identifying each provision of the contract;
(v) Any dates to which the parties agree, including construction completion date;
(vi) The total dollar amount of the contract; and
(vii) A statement that a copy of the contract is on site at the source and will be submitted upon written request of the Administrator or the permitting authority.
(b)
(c)
(d)
The following formula shall be used to determine the total number of allowances to be deducted for the calendar year from the allowances held in an affected unit's compliance subaccount as of the allowance transfer deadline applicable to that year:
(a) “Tons emitted” is the total tons of sulfur dioxide emitted by the unit during the calendar year, as reported in accordance with part 75 of this chapter.
(b) “Allowances surrendered for underutilization” is the total number of allowances calculated in accordance with § 72.92 (a) and (c).
(c) “Allowances deducted for Phase I extensions” is the total number of allowances calculated in accordance with § 72.42(f)(1)(i).
(d) “Allowances deducted for substitution or compensating units” is the total number of allowances calculated in accordance with the surrender requirements specified under § 72.41(d)(3) or (e)(1)(iii)(B) or § 72.43(d)(2).
(a) The Administrator may review, and conduct independent audits concerning, any compliance certification and any other submission under the Acid Rain Program and make appropriate adjustments of the information in the compliance certifications and other submissions.
(b) The Administrator may deduct allowances from or return allowances to a unit's Allowance Tracking System account in accordance with part 73 of this chapter based on the information in the compliance certifications and other submissions, as adjusted.
For the purposes of the Acid Rain Program, 1985 emissions limits must be expressed in pounds of SO
Annualization factors are used to develop annual equivalent SO
For the purposes of the Acid Rain Program, all emissions limits must be expressed in pounds of SO
The factor for converting pounds of sulfur to pounds of SO
The equation used to calculate the yearly SO
If gas is the only fuel, gas emissions are defaulted to 0.
Each fuel type SO
For coal, the yearly fuel burned is in tons/yr and the AP-42 factor (which accounts for the ash retention of sulfur in coal), in lbs SO
For oil, the yearly fuel burned is in gal/yr. If it is in bbl/yr, convert using 42 gal/bbl oil. The AP-42 factor (which accounts for the oil density), in lbs SO
For all fuel, the units conversion factor is 1 ton/2000 lbs.
The potential electrical output capacity is calculated from the maximum design heat input from the boiler by the following equation:
42 U.S.C. 7601 and 7651
The purpose of this part is to establish the requirements and procedures for the following:
(a) The allocation of sulfur dioxide emissions allowances;
(b) The tracking, holding, and transfer of allowances;
(c) The deduction of allowances for purposes of compliance and for purposes of offsetting excess emissions pursuant to parts 72 and 77 of this chapter;
(d) The sale of allowances through EPA-sponsored auctions and a direct sale, including the independent power producers written guarantee program; and
(e) The application for, and distribution of, allowances from the Conservation and Renewable Energy Reserve.
(f) The application for, and distribution of, allowances for desulfurization of fuel by small diesel refineries.
The following parties shall be subject to the provisions of this part:
(a) Owners, operators, and designated representatives of affected sources and affected units pursuant to § 72.6 of this chapter;
(b) Any new independent power producer as defined in section 416 of the Act and § 72.2 of this chapter, except as provided in section 405(g)(6) of the Act;
(c) Any owner of an affected unit who may apply to receive allowances under the Energy Conservation and Renewable Energy Reserve Program established in accordance with section 404(f) of the Act;
(d) Any small diesel refinery as defined in § 72.2 of this chapter, and
(e) Any other person, as defined in § 72.2 of this chapter, who chooses to purchase, hold, or transfer allowances as provided in section 403(b) of the Act.
Part 72 of this chapter, including §§ 72.2 (definitions), 72.3 (measurements, abbreviations, and acronyms), 72.4 (Federal authority), 72.5 (State authority), 72.6 (applicability), 72.7 (new units exemption), 72.8 (retired unit exemption), 72.9 (standard requirements), 72.10 (availability of information), and 72.11 (computation of time) of part 72, subpart A of this chapter, shall apply to this part. The procedures for appeals of decisions of the Administrator under this part are contained in part 78 of this chapter. Sections 73.3 (Definitions) and 73.4 (Deadlines), which were previously published with subpart E of this part—“Auctions, Direct Sales, andIndependent Power Producers Written Guarantee”, are codified at §§ 72.2 and 72.12 of this chapter, respectively.
(a)
(b)
(2) The Administrator will allocate allowances to the unit account for each unit listed in table 2 of this section in the amount specified in table 2 column F to be held in the future year subaccounts representing calendar years 2010 and each year thereafter.
(3) The owner of each unit listed in the following table shall surrender, for each allowance listed in Column A or B of such table, an allowance of the same or earlier compliance use date and shall return to the Administrator any proceeds received from allowances withheld from the unit, as listed in Column C of such table. The allowances shall be surrendered and the proceeds shall be returned by December 28, 1998.
(a)
(b) [Reserved]
(a)
(b)
(a)
(b)
(c)
(a)
(1) It is an existing unit that is a utility unit;
(2) It serves a generator with nameplate capacity equal to or greater than 75 MWe;
(3) Its 1985 actual SO
(4) Its 1990 actual SO
(5) Its actual SO
(6) It commenced commercial operation after January 1, 1970;
(7) It is part of a utility system whose combined commercial and industrial kilowatt-hour sales increased more than 20 percent between calendar years 1980 and 1990; and
(8) It is part of a utility system whose company-wide fossil-fuel SO
(b)[Reserved]
(a)
(1) The unit is not a unit subject to emissions limitation requirements of Phase I and is not a substitution unit (under 40 CFR 72.41) or a compensating unit (under 40 CFR 72.43);
(2) The unit is authorized by the Governor of the State in which the unit is located;
(3) The unit is part of a utility system (which, for the purposes of this section only, includes all generators operated by a single utility, including generators that are not fossil fuel-fired) that has decreased its total coal-
(4) The unit is part of a utility system that during calendar years 1985 through 1987 had a weighted capacity factor for all coal-fired units in the system of less than fifty percent. The weighted capacity factor is equal to:
(b)
(1) Be made no earlier than calendar year 1995 and no later than calendar year 1999; and
(2) Be due to physical changes to the plant or are a result of a change in the method of operating the plant including but not limited to changing the type or quality of fuel being burned.
(c)
(1) A letter from the Governor of the State in which the unit is located authorizing the unit to make reductions in sulfur dioxide emissions; and
(2) A report listing all units in the utility system, each fossil fuel-fired unit's fuel consumption and fuel heat content for calendar year 1980, and each generator's total electrical generation for calendar years 1980 and 1985 (including all generators, whether fossil fuel-fired, nuclear, hydroelectric or other).
(d)
(i) The calendar year for which credits for reductions are requested and the actual SO
(ii) A letter signed by the designated representative stating and documenting the specific physical changes to the plant or changes in the method of operating the plant (including but not limited to changing the type or quality of fuel being burned) which resulted in the reduction of emissions; and
(iii) A letter signed by the designated representative certifying that all photocopies are exact copies.
(2) The designated representative shall submit each request for allowances no later than March 1 of the calendar year following the year in which the reductions were made.
(e)
(1) “Prior year” means a single calendar year selected by the eligible unit from 1995 to 1999 inclusive.
(2) One “credit” equals one ton of eligible SO
(3) “ERC units” are units eligible for early reduction credits, and “non-ERC units” are fossil fuel-fired units that are part of the same operating system but are not eligible for early reduction credits.
(4) For any unit that did not operate during 1990, the unit's 1990 SO
(5) Early reduction credits will be calculated at the unit level, subject to
(6) The number of credits for eligible Phase II units will be calculated as follows:
(i)
(ii)
(iii)
(iv)
This result, expressed in million Btus, is the restricted utilization of the ERC unit to be used in the calculation of early reduction credits in paragraph (e)(6)(v)(B) of this section.
(v)(A)
(B)
(vi) The Administrator will allocate to the ERC unit allowances equal to the lesser of the calculated number of credits in paragraphs (e)(6)(v) (A) or (B) of this section and the following limitation:
(f)
For the purposes of this calculation, the unit's dispatch system will be the dispatch system as it existed as of November 15, 1990.
(2)
(3)
(ii) The number of allowances calculated under paragraph (f)(2) of this section shall be deducted, contemporaneously with the allocation under paragraph (f)(3)(i) of this section, from the unit's year 2015 subaccount.
(iii) Notwithstanding paragraph (f)(3)(ii) of this section, if the number of allowances to be deducted exceeds the amount of allowances allocated to the unit for the year 2015, allowances in the year 2015 subaccount equal to the amount of allowances allocated to the unit for the year 2015 shall be deducted. In addition to the deduction from the year 2015 subaccount, a sufficient amount of allowances in the year
(iv) Notwithstanding paragraph (f)(3)(ii) of this section, the procedure in paragraph (f)(3)(iii) shall be applied as follows to each year after 2015 (year-by-year in numerical order) for which the number of allowances to be deducted from that year's subaccount exceeds the number allocated to the unit for that year: allowances equal to the number allocated for that year shall be deducted from that year's subaccount and the remainder (up to the amount allocated) necessary to equal the number of allowances required to be deducted under paragraph (f)(3)(ii) of this section shall be deducted from the next year's subaccount.
(v) The owners and operators of the unit shall ensure that sufficient allowances are available to make the full deductions required under paragraphs (f)(3)(ii), (iii), and (iv) of this section. The designated representative may specify the serial number of each allowance to be deducted.
(4)
(a)
(b) Upon commencement of commercial operation of a new unit (under § 72.44(b)(2) of this chapter) with an approved repowering extension plan, allowances for use during the repowering extension period approved will end and allocations under § 73.10(b) for the existing unit will be transferred to the subaccounts for the new unit.
(c)(1) If the designated representative for a repowering unit terminates the repowering extension plan in accordance with § 72.44(g)(1) of this chapter, the repowering allowances allocated to that unit by paragraph (a) of this section will be terminated and any necessary allowances from that unit's account forfeited, calculated in the following manner:
(c)(2) The Administrator will reallocate any allowances forfeited in paragraph (c)(1) of this section with a compliance use date of 2000 or any allowances remaining in the repowering reserve to all Table 2 units’ years 2000 through 2009 subaccounts in the following manner:
The Administrator will initially allocate 3.5 million allowances to the Phase I Extension Reserve account of the Allowance Tracking System. Allowances from this Reserve will be allocated to units under § 72.42 of this chapter. Allowances remaining in the Phase I Extension Reserve account following allocation of all extension allowances under § 72.42 of this chapter will remain in the Reserve.
The Administrator will allocate 300,000 allowances to the Conservation and Renewable Energy Reserve subaccount of the Acid Rain Data System. Allowances from this Reserve will be allocated to units under subpart F of this part. Termination of this Reserve and reallocation of allowances will be made under § 73.80(c).
(a)
(2) The Administrator will allocate 250,000 allowances annually for calendar year 2000 and each year thereafter to the Auction Subaccount of the Special Allowance Reserve.
(b)
(2) Until June 1, 1998, monetary proceeds from the auctions of allowances from the Special Allowance Reserve (under subpart E of this part) for use in calendar years 2000 through 2009 will be distributed to the designated representative of each unit listed in Table 2 according to the following equation:
(3) On or after June 1, 1998, monetary proceeds from the auctions of allowances from the Special Allowance Reserve (under subpart E of this part) for use in calendar years 2000 through 2009 will be distributed to the designated representative of each unit listed in Table 2 according to the following equation:
(4) Monetary proceeds from the auctions of allowances from the Special Allowance Reserve (under subpart E of this part) from years of purchase from 1993 through 1998, remaining in the U.S. Treasury as a result of the surrender of allowances and return of proceeds under § 73.10(b)(3), will be distributed to the designated representative of each unit listed in Table 2 according to the following equation:
(5) Monetary proceeds from the auctions of allowances from the Special Allowance Reserve (under subpart E of this part) for use in calendar years 2010 and thereafter will be distributed to the designated representative of each unit listed in Table 2 according to the following equation:
(c)
(2) Until June 1, 1998, allowances, for use in calendar years 2000 through 2009, remaining in the Special Allowance Reserve at the end of each year, following that year's auction (under subpart E of this part), will be reallocated to the unit's Allowance Tracking System account according to the following equation:
(3) On or after June 1, 1998, allowances, for use in calendar years 2000 through 2009, remaining in the Special Allowance Reserve at the end of each year, following that year's auction (under subpart E of this part), will be reallocated to the unit's Allowance Tracking System account according to the following equation:
(4)[Reserved]
(5) Allowances, for use in calendar years 2010 and thereafter, remaining in the Special Allowance Reserve at the end of each year, following that year's auction (under subpart E of this part), will be reallocated to the unit's Allowance Tracking System account according to the following equation:
(d)
(e)
(2) If the sum of the proceeds to be distributed under paragraph (b) of this section is less than the total proceeds or the allowances to be reallocated under paragraph (c) of this section is less than the allowances remaining, then EPA will distribute one dollar or allowance for each unit, beginning with the unit receiving the largest number of dollars or allowances, in descending order, until the distribution balances with the proceeds and the reallocated allowances balance with the remaining allowances.
(a)
(b)
(a)
(b)
(c)
(i) Name and title of the authorized account representative and alternate authorized account representative (if any) pursuant to § 73.33;
(ii) Mailing address, telephone number and facsimile transmission number (if any) of the authorized account representative and alternate authorized account representative (if any);
(iii) Organization or company name (if applicable) and type of organization (if applicable);
(iv) A list of all persons subject to a binding agreement for the authorized account representative to represent their ownership interest with respect to the allowances held in the general account and which shall be amended and resubmitted within 30 days following any transaction giving rise to any change of the list of persons subject to the binding agreement;
(v) A certification statement by the authorized account representative and alternate authorized account representative (if any) that reads “I certify that I was selected under the terms of an agreement that is binding on all persons who have an ownership interest with respect to allowances held in the Allowance Tracking System account. I certify that I have all necessary authority to carry out my duties and responsibilities on behalf of the persons with an ownership interest and that they shall be fully bound by my actions, inactions, or submissions under 40 CFR part 73. I shall abide by any fiduciary responsibilities assigned pursuant to the binding agreement. I am authorized to make this submission on behalf of the persons with an ownership interest for whom this submission is made. I certify under penalty of law that I have personally examined and am familiar with the information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the information is to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false material information, or omitting material information, including the possibility of fine or imprisonment for violations.”;
(vi) The signature of the authorized account representative and the alternate authorized account representative (if any); and
(vii) The date of the signature of the authorized account representative and the alternate authorized account representative (if any).
(2) Upon receipt of such complete application, the Administrator will establish an Allowance Tracking System account for the person or persons identified in the application.
(3) No allowance transfers will be recorded for a general account until the
(d)
Each allowance account will include, at a minimum, the following:
(a) The name, address, telephone number and facsimile transmission number, if any, of the authorized account representative; and
(1) In the case of a unit account, a list of all persons identified as owners of record of the unit in § 72.24(a)(3) of this chapter, or
(2) In the case of a general account, a list of all persons subject to the binding agreement for the authorized account representative to represent their ownership interest with respect to allowances, as identified in accordance with § 73.31(c);
(b) A list of transfers of allowances to, and from, the account, including the identity of the transferror and transferee accounts;
(c) In the case of a unit account for an existing affected unit, beginning in 1995, a compliance subaccount;
(d) In the case of a unit account for a new unit, a compliance subaccount;
(e) In the case of a general account, a current year subaccount;
(f) Future year subaccounts for each of the 30 calendar years following the later of 1995 or the current calendar year;
(g) In the case of a unit account, the current total of sulfur dioxide emissions in tons for the current calendar year as reported to date pursuant to part 75 of this chapter.
(a) Following the establishment of an Allowance Tracking System account, all matters pertaining to the account, including, but not limited to, the deduction and transfer of allowances in the account, shall be undertaken only by the authorized account representative.
(b)
(c)
(d)
(1) The alternate authorized account representative may be changed at any time by the authorized account representative upon receipt by the Administrator of a new complete application as required in § 73.31(c);
(2) The alternate authorized account representative shall be subject to the provisions of this part applicable to authorized account representatives;
(3) Whenever the term “authorized account representative” is used in this part it shall be construed to include the alternate authorized account representative, unless such a construction would be illogical from the context; and
(4) Any action, representation or failure to act by the alternate authorized account representative when acting in that capacity shall be deemed to be an
(e)
(f)
(a)
(b)
(c)
(1) All allowances allocated or deducted for the unit for the year pursuant to subpart B of this part;
(2) All allowances allocated or deducted pursuant to §§ 72.41, 72.42, 72.43, and 72.44 and part 74 of this chapter;
(3) All allowances allocated pursuant to subparts F and G of this part;
(4) All allowances recorded as a result of purchases or returns from the annual auctions;
(5) All allowances recorded or deducted as a result of allowance transfers recorded pursuant to subpart D of this part; and
(6) All allowances deducted or returned pursuant to §§ 73.35(d), 72.91 and 72.92, part 74, and part 77 of this chapter.
(d)
(a)
(1) The compliance use date of the allowance is no later than the year in which the unit's SO
(2) Such allowance is:
(i) Recorded in the unit's compliance subaccount; or
(ii) Transferred to the unit's compliance subaccount, with the transfer submitted correctly pursuant to subpart D of this part for recordation in the compliance subaccount for the unit by not
(iii) Held in the compliance subaccount of another affected unit at the same source in accordance with paragraph (b)(3) of this section.
(b)
(2) The Administrator will make deductions until either the number of allowances deducted is equal to the amount calculated in accordance with § 72.95 of this chapter, or, for opt-in sources, in accordance with § 74.49 of this chapter, as modified under § 72.96 of this chapter or until no more allowances remain in the compliance subaccount.
(3)(i) If, after the Administrator completes the deductions under paragraph (b)(2) of this section for all affected units at the same source, a unit would otherwise have excess emissions and one or more other affected units at the source would otherwise have unused allowances in their compliance subaccounts and available for such other units under paragraph (a)(1) and (a)(2)(i) and (ii) of this section for the year for which compliance is being established, the Administrator will notify in writing the authorized account representative. The Administrator will state that the authorized account representative may specify in writing which of such allowances to deduct up to the amount calculated as follows, in order to reduce the tons of excess emissions otherwise at the unit:
Where:
(ii) Notwithstanding paragraph (b)(3)(i) of this section, if the amount calculated results in less than 10 tons of excess emissions, the maximum deduction from other units shall be adjusted so that 10 tons of excess emissions, or the tons of excess emissions that would result if no allowances could be deducted from other units, whichever is less, remain for the unit.
(iii) If the authorized account representative submits within 15 days of receipt of a notification under paragraph (b)(3)(i) of this section a written request specifying allowances to deduct in accordance with paragraphs (b)(3)(i) and (ii) of this section, the Administrator will deduct such allowances, and reduce the tons of excess emissions otherwise at the unit by an equal amount, up to the amount calculated under paragraphs (b)(3)(i) and (ii) of this section.
(c)(1)
(2)
(d)
(e)
(a)
(b)
(a)
(1) A description of the error alleged to have been made by the Administrator;
(2) A proposed correction of the alleged error;
(3) Any supporting documentation or other information concerning the alleged error and proposed correction; and
(4) Certification by the signature of and the date of the signature of the authorized account representative.
(b)
(1) The determination made and any action taken by, the Administrator; and
(2) The reasons for such action.
(c)
(d)
(e)
(f)
(a)
(b)
(a)
(b)
(i) The numbers identifying both the transferror and transferee accounts;
(ii) A specification by serial number of each allowance to be transferred, or correct indication on the allowance transfer where a request involves the transfer of the unit's allowances in perpetuity;
(iii) Signatures of the authorized account representatives of both the transferror and transferee accounts;
(iv) The dates of the signatures of the authorized account representatives;
(v) The numbers identifying the authorized account representatives for both the transferror and transferee account; and
(vi) Where the transferee account has not been established, information as required pursuant to § 73.31 (b) or (c).
(2)(i) The authorized account representative for the transferee account can meet the requirements in paragraphs (b)(1)(iii) and (iv) of this section by submitting, in a format prescribed by the Administrator, a statement
(ii) The statement under paragraph (b)(2)(i) of this section shall include the following: “By this signature, I authorize any transfer of allowances into each Allowance Tracking System account listed herein, except that I do not waive any remedies under 40 CFR part 73, or any other remedies under State or federal law, to obtain correction of any erroneous transfers into such accounts. This authorization shall be binding on any authorized account representative for such account unless and until a statement signed by the authorized account representative retracting this authorization for the account is received by the Administrator.”
(3) Transfers of allowances to or from compliance subaccounts submitted for recordation following the allowance transfer deadline will not be recorded until after completion of the process of recordation set forth in § 73.34(a).
Except as provided in § 73.34(a), the Administrator will not record a transfer of allowances from a future year subaccount to a subaccount for an earlier year.
(a)
(1) The information submitted pursuant to § 73.50 is complete;
(2) The transferror account includes each allowance identified by serial number in the allowance transfer request submitted pursuant to § 73.50, except when a request for transfer of the unit's allowances in perpetuity is indicated correctly on the allowance transfer submission;
(3) If the allowances identified by serial number specified pursuant to § 73.50(b)(1)(ii) are subject to the limitation on transfer imposed pursuant to § 72.44(h)(1)(i) of this chapter, § 74.42 of this chapter, or § 74.47(c) of this chapter, the transfer is in accordance with such limitation; and
(4) The transfer meets all applicable requirements of this subpart.
(b) Where an allowance transfer submitted for recordation fails to meet the requirements of this subpart, the Administrator will not record such transfer.
(a)
(b)
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(c) Nothing in this section shall preclude the submission of an allowance
(a)
(b)
(c)
(1) The compliance use date of the allowances offered;
(2) The number of allowances to be sold and any other information identifying the allowances offered that may be required by subpart C of this part;
(3) Any minimum price; and
(4) Whether the authorized account representative is willing to sell fewer allowances than the number stated in paragraph (c)(2) of this section, if the full amount cannot be sold. After notification, the Administrator will deduct allowances from the appropriate Allowance Tracking System account from which allowances are being offered and place them in a separate subaccount for such allowances.
(d)
(i) All allowances are sold,
(ii) No bids remain, or
(iii) Prices of remaining bids do not meet minimum prices required in remaining offers.
(2) In the event that there is more than one bid submitting the same price and the total number of allowances requested in all such bids exceeds the number of allowances remaining, the Administrator will award the remaining allowances by lottery to such bidders.
(3) In the event that there are more offers of sale at the minimum price than there are bids meeting that price, allowances from all such offers will be sold to cover the bids, according to each such offeror's pro rata share of all allowances so offered.
(4) In the event that fewer allowances remain than are requested in a bid, the Administrator will sell such remaining allowances to the bidder provided that, pursuant to § 73.71(b)(4), the bid states the bidder's willingness to purchase fewer allowances than requested in the bid.
(5) In the event that fewer than all allowances included in an offer for sale would be sold to remaining bids based on price, the Administrator will sell such allowances to the bidder(s), provided that, pursuant to § 73.70(c)(4), the offer states the offeror's willingness to sell fewer allowances than were offered for sale.
(e)
(f)
(g)
(h)
(1) Allowances auctioned from the Auction Subaccount. Not later than 90 days following each auction, the Administrator will pay a pro rata share of the proceeds of each auction to the authorized account representative of each unit from whose annual allowance allocation allowances were withheld for the purposes of establishing the Auction Subaccount. Each unit's pro rata share will be calculated pursuant to regulations to be promulgated under subpart B.
(2) Allowances contributed from others. Not later than 90 days following each auction, the Administrator will transfer the full amount of the proceeds of each sale of allowances offered by authorized account representatives to such representatives. Proceeds from the sale of allowances that were offered with the same specified minimum price will be distributed according to each such offeror's pro rata share of the sale of such allowances.
(3) The Administrator will pay no interest on any payment made pursuant to paragraphs (h) (1) and (2) of this section.
(i)
(1) Allowances in the Auction Subaccount. At the conclusion of each auction, the Administrator will transfer to the Allowance Tracking System account of each unit specified in paragraph (h)(1) of this section its pro rata share of any allowances remaining in the Auction Subaccount. Each unit's pro rata share will be calculated pursuant to regulations to be promulgated under subpart B.
(2) Allowances contributed from others. At the conclusion of each auction, the Administrator will return unsold allowances to the appropriate offerors’ Allowance Tracking System accounts. Any unsold allowances that were offered with the same specified minimum price will be distributed according to each such offeror's pro rata share of all such allowances offered.
(a)
(b)
(1) The number of allowances sought and the price;
(2) Whether spot or advance allowances are sought;
(3) Allowance Tracking System account number;
(4) Whether the bidder is willing to purchase fewer allowances than the number of allowances stated in (b)(1) of this section if the full amount is not available. Where the bidder holds no Allowance Tracking System account, a New Account/New Authorized Account Representative Form must accompany the bid. New account information shall include at a minimum: Name, address, telephone number, facsimile number, organization or company name (if applicable), type of organization, and the authorized account representative for purposes of the account.
(c)
(d)
(e)
(f)
Allowances that were formerly part of the direct sale program, which has been terminated under § 73.73(b), will be included in the annual allowance auctions in accordance with § 73.70(a).
(a)
(b)
(c)
(a)
(b)
(c)
(a)
(1) Is specified in appendix A(1) of this subpart; or
(2) In the case of a device or material that is not included in appendix A(1) of this subpart,
(i) Is a cost-effective demand-side measure consistent with an applicable least-cost plan or least-cost planning process that increases the efficiency of the customer's use of electricity (as measured in accordance with § 73.82(c)) without increasing the use by the customer of any fuel other than qualified renewable energy, industrial waste heat, or, pursuant to paragraph (b)(5) of this section, industrial waste gases;
(ii) Is implemented pursuant to a conservation program approved by the utility regulatory authority, which certifies that it meets the requirements of paragraph (a)(2)(i) of this section and is not excluded by paragraph (b) of this section; and
(iii) Is reported by the applicant in its application to the Reserve.
(b)
(1) Demand-side measures that were operational before January 1, 1992;
(2) Supply-side measures;
(3) Conservation programs that are exclusively informational or educational in nature;
(4) Load management measures that lead to economic reduction of electric energy demand during a utility's peak generating periods, unless kilowatt hour savings can be verified by the utility pursuant to § 73.82(c); or
(5) Utilization of industrial waste gases, unless the applicant has certified that there is no net increase in sulfur dioxide emissions from such utilization.
(c)
(1) Is specified in appendix A(3) of this subpart; or
(2) In the case of renewable energy generation that is not included in appendix A(3) of this subpart is#:
(i) Consistent with a least cost plan or a least cost planning process and derived from biomass (
(ii) Implemented pursuant to approval by the utility regulatory authority, which certifies that it meets the requirements of paragraphs (c)(2)(i) and (c)(2)(ii) of this section and is not excluded by paragraph (d) of this section; and
(iii) Is reported by the applicant in its application to the Reserve.
(d)
(1) Renewable energy generation that was operational before January 1, 1992;
(2) Measures that reduce electricity demand for a utility's customers without providing electric generation directly for sale to customers; and
(3) Measures that appear on the list of qualified energy conservation measures in appendix A(1) of this subpart.
(a)
(1) Certify that the applicant is a utility;
(2) Demonstrate that the applicant, any subsidiary of the applicant, or any subsidiary of the applicant's holding company, is an owner or operator, in whole or in part, of at least one Phase I or Phase II unit by including in the application the name and Allowance Tracking System account number of a Phase I or Phase II unit which it owns or operates and for which it is listed as an owner or operator on the certificate of representation submitted by the designated representative for the unit pursuant to § 72.20 of this chapter;
(3) Through certification, demonstrate that the applicant is paying in whole or in part for one or more qualified energy conservation measures or qualified renewable energy generation (that became operational during the period of applicability) either directly or through payment to another person that purchases the qualified energy conservation measure or qualified renewable energy generation;
(4) Demonstrate that the applicant is subject to a least cost plan or a least cost planning process that:
(i) provides an opportunity for public notice and comment or other public participation processes;
(ii) evaluates the full range of existing and incremental resources in order to meet expected future demand at lowest system cost;
(iii) treats demand-side resources and supply-side resources on a consistent and integrated basis;
(iv) takes into account necessary features for system operation such as diversity, reliability, dispatchability, and other factors of risk;
(v) may take into account other factors, including the social and environmental costs and benefits of resource investments; and
(vi) is being implemented by the applicant to the maximum extent practicable.
(5) Demonstrate that the qualified energy conservation measure adopted or qualified renewable energy generated, or both, are consistent with the least cost plan or least cost planning process;
(6) If the applicant is subject to the rate-making jurisdiction of a State or local utility regulatory authority, its least cost plan or least cost planning process has been approved or accepted by the utility regulatory authority in the State or locality in which the qualified conservation measure(s) are adopted or in which the qualified renewable energy generation is utilized, and such State or local utility regulatory authority certifies that the least-cost plan or least-cost planning process meets the requirements of paragraph (a)(4) of this section;
(7) If the applicant is not subject to the rate-making jurisdiction of a State or local regulatory authority, its least cost plan or least cost planning process has been approved or has been accepted by the utility regulatory authority with rate-making jurisdiction over the applicant, and such utility regulatory authority certifies that the least cost plan or least cost planning process
(8) If the applicant is an independent power production facility that sells qualified renewable energy generation to another utility, the applicant has enclosed documentation that such qualified renewable energy generation was purchased pursuant to the purchasing utility's least cost plan or least cost planning process, which has been approved or accepted by the purchasing utility's utility regulatory authority.
(9)(i) If the applicant is an investor-owner utility subject to the ratemaking jurisdiction of a State utility regulatory authority and is submitting an application on the basis of one or more qualified energy conservation measures, such State utility regulatory authority has established a procedure for determining rates and charges ensuring net income neutrality, as defined in § 72.2 of this chapter, including a provision that the utility's net income is compensated in full (considering factors such as risk) for lost sales attributable to the utility's conservation programs, which may include:
(A) General ratemaking for formulas that decouple utility profits from actual utility sales;
(B) Specific rate adjustment formulas that allow a utility to recover in its retail rates the full costs of conservation measures plus any associated net revenues lost as a result of reduced sales resulting from conservation initiatives; or
(C) Conservation incentive mechanisms designed to provide positive financial rewards to a utility to encourage implementation of cost-effective measures;
(ii) Provided that the existence of any one of the categories of ratemaking or rate adjustment formulas or conservation incentive mechanisms specified in paragraph (a)(9)(i) of this section shall not necessarily constitute fulfillment of the net income neutrality requirement unless, pursuant to § 73.83, the Secretary of Energy has certified the establishment of such net income neutrality;
(10) Demonstrate that the applicant has implemented the qualified energy conservation measures or used the qualified renewable energy generation specified in the application during the period of applicability;
(11) Demonstrate the extent to which installation of the qualified conservation measure(s) has achieved actual energy savings, by stating, on the basis of the performance of the measure(s) following installation:
(i) The amount of kilowatt hour savings resulting from the measure(s) in the given year(s);
(ii) Pursuant to paragraph (c) of this section, the methodology used to calculate the kilowatt hour savings; and
(iii) The name, address, and phone number of the person who performed the calculation of kilowatt hour savings;
(12) Report the type and amount of yearly qualified renewable energy generation, by stating (and submitting documentation, including copies of plant operation records, supporting such statements) the kilowatt hours of qualified renewable energy generated during a previous calendar year or years; and
(13) Report the extent to which qualified renewable energy generation was produced in combination with other energy sources (hereafter “hybrid generation”) by stating (and submitting documentation, including copies of plant operation records, supporting such statements) the heat input and heat rate of the non-qualified renewable generation, the total annual kilowatt hours generated, and the kilowatt hours that can be attributed to qualified renewable energy generation;
(14) Demonstrate the extent to which the implementation of qualified energy conservation measures or the use of qualified renewable energy generation has resulted in avoided tons of sulfur dioxide emissions by the utility during the period of applicability, pursuant to paragraph (d) of this section.
(b)
(1) If a utility applying for allowances from the Reserve has not received certification of net income neutrality from the Secretary of Energy or
(i) A copy of the relevant State utility regulatory authority's final order or decision setting forth the approved ratemaking mechanisms that ensure that a utility's net income will be at least as high upon implementation of energy conservation measures as such net income would have been if the energy conservation measures has not been implemented;
(ii) A description of how the State utility regulatory authority's order or decision meets the definition of net income neutrality as defined in § 72.2; and
(iii) Any additional information necessary for Secretary of Energy to certify that the State regulatory authority has established rates and charges that ensure net income neutrality.
(2) If a utility applying for allowances from the Reserve has already received certification of net income neutrality from the Secretary of Energy in connection with a previous application for allowances, and the ratemaking methods or procedures that ensure net income neutrality have not been altered, the applicant shall certify that the ratemaking methods and procedures that led to the original certification are still in place.
(c)
(1) Applicants subject to the ratemaking jurisdiction of a State utility regulatory authority shall use the energy conservation verification methodology approved by such authority in support of energy conservation applications under this subpart and part 72 of this chapter, provided that
(i) The authority in question uses this methodology to determine the applicant's entitlement to performance-based rate adjustments, which permit a utility's rates to be adjusted for additional kilowatt hours saved due to the utility's energy conservation programs;
(ii) Such performance based rate adjustments are subject to modification either prospectively or retrospectively to reflect periodic evaluations of energy savings secured by the applicant; and
(iii) The applicant has provided the Administrator with a description of the State utility regulatory authority's verification methodology and documentation that the requirements of this paragraph (e) have been met.
(2) All other applicants, including applicants whose rates are not subject to the ratemaking jurisdiction of a State utility regulatory authority shall demonstrate to the satisfaction of the Administrator through submission of documentation that savings have been achieved and may use the EPA Conservation Verification Protocol.
(3) All records of verification of energy savings shall be kept on file by the applicant for a period of 3 years. The Administrator may extend this period for cause at any time prior to the end of 3 years by notifying the applicant in writing.
(4) The Administrator reserves the right to conduct independent reviews, analyses, or audits to ascertain that the verification is valid and correct. If the Administrator determines that the verification is not valid or correct, the Administrator may revise the allocation of allowances to an applicant or require the surrender of allowances from the applicant's Allowance Tracking System account.
(d)
(1) In the case of an application submitted on the basis of qualified energy conservation measures, the sulfur dioxide emissions tonnage deemed avoided for any calendar year shall be equal to the product of:
(A) = the kilowatt hours that were not, but would otherwise have been, supplied by the utility during such year in the absence of such qualified energy conservation measures.
(B) = 0.004 1bs. of sulfur dioxide per kilowatt hour.
(2) In the case of an application submitted on the basis of qualified renewable energy generation, the sulfur dioxide emissions tonnage deemed avoided
(A) = the actual kilowatt hours of qualified renewable energy generated or purchased by the applicant (based on the qualified renewable energy generation portion for hybrid generation).
(B) = 0.004 lbs. of sulfur dioxide per kilowatt hour.
(e)
(1) Certification of all application requirements, including the net income neutrality requirements, shall be made by a certifying official of the applicant upon such official's verification of all information and documentation submitted.
(2) The applicant shall submit a certification statement signed by the applicant's certifying official that reads “I certify under penalty of law that I have personally examined and am familiar with the information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the information is to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false material information, or omitting material information, including the possibility of fine or imprisonment for violations.”
(f)
(g)
(2) Beginning no earlier than January 1, 1993, any applicant may apply to the Secretary of Energy for the Secretary's certification of net income neutrality where the application is based on the use of one or more qualified energy conservation measures.
(3) Applications will be received by the Administrator and the Secretary of Energy until January 2, 2010, pursuant to § 73.80(c), or until no allowances remain in the Reserve.
(h)
(a)
(b)
(c)
(a)
(b)
(c)
(d)
(e)
(2) In the event that a subaccount is established by EPA, pursuant to § 73.85, and the applicant is making a request for allowances not included in the subaccount, the Allowance Reserve allocations for the approved applicant will be made, in addition to any that may be allocated pursuant to paragraph (f)(3) of this section, from any allowances remaining in the Reserve that are not contained in the subaccount.
(f)
(2) If Reserve applications are received by the Administrator after all allowances from the Reserve have been allocated, the Administrator will so notify the applicant within 5 business days after receipt of the application.
(3) In the event that applications meeting the requirements pursuant to § 73.82 are received by the Administrator prior to February 1, 1998, and
(i) All remaining allowances in the Reserve have been placed in a subaccount pursuant to § 73.85; and
(ii) The applicant is not eligible for an allocation of allowances from the subaccount; the application will be placed on a waiting list in order of receipt.
(iii) The Administrator will notify the applicant of such action within 5 business days after receipt of the application.
(4) If any allowances are returned to the Reserve after February 1, 1998 pursuant to § 73.85(c), the Administrator will review the wait-listed applications in order of receipt and allocate any remaining allowances to the approved applicants in the order of their receipt until no more allowances remain in the Reserve.
(g)
(2) Any allowances awarded pursuant to two or more applications received on the same date based on the same avoided emissions from the same energy conservation measure or the same renewable electric generation will be divided equally between all such applicants unless the Administrator is otherwise directed by all such applicants.
(a)
(1) If at least 60,000 allowances have been allocated from the Reserve for
(i) Qualified energy conservation measures, and
(ii) Qualified renewable energy generation, allocations of allowances will continue pursuant to § 73.82, until no more allowances remain in the Reserve.
(2) If fewer than 60,000 allowances have been allocated for either qualified energy conservation measures or qualified renewable energy generation, the Administrator will establish a subaccount for the allocation of allowances for applications based on the category for which fewer than 60,000 allowances have been allocated. The subaccount will contain allowances equal to 60,000 less the number of allowances previously allocated for such category.
(b)
(c)
Nothing in this subpart shall preclude a State or State regulatory authority from providing additional incentives to utilities to encourage investment in any conservation measures or renewable energy generation.
The following listed measures are approved as “qualified energy conservation measures” for purposes of the Conservation and Renewable Energy Reserve Program or reduced utilization qualified energy conservation plans under § 72.43 of this chapter. Measures not appearing on the list may also be qualified conservation measures if they meet the requirements specified in § 73.81(a) of this part.
• Electric furnace improvements (intermittent ignition, automatic vent dampers, and heating element change-outs)
• Air conditioner (central and room) upgrades/replacements
• Heat pump (ground source, solar assisted, and conventional) upgrades/replacements
• Cycling of air conditioners and heat pumps
• Natural ventilation
• Heat recovery ventilation
• Clock thermostats
• Setback thermostats
• Geothermal steam direct use
• Improved equipment controls
• Solar assisted space conditioning (ventilation, air-conditioning, and desiccant cooling)
• Passive solar designs
• Air conditioner and heat pump clean and tune-up
• Heat pipes
• Whole house fans
• High efficiency fans and motors
• Hydronic pump insulation
• Register relocation
• Register size and blade configuration
• Return air location
• Duct sizing
• Duct insulation
• Duct sealing
• Duct cleaning
• Shade tree planting
• Electric water heater upgrades/replacements
• Electric water heater tank wraps/blankets
• Low-flow showerheads and fittings
• Solar heating and pre-heat units
• Geothermal heating and pre-heat units
• Heat traps
• Water heater heat pumps
• Recirculation pumps
• Setback thermostats
• Water heater cycling control
• Solar heating for swimming pools
• Pipe wrap insulation
• Lamp replacement
• Dimmers
• Motion detectors and occupancy sensors
• Photovoltaic lighting
• Fixture replacement
• Outdoor lighting controls
• Attic, basement, ceiling, and wall insulation
• Passive solar building systems
• Exterior roof insulation
• Exterior wall insulation
• Exterior wall insulation bordering unheated space (e.g., a garage)
• Knee wall insulation in attic
• Floor insulation
• Perimeter insulation
• Storm windows/doors
• Caulking/weatherstripping
• Multi-glazed inserts for sliding glass doors
• Sliding door replacements
• Installation of French doors
• Hollow core door replacement
• Radiant barriers
• Window vent conversions
• Window replacement
• Window shade screens
• Low-e windows
• Window reduction
• Attic ventilation
• Whole house fan
• Passive solar design
• Refrigerator replacements
• Freezer replacements
• Oven/range replacements
• Dishwasher replacements
• Clothes washer replacements
• Clothes dryer replacements
• Customer located power generation based on photovoltaic, solar thermal, biomass, wind or geothermal resources
• Swimming pool pump replacements
• Gasket replacements
• Maintenance/coil cleaning
• Heat pump replacement
• Fan motor efficiency
• Resizing of chillers
• Heat pipe retrofits in air conditioning units
• Dehumidifiers
• Steam trap insulation
• Radiator thermostatic valves
• Variable speed drive on fan motor
• Solar assisted HVAC including ventilation, chillers, heat pumps, and desiccants
• HVAC piping insulation
• HVAC ductwork insulation
• Boiler insulation
• Automatic night setback
• Automatic economizer cooling
• Outside air control
• Hot and cold deck automatic reset
• Reheat system primary air optimization
• Process heat recovery
• Deadband thermostat
• Timeclocks on circulating pumps
• Chiller system
• Increase condensing unit efficiency
• Separate make-up air for exhaust hoods
• Variable air volume system
• Direct tower cooling (chiller strainer cycle)
• Multiple chiller control
• Radiant heating
• Evaporative roof surface cooling
• Cooling tower flow control
• Ceiling fans
• Evaporative cooling
• Direct expansion cooling system
• Heat recovery ventilation (water and air-source)
• Set-back controls for heating/cooling
• Make-up air control
• Manual fan switches
• Energy saving exhaust hood
• Night flushing
• Spot radiant heating
• Terminal regulated air volume control scheme
• Variable speed motors for HVAC system
• Waterside economizers
• Airside economizer
• Gray water systems
• Well water for cooling
• Insulation
• Wall insulation
• Floor/slab insulation
• Roof insulation
• Window and door upgrades, replacements, and films (to reduce solar heat gains)
• Passive solar design
• Earth berming
• Shading devices and tree planting
• High reflectivity roof coating
• Evaporative cooling
• Infiltration reduction
• Weatherstripping
• Caulking
• Low-e windows
• Multi-glazed windows
• Replace glazing with insulated walls
• Thermal break window frames
• Tinted glazing
• Vapor barrier
• Vestibule entry
• Electronic ballast replacements
• Delamping
• Reflectors
• Occupancy sensors
• Daylighting with controls
• Photovoltaic lighting
• Efficient exterior lighting
• Manual selective switching
• Efficient exit signs
• Daylighting construction
• Cathode cutout ballasts
• High intensity discharge luminaries
• Outdoor light timeclock and photocell
• Refrigerator replacement
• Freezer replacement
• Optimize heat gains to refrigerated space
• Optimize defrost control
• Refrigeration pressure optimization control
• High efficiency compressors
• Anti-condensate heater control
• Floating head pressure
• Hot gas defrost
• Parallel unequal compressors
• Variable speed compressors
• Water cooler controls
• Waste heat utilization
• Air doors on refrigeration equipment
• Electric water heating upgrades/replacements
• Electric water heater wraps/blankets
• Pipe insulation
• Solar heating and/or pre-heat units
• Geothermal heating and/or pre-heat units
• Circulating pump control
• Point-of-use water heater
• Heat recovery domestic water heater (DWH) system
• Chemical dishwashing system
• End-use reduction using low-flow fittings
• Energy management control systems for building operations
• Customer located power based on photovoltaic, solar thermal, biomass, wind, and geothermal resources
• Energy efficient office equipment
• Customer-owned transformer upgrades and proper sizing
• Retire inefficient motors and replace with energy efficient motors, including the use of electronic adjustable speed or variable frequency drives
• Rebuild motors to operate more efficiently through greater contamination protection and improved magnetic materials
• Install self-starters
• Replace improperly sized motors
• Electronic ballast replacement/improvement
• Electromagnetic ballast upgrade
• Installation of reflectors
• Substitution of lamps with built-in automatic cathode cut-out switches
• Modify ballast circuits with additional impedance devices
• Metal halide and high pressure sodium lamp retrofits
• High pressure sodium retrofits
• Daylighting with controls
• Occupancy sensors
• Delamping
• Photovoltaic lighting
• Two step and dimmable high intensity discharge ballast
• Heat pump replacement/upgrade
• Furnace upgrade/replacement
• Fan motor efficiency
• Resizing of chillers
• Heat pipe retrofits on air conditioners
• Variable speed drive on fan motor
• Solar assisted HVAC including ventilation, chillers, heat pumps and desiccants
• Upgrades in heat transfer equipment
• Insulation and burner upgrades for industrial furnaces/ovens/boilers to reduce electricity loads on motors and fans
• Insulation and redesign of piping
• Upgrades/retrofits in condenser/evaporation equipment
• Process air and water filtration for improved efficiency
• Upgrades of catalytic combustors
• Solar process heat
• Customer located power based on photovoltaic, solar thermal, biomass, wind, and geothermal resources
• Power factor controllers
• Utilization of waste gas fuels
• Steam line and steam trap repairs/upgrades
• Compressed air system improvements/repairs
• Industrial process heat pump
• Optimization of equipment lubrication or maintenance
• Resizing of process equipment for optimal energy efficiency
• Use of unique thermodynamic power cycles
• Insulation of ceiling, walls, and ducts
• Window and door replacement/upgrade, including thermal energy barriers
• Caulking/weatherstripping
• Electric water heater upgrades/replacements
• Electric water heater wraps/blankets
• Pipe insulation
• Low-flow showerheads and fittings
• Solar heating and pre-heat units
• Geothermal heating and pre-heat units
• Refrigeration system retrofit/replacement
• Energy management control systems and end use metering
• Customer-owned transformer retrofits/replacements and proper sizing
• Building envelope measures
• Efficient HVAC equipment
• Heat pipe retrofit on air conditioners
• System and control measures
• Solar assisted HVAC including ventilation, chillers, heat pumps, and desiccants
• Air-source and geothermal heat pumps replacement/upgrades
• Upgrades/replacements
• Water heater wraps/blankets
• Pipe insulation
• Low-flow showerheads and fittings
• Solart heating and/or pre-hear units
• Geothermal heating and/or pre-heat units
• Electronic ballast replacements
• Delamping
• Reflectors
• Occupancy sensors
• Daylighting with controls
• Photovoltaic lighting
• Outdoor lighting controls
• Pump upgrades/retrofits
• Computerized pump control systems
• Irrigation load management strategies
• Irrigation pumping plants
• Computer irrigation control
• Surge irrigation
• Computerized scheduling of irrigation
• Drip irrigation systems
• Retire inefficient motors and replace with energy efficient motors, including the use of electronic adjustable speed and variable frequency drives
• Rebuild motors to operate more efficiently through greater contamination protection and improved magnetic materials
• Install self-starters
• Replace improperly sized motors
• Ventilation fans
• Cooling and refrigeration system upgrades
• Grain drying using unheated air
• Grain drying using low temperature electric
• Customer-owned transformer retrofits/replacements and proper sizing
• Programmable controllers for electrical farm equipment
• Controlled livestock ventilation
• Water heating for production agriculture
• Milk cooler heat exchangers
• Direct expansion/ice bank milk cooling
• Low energy precision application systems
• Heat pump crop drying
• Replace incandescent and mercury vapor lamps with high pressure sodium and metal halide
• Energy efficiency improvements in motors, pumps, and controls for water supply and waste water treatment
• District heating and cooling measures derived for cogeneration that result in electricity savings
Supply-side measures that may be approved for purposes of reduced utilization plans under § 72.43 include the following:
• Heat rate improvement programs
• Availability improvement programs
• Coal cleaning measures that improve boiler efficiency
• Turbine improvements
• Boiler improvements
• Control improvements, including artificial intelligence and expert systems
• Distributed control—local (real-time) versus central (delayed)
• Equipment monitoring
• Performance monitoring
• Preventive maintenance
• Additional or improved heat recovery
• Sliding/variable pressure operations
• Adjustable speed drives
• Improved personnel training to improve man/machine interface
• High efficiency transformer switchouts using amorphous core and silicon steel technologies
• Low-loss windings
• Innovative cable insulation
• Reactive power dispatch optimization
• Power factor control
• Primary feeder reconfiguration
• Primary distribution voltage upgrades
• High efficiency substation transformers
• Controllable series capacitors
• Real-time distribution data acquisition analysis and control systems
• Conservation voltage regulation
The following listed measures are approved as “qualified renewable energy generation” for purposes of the Conservation and Renewable Energy Reserve Program. Measures not appearing on the list may also be qualified renewable energy generation measures if they meet the requirements specified in § 73.81.
• Combustible energy-producing materials from biological sources which include: wood, plant residues, biological wastes, landfill gas, energy crops, and eligible components of municipal solid waste.
• Solar thermal systems and the non-fossil fuel portion of solar thermal hybrid systems
• Grid and non-grid connected photovoltaic systems, including systems added for voltage or capacity augmentation of a distribution grid.
• Hydrothermal or geopressurized resources used for dry steam, flash steam, or binary cycle generation of electricity.
• Grid-connected and non-grid-connected wind farms
• Individual wind-driven electrical generating turbines
(a)
(1) Photocopies of Form EIA-810 for each month of calendar years 1988 through 1990 for the refinery;
(2) Photocopies of Form EIA-810 for each month of calendar years 1988 through 1990 for each refinery owned or controlled by the refiner that owns or controls the refinery seeking certification; and
(3) A letter certified by the certifying official that the submitted photocopies are exact duplicates of those forms filed with the Department of Energy for 1988 through 1990.
(b)
(2) The request for allowances shall be submitted to the address in § 72.13 and shall include the following information:
(i) Certification that all motor fuel produced by the refinery for which allowances are claimed meets the requirements of subsection 211(i) of the Clean Air Act;
(ii) For calendar year 1993 desulfurized diesel fuel, photocopies of
(iii) For calendar years 1994 through 1999, inclusive, photocopies of Form 810 for each month in the respective calendar year.
(3) For joint ventures, each eligible refinery shall submit a separate application under paragraph (b)(2) of this section. Each application must include the diesel fuel throughput applicable to the joint agreement and the requested distribution of allowances that would be allocated to the joint agreement. If the applications for refineries involved in the joint agreement are inconsistent as to the throughput of diesel fuel applicable to the joint agreement or as to the distribution of the allowances, all involved applications will be considered void for purposes of the joint agreement.
(4) The certifying official shall submit all requests for allowances by April 1 of the calendar year following the year in which the diesel fuel was desulfurized to the Director, Acid Rain Division, under the procedures set forth in § 73.13 of this part.
(c)
(1) Allowances allocated under this section to any eligible refinery will be limited to the tons of SO
(3) If applications for a given year request, in the aggregate, more than 35,000 allowances, the Administrator will allocate allowances to each refinery in the amount equal to the lesser of 1500 or:
42 U.S.C. 7601 and 7651
The purpose of this part is to establish the requirements and procedures for:
(a) The election of a combustion or process source that emits sulfur dioxide to become an affected unit under the Acid Rain Program, pursuant to section 410 of title IV of the Clean Air Act, 42 U.S.C. 7401,
(b) Issuing and modifying operating permits; certifying monitors; and allocating, tracking, transferring, surrendering and deducting allowances for combustion or process sources electing to become affected units.
Combustion or process sources that are not affected units under § 72.6 of this chapter and that are operating and are located in the 48 contiguous States or the District of Columbia may submit an opt-in permit application to become opt-in sources upon issuance of an opt-in permit. Units for which an exemption under § 72.7, § 72.8 or § 72.14 of this chapter is in effect and combustion or process sources that are not operating are not eligible to submit an opt-in permit application to become opt-in sources.
(a)
(2) Subpart A, B, G, and H of part 72 of this chapter, including §§ 72.2 (definitions), 72.3 (measurements, abbreviations, and acronyms), 72.4 (Federal authority), 72.5 (State authority), 72.6 (applicability), 72.7 (New units exemption), 72.8 (Retired units exemption), 72.9 (Standard Requirements), 72.10 (availability of information), and 72.11 (computation of time), shall apply to this part.
(b)
(c)
(d)
(e)
(f)
(a) The provisions of subpart B of part 72 of this chapter shall apply to the designated representative of an opt-in source.
(b) If a combustion or process source is located at the same source as one or more affected units, the combustion or process source shall have the same designated representative as the other affected units at the source.
(c)(1) Notwithstanding paragraph (b) of this section, a certifying official of a combustion or process source that is located at the same source as one or more affected utility units and that, on the date on which an initial opt-in permit application is submitted for such combustion or process source and thereafter, does not serve a generator that produces electricity for sale may elect to designate, for such combustion or process source, a different designated representative than the designated representative for the affected utility units.
(2) In order to make such an election, the certifying official shall submit to the Administrator, in a format prescribed by the Administrator: a certification that the combustion or process source for which the election is made meets each of the requirements for election in paragraph (c)(1) of this section; and a certificate of representation for the designated representative of the combustion or process source in accordance with § 72.24 of this chapter. The Administrator will rely on such certificate of representation in accordance with § 72.25 of this chapter, unless the Administrator determines that the requirements for election in paragraph (c)(1) of this section are not met. If, after the election is made, the requirements for election in paragraph (c)(1) of this section are no longer met, the election shall automatically terminate on the first date on which the requirements are no longer met and, within 30
(a)
(1)
(2) Certifying or recertifying monitoring systems for combustion or process sources as provided under § 74.20 of this chapter;
(3) Establishing allowance accounts, tracking allowances, assessing end-of-year compliance, determining reduced utilization, approving thermal energy transfer and accounting for the replacement of thermal energy, closing accounts for opt-in sources that shut down, are reconstructed, become affected under § 72.6 of this chapter, or fail to renew their opt-in permit, and deducting allowances as provided under subpart E of this part; and
(4) Ensuring that the opt-in source meets all withdrawal conditions prior to withdrawal from the Acid Rain Program as provided under § 74.18; and
(5) Approving and disapproving the request to withdraw from the Acid Rain Program.
(b)
(1) Issuing the draft and final opt-in permit;
(2) Revising and renewing the opt-in permit; and
(3) Terminating the opt-in permit for an opt-in source as provided in § 74.18 (withdrawal), § 74.46 (shutdown, reconstruction or change in affected status) and § 74.50 (deducting allowances).
(a) The opt-in permit shall be included in the Acid Rain permit.
(b)
(c)
(1) All elements required for a complete opt-in permit application as provided under § 74.16 for combustion sources or under § 74.17 for process sources or, if applicable, all elements required for a complete opt-in permit renewal application as provided in § 74.19 for combustion sources or under § 74.17 for process sources;
(2) The allowance allocation for the opt-in source as determined by the Administrator under subpart C of this part for combustion sources or subpart D of this part for process sources;
(3) The standard permit requirements as provided under § 72.9 of this chapter, except that the provisions in § 72.9(d) of this chapter shall not be included in the opt-in permit; and
(4)
(d) Each opt-in permit is deemed to incorporate the definitions of terms under § 72.2 of this chapter.
(e)
(f)
(1) If an opt-in permit is issued prior to January 1, 2000, then the opt-in permit may, at the option of the permitting authority, expire on December 31, 1999; and
(2) If an affected unit with an Acid Rain permit is located at the same source as the combustion source, the combustion source's opt-in permit may, at the option of the permitting authority, expire on the same date as the affected unit's Acid Rain permit expires.
(a)
(b)
(1)
(2)
(3)
(4)
(5)
(6)
(ii) If the State is the permitting authority, an opt-in permit will be issued or denied within 18 months of receipt of a complete opt-in permit application or
(7)
(c) [Reserved]
(d)
(2)
(e)
(a)
(1) Identification of the combustion source, including company name, plant name, plant site address, mailing address, description of the combustion source, and information and diagrams on the combustion source's configuration;
(2) Identification of the designated representative, including name, address, telephone number, and facsimile number;
(3) The year and month the combustion source commenced operation;
(4) The number of hours the combustion source operated in the six months preceding the opt-in permit application and supporting documentation;
(5) The baseline or alternative baseline data under § 74.20;
(6) The actual SO
(7) The allowable 1985 SO
(8) The current allowable SO
(9) The current promulgated SO
(10) If the combustion source seeks to qualify for a transfer of allowances from the replacement of thermal energy, a thermal energy plan as provided in § 74.47 for combustion sources; and
(11) A statement whether the combustion source was previously an affected unit under this part;
(12) A statement that the combustion source is not an affected unit under § 72.6 of this chapter and does not have an exemption under § 72.7, § 72.8, or § 72.14 of this chapter;
(13) A complete compliance plan for SO
(14) The following statement signed by the designated representative of the
(b)
(a)
(b)
(c)
(1) By no later than January 30 of the first calendar year in which the withdrawal is to be effective, the designated representative must submit to the Administrator an annual compliance certification report pursuant to § 74.43.
(2) If the opt-in source has excess emissions in the calendar year before the year for which the withdrawal is to be in effect, the designated representative must submit an offset plan for excess emissions, pursuant to part 77 of this chapter, that provides for immediate deduction of allowances.
(d)
(e)
(f)
(2) If the requirements for withdrawal under paragraphs (b) and (c) of this section are not met or the Administrator's action under paragraph (d) of this section cannot be completed, the Administrator will issue a notification to the permitting authority and the designated representative of the opt-in source that the opt-in source's request to withdraw is denied. If the opt-in source's request to withdraw is denied, the opt-in source shall remain in the Opt-in Program and shall remain subject to the requirements for opt-in sources contained in this part.
(g)
(2) The termination of the opt-in permit under paragraph (g)(1) of this section will be effective on January 1 of the year for which the withdrawal is requested. An opt-in source shall continue to be an affected unit until the effective date of the termination.
(h)
(i)
(a) The designated representative of an opt-in source may submit revisions to its opt-in permit in accordance with subpart H of part 72 of this chapter.
(b) The designated representative of an opt-in source may renew its opt-in permit by meeting the following requirements:
(1)(i) In order to renew an opt-in permit if the Administrator is the permitting authority for the renewed permit, the designated representative of an opt-in source must submit to the Administrator an opt-in permit application at least 6 months prior to the expiration of an existing opt-in permit.
(ii) In order to renew an opt-in permit if the State is the permitting authority for the renewed permit, the designated representative of an opt-in source must submit to the permitting authority an opt-in permit application at least 18 months prior to the expiration of an existing opt-in permit or such shorter time as may be approved for operating permits under part 70 of this chapter.
(2) Each complete opt-in permit application submitted to renew an opt-in permit shall contain the following elements in a format prescribed by the Administrator:
(i) Elements contained in the opt-in source's initial opt-in permit application as specified under § 74.16(a)(1), (2), (10), (11), (12), and (13).
(ii) An updated monitoring plan, if applicable under § 75.53(b) of this chapter.
(c)(1) Upon receipt of an opt-in permit application submitted to renew an opt-in permit, the permitting authority shall issue or deny an opt-in permit in accordance with the requirements under subpart B of this part, except as provided in paragraph (c)(2) of this section.
(2) When issuing a renewed opt-in permit, the permitting authority shall not alter an opt-in source's allowance allocation as established, under subpart B and subpart C of this part for combustion sources and under subpart B and subpart D of this part for process sources, in the opt-in permit that is being renewed.
(a)
(2) The following data shall be submitted for the combustion source for the calendar year(s) under paragraph (a)(3) of this section:
(i) Monthly or annual quantity of each type of fuel consumed, expressed in thousands of tons for coal, thousands of barrels for oil, and million standard cubic feet (scf) for natural gas. If other fuels are used, the combustion source must specify units of measure.
(ii) Monthly or annual heat content of fuel consumed for each type of fuel
(iii) Monthly or annual sulfur content of fuel consumed for each type of fuel consumed, expressed as a percentage by weight.
(3)
(ii) For combustion sources that commenced operation after January 1, 1985, the data under this section shall be submitted for the first three consecutive calendar years during which the combustion source operated after December 31, 1985.
(b)
(i) for a combustion source submitting monthly data,
(ii) for a combustion source submitting annual data,
(2) For combustion sources that commenced operation after January 1, 1985, the alternative baseline is the average annual quantity of fuel consumed in the first three consecutive calendar years during which the combustion source operated after December 31, 1985, expressed in mmBtu. The alternative baseline shall be calculated as follows:
(c)
(2) Except as provided in paragraph (c)(1) of this section, no alternative data may be submitted. A combustion source that cannot submit all required data, in accordance with this section, shall not be eligible to submit an opt-in permit application.
(d)
(a)
(1) For combustion sources that commenced operation prior to January 1, 1985, the calendar year for calculating the actual SO
(2) For combustion sources that commenced operation after January 1, 1985, the calendar year for calculating the actual SO
(3) For combustion sources meeting the requirements of § 74.20(c), the calendar year for calculating the actual SO
(b)
(c)
(1) For a combustion source submitting monthly data,
(2) For a combustion source submitting annual data:
(d)
(e)
(a)
(i) Allowable SO
(ii) Citation of statute, regulations, and any other authority under which the allowable emissions rate under paragraph (a)(1) of this section is established as applicable to the combustion source;
(iii) Averaging time associated with the allowable emissions rate under paragraph (a)(1) of this section.
(iv) The annualization factor for the combustion source, based on the type of combustion source and the associated averaging time of the allowable emissions rate of the combustion source, as set forth in the Table 2 of this section:
(2)
(ii) For combustion sources that commenced operation after January 1, 1985, the calendar year for the allowable SO
(iii) For combustion sources meeting the requirements of § 74.20(c), the calendar year for calculating the allowable SO
(b)
The designated representative shall submit the following data:
(a) Current allowable SO
(b) Citations of statute, regulation, and any other authority under which the allowable emissions rate under paragraph (a) of this section is established as applicable to the combustion source;
(c) Averaging time associated with the allowable emissions rate under paragraph (a) of this section.
The designated representative shall submit the following data:
(a) Current promulgated SO
(b) Citations of statute, regulation and any other authority under which the emissions limit under paragraph (a) of this section is established as applicable to the combustion source;
(c) Averaging time associated with the emissions limit under paragraph (a) of this section.
(d) Effective date of the emissions limit under paragraph (a) of this section.
(a) The Administrator will calculate the annual allowance allocation for a combustion source based on the data, corrected as necessary, under § 74.20 through § 74.25 as follows:
(1) For combustion sources for which the current promulgated SO
(2) For combustion sources for which the current promulgated SO
(i) The number of allowances for each year ending prior to the effective date of the promulgated SO
(ii) The number of allowances for the year that includes the effective date of the promulgated SO
(a)
(2) If an opt-in source provided annual data under § 74.20, the opt-in source's opt-in permit must become effective on January 1.
(b)
(1) For combustion sources that commenced operations before January 1, 1985,
(2) For combustion sources that commenced operations after January 1, 1985,
(3) Under paragraphs (b) (1) and (2) of this section,
(i) “Remaining calendar quarters” shall be the calendar quarters in the first year for which the opt-in permit will be effective.
(ii) Fuel consumption for remaining calendar quarters =
(a)
(b)
(a)
(b)
(2) Authorized account representatives may not offer for sale in the advance auctions under § 73.70 of this chapter allowances allocated to opt-in sources.
The Administrator will not record a transfer of opt-in allowances allocated to opt-in sources from a future year subaccount into any other future year subaccount in the Allowance Tracking System.
(a)
(b)
(1) Identification of the opt-in source;
(2) An opt-in utilization report in accordance with § 74.44 for combustion sources and § 74.45 for process sources;
(3) A thermal energy compliance report in accordance with § 74.47 for combustion sources and § 74.48 for process sources, if applicable;
(4) Shutdown or reconstruction information in accordance with § 74.46, if applicable;
(5) A statement that the opt-in source has not become an affected unit under § 72.6 of this chapter;
(6) At the designated representative's option, the total number of allowances to be deducted for the year, using the formula in § 74.49, and the serial numbers of the allowances that are to be deducted; and
(7) At the designated representative's option, for opt-in sources that share a common stack and whose emissions of sulfur dioxide are not monitored separately or apportioned in accordance with part 75 of this chapter, the percentage of the total number of allowances under paragraph (b)(6) of this section for all such affected units that is to be deducted from each affected unit's compliance subaccount; and
(8) The compliance certification under paragraph (c) of this section.
(c)
(1) Whether the opt-in source was operated in compliance with applicable Acid Rain emissions limitations, including whether the opt-in source held allowances, as of the allowance transfer deadline, in its compliance subaccount (after accounting for any allowance deductions or other adjustments under § 73.34(c) of this chapter) not less than the opt-in source's total sulfur dioxide emissions during the calendar year covered by the annual report;
(2) Whether the monitoring plan that governs the opt-in source has been maintained to reflect the actual operation and monitoring of the opt-in source and contains all information necessary to attribute monitored emissions to the opt-in source;
(3) Whether all the emissions from the opt-in source or group of affected units (including the opt-in source) using a common stack were monitored or accounted for through the missing data procedures and reported in the quarterly monitoring reports in accordance with part 75 of this chapter;
(4) Whether the facts that form the basis for certification of each monitor at the opt-in source or group of affected units (including the opt-in source) using a common stack or of an opt-in source's qualifications for using an Acid Rain Program excepted monitoring method or approved alternative monitoring method, if any, have changed;
(5) If a change is required to be reported under paragraph (c)(4) of this section, specify the nature of the change, the reason for the change, when the change occurred, and how the unit's compliance status was determined subsequent to the change, including what method was used to determine emissions when a change mandated the need for monitoring recertification; and
(6) When applicable, whether the opt-in source was operating in compliance with its thermal energy plan as provided in § 74.47 for combustion sources and § 74.48 for process sources.
(a)
(A) “Actual heat input” shall be the actual annual heat input (in mmBtu) of the opt-in source for the calendar year determined in accordance with appendix F of part 75 of this chapter.
(B) “Reduction from improved efficiency” shall be the sum of the following four elements: Reduction from
(C) “Reduction from demand side measures that improve the efficiency of electricity consumption” shall be a good faith estimate of the expected kilowatt hour savings during the calendar year for such measures and the corresponding reduction in heat input (in mmBtu) resulting from those measures. The demand side measures shall be implemented at the opt-in source, in the residence or facility to which the opt-in source delivers electricity for consumption or in the residence or facility of a customer to whom the opt-in source's utility system sells electricity. The verified amount of such reduction shall be submitted in accordance with paragraph (c)(2) of this section.
(D) “Reduction from demand side measures that improve the efficiency of steam consumption” shall be a good faith estimate of the expected steam savings (in mmBtu) from such measures during the calendar year and the corresponding reduction in heat input (in mmBtu) at the opt-in source as a result of those measures. The demand side measures shall be implemented at the opt-in source or in the facility to which the opt-in source delivers steam for consumption. The verified amount of such reduction shall be submitted in accordance with paragraph (c)(2) of this section.
(E) “Reduction from improvements in heat rate” shall be a good faith estimate of the expected reduction in heat rate during the calendar year and the corresponding reduction in heat input (in mmBtu) at the opt-in source as a result of all improved unit efficiency measures at the opt-in source and may include supply-side measures listed in appendix A, section 2.1 of part 73 of this chapter. The verified amount of such reduction shall be submitted in accordance with paragraph (c)(2) of this section.
(F) “Reduction from improvement in the efficiency of steam production at the opt-in source” shall be a good faith estimate of the expected improvement in the efficiency of steam production at the opt-in source during the calendar year and the corresponding reduction in heat input (in mmBtu) at the opt-in source as a result of all improved steam production efficiency measures. In order to claim improvements in the efficiency of steam production, the designated representative of the opt-in source must demonstrate to the satisfaction of the Administrator that the heat rate of the opt-in source has not increased. The verified amount of such reduction shall be submitted in accordance with paragraph (c)(2) of this section.
(G) Notwithstanding paragraph (a)(1)(i)(B) of this section, where two or more opt-in sources, or two or more opt-in sources and Phase I units, include in their annual compliance certification reports their good faith estimate of kilowatt hour savings or steam savings from the same specific measures:
(
(
(ii) For an opt-in source whose opt-in permit becomes effective on a date other than January 1, annual utilization for the first year shall be calculated as follows:
(2)
(i) For the first two calendar years after the effective date of an opt-in permit taking effect on January 1, average utilization will be calculated as follows:
(A) Average utilization for the first year = annual utilization
(B) Average utilization for the second year
(ii) For the first three calendar years after the effective date of the opt-in permit taking effect on a date other than January 1, average utilization will be calculated as follows:
(A) Average utilization for the first year after opt-in = annual -utilization
(B) Average utilization for the second year after opt-in
(C) Average utilization for the third year after opt-in
(iii) Except as provided in paragraphs (a)(2)(i) and (a)(2)(ii) of this section, average utilization shall be the sum of annual utilization for the calendar year and the revised annual utilization, submitted under paragraph (c)(2)(i)(B) of this section and adjusted by the Administrator under paragraph (c)(2)(iii) of this section, for the two immediately preceding calendar years divided by 3.
(b)
(2)
(i) Allowances deducted for reduced utilization =
(ii) The allowances deducted shall have the same or an earlier compliance use date as those allocated under subpart C of this part for the calendar year for which the opt-in source has reduced utilization.
(c)
(i) The name, authorized account representative identification number, and telephone number of the designated representative of the opt-in source;
(ii) The opt-in source's account identification number in the Allowance Tracking System;
(iii) The opt-in source's annual utilization for the calendar year, as defined under paragraph (a)(1) of this section, and the revised annual utilization, submitted under paragraph (c)(2)(i)(B) of this section and adjusted under paragraph (c)(2)(iii) of this section, for the two immediately preceding calendar years;
(iv) The opt-in source's average utilization for the calendar year, as defined under paragraph (a)(2) of this section;
(v) The difference between the opt-in source's average utilization and its baseline;
(vi) The number of allowances that shall be deducted, if any, using the formula in paragraph (b)(2)(i) of this section and the supporting calculations;
(2)
(A)
(B)
(C)
(D)
(E)
(ii)
(B) Notwithstanding paragraph (c)(2)(i)(A) of this section, where two or more opt-in sources, or two or more opt-in sources and Phase I units include in the confirmation report under paragraph (c)(2) of this section or § 72.91(b) of this chapter the verified kilowatt hour savings or steam savings defined under paragraph (c)(2)(i)(A) of this section, for the calendar year, from the same specific measures:
(
(
(iii)
(B)
(C)
(D)
(E)
(
(
(
(
(
(
(
(F) If the opt-in source is governed by an approved thermal energy plan under § 74.47 and if the opt-in source must submit a confirmation report as specified under paragraph (c)(2) of this section, the adjusted amount of allowances that should remain in the opt-in source's compliance subaccount shall be calculated as follows:
(a)
(2) When an opt-in source has undergone a modification that qualifies as a reconstruction as defined in § 60.15 of this chapter, the designated representative shall notify the Administrator of the date of completion of the reconstruction, within 30 days of such completion.
(3) When an opt-in source becomes an affected unit under § 72.6 of this chapter, the designated representative shall notify the Administrator of such change in the opt-in source's affected status within 30 days of such change.
(b)
(i) When an opt-in source has permanently shutdown. The Administrator shall deduct allowances equal in number to and with the same or earlier compliance use date as those allocated to the opt-in source under § 74.40 for the calendar year in which the shut down occurs and for all future years following the year in which the shut down occurs; or
(ii) When an opt-in source has undergone a modification that qualifies as a reconstruction as defined in § 60.15 of this chapter. The Administrator shall deduct allowances equal in number to and with the same or earlier compliance use date as those allocated to the opt-in source under § 74.40 for the calendar year in which the reconstruction is completed and all future years following the year in which the reconstruction is completed; or
(iii) When an opt-in source becomes an affected unit under § 72.6 of this chapter. The Administrator shall deduct allowances equal in number to and with the same or earlier compliance use date as those allocated to the opt-in source under § 74.40 for the calendar year in which the opt-in source becomes affected under § 72.6 of this chapter and all future years following the calendar year in which the opt-in source becomes affected under § 72.6; or
(iv) When an opt-in source does not renew its opt-in permit. The Administrator shall deduct allowances equal in number to and with the same or earlier compliance use date as those allocated to the opt-in source under § 74.40 for the calendar year in which the opt-in source's opt-in permit expires and all future years following the year in which the opt-in source's opt-in permit expires.
(2) After the allowance deductions under paragraph (b)(1) of this section are made, the Administrator will close the opt-in source's unit account in the Allowance Tracking System. If any allowances remain in the opt-in source's unit account after allowance deductions are made under paragraph (b)(1) of this section, and any deductions made under part 77 of this chapter, the Administrator will establish a general account for the opt-in source, and transfer any remaining allowances into this general account. The designated representative for the opt-in source shall become the authorized account representative for the general account.
(a)
(2)
(3)
(i) The calendar year and quarter that the thermal energy plan takes effect, which shall be the first year and quarter the replacement unit(s) will replace thermal energy of the opt-in source;
(ii) The name, authorized account representative identification number, and telephone number of the designated representative of the opt-in source;
(iii) The name, authorized account representative identification number, and telephone number of the designated representative of each replacement unit;
(iv) The opt-in source's account identification number in the Allowance Tracking System;
(v) Each replacement unit's account identification number in the Allowance Tracking System (ATS);
(vi) The type of fuel used by each replacement unit;
(vii) The allowable SO
(viii) The estimated annual amount of total thermal energy to be reduced at the opt-in source, including all energy flows (steam, gas, or hot water) used for any process or in any heating or cooling application, and, for a plan starting April 1, July 1, or October 1, such estimated amount of total thermal energy to be reduced starting April 1, July 1, or October 1 respectively and ending on December 31;
(ix) The estimated amount of total thermal energy at each replacement unit for the calendar year prior to the year for which the plan is to take effect, including all energy flows (steam, gas, or hot water) used for any process or in any heating or cooling application, and, for a plan starting April 1, July 1, or October 1, such estimated amount of total thermal energy for the portion of such calendar year starting April 1, July 1, or October 1 respectively;
(x) The estimated annual amount of total thermal energy at each replacement unit after replacing thermal energy at the opt-in source, including all energy flows (steam, gas, or hot water) used for any process or in any heating or cooling application, and, for a plan starting April 1, July 1, or October 1, such estimated amount of total thermal energy at each replacement unit after replacing thermal energy at the opt-in source starting April 1, July 1, or October 1 respectively and ending December 31;
(xi) The estimated annual amount of thermal energy at each replacement unit, including all energy flows (steam, gas, or hot water) used for any process or in any heating or cooling application, replacing thermal energy at the opt-in source, and, for a plan starting April 1, July 1, or October 1, such estimated amount of thermal energy replacing thermal energy at the opt-in source starting April 1, July 1, or October 1 respectively and ending December 31;
(xii) The estimated annual total fuel input at each replacement unit after replacing thermal energy at the opt-in source and, for a plan starting April 1, July 1, or October 1, such estimated total fuel input after replacing thermal energy at the opt-in source starting April 1, July 1, or October 1 respectively and ending December 31;
(xiii) The number of allowances calculated under paragraph (b) of this section that the opt-in source will transfer to each replacement unit represented in the thermal energy plan.
(xiv) The estimated number of allowances to be deducted for reduced utilization under § 74.44;
(xv) Certification that each replacement unit has entered into a legally binding steam sales agreement to provide the thermal energy, as calculated under paragraph (a)(3)(xi) of this section, that it is replacing for the opt-in source. The designated representative of each replacement unit shall maintain and make available to the Administrator, at the Administrator's request, copies of documents demonstrating that the replacement unit is replacing the thermal energy at the opt-in source.
(4)
(5)
(A) The designated representative of the opt-in source shall include in the plan a request for an exemption from the requirements of part 75 in accordance with § 75.67 of this chapter and shall submit the following statement: “I certify that the opt-in source (“is” or “will be”, as applicable) permanently retired on the date specified in this plan and will not emit any sulfur dioxide or nitrogen oxides after such date.”
(B) The opt-in source shall not emit any sulfur dioxide or nitrogen oxides after the date specified in the plan.
(ii) Notwithstanding the monitoring exemption discussed in paragraph (a)(5)(i) of this section, the designated representative for the opt-in source shall submit the annual compliance certification report provided under paragraph (d) of this section.
(6)
(7)
(ii) In order to revise an opt-in permit to add an approved thermal energy plan or to change an approved thermal energy plan, the designated representative of the opt-in source shall submit a plan or a revised plan under paragraph (a)(4) of this section and meet the requirements for permit revisions under § 72.80 and either § 72.81 or § 72.82 of this chapter.
(8)
(ii)
(iii) If the requirements of paragraph (a)(8)(ii) of this section are met and upon revision of the opt-in permit of the opt-in source and the Acid Rain
(9)
(b)
(2)
(3)
(c)
(d)
(ii) The designated representative of an opt-in source must submit a thermal energy compliance report for the calendar year as part of the annual compliance certification report, which must include the following elements in a format prescribed by the Administrator:
(A) The name, authorized account representative identification number, and telephone number of the designated representative of the opt-in source;
(B) The name, authorized account representative identification number, and telephone number of the designated representative of each replacement unit;
(C) The opt-in source's account identification number in the Allowance Tracking System (ATS);
(D) The account identification number in the Allowance Tracking System (ATS) for each replacement unit;
(E) The actual amount of total thermal energy reduced at the opt-in source during the calendar year, including all energy flows (steam, gas, or hot water) used for any process or in any heating or cooling application;
(F) The actual amount of thermal energy at each replacement unit, including all energy flows (steam, gas, or hot water) used for any process or in any heating or cooling application, replacing the thermal energy at the opt-in source;
(G) The actual amount of total thermal energy at each replacement unit after replacing thermal energy at the opt-in source, including all energy flows (steam, gas, or hot water) used for any process or in any heating or cooling application;
(H) Actual total fuel input at each replacement unit as determined in accordance with part 75 of this chapter;
(I) Calculations of allowance adjustments to be performed by the Administrator in accordance with paragraph (d)(2) of this section.
(2)
(A) The number of allowances transferable by the opt-in source to each replacement unit, calculated in paragraph (b) of this section using the actual, rather than estimated, thermal energy at the replacement unit replacing thermal energy at the opt-in source.
(B) The number of allowances deducted from the Allowance Tracking System account of the opt-in source, calculated under § 74.44(b)(2).
(ii) If the opt-in source includes in the opt-in utilization report under § 74.44 estimates for reductions in heat input, then the Administrator will adjust the number of allowances in the Allowance Tracking System accounts for the opt-in source and for each replacement unit to reflect any differences between the estimated values submitted in the opt-in utilization report and the actual values submitted in the confirmation report pursuant to § 74.44(c)(2).
(3)
(a)
(1)(i) Except as provided in paragraph (a)(1)(ii) of this section, “Tons emitted” shall be the total tons of sulfur dioxide emitted by the opt-in source during the calendar year, as reported in accordance with subpart F of this part for combustion sources or subpart G of this part for process sources.
(ii) If the effective date of the opt-in source's permit took effect on a date other than January 1, “Tons emitted” for the first calendar year shall be the total tons of sulfur dioxide emitted by the opt-in source during the calendar quarters for which the opt-in source's opt-in permit is effective, as reported in accordance with subpart F of this part for combustion sources or subpart G of this part for process sources.
(2) “Allowances deducted for reduced utilization” shall be the total number of allowances deducted for reduced utilization as calculated in accordance with § 74.44 for combustion sources or § 74.45 for process sources.
(b) [Reserved]
(a)(1)
(i) When the opt-in source has permanently shut down; or
(ii) When the opt-in source has been reconstructed; or
(iii) When the opt-in source becomes an affected unit under § 72.6 of this chapter; or
(iv) When the opt-in source fails to renew its opt-in permit.
(2) An opt-in allowance may not be deducted under paragraph (a)(1) of this section from any Allowance Tracking System Account other than the account of the opt-in source allocated such allowance:
(i) After the Administrator has completed the process of recordation as set forth in § 73.34(a) of this chapter following the deduction of allowances from the opt-in source's compliance subaccount for the year for which such allowance may first be used; or
(ii) If the opt-in source includes in the annual compliance certification report estimates of any reduction in heat input resulting from improved efficiency under § 74.44(a)(1)(i), after the Administrator has completed action on the confirmation report concerning such estimated reduction pursuant to § 74.44(c)(2)(iii)(E)(
(b)
(c)
(1) The serial numbers of all allowances deducted from the account,
(2) The reason for deducting the allowances, and
(3) The date of deduction of the allowances.
(d)
(a)
(b)
(a)
(b) [Reserved]
42 U.S.C. 7601 and 7651K, and 7651K note.
(a)
(b)
(2) Statistical estimation procedures for missing data are included in appendix C to this part. Optional protocols for estimating SO
(a) Except as provided in paragraphs (b) and (c) of this section, the provisions of this part apply to each affected unit subject to Acid Rain emission limitations or reduction requirements for SO
(b) The provisions of this part do not apply to:
(1) A new unit for which a written exemption has been issued under § 72.7 of this chapter (any new unit that serves one or more generators with total nameplate capacity of 25 MWe or less and burns only fuels with a sulfur content of 0.05 percent or less by weight may apply to the Administrator for an exemption); or
(2) Any unit not subject to the requirements of the Acid Rain Program due to operation of any paragraph of § 72.6(b) of this chapter; or
(3) An affected unit for which a written exemption has been issued under § 72.8 of this chapter and an exception granted under § 75.67 of this part.
(c) The provisions of this part apply to sources subject to a State or federal NO
The provisions of part 72, including the following, shall apply to this part:
(a) § 72.2(Definitions);
(b) § 72.3(Measurements, Abbreviations, and Acronyms);
(c) § 72.4(Federal Authority);
(d) § 72.5(State Authority);
(e) § 72.6(Applicability);
(f) § 72.7(New Unit Exemption);
(g) § 72.8(Retired Units Exemption);
(h) § 72.9(Standard Requirements);
(i) § 72.10(Availability of Information); and
(j) § 72.11(Computation of Time).
(a) The provisions of this part apply to each existing Phase I and Phase II unit on February 10, 1993. For substitution or compensating units that are so designated under the Acid Rain permit which governs that unit and contains the approved substitution or reduced utilization plan, pursuant to § 72.41 or § 72.43 of this chapter, the provisions of this part become applicable upon the issuance date of the Acid Rain permit. For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter, the provisions of this part become applicable upon the submission of an opt-in permit application in accordance with § 74.14 of this chapter. The provisions of this part for the monitoring, recording, and reporting of NO
(1) For a unit listed in table 1 of § 73.10(a) of this chapter, November 15, 1993.
(2) For a substitution or a compensating unit that is designated under an approved substitution plan or reduced utilization plan pursuant to § 72.41 or § 72.43 of this chapter, or for a unit that is designated an early election unit
(i) January 1, 1995; or
(ii) 90 days after the issuance date of the Acid Rain permit (or date of approval of permit revision) that governs the unit and contains the approved substitution plan, reduced utilization plan, or NO
(3) For either a Phase II unit, other than a gas-fired unit or an oil-fired unit, or a substitution or compensating unit that is not a substitution or compensating unit under paragraph (a)(2) of this section: January 1, 1995.
(4) For a gas-fired Phase II unit or an oil-fired Phase II unit, January 1, 1995, except that installation and certification tests for continuous emission monitoring systems for NO
(i) For an oil-fired Phase II unit or a gas-fired Phase II unit located in an ozone nonattainment area or the ozone transport region, not later than July 1, 1995; or
(ii) For an oil-fired Phase II unit or a gas-fired Phase II unit not located in an ozone nonattainment area or the ozone transport region, not later than January 1, 1996.
(5) For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter, the expiration date of a combustion source's opt-in permit under § 74.14(e) of this chapter.
(b) In accordance with § 75.20, the owner or operator of each new affected unit shall ensure that all monitoring systems required under this part for monitoring of SO
(1) January 1, 1995, except that for a gas-fired unit or oil-fired unit located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NO
(2) Not later than 90 days after the date the unit commences commercial operation, notice of which date shall be provided under subpart G of this part.
(c) In accordance with § 75.20, the owner or operator of any unit affected under any paragraph of § 72.6(a)(3) (ii) through (vii) of this chapter shall ensure that all monitoring systems required under this part for monitoring of SO
(1) January 1, 1995, except that for a gas-fired unit or oil-fired unit located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NO
(2) Not later than 90 days after the date the unit becomes subject to the requirements of the Acid Rain Program, notice of which date shall be provided under subpart G of this part.
(d) In accordance with § 75.20, the owner or operator of an existing unit that is shutdown and is not yet operating by the applicable dates listed in paragraph (a) of this section, or an existing unit which has been placed in long-term cold storage after having previously reported emissions data in accordance with this part, shall ensure that all monitoring systems required under this part for monitoring of SO
(1) The maximum potential concentration of SO
(2) Reference methods under § 75.22(b); or
(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.
(e) In accordance with § 75.20, if the owner or operator of an existing unit completes construction of a new stack, flue, or flue gas desulfurization system after the applicable deadline in paragraph (a) of this section, then the owner or operator shall ensure that all monitoring systems required under this part for monitoring SO
(1) The appropriate value for substitution of missing data upon recertification pursuant to § 75.20(b)(3); or
(2) Reference methods under § 75.22(b) of this part; or
(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.
(f) In accordance with § 75.20, the owner or operator of a gas-fired or oil-fired peaking unit, if planning to use appendix E of this part, shall ensure that the required certification tests for excepted monitoring systems under appendix E are completed for backup fuel as defined in § 72.2 of this chapter by no later than the later of: 30 unit operating days after the date that the unit first combusted that backup fuel after the certification testing of the primary fuel; or The deadline in paragraph (a) of this section. The owner or operator shall determine and report NO
(1) The maximum potential NO
(2) Reference methods under § 75.22(b) of this part; or
(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.
(g) The provisions of this paragraph shall apply unless an owner or operator is exempt from certifying a fuel flowmeter for use during combustion of emergency fuel under section 2.1.4.3 of appendix D to this part, in which circumstance the provisions of section 2.1.4.3 of appendix D shall apply.In accordance with § 75.20, whenever the owner or operator of a gas-fired or oil-fired unit uses an excepted monitoring system under appendix D or E of this part and combusts emergency fuel as defined in § 72.2 of this chapter, then the owner or operator shall ensure that a fuel flowmeter measuring emergency fuel is installed and the required certification tests for excepted monitoring systems are completed by no later than 30 unit operating days after the first date after January 1, 1995 that the unit combusts emergency fuel. For all unit operating hours that the unit combusts emergency fuel after January
(1) The maximum potential fuel flow rate, as described in appendix D of this part, and the maximum sulfur content of the fuel, as described in section 2.1.1.1 of appendix A of this part;
(2) Reference methods under § 75.22(b) of this part; or
(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.
(h) In accordance with § 75.20, the owner or operator of a unit with a qualifying Phase I technology shall ensure that all certification tests for the inlet and outlet SO
(i) In accordance with § 75.20, the owner or operator of each affected unit at which SO
(1) April 1, 2000, for a unit that is existing and has commenced commercial operation by January 2, 2000; or
(2) For a new affected unit which has not commenced commercial operation by January 2, 2000, no later than 90 days after the date the unit commences commercial operation; or
(3) For an existing unit that is shutdown and is not yet operating by April 1, 2000, no later than the earlier of 45 unit operating days or 180 calendar days after the date that the unit recommences commercial operation.
(a) A violation of any applicable regulation in this part by the owners or operators or the designated representative of an affected source or an affected unit is a violation of the Act.
(b) No owner or operator of an affected unit shall operate the unit without complying with the requirements of §§ 75.2 through 75.75 and appendices A through G to this part.
(c) No owner or operator of an affected unit shall use any alternative monitoring system, alternative reference method, or any other alternative for the required continuous emission monitoring system without having obtained the Administrator's prior written approval in accordance with §§ 75.23, 75.48 and 75.66.
(d) No owner or operator of an affected unit shall operate the unit so as to discharge, or allow to be discharged, emissions of SO
(e) No owner or operator of an affected unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording SO
(f) No owner or operator of an affected unit shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, the continuous opacity monitoring system, or any other approved emission monitoring system under this part, except under any one of the following circumstances:
(1) During the period that the unit is covered by an approved retired unit exemption under § 72.8 of this chapter that is in effect; or
(2) The owner or operator is monitoring emissions from the unit with another certified monitoring system or an excepted methodology approved by the Administrator for use at that unit that provides emissions data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(3) The designated representative submits notification of the date of recertification testing of a replacement monitoring system in accordance with §§ 75.20 and 75.61, and the owner or operator recertifies thereafter a replacement monitoring system in accordance with § 75.20.
The materials listed in this section are incorporated by reference in the corresponding sections noted. These incorporations by reference were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they existed on the date of approval, and a notice of any change in these materials will be published in the
(a) The following materials are available for purchase from the following addresses: American Society for Testing and Material (ASTM), 1916 Race Street, Philadelphia, Pennsylvania 19103; and the University Microfilms International 300 North Zeeb Road, Ann Arbor, Michigan 48106.
(1) ASTM D129-91, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), for appendices A and D of this part.
(2) ASTM D240-87 (Reapproved 1991), Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, for appendices A, D and F of this part.
(3) ASTM D287-82 (Reapproved 1987), Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), for appendix D of this part.
(4) ASTM D388-92, Standard Classification of Coals by Rank, incorporation by reference for appendix F of this part.
(5) ASTM D941-88, Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Lipkin Bicapillary Pycnometer, for appendix D of this part.
(6) ASTM D1072-90, Standard Test Method for Total Sulfur in Fuel Gases, for appendix D of this part.
(7) ASTM D1217-91, Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Bingham Pycnometer, for appendix D of this part.
(8) ASTM D1250-80 (Reapproved 1990), Standard Guide for Petroleum Measurement Tables, for appendix D of this part.
(9) ASTM D1298-85 (Reapproved 1990), Standard Practice for Density, Relative Density (Specific Gravity) or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, for appendix D of this part.
(10) ASTM D1480-91, Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer, for appendix D of this part.
(11) ASTM D1481-91, Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Lipkin Bicapillary Pycnometer, for appendix D of this part.
(12) ASTM D1552-90, Standard Test Method for Sulfur in Petroleum Products (High Temperature Method), for appendices A and D of the part.
(13) ASTM D1826-88, Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, for appendices D and F to this part.
(14) ASTM D1945-91, Standard Test Method for Analysis of Natural Gas by Gas Chromatography, for appendices F and G of this part.
(15) ASTM D1946-90, Standard Practice for Analysis of Reformed Gas by
(16) ASTM D1989-92, Standard Test Method for Gross Calorific Value of Coal and Coke by Microprocessor Controlled Isoperibol Calorimeters, for appendix F of this part.
(17) ASTM D2013-86, Standard Method of Preparing Coal Samples for Analysis, for § 75.15 and appendix F of this part.
(18) ASTM D2015-91, Standard Test Method for Gross Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter, for § 75.15 and appendices A, D and F of this part.
(19) ASTM D2234-89, Standard Test Methods for Collection of a Gross Sample of Coal, for § 75.15 and appendix F of this part.
(20) ASTM D2382-88, Standard Test Method for Heat of Combustion of Hydrocarbon Fuels by Bomb Calorimeter (High-Precision Method), for appendices D and F of this part.
(21) ASTM D2502-87, Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils from Viscosity Measurements, for appendix G of this part.
(22) ASTM D2503-82 (Reapproved 1987), Standard Test Method for Molecular Weight (Relative Molecular Mass) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, for appendix G of this part.
(23) ASTM D2622-92, Standard Test Method for Sulfur in Petroleum Products by X-Ray Spectrometry, for appendices A and D of this part.
(24) ASTM D3174-89, Standard Test Method for Ash in the Analysis Sample of Coal and Coke From Coal, for appendix G of this part.
(25) ASTM D3176-89, Standard Practice for Ultimate Analysis of Coal and Coke, for appendices A and F of this part.
(26) ASTM D3177-89, Standard Test Methods for Total Sulfur in the Analysis Sample of Coal and Coke, for § 75.15 and appendix A of this part.
(27) ASTM D3178-89, Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke, for appendix G of this part.
(28) ASTM D3238-90, Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, for appendix G of this part.
(29) ASTM D3246-81 (Reapproved 1987), Standard Test Method for Sulfur in Petroleum Gas By Oxidative Microcoulometry, for appendix D of this part.
(30) ASTM D3286-91a, Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter, for appendix F of this part.
(31) ASTM D3588-91, Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density (Specific Gravity) of Gaseous Fuels, for appendices D and F to this part.
(32) ASTM D4052-91, Standard Test Method for Density and Relative Density of Liquids by Digital Density Meter, for appendix D of this part.
(33) ASTM D4057-88, Standard Practice for Manual Sampling of Petroleum and Petroleum Products, for appendix D of this part.
(34) ASTM D4177-82 (Reapproved 1990), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, for appendix D of this part.
(35) ASTM D4239-85, Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion Methods, for § 75.15 and appendix A of this part.
(36) ASTM D4294-90, Standard Test Method for Sulfur in Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectroscopy, for appendices A and D of this part.
(37) ASTM D4468-85 (Reapproved 1989), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, for appendix D of this part.
(38) ASTM D4891-89, Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, for appendices D and F to this part.
(39) ASTM D5291-92, Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, for appendices F and G to this part.
(40) ASTM D5373-93, “Standard Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
(41) ASTM D5504-94, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, for appendix D of this part.
(b) The following materials are available for purchase from the American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 2350, Fairfield, NJ 07007-2350.
(1) ASME MFC-3M-1989 with September 1990 Errata, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, for appendix D of this part.
(2) ASME MFC-4M-1986 (Reaffirmed 1990), Measurement of Gas Flow by Turbine Meters, for appendix D of this part.
(3) ASME-MFC-5M-1985, Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, for appendix D of this part.
(4) ASME MFC-6M-1987 with June 1987 Errata, Measurement of Fluid Flow in Pipes Using Vortex Flow Meters, for appendix D of this part.
(5) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles, for appendix D of this part.
(6) ASME MFC-9M-1988 with December 1989 Errata, Measurement of Liquid Flow in Closed Conduits by Weighing Method, for appendix D of this part.
(c) The following materials are available for purchase from the American National Standards Institute (ANSI), 11 W. 42nd Street, New York NY 10036: ISO 8316: 1987(E) Measurement of Liquid Flow in Closed Conduits-Method by Collection of the Liquid in a Volumetric Tank, for appendices D and E of this part.
(d) The following materials are available for purchase from the following address: Gas Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74145:
(1) GPA Standard 2172-86, Calculation of Gross Heating Value, Relative Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis, for appendices D, E, and F of this part.
(2) GPA Standard 2261-90, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, for appendices D, F, and G of this part.
(e) The following materials are available for purchase from the following address: American Gas Association, 1515 Wilson Boulevard, Arlington VA 22209:
(1) American Gas Association Report No. 3: Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines (October 1990 Edition), Part 2: Specification and Installation Requirements (February 1991 Edition) and Part 3: Natural Gas Applications (August 1992 Edition), for appendices D and E of this part.
(2) American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (Second Revision, April, 1996), for appendix D to this part.
(f) The following materials are available for purchase from the following address: American Petroleum Institute, Publications Department, 1220 L Street NW, Washington, DC 20005-4070.
(1) American Petroleum Institute (API) Petroleum Measurement Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, December 1994; Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992 (reaffirmed January 1997); Section 2, Standard Practice for Gauging Petroleum and Petroleum Products in Tank Cars, September 1995; Section 3, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June 1996; Section 4, Standard Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995; and Section 5, Standard Practice for Level Measurement of Light Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging, March 1997; for § 75.19.
(2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed August 1987, October 1992), for § 75.19.
(3) American Petroleum Institute (API) Section 2, “Conventional Pipe Provers,” Section 3, “Small Volume Provers,” and Section 5, “Master-Meter Provers,” from Chapter 4 of the Manual of Petroleum Measurement Standards, October 1988 (Reaffirmed 1993), for appendix D to this part.
(a)
(1) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a SO
(2) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a NO
(3) The owner or operator shall determine CO
(i) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a CO
(ii) The owner or operator shall determine CO
(iii) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a flow monitoring system and a CO
(4) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements in this part, a continuous opacity monitoring system with the automated data acquisition and handling system for measuring and recording the opacity of emissions (in percent opacity) discharged to the atmosphere, except as provided in §§ 75.14 and 75.18.
(b)
(c)
(d)
(1) The owner or operator shall ensure that each continuous emission monitoring system and component thereof is capable of completing a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-min interval. The owner or operator shall reduce all SO
(2) The owner or operator shall ensure that each continuous opacity monitoring system is capable of completing a minimum of one cycle of sampling and analyzing for each successive 10-sec period and one cycle of data recording for each successive 6-min period. The owner or operator shall reduce all opacity data to 6-min averages calculated in accordance with the provisions of part 51, appendix M of this chapter, except where the applicable State implementation plan or operating permit requires a different averaging period, in which case the State requirement shall satisfy this Acid Rain Program requirement.
(3) Failure of an SO
(e)
(f)
(a)
(b)
(1) Report the appropriate fuel-specific default moisture value for each unit operating hour, selected from among the following: 3.0%, for anthracite coal; 6.0% for bituminous coal; 8.0% for sub-bituminous coal; 11.0% for lignite coal; 13.0% for wood; or
(2) Install, operate, maintain, and quality assure a continuous moisture monitoring system for measuring and recording the moisture content of the flue gases, in order to correct the measured hourly volumetric flow rates for moisture when calculating SO
(c)
(1) The designated representative shall petition the Administrator for an alternative method for monitoring volumetric flow in accordance with § 75.66; or
(2) The owner or operator shall construct a new stack or modify existing ductwork to accommodate the installation of a flow monitor, and the designated representative shall petition the Administrator for an extension of the required certification date given in § 75.4 and approval of an interim alternative flow monitoring methodology in accordance with § 75.66. The Administrator may grant existing Phase I affected units an extension to January 1, 1995, and existing Phase II affected units an extension to January 1, 1996 for the submission of the certification application for the purpose of constructing a new stack or making substantial modifications to ductwork for installation of a flow monitor; or
(3) The owner or operator shall install a flow monitor in any existing location in the stack or ducts serving the affected unit at which the monitor can achieve the performance specifications of this part.
(d)
(1) By meeting the general operating requirements in § 75.10 for an SO
(2) By providing other information satisfactory to the Administrator using the applicable procedures specified in appendix D to this part for estimating hourly SO
(3) By using the low mass emissions excepted methodology in § 75.19(c) for estimating hourly SO
(e)
(1) If the gaseous fuel meets the definition of “pipeline natural gas” or “natural gas” in § 72.2 of this chapter, the owner or operator may, in lieu of operating and recording data from the SO
(2) The owner or operator may, in lieu of operating and recording data from the SO
(3) The owner or operator may determine SO
(i) When conducting the daily calibration error tests of the SO
(ii) EPA recommends that the calibration response of the SO
(iii) Any hourly average SO
(iv) In accordance with the requirements of section 2.1.1.2 of appendix A to this part, for units that sometimes burn gaseous fuel that is very low sulfur fuel (as defined in § 72.2 of this chapter) and at other times burn higher sulfur fuel(s) such as coal or oil, a second low-scale SO
(f)
(a)
(b)
(c)
(d)
(1) Meet the general operating requirements in § 75.10 for a NO
(2) Provide information satisfactory to the Administrator using the procedure specified in appendix E of this part for estimating hourly NO
(e)
(1) Meet the general operating requirements in § 75.10 for a NO
(2) Meet the requirements specified in paragraph (d)(2) of this section for using the excepted monitoring procedures in appendix E to this part, if applicable; or
(3) Use the low mass emissions excepted methodology in § 75.19(c) for estimating hourly NO
(f)
(a)
(b)
(c)
(d)
(1) Meet the general operating requirements in § 75.10 for a CO
(2) Meet the requirements specified in paragraph (b) or (c) of this section for use of the methods in appendix G or F to this part, respectively; or
(3) Use the low mass emissions excepted methodology in § 75.19(c) for estimating hourly CO
(a)
(b)
(c)
(d)
(a)
(1)
(2)
(3)
(i) Both inlet and outlet SO
(ii) The SO
(iii) The SO
(b)
(1) Calculate the average annual SO
(2) The owner or operator shall include all periods when fuel is being combusted in determining total unit operating hours for the purpose of calculating the average SO
(3) The owner or operator shall use only quality-assured SO
(4) Compliance with the 90-percent SO
(a)
(1)
(i) Install, certify, operate, and maintain an SO
(ii) Install, certify, operate, and maintain an SO
(A) Combine emissions for the affected units for recordkeeping and compliance purposes; or
(B) Provide information satisfactory to the Administrator on methods for apportioning SO
(2)
(i) Install, certify, operate, and maintain an SO
(ii) Install, certify, operate, and maintain an SO
(A) Designate any Phase II unit(s) as a substitution or compensating unit(s) in accordance with part 72 of this chapter and any nonaffected unit(s) as opt-in units in accordance with part 74 of this chapter and combine emissions for recordkeeping and compliance purposes; or
(B) Install, certify, operate, and maintain an SO
(C) Install, certify, operate, and maintain an SO
(D) Record the combined emissions from all units as the combined SO
(E) Provide information satisfactory to the Administrator on methods for apportioning SO
(3)
(b)
(1)
(i) Install, certify, operate, and maintain an SO
(ii) Install, certify, operate, and maintain an SO
(A) Combine emissions for the affected units for recordkeeping and compliance purposes; or
(B) Provide information satisfactory to the Administrator on methods for apportioning SO
(2)
(i) Install, certify, operate, and maintain an SO
(ii) Install, certify, operate, and maintain an SO
(A) Designate the nonaffected units as opt-in units in accordance with part 74 of this chapter and combine emissions for recordkeeping and compliance purposes; or
(B) Install, certify, operate, and maintain an SO
(C) Record the combined emissions from all units as the combined SO
(D) Petition through the designated representative and provide information satisfactory to the Administrator on methods for apportioning SO
(c)
(1) Install, certify, operate, and maintain an SO
(2) Monitor SO
(3) Where a Federal, State, or local regulation or permit prohibits operation of the bypass stack or duct or limits operation of the bypass stack or duct to emergency situations resulting from the malfunction of a flue gas desulfurization system record the following values for each hour during which emissions pass through the bypass stack or duct: the maximum potential concentration for SO
(d)
(1) Install, certify, operate, and maintain an SO
(2) Install, certify, operate, and maintain an SO
(e)
(1) The owner or operator of an affected unit using a common stack, bypass stack, or multiple stack with a diluent monitor and a flow monitor on each stack may choose to install monitors to determine the heat input for the affected unit, wherever flow and diluent monitor measurements are used to determine the heat input, using the procedures specified in paragraphs (a) through (d) of this section, except that the term “heat input” shall apply rather than “SO
(2) In the event that an owner or operator of a unit with a bypass stack does not install and certify a diluent monitor and flow monitoring system in a bypass stack, the owner or operator shall determine total heat input to the unit for each unit operating hour during which the bypass stack is used according to the missing data provisions for heat input under § 75.36 or the procedures for calculating heat input from fuel sampling and analysis in section 5.5 of appendix F of this part.
(3) The owner or operator of an affected unit with a diluent monitor and a flow monitor installed on a common stack to determine heat input at the common stack may choose to apportion the heat input from the common stack to each affected unit utilizing the common stack by using either of the following two methods, provided that all of the units utilizing the common stack are combusting fuel with the same F-factor found in section 3 of appendix F of this part. The heat input may be apportioned either by using the ratio of load (in MWe) for each individual unit to the total load for all units utilizing the common stack or by using the ratio of steam flow (in 1000 lb/hr) for each individual unit to the total steam flow for all units utilizing the common stack. If using either of these apportionment methods, the owner or operator shall apportion according to section 5.6 of appendix F to this part.
(4) Notwithstanding paragraph (e)(1) of this section, any affected unit that is using the procedures in this part to meet the monitoring and reporting requirements of a State or federal NO
Notwithstanding the provisions of paragraphs (a), (b), and (c) of this section, the owner or operator of an affected unit that is using the procedures in this part to meet the monitoring and reporting requirements of a State or federal NO
(a)
(1) Install, certify, operate, and maintain a NO
(2) Install, certify, operate, and maintain a NO
(i) When each of the affected units has a NO
(A) Each unit will comply with the most stringent NO
(B) Each unit will comply with the applicable NO
(C) Each unit's compliance with the applicable NO
(ii) When none of the affected units has a NO
(iii) When at least one of the affected units has a NO
(A) Install, certify, operate, and maintain NO
(B) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NO
(b)
(1) Install, certify, operate, and maintain a NO
(2) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NO
(c)
(1) Install, certify, operate, and maintain a NO
(2) Install, certify, operate, and maintain a NO
(a)
(1) Where another regulation requires the installation of a continuous opacity monitoring system upon each affected unit, the owner or operator shall install, certify, operate, and maintain a continuous opacity monitoring system meeting Performance Specification 1 in appendix B to part 60 of this chapter (referred to hereafter as a “certified continuous opacity monitoring system”) upon each unit.
(2) Where another regulation does not require the installation of a continuous opacity monitoring system upon each affected unit, and where the affected source is not subject to any existing Federal, State, or local opacity regulations, the owner or operator shall install, certify, operate, and maintain a certified continuous opacity monitoring system upon each common stack for the combined effluent.
(b)
(1) An applicable Federal, State, or local opacity regulation or permit exempts the unit from a requirement to install a continuous opacity monitoring system in the bypass stack; or
(2) A continuous opacity monitoring system is already installed and certified at the inlet of the add-on emissions controls.
(3) The owner or operator monitors opacity using method 9 of appendix A of part 60 of this chapter whenever emissions pass through the bypass stack. Method 9 shall be used in accordance with the applicable State regulations.
(a)
(i) A low mass emissions unit is an affected unit that is gas-fired, or oil-
(A) An initial demonstration is provided, in accordance with paragraph (a)(2) of this section, which shows that the unit emits no more than 25 tons of SO
(B) An annual demonstration is provided thereafter, using one of the allowable methodologies in paragraph (c) of this section, showing that the low mass emission unit continues to emit no more than 25 tons of SO
(ii) Any qualifying unit must start using the low mass emissions excepted methodology in the first hour in which the unit operates in a calendar year. Notwithstanding, the earliest date for which a unit that meets the eligibility requirements of this section may begin to use this methodology is January 1, 2000.
(2) A unit may initially qualify as a low mass emissions unit only under the following circumstances:
(i) If the designated representative submits a certification application to use the low mass emissions excepted methodology and the Administrator certifies the use of such methodology. The certification application must contain:
(A) Actual SO
(B) Calculated SO
(ii) When the three full years of actual, historical SO
(b)
(2) If any low mass emission unit fails to provide the required annual demonstration under paragraph (b)(1) of this section, such that the calculated cumulative year-to-date emissions for the unit exceed 25 tons of SO
(i) The low mass emission unit shall be disqualified from using the low mass emissions excepted methodology as of the end of the second calendar quarter following such quarter in which either the 25 ton limit for SO
(ii) The owner or operator of the low mass emission unit shall have two calendar quarters from the end of the quarter in which the unit exceeded the 25 ton limit for SO
(3) If a low mass emission unit that initially qualifies to use the low mass emissions excepted methodology under this section changes fuels, such that a fuel other than those allowed for use in the low mass emissions methodology (e.g. natural gas or fuel oil) is combusted in the unit, the unit shall be disqualified from using the low mass emissions excepted methodology as of the first hour that the new fuel is combusted in the unit. The owner or operator shall install, certify, and report SO
(4) If a unit commencing operation after January 1, 1997 initially qualifies to use the low mass emissions excepted methodology under this section and the owner or operator wants to use a low mass emissions methodology for the unit, he or she must:
(i) Keep the records specified in paragraph (c)(2) of this section, beginning with the date and hour of commencement of commercial operation, for a unit subject to an Acid Rain emission limitation, and beginning with the date and hour of the commencement of operation, for a unit subject to a NO
(ii) Use these records to determine the cumulative heat input and SO
(iii) Determine the cumulative SO
(5) A low mass emission unit that has been disqualified from using the low mass emissions excepted methodology may subsequently qualify again to use the low mass emissions methodology under paragraph (a)(2) of this section, provided that if such unit qualified under paragraph (a)(2)(ii) of this section, the unit may subsequently qualify again only if the unit meets the requirements of paragraph (a)(2)(i) of this section.
(c)
(ii) Use either the appropriate NO
(iii) Use Table 3 of this section to determine the appropriate CO
(iv) In lieu of using the default NO
(A) Except as otherwise provided in paragraphs (c)(1)(iv)(F) and (G) of this paragraph, determine a fuel-and-unit-specific NO
(
(
(B) Representative appendix E testing may be done on low mass emission units in a group of identical units. All of the units in a group of identical units must combust the same fuel type but do not have to share a common fuel supply.
(
(
(
(
(
(
(
(C) Based on the results of the appendix E testing, determine the fuel-and-unit-specific NO
(
(
(
(
(
(
(
(
(
(
(
(
(D) For each low mass emission unit, each unit in a group of units sharing a common fuel supply, or identical units for which the provisions of paragraph (c)(1)(iv) of this section are used to account for NO
(E) Each low mass emission unit, each low mass emission unit in a group of units combusting a common fuel, or each low mass emission unit in a group of identical units for which a fuel-and-unit-specific NO
(F) Low mass emission units may use the results of appendix E testing, if such test results are available from a test conducted no more than five years prior to the time of initial certification, to determine the appropriate fuel-and-unit-specific NO
(G) Low mass emission units for which at least 3 years of NO
(H) For low mass emission units with NO
(
(
(2)
(i) For each low mass emission unit, the owner or operator shall keep hourly records which indicate whether or not the unit operated during each clock hour of each calendar year. The owner or operator may report partial
(ii) For each low mass emissions unit, the owner or operator shall keep hourly records indicating the type(s) of fuel(s) combusted in the unit during each hour of unit operation.
(iii) For each low mass emission unit using the long term fuel flow methodology under paragraph (c)(3)(ii) of this section to determine hourly heat input, the owner or operator shall keep hourly records of unit output (in megawatts or thousands of pounds of steam), for the purpose of apportioning heat input to the individual unit operating hours.
(iv) For each low mass emission unit with NO
(3)
(i)
(B) The quarterly heat input, HI
(c)(3)(i)(A) of this section (mmBtu).
(C) The year-to-date cumulative heat input (mmBtu) shall be the sum of the quarterly heat input values for all of the calendar quarters in the year to date.
(ii)
(A) This option may be used for a group of low mass emission units only if:
(
(
(
(B) For each fuel used during the quarter, the volume in standard cubic feet (for gas) or gallons (for oil) may be determined using any of the following methods;
(
(
(
(C) For each fuel combusted during a quarter, the gross calorific value of the fuel shall be determined by either:
(
(
(D) For each type of fuel oil combusted during the quarter, the specific gravity of the oil shall be determined either by:
(
(
(E) The quarterly heat input from each type of fuel combusted during the quarter by a low mass emission unit or group of low mass emission units sharing a common fuel supply shall be determined using Equation LM-2 for oil and LM-3 for natural gas.
(F) The quarterly heat input (mmBtu) for all fuels for the quarter, HI
(G) The year-to-date cumulative heat input (mmBtu) for all fuels shall be the sum of all quarterly total heat input (HI
(H) For each low mass emission unit, each low mass emission unit of an identical group of units, or each low mass emission unit in a group of units sharing a common fuel supply, the owner or operator shall determine the quarterly unit output in megawatts or pounds of
(I) For a low mass emission unit that is not included in a group of low mass emission units sharing a common fuel supply, apportion the total heat input for the quarter, HI
(J) For each low mass emission unit that is included in a group of units sharing a common fuel supply, apportion the total heat input for the quarter, HI
(4)
(i)
(B) The quarterly SO
(C) The year-to-date cumulative SO
(ii)
(B) The quarterly NO
(C) The year-to-date cumulative NO
(iii)
(B) The quarterly CO
(C) The year-to-date cumulative CO
(d) Each unit that qualifies under this section to use the low mass emissions methodology must follow the recordkeeping and reporting requirements pertaining to low mass emissions units in subparts F and G of this part.
(e) The quality control and quality assurance requirements in § 75.21 are not applicable to a low mass emissions
(1) For low mass emission units or groups of units which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section and which use fuel billing records to determine fuel usage, the owner or operator shall keep, at the facility, for three years, the records of the fuel billing statements used for long term fuel flow determinations.
(2) For low mass emission units or groups of units which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section and which use American Petroleum Institute (API) standard, American Petroleum Institute (API) Petroleum Measurement Standards, Chapter 3, Tank Gauging: Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, December 1994; Section 1B, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, April 1992 (reaffirmed January 1997); Section 2, Standard Practice for Gauging Petroleum and Petroleum Products in Tank Cars, September 1995; Section 3, Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank Gauging, June 1996; Section 4, Standard Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank Gauging, April 1995; and Section 5, Standard Practice for Level Measurement of Light Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging, March 1997, Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed August 1987, October 1992) (incorporated by reference under § 75.6), to determine fuel usage, the owner or operator shall keep, at the facility, a copy of the standard used and shall keep records, for three years, of all measurements obtained for each quarter using the methodology.
(3) For low mass emission units or groups of units which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section and which use a certified fuel flow meter to determine fuel usage, the owner or operator shall comply with the quality control quality assurance requirements for a fuel flow meter under section 2.1.6 of appendix D of this part.
(4) For each low mass emission unit for which fuel-and-unit-specific NO
(5) For each low mass emission unit for which fuel-and-unit-specific NO
(a)
(1)
(2)
(3)
(4)
(i)
(ii)
(iii)
(iv)
(5)
(i) Until such time, date, and hour as the continuous emission monitoring system or component thereof can be adjusted, repaired, or replaced and certification tests successfully completed, the owner or operator shall substitute the following values, as applicable, for each hour of unit operation during the period of invalid data specified in paragraph (a)(4)(iii) of this section or in § 75.21: the maximum potential concentration of SO
(ii) The designated representative shall submit a notification of certification retest dates as specified in § 75.61(a)(1)(ii) and a new certification application according to the procedures in paragraph (a)(2) of this section; and
(iii) The owner or operator shall repeat all certification tests or other requirements that were failed by the continuous emission or opacity monitoring system, as indicated in the Administrator's notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(b)
(1)
(2)
(3)
(i) In the period extending from the hour of the replacement, modification or change made to a monitoring system that triggers the need to perform recertification test(s) of the CEMS to the hour of successful completion of a probationary calibration error test (according to paragraph (b)(3)(ii) of this section) following the replacement, modification, or change to the CEMS, the owner or operator shall either substitute for missing data, according to the standard missing data procedures in §§ 75.33 through 75.37, or report emission data using a reference method or another monitoring system that has been certified or approved for use under this part. Notwithstanding this requirement, if the replacement, modification, or change requiring recertification of the CEMS is such that the historical data stream is no longer representative (e.g., where the SO
(ii) Once the modification or change to the CEMS has been completed and all of the associated repairs, component replacements, adjustments, linearization, and reprogramming of the CEMS have been completed, a probationary calibration error test is required to establish the beginning point of the recertification test period. In this instance, the first successful calibration error test of the monitoring system following completion of all necessary repairs, component replacements, adjustments, linearization and reprogramming shall be the probationary calibration error test. The probationary calibration error test must be passed before any of the required recertification tests are commenced.
(iii) Beginning with the hour of commencement of a recertification test period, emission data recorded by the CEMS are considered to be conditionally valid, contingent upon the results of the subsequent recertification tests.
(iv) Each required recertification test shall be completed no later than the following number of unit operating hours (or unit operating days) after the probationary calibration error test that initiates the test period:
(A) For a linearity check and/or cycle time test, 168 consecutive unit operating hours, as defined in § 72.2 of this chapter or, for CEMS installed on common stacks or bypass stacks, 168 consecutive stack operating hours, as defined in § 72.2 of this chapter;
(B) For a RATA (whether normal-load or multiple-load), 720 consecutive unit operating hours, as defined in § 72.2 of this chapter or, for CEMS installed on common stacks or bypass stacks, 720 consecutive stack operating hours, as defined in § 72.2 of this chapter; and
(C) For a 7-day calibration error test, 21 consecutive unit operating days, as defined in § 72.2 of this chapter.
(v) All recertification tests shall be performed hands-off. No adjustments to the calibration of the CEMS, other than the routine calibration adjustments following daily calibration error tests as described in section 2.1.3 of appendix B to this part, are permitted during the recertification test period. Routine daily calibration error tests shall be performed throughout the recertification test period, in accordance with section 2.1.1 of appendix B to this part. The additional calibration error test requirements in section 2.1.3 of appendix B to this part shall also apply during the recertification test period.
(vi) If all of the required recertification tests and required daily calibration error tests are successfully completed in succession with no failures, and if each recertification test is completed within the time period specified in paragraph (b)(3)(iv)(A), (B), or (C) of this section, then all of the conditionally valid emission data recorded by the CEMS shall be considered quality assured, from the hour of commencement of the recertification test period until the hour of completion of the required test(s).
(vii) If a required recertification test is failed or aborted due to a problem with the CEMS, or if a daily calibration error test is failed during a recertification test period, data validation shall be done as follows:
(A) If any required recertification test is failed, it shall be repeated. If any recertification test other than a 7-day calibration error test is failed or aborted due to a problem with the CEMS, the original recertification test period is ended, and a new recertification test period must be commenced
(B) If a linearity check, RATA, or cycle time test is failed or aborted due to a problem with the CEMS, all conditionally valid emission data recorded by the CEMS are invalidated, from the hour of commencement of the recertification test period to the hour in which the test is failed or aborted, except for the case in which a multiple-load flow RATA is passed at one or more load levels, failed at a subsequent load level, and the problem that caused the RATA failure is corrected without re-linearizing the instrument. In that case, data invalidation shall be prospective, from the hour of failure of the RATA until the commencement of the new recertification test period. Data from the CEMS remain invalid until the hour in which a new recertification test period is commenced, following corrective action, and a probationary calibration error test is passed, at which time the conditionally valid status of emission data from the CEMS begins again;
(C) If a 7-day calibration error test is failed within the recertification test period, previously-recorded conditionally valid emission data from the CEMS are not invalidated. The conditionally valid data status is unaffected, unless the calibration error on the day of the failed 7-day calibration error test exceeds twice the performance specification in section 3 of appendix A to this part, as described in paragraph (b)(3)(vii)(D) of this section; and
(D) If a daily calibration error test is failed during a recertification test period (i.e., the results of the test exceed twice the performance specification in section 3 of appendix A to this part), the CEMS is out-of-control as of the hour in which the calibration error test is failed. Emission data from the CEMS shall be invalidated prospectively from the hour of the failed calibration error test until the hour of completion of a subsequent successful calibration error test following corrective action, at which time the conditionally valid status of data from the monitoring system resumes. Failure to perform a required daily calibration error test during a recertification test period shall also cause data from the CEMS to be invalidated prospectively, from the hour in which the calibration error test was due until the hour of completion of a subsequent successful calibration error test. Whenever a calibration error test is failed or missed during a recertification test period, no further recertification tests shall be performed until the required subsequent calibration error test has been passed, re-establishing the conditionally valid status of data from the monitoring system. If a calibration error test failure occurs while a linearity check or RATA is still in progress, the linearity check or RATA must be re-started.
(E) Trial gas injections and trial RATA runs are permissible during the recertification test period, prior to commencing a linearity check or RATA, for the purpose of optimizing the performance of the CEMS. The results of such gas injections and trial runs shall not affect the status of previously-recorded conditionally valid
(
(
(
(
(F) If the results of any trial gas injection(s) or RATA run(s) are outside the limits in paragraphs (b)(3)(vii)(E)(
(viii) If any required recertification test is not completed within its allotted time period, data validation shall be done as follows. For a late linearity test, RATA, or cycle time test that is passed on the first attempt, data from the monitoring system shall be invalidated from the hour of expiration of the recertification test period until the hour of completion of the late test. For a late 7-day calibration error test, whether or not it is passed on the first attempt, data from the monitoring system shall also be invalidated from the hour of expiration of the recertification test period until the hour of completion of the late test. For a late linearity test, RATA, or cycle time test that is failed on the first attempt or aborted on the first attempt due to a problem with the monitor, all conditionally valid data from the monitoring system shall be considered invalid back to the hour of the first probationary calibration error test which initiated the recertification test period. Data from the monitoring system shall remain invalid until the hour of successful completion of the late recertification test and any additional recertification or diagnostic tests that are required as a result of changes made to the monitoring system to correct problems that caused failure of the late recertification test.
(ix) If any required recertification test of a monitoring system has not been completed by the end of a calendar quarter and if data contained in the quarterly report are conditionally valid pending the results of test(s) to be completed in a subsequent quarter, the owner or operator shall indicate this by means of a suitable conditionally valid data flag in the electronic quarterly report for that quarter. The owner or operator shall resubmit the report for that quarter if the required recertification test is subsequently failed. In the resubmitted report, the owner or operator shall use the appropriate missing data routine in § 75.31 or § 75.33 to replace with substitute data each hour of conditionally valid data that was invalidated by the failed recertification test. Alternatively, if any required recertification test is not completed by the end of a particular calendar quarter but is completed no later than 30 days after the end of that quarter (i.e., prior to the deadline for submitting the quarterly report under § 75.64), the test data and results may be submitted with the earlier quarterly report even though the test date(s) are from the next calendar quarter. In such instances, if the recertification test(s) are passed in accordance with the provisions of paragraph (b)(3) of this section, conditionally valid data may be reported as quality-assured, in lieu of reporting a conditional data flag. If the recertification test(s) is failed and if conditionally valid data are replaced, as appropriate, with substitute data, then neither the reporting of a conditional data flag nor
(4)
(5)
(c)
(1) For each SO
(i) A 7-day calibration error test, where, for the NO
(ii) A linearity check, where, for the NO
(iii) A relative accuracy test audit. For the NO
(iv) A bias test; and
(v) A cycle time test.
(v) A cycle time/response time test.
(2) For each flow monitor:
(i) A 7-day calibration error test;
(ii) Relative accuracy test audits at three flue gas velocities; and
(iii) A bias test (at normal operating load).
(3) The initial certification test data from an O
(4) For each CO
(i) A 7-day calibration error test, where, for the SO
(ii) A linearity check, where, for the SO
(iii) A relatively accuracy test audit; and
(iv) A cycle-time test.
(5) For each continuous moisture monitoring system consisting of wet- and dry-basis O
(i) A 7-day calibration error test of each O
(ii) A cycle time test of each O
(iii) A linearity test of each O
(iv) A RATA, directly comparing the percent moisture measured by the monitoring system to a reference method.
(6) For each continuous moisture sensor: A RATA, directly comparing the percent moisture measured by the monitor sensor to a reference method.
(7) For a continuous moisture monitoring system consisting of a temperature sensor and a data acquisition and handling system (DAHS) software component programmed with a moisture lookup table:
(i) A demonstration that the correct moisture value for each hour is being taken from the moisture lookup tables and applied to the emission calculations. At a minimum, the demonstration shall be made at three different temperatures covering the normal range of stack temperatures from low to high.
(ii) [Reserved]
(8) The owner or operator shall ensure that initial certification or recertification of a continuous opacity monitor for use under the Acid Rain Program is conducted according to one of the following procedures:
(i) Performance of the tests for initial certification or recertification, according to the requirements of Performance Specification 1 in appendix B to part 60 of this chapter; or
(ii) A continuous opacity monitoring system tested and certified previously under State or other Federal requirements to meet the requirements of Performance Specification 1 shall be deemed certified for the purposes of this part.
(9) For the automated data acquisition and handling system, tests designed to verify:
(i) Proper computation of hourly averages for pollutant concentrations, flow rate, pollutant emission rates, and pollutant mass emissions; and
(ii) Proper computation and application of the missing data substitution procedures in subpart D of this part and the bias adjustment factors in section 7 of appendix A to this part.
(10) The owner or operator shall provide adequate facilities for initial certification or recertification testing that include:
(i) Sampling ports adequate for test methods applicable to such facility, such that:
(A) Volumetric flow rate, pollutant concentration, and pollutant emission rates can be accurately determined by applicable test methods and procedures; and
(B) A stack or duct free of cyclonic flow during performance tests is available, as demonstrated by applicable test methods and procedures.
(ii) Basic facilities (e.g., electricity) for sampling and testing equipment.
(d)
(2)
(i) Except as provided in paragraph (d)(2)(v) of this section, for a regular non-redundant backup CEMS (i.e., a non-redundant backup CEMS that has its own separate probe, sample interface, and analyzer), or a non-redundant backup flow monitor, all of the tests in paragraph (c) of this section are required for initial certification of the system, except for the 7-day calibration error test.
(ii) For a like-kind replacement non-redundant backup analyzer (i.e., a non-redundant backup analyzer that uses the same probe and sample interface as a primary monitoring system), no initial certification of the analyzer is required. A non-redundant backup analyzer, connected to the same probe and interface as a primary CEMS in order to satisfy the dual span requirements of section 2.1.1.4 or 2.1.2.4 of appendix A to this part, shall be treated in the same manner as a like-kind replacement analyzer.
(iii) Each non-redundant backup CEMS or like-kind replacement analyzer shall comply with the daily and quarterly quality assurance and quality control requirements in appendix B to this part for each day and quarter that the non-redundant backup CEMS or like-kind replacement analyzer is used to report data, and shall meet the additional linearity and calibration error test requirements specified in this paragraph. The owner or operator shall ensure that each non-redundant backup CEMS or like-kind replacement analyzer passes a linearity check (for pollutant concentration and diluent gas monitors) or a calibration error test (for flow monitors) prior to each use for recording and reporting emissions. For a primary NO
(iv) When data are reported from a non-redundant backup CEMS or like-kind replacement analyzer, the appropriate bias adjustment factor shall be determined as follows:
(A) For a regular non-redundant backup CEMS, as described in paragraph (d)(2)(i) of this section, apply the bias adjustment factor from the most recent RATA of the non-redundant backup system (even if that RATA was done more than 12 months previously); or
(B) When a like-kind replacement non-redundant backup analyzer is used as a component of a primary CEMS (as described in paragraph (d)(2)(ii) of this section), apply the primary monitoring system bias adjustment factor.
(v) For each parameter monitored (i.e., SO
(vi) For each regular non-redundant backup CEMS, no more than eight successive calendar quarters shall elapse following the quarter in which the last RATA of the CEMS was done at a particular unit or stack, without performing a subsequent RATA. Otherwise, the CEMS may not be used to report data from that unit or stack until the hour of completion of a passing RATA at that location.
(vii) Each regular non-redundant backup CEMS shall be represented in the monitoring plan required under § 75.53 as a separate monitoring system, with unique system and component identification numbers. When like-kind replacement non-redundant backup analyzers are used, the owner or operator shall represent each like-kind replacement analyzer used during a particular calendar quarter in the monitoring plan required under § 75.53 as a component of a primary monitoring system. The owner or operator shall also assign a unique component identification number to each like-kind replacement analyzer and specify the manufacturer, model and serial number of the like-kind replacement analyzer. This information may be added, deleted or updated as necessary, from quarter to quarter. The owner or operator shall also report data from the like-kind replacement analyzer using the system identification number of the primary monitoring system and the assigned component identification number of the like-kind replacement analyzer. For the purposes of the electronic quarterly report required under § 75.64, the owner or operator may manually enter the appropriate component identification number(s) of any like-kind replacement analyzer(s) used for data reporting during the quarter.
(viii) When reporting data from a certified regular non-redundant backup CEMS, use a method of determination (MODC) code of “02.” When reporting data from a like-kind replacement non-redundant backup analyzer, use a MODC of “17” (see Table 4a under § 75.57). For the purposes of the electronic quarterly report required under § 75.64, the owner or operator may manually enter the required MODC of “17” for a like-kind replacement analyzer.
(3)
(e)
(f)
(1) The Administrator will publish each request for initial certification of an alternative monitoring system in the
(2) No alternative monitoring system shall be authorized by the Administrator in a permit issued pursuant to part 72 of this chapter unless approved by the Administrator in accordance with this part.
(g)
(1)
(i) When the optional SO
(ii) For the automated data acquisition and handling system used under either the optional SO
(A) The proper computation of hourly averages for pollutant concentrations, fuel flow rates, emission rates, heat input, and pollutant mass emissions; and
(B) Proper computation and application of the missing data substitution procedures in appendix D or E of this part.
(iii) When the optional NO
(2)
(3)
(4)
(5)
(6)
(7)
(h)
(1)
(2)
(3)
(i) For a unit that commenced operation on or before January 1, 1997, from January 1 of the year following submission of the certification application until the completion of the period for the Administrator's review; or
(ii) For a unit that commenced operation after January 1, 1997, from the date of submission of a certification application for approval to use the low mass emissions excepted methodology under § 75.19 until the completion of the period for the Administrator's review, except that the methodology may be used retrospectively until the date and hour that the unit commenced operation for purposes of demonstrating that the unit qualified to use the methodology under § 75.19(b)(4)(iii).
(4)
(i) The owner or operator shall substitute the following values, as applicable, for each hour of unit operation during the period of invalid data specified in paragraph (a)(4)(iii) of this section or in §§ 75.21(e) (introductory paragraph) and 75.21(e)(1): the maximum potential concentration of SO
(ii) The designated representative shall submit a notification of certification test dates, as specified in § 75.61(a)(1)(ii), and a new certification application according to the procedures in paragraph (a)(2) of this section; and
(iii) The owner or operator shall install and provisionally certify continuous emission monitoring systems or excepted monitoring systems, where applicable, two calendar quarters from the end of the quarter in which the unit no longer qualifies as a low mass emissions unit.
(a)
(1) The owner or operator shall operate, calibrate and maintain each primary and redundant backup continuous emission monitoring system according to the quality assurance and quality control procedures in appendix B of this part.
(2) The owner or operator shall ensure that each non-redundant backup CEMS meets the quality assurance requirements of § 75.20(d) for each day and quarter that the system is used to report data.
(3) The owner or operator shall perform quality assurance upon a reference method backup monitoring system according to the requirements of method 2, 6C, 7E, or 3A in appendix A of part 60 of this chapter (supplemented, as necessary, by guidance from the Administrator), instead of the procedures specified in appendix B of this part.
(4) The owner or operator of a unit with an SO
(5) For a unit with an SO
(6) If the designated representative certifies that a unit with an SO
(7) If the designated representative certifies that a particular unit with an SO
(8) On and after April 1, 2000, the quality assurance provisions of §§ 75.11(e)(3)(i) through 75.11(e)(3)(iv) shall apply to all units with SO
(9) Provided that a unit with an SO
(10) The owner or operator who, in accordance with § 75.11(e)(1), uses a certified flow monitor and a certified diluent monitor and Equation F-23 in appendix F to this part to calculate SO
(b)
(c)
(d)
(e)
(1)
(2)
(a) The owner or operator shall use the following methods included in appendix A to part 60 of this chapter to conduct monitoring system tests for certification or recertification of continuous emission monitoring systems and excepted monitoring systems under appendix E of this part and quality assurance and quality control procedures. Unless otherwise specified in this part, use only codified versions of Methods 3A, 4, 6C and 7E revised as of July 1, 1995 or July 1, 1996 or July 1, 1997.
(1) Methods 1 or 1A are the reference methods for selection of sampling site and sample traverses.
(2) Method 2 or its allowable alternatives, as provided in appendix A to part 60 of this chapter, except for Methods 2B and 2E, are the reference methods for determination of volumetric flow.
(3) Methods 3, 3A, or 3B are the reference methods for the determination of the dry molecular weight O
(4) Method 4 (either the standard procedure described in section 2 of the method or the moisture approximation procedure described in section 3 of the method) shall be used to correct pollutant concentrations from a dry basis to a wet basis (or from a wet basis to a dry basis) and shall be used when relative accuracy test audits of continuous moisture monitoring systems are conducted. For the purpose of determining the stack gas molecular weight, however, the alternative techniques for approximating the stack gas moisture content described in section 1.2 of Method 4 may be used in lieu of the procedures in sections 2 and 3 of the method.
(5) Methods 6, 6A, 6B or 6C, and 7, 7A, 7C, 7D or 7E, as applicable, are the reference methods for determining SO
(6) Method 20 is the reference method for determining NO
(b) The owner or operator may use the following methods in appendix A of part 60 of this chapter as a reference method backup monitoring system to provide quality-assured monitor data:
(1) Method 3A for determining O
(2) Method 6C for determining SO
(3) Method 7E for determining total NO
(4) Method 2, or its allowable alternatives, as provided in appendix A to part 60 of this chapter, except for Methods 2B and 2E, for determining volumetric flow. The sample point(s) for reference methods shall be located according to the provisions of section 6.5.5 of appendix A to this part.
(c)(1) Instrumental EPA Reference Methods 3A, 6C, 7E, and 20 shall be conducted using calibration gases as defined in section 5 of appendix A to this part. Otherwise, performance tests shall be conducted and data reduced in accordance with the test methods and procedures of this part unless the Administrator:
(i) Specifies or approves, in specific cases, the use of a reference method with minor changes in methodology;
(ii) Approves the use of an equivalent method; or
(iii) Approves shorter sampling times and smaller sample volumes when necessitated by process variables or other factors.
(2) Nothing in this paragraph shall be construed to abrogate the Administrator's authority to require testing under Section 114 of the Act.
(a) The designated representative of a unit may petition the Administrator for an alternative to any standard incorporated by reference and prescribed in this part in accordance with § 75.66(c).
(b) [Reserved]
(a) If an out-of-control period occurs to a monitor or continuous emission monitoring system, the owner or operator shall take corrective action and repeat the tests applicable to the “out-of-control parameter” as described in appendix B of this part.
(1) For daily calibration error tests, an out-of-control period occurs when the calibration error of a pollutant concentration monitor exceeds 5.0 percent based upon the span value, the calibration error of a diluent gas monitor exceeds 1.0 percent O
(2) For quarterly linearity checks, an out-of-control period occurs when the error in linearity at any of three gas concentrations (low, mid-range, and high) exceeds the applicable specification in appendix A to this part.
(3) For relative accuracy test audits, an out-of-control period occurs when the relative accuracy exceeds the applicable specification in appendix A to this part.
(b) When a monitor or continuous emission monitoring system is out-of-control, any data recorded by the monitor or monitoring system are not quality-assured and shall not be used in calculating monitor data availabilities pursuant to § 75.32 of this part.
(c) When a monitor or continuous emission monitoring system is out-of-control, the owner or operator shall take one of the following actions until the monitor or monitoring system has successfully met the relevant criteria in appendices A and B of this part as demonstrated by subsequent tests:
(1) Apply the procedures for missing data substitution to emissions from affected unit(s); or
(2) Use a certified backup or certified portable monitor or monitoring system or a reference method for measuring and recording emissions from the affected unit(s); or
(3) Adjust the gas discharge paths from the affected unit(s) with emissions normally observed by the out-of-control monitor or monitoring system so that all exhaust gases are monitored by a certified monitor or monitoring system meeting the requirements of appendices A and B of this part.
(d) When the bias test indicates that an SO
(e) The owner or operator shall determine if a continuous opacity monitoring system is out-of-control and shall take appropriate corrective actions according to the procedures specified for State Implementation Plans,
(a) Except as provided in § 75.34, the owner or operator shall provide substitute data for each affected unit using a continuous emission monitoring system according to the missing data procedures in this subpart whenever the unit combusts any fuel and:
(1) A valid, quality-assured hour of SO
(2) A valid, quality-assured hour of flow data (in scfh) has not been measured and recorded for an affected unit from a certified flow monitor, or by an approved alternative monitoring system under subpart E of this part; or
(3) A valid, quality-assured hour of NO
(4) A valid, quality-assured hour of CO
(5) A valid, quality-assured hour of NO
(6) A valid, quality-assured hour of CO
(b) However, the owner or operator shall have no need to provide substitute data according to the missing data procedures in this subpart if the owner or operator uses SO
(c) When the certified primary monitor is not operating or out-of-control, then data recorded for an affected unit from a certified backup continuous emission monitor or backup reference method monitoring system are used, as if such data were from the certified primary monitor, to calculate monitor
(d) The owner or operator shall comply with the applicable provisions of this paragraph during hours in which a unit with an SO
(1) Whenever a unit with an SO
(2) Whenever a unit with an SO
(3) The owner or operator of a unit with an SO
(4) During all hours in which a unit with an SO
(a) During the first 720 quality-assured monitor operating hours following initial certification (i.e., the date and time at which quality assured data begins to be recorded by the CEMS) of an SO
(b)
(1) Whenever prior quality-assured data exist, the owner or operator shall substitute, by means of the data acquisition and handling system, for each hour of missing data, the average of the hourly SO
(2) Whenever no prior quality assured SO
(c)
(1) Whenever prior quality-assured data exist in the load range corresponding to the operating load at the time the missing data period occurred, the owner or operator shall substitute, by means of the automated data acquisition and handling system, for each hour of missing data, the average hourly flow rate or NO
(2) Whenever no prior quality-assured flow or NO
(3) Whenever no prior quality assured flow rate or NO
(a) Following initial certification (i.e., the date and time at which quality assured data begins to be recorded by the CEMS), upon completion of: the first 720 quality-assured monitor operating hours of an SO
(1) Prior to completion of 8,760 unit operating hours following initial certification, the owner or operator shall, for the purpose of applying the standard missing data procedures of § 75.33, use equation 8 to calculate, hourly, percent monitor data availability.
(2) Upon completion of 8,760 unit operating hours following initial certification (or, for a unit with less than 8,760 unit operating hours three years (26,280 clock hours) after initial certification, upon completion of three years (26,280 clock hours) following initial certification) and thereafter, the owner or operator shall, for the purpose of applying the standard missing data procedures of § 75.33, use equation 9 to calculate, hourly, percent monitor data availability.
(3) The owner or operator shall include all unit operating hours, and all monitor operating hours for which quality-assured data were recorded by a certified primary monitor; a certified redundant or non-redundant backup monitor or a reference method for that unit; or by an approved alternative monitoring system under subpart E of this part when calculating percent monitor data availability using equation 8 or 9. No hours from more than three years (26,280 clock hours) earlier shall be used in equation 9. The owner or operator of a unit with an SO
(b) The monitor data availability need not be calculated during the missing data period. The owner or operator shall record the percent monitor data availability for the last hour of each missing data period as the monitor availability used to implement the missing data substitution procedures.
(a) Following initial certification (i.e., the date and time at which quality assured data begins to be recorded by the CEMS) and upon completion of the first 720 quality-assured monitor operating hours of the SO
(b)
(1) Whenever the monitor data availability is equal to or greater than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for each hour of each missing data period according to the following procedures:
(i) For a missing data period less than or equal to 24 hours, substitute the average of the hourly SO
(ii) For a missing data period greater than 24 hours, substitute the greater of:
(A) The 90th percentile hourly SO
(B) The average of the hourly SO
(2) Whenever the monitor data availability is at least 90.0 percent but less than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for each hour of each missing data period according to the following procedures:
(i) For a missing data period of less than or equal to 8 hours, substitute the average of the hourly SO
(ii) For a missing data period of more than 8 hours, substitute the greater of:
(A) the 95th percentile hourly SO
(B) The average of the hourly SO
(3) Whenever the monitor data availability is at least 80.0 percent but less than 90.0 percent, the owner or operator shall substitute for each missing data period the maximum hourly SO
(4) Whenever the monitor data availability is less than 80.0 percent, the owner or operator shall substitute for each missing data period the maximum potential SO
(c)
(1) Whenever the monitor or continuous emission monitoring system data availability is equal to or greater than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for each hour of each missing data period according to the following procedures:
(i) For a missing data period less than or equal to 24 hours, substitute, as applicable, for each missing hour, the arithmetic average of the flow rates or NO
(ii) For a missing data period greater than 24 hours, substitute, as applicable, for each missing hour, the greater of:
(A) The 90th percentile hourly flow rate or the 90th percentile NO
(B) The average of the recorded hourly flow rates, NO
(2) Whenever the monitor or continuous emission monitoring system data availability is at least 90.0 percent but less than 95.0 percent, the owner or operator shall calculate substitute data by means of the automated data acquisition and handling system for each hour of each missing data period according to the following procedures:
(i) For a missing data period of less than or equal to 8 hours, substitute, as applicable, the arithmetic average hourly flow rate or NO
(ii) For a missing data period greater than 8 hours, substitute, as applicable, for each missing hour, the greater of:
(A) The 95th percentile hourly flow rate or the 95th percentile NO
(B) The average of the hourly flow rates, NO
(3) Whenever the monitor data availability is at least 80.0 percent but less than 90.0 percent, the owner or operator shall, by means of the automated data acquisition and handling system, substitute, as applicable, for each hour of each missing data period, the maximum hourly flow rate or the maximum hourly NO
(4) Whenever the monitor data availability is less than 80.0 percent, the owner or operator shall substitute, as applicable, for each hour of each missing data period, the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part, or the maximum NO
(5) Whenever no prior quality-assured flow rate data, NO
(6) Whenever no prior quality-assured flow rate data, NO
(a) The owner or operator of an affected unit equipped with add-on SO
(1) The owner or operator may use the missing data substitution procedures as specified for all affected units in §§ 75.31 through 75.33 to substitute data for each hour in which the add-on emission controls are operating within the proper parametric ranges specified in the quality assurance/quality control program for the unit, required by section 1 in appendix B of this part. The designated representative shall document in the quality assurance/ quality control program the ranges of the add-on emission control operating
(2) The designated representative may petition the Administrator under § 75.66 to replace the maximum recorded value in the last 720 quality-assured monitor operating hours with a value corresponding to the maximum controlled emission rate (an emission rate recorded when the add-on emission controls were operating) recorded during the last 720 quality-assured monitor operating hours. For such a petition, the designated representative must demonstrate that the following conditions are met: the monitor data availability, calculated in accordance with § 75.32, for the affected unit is below 90.0 percent and parametric data establish that the add-on emission controls were operating properly (i.e., within the range of operating parameters provided in the quality assurance/ quality control program) during the time period under petition.
(3) The designated representative may petition the Administrator under § 75.66 for approval of site-specific parametric monitoring procedure(s) for calculating substitute data for missing SO
(b) For an affected unit equipped with add-on SO
(1) Where the monitor data availability is 90.0 percent or more for an outlet SO
(2) Where the monitor data availability for an outlet SO
(c) For an affected unit with NO
(1) Where monitor data availability for a NO
(2) Where monitor data availability for a NO
(d) The owner or operator shall keep records of information as described in subpart F of this part to verify the proper operation of the SO
(a) On and after April 1, 2000, the owner or operator of a unit with a CO
(b) During the first 720 quality assured monitor operating hours following initial certification (i.e., the date and time at which quality assured data begins to be recorded by the CEMS), of the CO
(c) Upon completion of the first 720 quality-assured monitor operating hours following initial certification of the CO
(1) Whenever a quality-assured monitoring operating hour of CO
(2) Whenever no quality-assured CO
(3) Whenever no quality-assured CO
(d) Upon completion of 720 quality assured monitor operating hours using the initial missing data procedures of § 75.31(b), the owner or operator shall provide substitute data for CO
(a) When hourly heat input is determined using a flow monitoring system and a diluent gas (O
(b) During the first 720 quality assured monitor operating hours following initial certification (i.e., the date and time at which quality assured data begins to be recorded by the CEMS), or (for a previously certified CO
(c) Upon completion of the first 720 quality-assured monitor operating hours following initial certification of the CO
(1) Whenever a quality-assured monitor operating hour of CO
(2) Whenever a quality-assured monitor operating hour of CO
(3) Whenever no quality-assured CO
(d) Upon completion of 720 quality-assured monitor operating hours using the initial missing data procedures of § 75.31(b), the owner or operator shall provide substitute data for CO
(a) On and after April 1, 2000, the owner or operator of a unit with a continuous moisture monitoring system shall substitute for missing moisture data using the procedures of this section. Prior to April 1, 2000, the owner or operator may substitute for missing moisture data using the procedures of this section.
(b) Where no prior quality assured moisture data exist, substitute the minimum potential moisture percentage, from section 2.1.5 of appendix A to this part, except when Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to determine NO
(c) During the first 720 quality assured monitor operating hours following initial certification (i.e., the date and time at which quality assured data begins to be recorded by the moisture monitoring system), the owner or operator shall provide substitute data for moisture according to § 75.31(b).
(d) Upon completion of the first 720 quality-assured monitor operating hours following initial certification of the moisture monitoring system, the owner or operator shall provide substitute data for moisture as follows:
(1) Unless Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to determine NO
(2) When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to determine NO
(i) Provided that none of the following equations is used to determine SO
(ii) If any of the following equations is used to determine SO
(a) The owner or operator of an affected unit, or the owner or operator of an affected unit and representing a class of affected units which meet the criteria specified in § 75.47, required to install a continuous emission monitoring system may apply to the Administrator for approval of an alternative monitoring system (or system component) to determine average hourly emission data for SO
(b) The requirements of this subpart shall be met by the alternative monitoring system when compared to a contemporaneously operating, fully certified continuous emission monitoring system or a contemporaneously operating reference method, where the appropriate reference methods are listed in § 75.22.
(a)
(1) Data from the alternative monitoring system and the continuous emission monitoring system shall be collected and paired in a manner that ensures each pair of values applies to hourly average emissions during the same hour.
(2) An alternative monitoring system that directly measures emissions shall have probes or other measuring devices in locations that are in proximity to the continuous emission monitoring system and shall provide data on the same parameters as those measured by the continuous emission monitoring system. Data from the alternative monitoring system shall meet the statistical tests for precision in paragraph (c) of this section and the t-test for bias in appendix A of this part.
(3) An alternative monitoring system that indirectly quantifies emission values by measuring inputs, operating characteristics, or outputs and then applying a regression or another quantitative technique to estimate emissions, shall meet the statistical tests for precision in paragraph (c) of this section and the t-test for bias in appendix A of this part.
(4) For flow monitor alternatives, the alternative monitoring system must provide sample data for each of three different exhaust gas velocities while the unit or units, if more than one unit
(i) A frequently used low operating level, selected within the range between the minimum safe and stable operating level and 50 percent of the maximum operating level,
(ii) A frequently used high operating level, selected within the range between 80 percent of the maximum operating level and the maximum operating level, and
(iii) The normal operating level, or an evenly spaced intermediary level between low and high levels used if the normal operating level is within a specified range (10.0 percent of the maximum operating level), of either paragraphs (a)(4) (i) or (ii) of this section.
(5) For pollutant concentration monitor alternatives, the alternative monitoring system shall provide sample data for the primary fuel supply and for all alternative fuel supplies that have significantly different sulfur content.
(6) For the normal unit operating level and primary fuel supply, paired hourly sample data shall be provided for at least 90.0 percent of the hours during 720 unit operating hours. For each of the remaining two operating levels for flow monitor alternatives, and for each alternative fuel supply for pollutant concentration monitor alternatives, paired hourly sample data shall be provided for at least 24 successive unit operating hours.
(7) The owner or operator shall not use missing data substitution procedures to provide sample data.
(8) If the collected data meet the requirements of the F-test, the correlation test, and the t-test at one or more, but not all, of the operating levels or fuel supplies, the owner or operator may elect to continue collecting the paired data for up to 1,440 additional operating hours and repeat the statistical tests using the data for the entire 30- to 90-day period.
(9) The owner or operator shall provide two separate time series data plots for the data at each operating level or fuel supply described in paragraphs (a)(4) and (a)(5) of this section. Each data plot shall have a horizontal axis that represents the clock hour and calendar date of the readings and shall contain a separate data point for every hour for the duration of the performance evaluation. The data plots shall show the following:
(i) Percentage difference versus time where the vertical axis represents the percentage difference between each paired hourly reading generated by the continuous emission monitoring system (or reference method) and the alternative emission monitoring system as calculated using the following equation:
(ii) Alternative monitoring system readings and continuous emission monitoring system (or reference method) readings versus time where the vertical axis represents hourly pollutant concentrations or volumetric flow, as appropriate, and two different symbols are used to represent the readings from the alternative monitoring system and the continuous emission monitoring system (or reference method), respectively.
(b)
(1)
(i) Apply the log transformation to each measured value of either the certified continuous emissions monitoring system or certified flow monitor, using the following equation:
and to each measured value, e
(ii) Separately test each set of transformed data,
(A) Shapiro-Wilk test;
(B) Histogram of the transformed data; and
(C) Quantile-Quantile plot of the transformed data.
(iii) The transformed data in a data set will be considered normally distributed if all of the following conditions are satisfied:
(A) The Shapiro-Wilk test statistic, W, is greater than or equal to 0.75 or is not statistically significant at
(B) The histogram of the data is unimodal and symmetric.
(C) The Quantile-Quantile plot is a diagonal straight line.
(iv) If both of the transformed data sets,
(v) If the transformed data are used in the statistical tests in paragraph (c) of this section and in appendix A of this part, the owner or operator shall provide the following:
(A) Copy of the original measured values and the corresponding transformed data in printed and electronic format.
(B) Printed copy of the test results and plots described in paragraphs (b)(1) (i) through (iii) of this section.
(2)
(i) Calculate the degree of auto-cor-re-la-tion of the data on their LAG1 values, where the degree of auto-cor-re-la-tion is represented by the Pearson auto-cor-re-la-tion co-ef-fi-ci-ent,
(ii) The data in a data set will be considered autocorrelated if the auto-cor-rela-tion coefficient,
(iii) If the data in a data set satisfy the conditions for auto-cor-rela-tion, specified in paragraph (b)(2)(ii) of this section, the variance of the data,
(iv) The procedures described in paragraphs (b)(2)(i)-(iii) of this section may be separately applied to the following data sets in order to derive distinct auto-cor-rela-tion coefficients and variance inflation factors for each data set:
(A) The set of measured hourly values, e
(B) The set of hourly values, e
(C) The set of hourly differences, e
(v) For any data set, listed in paragraph (b)(2)(iv) of this section, that satisfies the conditions for auto-cor-rela-tion specified in paragraph (b)(2)(ii) of this section, the owner or operator may adjust the variance of that data set, using equation 20 of this section.
(A) The adjusted variance may be used in place of the corresponding original variance, as calculated using equation 23 of this section, in the F-test (Equation 24) of this section.
(B) In place of the standard error of the mean,
(vi) For each data set in which a variance adjustment is used, the owner or operator shall provide the following:
(A) All values in the data set in printed and electronic format.
(B) Values of the auto-cor-rela-tion coefficient, its level of significance, the variance inflation factor, and the unadjusted original and adjusted values found in equations 20 and 22 of this section.
(C) Equation and related statistics of the AR(1) autoregression model of the data set.
(D) Printed documentation of the intermediate calculations used to derive the auto-cor-rela-tion coefficient and the Variance Inflation Factor.
(c)
(1)
(i) Calculate the variance of the certified continuous emission monitoring system or certified flow monitor as applicable, S
(ii) Determine if the variance of the proposed method is significantly different from that of the certified continuous emission monitoring system or certified flow monitor, as applicable, by calculating the F-value using the following equation.
(2)
(i) Plot each of the paired emissions readings as a separate point on a graph where the vertical axis represents the value (pollutant concentration or volumetric flow, as appropriate) generated by the alternative monitoring system and the horizontal axis represents the
(ii) Use the following equation to calculate the coefficient of correlation, r, between the emissions data from the alternative monitoring system and the continuous emission monitoring system using all hourly data for which paired values were available from both monitoring systems.
(iii) If the calculated r-value is less than 0.8, the proposed method is unacceptable.
To demonstrate reliability equal to or better than the continuous emission monitoring system, the owner or operator shall demonstrate that the alternative monitoring system is capable of providing valid 1-hr averages for 95.0 percent or more of unit operating hours over a 1-yr period and that the system meets the applicable requirements of appendix B of this part.
To demonstrate accessibility equal to or better than the continuous emission monitoring system, the owner or operator shall provide reports and onsite records of emission data to demonstrate that the alternative monitoring system provides data meeting the requirements of subparts F and G of this part.
To demonstrate timeliness equal to or better than the continuous emission monitoring system, the owner or operator shall demonstrate that the alternative monitoring system can meet the requirements of subparts F and G of this part; can provide a continuous, quality-assured, permanent record of certified emissions data on an hourly basis; and can issue a record of data for the previous day within 24 hours.
The owner or operator shall either demonstrate that daily tests equivalent to those specified in appendix B of this part can be performed on the alternative monitoring system or demonstrate and document that such tests are unnecessary for providing quality-assured data.
The owner or operator shall demonstrate that all missing data can be accounted for in a manner consistent with the applicable missing data procedures in subpart D of this part.
(a) The owner or operator of an affected unit may represent a class of affected units for the purpose of applying to the Administrator for a class-approved alternative monitoring system.
(b) The owner or operator of an affected unit representing a class of affected units shall provide the following information:
(1) A description of the affected unit and how it appropriately represents the class of affected units;
(2) A description of the class of affected units, including data describing all the affected units which will comprise the class; and
(3) A demonstration that the magnitude of emissions of all units which will comprise the class of affected units are
(c) If the Administrator determines that the emissions from all affected units which will comprise the class of units are
(a) The designated representative shall submit the following information in the application for certification or recertification of an alternative monitoring system.
(1) Source identification information.
(2) A description of the alternative monitoring system.
(3) Data, calculations, and results of the statistical tests, specified in § 75.41(c) of this part, including:
(i) Date and hour.
(ii) Hourly test data for the alternative monitoring system at each required operating level and fuel type. The fuel type, operating level and gross unit load shall be recorded.
(iii) Hourly test data for the continuous emissions monitoring system at each required operating level and fuel type. The fuel type, operating level and gross unit load shall be recorded.
(iv) Arithmetic mean of the alternative monitoring system measurement values, as specified in Equation 25 in § 75.41(c) of this part, of the continuous emission monitoring system values, as specified in Equation 26 in § 75.41(c) of this part, and of their differences.
(v) Standard deviation of the difference, as specified in equation A-8 in appendix A of this part.
(vi) Confidence coefficient, as specified in equation A-9 in appendix A of this part.
(vii) The bias test results as specified in § 7.6.4 in appendix A of this part.
(viii) Variance of the measured values for the alternative monitoring system and of the measured values for the continuous emission monitoring system, as specified in Equation 23 in § 75.41(c) of this part.
(ix) F-statistic, as specified in Equation 24 in § 75.41(c) of this part.
(x) Critical value of F at the 95-percent confidence level with n-1 degrees of freedom.
(xi) Coefficient of correlation, r, as specified in Equation 27 in § 75.41(c) of this part.
(4) Data plots, specified in §§ 75.41(a)(9) and 75.41(c)(2)(i) of this part.
(5) Results of monitor reliability analysis.
(6) Results of monitor accessibility analysis.
(7) Results of monitor timeliness analysis.
(8) A detailed description of the process used to collect data, including location and method of ensuring an accurate assessment of operating hourly conditions on a real-time basis.
(9) A detailed description of the operation, maintenance, and quality assurance procedures for the alternative monitoring system as required in appendix B of this part.
(10) A description of methods used to calculate heat input or diluent gas concentration, if applicable.
(11) Results of tests and measurements (including the results of all reference method field test sheets, charts, laboratory analyses, example calculations, or other data as appropriate) necessary to substantiate that the alternative monitoring system is equivalent in performance to an appropriate, certified operating continuous emission monitoring system.
(b) [Reserved]
(a)
(2) The owner or operator of an affected unit shall prepare and maintain a monitoring plan. Except as provided in paragraphs (d) or (f) of this section (as applicable), a monitoring plan shall contain sufficient information on the continuous emission or opacity monitoring systems, excepted methodology under § 75.19, or excepted monitoring systems under appendix D or E to this part and the use of data derived from these systems to demonstrate that all unit SO
(b) Whenever the owner or operator makes a replacement, modification, or change in the certified CEMS, continuous opacity monitoring system, excepted methodology under § 75.19, excepted monitoring system under appendix D or E to this part, or alternative monitoring system under subpart E of this part, including a change in the automated data acquisition and handling system or in the flue gas handling system, that affects information reported in the monitoring plan (e.g., a change to a serial number for a component of a monitoring system), then the owner or operator shall update the monitoring plan.
(c)
(1) Precertification information, including, as applicable, the identification of the test strategy, protocol for the relative accuracy test audit, other relevant test information, span calculations, and apportionment strategies under §§ 75.10 through 75.18 of this part.
(2)
(i) Short name;
(ii) Classification of unit as one of the following: Phase I (including substitution or compensating units), Phase II, new, or nonaffected;
(iii) Type of boiler (or boilers for a group of units using a common stack);
(iv) Type of fuel(s) fired, by boiler, and if more than one fuel, the fuel classification of the boiler;
(v) Type(s) of emission controls for SO
(vi) Identification of all units using a common stack.
(3)
(4)
(i) Manufacturer model number and serial number;
(ii) Component/system identification code assigned by the utility to each identifiable monitoring component (such as the analyzer and/or probe). The code shall use a six-digit format, unique to each monitoring component, where the first three digits indicate the number of the component and the second three digits indicate the system to which the component belongs;
(iii) Actual or projected installation date (month and year);
(iv) A brief description of the component type or method of operation, such as in situ pollutant concentration monitor or thermal flow monitor;
(v) A brief description of the flow monitor that is sufficiently detailed to allow a determination of whether the applicable interference check design specification meets the requirements specified in appendix A of this part; and
(vi) A designation of the system as a primary, redundant backup, non-redundant backup or reference method backup system, as provided for in § 75.10(e).
(5)
(i) For hardware components, the manufacturer, model number, and actual or projected installation date;
(ii) For software components, identification of the provider and a brief description of features;
(iii) A data flow diagram denoting the complete information handling path from output signals of continuous emission monitoring system components to final reports;
(iv) A copy of the test results verifying the accuracy of the automated data acquisition and handling system (once such results are available).
(6)
(7)
(8)
(9) Inside crosssectional area (ft
(10)
(d)
(1) For each gas-fired unit or oil-fired unit for which the owner or operator uses the optional protocol in appendix D of this part for estimating SO
(i) A description of the fuel flowmeter (and data demonstrating its flow meter accuracy, when available);
(ii) The installation location of each fuel flowmeter;
(iii) The fuel sampling location(s); and
(iv) Procedures used for calibrating each fuel flowmeter.
(2) For each gas-fired peaking unit and oil-fired peaking unit for which the owner or operator uses the optional procedures in appendix E of this part for estimating NO
(i) A protocol containing methods used to perform the baseline or periodic NO
(ii) Unit operating and capacity factor information demonstrating that the unit qualifies as a peaking unit, as defined in § 72.2 of this chapter; and
(iii) Unit operating parameters related to NO
(3) For each gas-fired unit and diesel-fired unit or unit with a wet flue gas pollution control system for which the designated representative claims an opacity monitoring exemption under § 75.14, the designated representative shall include in the monitoring plan information demonstrating that the unit qualifies for the exemption.
(e)
(1)
(A) Short name;
(B) Classification of the unit as one of the following: Phase I (including substitution or compensating units), Phase II, new, or nonaffected;
(C) Type of boiler (or boilers for a group of units using a common stack);
(D) Type of fuel(s) fired by boiler, fuel type start and end dates, primary/secondary fuel indicator, and, if more than one fuel, the fuel classification of the boiler;
(E) Type(s) of emission controls for SO
(F) Maximum hourly heat input capacity;
(G) Date of first commercial operation;
(H) Unit retirement date (if applicable);
(I) Maximum hourly gross load (in MW, rounded to the nearest MW, or steam load in 1000 lb/hr, rounded to the nearest 100 lb/hr);
(J) Identification of all units using a common stack;
(K) Activation date for the stack/pipe;
(L) Retirement date of the stack/pipe (if applicable); and
(M) Indicator of whether the stack is a bypass stack.
(ii) For each unit and parameter required to be monitored, identification of monitoring methodology information, consisting of monitoring methodology, type of fuel associated with the methodology, primary/secondary methodology indicator, missing data approach for the methodology, methodology start date, and methodology end date (if applicable).
(iii) The following information:
(A) Program(s) for which the EDR is submitted;
(B) Unit classification;
(C) Reporting frequency;
(D) Program participation date;
(E) State regulation code (if applicable); and
(F) State or local regulatory agency code.
(iv) Identification and description of each monitoring component (including each monitor and its identifiable components, such as analyzer and/or probe) in the CEMS (e.g., SO
(A) Manufacturer, model number and serial number;
(B) Component/system identification code assigned by the utility to each identifiable monitoring component (such as the analyzer and/or probe). Each code shall use a three-digit format, unique to each monitoring component and unique to each monitoring system;
(C) Designation of the component type and method of sample acquisition or operation, (e.g., in situ pollutant concentration monitor or thermal flow monitor);
(D) Designation of the system as a primary, redundant backup, non-redundant backup, data backup, or reference method backup system, as provided in § 75.10(e);
(E) First and last dates the system reported data;
(F) Status of the monitoring component; and
(G) Parameter monitored.
(v) Identification and description of all major hardware and software components of the automated data acquisition and handling system, including:
(A) Hardware components that perform emission calculations or store data for quarterly reporting purposes (provide the manufacturer and model number); and
(B) Software components (provide the identification of the provider and model/version number).
(vi) Explicit formulas for each measured emission parameter, using component/system identification codes for the primary system used to measure the parameter that links CEMS or excepted monitoring system observations with reported concentrations, mass emissions, or emission rates, according to the conversions listed in appendix D or E to this part. Formulas for backup monitoring systems are required only if different formulas for the same parameter are used for the primary and backup monitoring systems (e.g., if the primary system measures pollutant concentration on a different moisture basis from the backup system). The formulas must contain all constants and factors required to derive mass emissions or emission rates from component/system code observations and an indication of whether the formula is being added, corrected, deleted, or is unchanged. Each emissions formula is identified with a unique three digit code. The owner or operator of a low mass emissions unit for which the owner or operator is using the optional low mass emissions excepted methodology in § 75.19(c) is not required to report such formulas.
(vii) Inside cross-sectional area (ft
(viii) Stack height (ft) above ground level and stack base elevation above sea level.
(ix) Part 75 monitoring location identification, facility identification code as assigned by the Administrator for use under the Acid Rain Program or this part, and the following information, as reported to the Energy Information Administration (EIA): facility
(x) For each parameter monitored: scale, maximum potential concentration (and method of calculation), maximum expected concentration (if applicable) (and method of calculation), maximum potential flow rate (and method of calculation), maximum potential NO
(xi) If the monitoring system or excepted methodology provides for the use of a constant, assumed, or default value for a parameter under specific circumstances, then include the following information for each such value for each parameter:
(A) Identification of the parameter;
(B) Default, maximum, minimum, or constant value, and units of measure for the value;
(C) Purpose of the value;
(D) Indicator of use during controlled/uncontrolled hours;
(E) Type of fuel;
(F) Source of the value;
(G) Value effective date and hour;
(H) Date and hour value is no longer effective (if applicable); and
(I) For units using the excepted methodology under § 75.19, the applicable SO
(xii) For each unit or common stack (except for peaking units) on which hardware CEMS are installed:
(A) The upper and lower boundaries of the range of operation (as defined in section 6.5.2.1 of appendix A to this part), expressed in megawatts or thousands of lb/hr of steam;
(B) The load level(s) designated as normal in section 6.5.2.1 of appendix A to this part, expressed in megawatts or thousands of lb/hr of steam;
(C) The two load levels (i.e., low, mid, or high) identified in section 6.5.2.1 of appendix A to this part as the most frequently used;
(D) The date of the load analysis used to determine the normal load level(s) and the two most frequently-used load levels; and
(E) Activation and deactivation dates, when the normal load level(s) or two most frequently-used load levels change and are updated.
(xiii) For each unit for which the optional fuel flow-to-load test in section 2.1.7 of appendix D to this part is used:
(A) The upper and lower boundaries of the range of operation (as defined in section 6.5.2.1 of appendix A to this part), expressed in megawatts or thousands of lb/hr of steam;
(B) The load level designated as normal, pursuant to section 6.5.2.1 of appendix A to this part, expressed in megawatts or thousands of lb/hr of steam; and
(C) The date of the load analysis used to determine the normal load level.
(2)
(ii) Description of site locations for each monitoring component in the continuous emission or opacity monitoring systems, including schematic diagrams and engineering drawings specified in paragraphs (e)(2)(iv) and (e)(2)(v) of this section and any other documentation that demonstrates each monitor location meets the appropriate siting criteria.
(iii) A data flow diagram denoting the complete information handling path from output signals of CEMS components to final reports.
(iv) For units monitored by a continuous emission or opacity monitoring system, a schematic diagram identifying entire gas handling system from boiler to stack for all affected units, using identification numbers for units,
(v) For units monitored by a continuous emission or opacity monitoring system, stack and duct engineering diagrams showing the dimensions and location of fans, turning vanes, air preheaters, monitor components, probes, reference method sampling ports, and other equipment that affects the monitoring system location, performance, or quality control checks.
(f)
(1) For each gas-fired unit or oil-fired unit for which the owner or operator uses the optional protocol in appendix D to this part for estimating heat input and/or SO
(i)
(A) Parameter monitored;
(B) Type of fuel measured, maximum fuel flow rate, units of measure, and basis of maximum fuel flow rate (i.e., upper range value or unit maximum) for each fuel flowmeter;
(C) Test method used to check the accuracy of each fuel flowmeter;
(D) Submission status of the data;
(E) Monitoring system identification code; and
(F) For gaseous fuels fired by the unit, the method used to verify that the fuel meets the definition in § 72.2 of pipeline natural gas or natural gas, if applicable, and the demonstration methods used for other gaseous fuels, if applicable, to determine the appropriate frequency for sampling for GCV or sulfur content of the fuel.
(ii)
(B) For units using the optional default SO
(C) For units using the 720 hour test under 2.3.6 of Appendix D of this part to determine the required sulfur sampling requirements, report the procedures and results of the test; and
(D) For units using the 720 hour test under 2.3.5 of Appendix D of this part to determine the appropriate fuel GCV sampling frequency, report the procedures used and the results of the test;
(2) For each gas-fired peaking unit and oil-fired peaking unit for which the owner or operator uses the optional procedures in appendix E to this part for estimating NO
(i)
(A) Test date;
(B) Test number;
(C) Operating level;
(D) Segment ID of the NO
(E) NO
(F) Low and high heat input values and corresponding NO
(G) Type of fuel; and
(H) To document the unit qualifies as a peaking unit, current calendar year, capacity factor data as specified in the definition of peaking unit in § 72.2 of this part, and an indication of whether the data are actual or projected data.
(ii)
(B) Unit operating parameters related to NO
(3) For each gas-fired unit and diesel-fired unit or unit with a wet flue gas pollution control system for which the designated representative claims an opacity monitoring exemption under § 75.14, the designated representative shall include in the hardcopy monitoring plan the information specified under § 75.14(b), (c), or (d), demonstrating that the unit qualifies for the exemption.
(4) For each monitoring system recertification, maintenance, or other event, the designated representative shall include the following additional information in electronic format in the monitoring plan:
(i) Component/system identification code;
(ii) Event code or code for required test;
(iii) Event begin date and hour;
(iv) Conditionally valid data period begin date and hour (if applicable);
(v) Date and hour that last test is successfully completed; and
(vi) Indicator of whether conditionally valid data were reported at the end of the quarter.
(5) For each unit using the low mass emission excepted methodology under § 75.19 the designated representative shall include the following additional information in the monitoring plan:
(i)
(ii)
(B) For units which use the long term fuel flow methodology under § 75.19(c)(3), the designated representative must provide a diagram of the fuel flow to each affected unit or group of units and describe in detail the procedures used to determine the long term fuel flow for a unit or group of units for each fuel combusted by the unit or group of units;
(C) A statement that the unit burns only natural gas or fuel oil and a list of the fuels that are burned or a statement that the unit is projected to burn only natural gas or fuel oil and a list of the fuels that are projected to be burned;
(D) A statement that the unit meets the applicability requirements in §§ 75.19(a) and (b); and
(E) Any unit historical actual and projected emissions data and calculated emissions data demonstrating that the affected unit qualifies as a low mass emissions unit under §§ 75.19(a) and 75.19(b).
(6) For each gas-fired unit the designated representative shall include in the monitoring plan, in electronic format, the following: current calendar year, fuel usage data as specified in the definition of gas-fired in § 72.2 of this part, and an indication of whether the data are actual or projected data.
(a)
(1) The data and information required in paragraphs (b) through (g) of this section, beginning with the earlier of the date of provisional certification, or the deadline in § 75.4(a), (b) or (c);
(2) The supporting data and information used to calculate values required in paragraphs (b) through (f) of this section, excluding the subhourly data points used to compute hourly averages under § 75.10(d), beginning with the earlier of the date of provisional certification, or the deadline in § 75.4(a), (b) or (c);
(3) The data and information required in § 75.55 of this part for specific situations, as applicable, beginning with the earlier of the date of provisional certification, or the deadline in § 75.4(a), (b) or (c);
(4) The certification test data and information required in § 75.56 for tests required under § 75.20, beginning with the date of the first certification test performed, and the quality assurance and quality control data and information required in § 75.56 for tests and the quality assurance/quality control plan required under § 75.21 and appendix B of this part, beginning with the date of provisional certification;
(5) The current monitoring plan as specified in § 75.53, beginning with the initial submission required by § 75.62; and
(6) The quality control plan as described in appendix B to this part, beginning with the date of provisional certification.
(b)
(1) Date and hour;
(2) Unit operating time (rounded up to nearest 15 minutes);
(3) Total hourly gross unit load (rounded to nearest MWge) (or steam load in lb/hr at stated temperature and pressure, rounded to the nearest 1000 lb/hr, if elected in the monitoring plan);
(4) Operating load range corresponding to total gross load of 1-10, except for units using a common stack or common pipe header, which may use the number of unit load ranges up to 20 for flow, as specified in the monitoring plan; and
(5) Total heat input (mmBtu, rounded to the nearest tenth).
(c)
(1) For SO
(i) Component-system identification code as provided for in § 75.53;
(ii) Date and hour;
(iii) Hourly average SO
(iv) Hourly average SO
(v) Percent monitor data availability (recorded to the nearest tenth of a percent) calculated pursuant to § 75.32; and
(vi) Method of determination for hourly average SO
(2) For flow as measured and reported from each certified primary monitor,
(i) Component/system identification code as provided for in § 75.53;
(ii) Date and hour;
(iii) Hourly average volumetric flow rate (in scfh, rounded to the nearest thousand);
(iv) Hourly average volumetric flow rate (in scfh, rounded to the nearest thousand) adjusted for bias, if bias adjustment factor required as provided for in § 75.24(d);
(v) Hourly average moisture content of flue gases (percent, rounded to the nearest tenth) where SO
(vi) Percent monitor data availability (recorded to the nearest tenth of a percent), calculated pursuant to § 75.32; and
(vii) Method of determination for hourly average flow rate using Codes 1-15 in table 4.
(3) For SO
(i) Date and hour;
(ii) Hourly SO
(iii) Hourly SO
(iv) Identification code for emissions formula used to derive hourly SO
(d)
(1) Component/system identification code as provided for in § 75.53;
(2) Date and hour;
(3) Hourly average NO
(4) Hourly average diluent gas concentration (percent O
(5) Hourly average NO
(6) Hourly average NO
(7) Percent monitoring system data availability, (recorded to the nearest tenth of a percent), calculated pursuant to § 75.32;
(8) Method of determination for hourly average NO
(9) Identification code for emissions formula used to derive hourly average NO
(e)
(1) If the owner or operator chooses to use a CO
(i) Component/system identification code as provided for in § 75.53;
(ii) Date and hour;
(iii) Hourly average CO
(iv) Hourly average volumetric flow rate (scfh, rounded to the nearest thousand scfh);
(v) Hourly CO
(vi) Percent monitor data availability (recorded to the nearest tenth of a percent); calculated pursuant to § 75.32;
(vii) Method of determination for hourly CO
(viii) Identification code for emissions formula used to derive average hourly CO
(2) As an alternative to § 75.54(e)(1), the owner or operator may use the procedures in § 75.13 and in appendix G to this part, and shall record daily the following information for CO
(i) Date;
(ii) Daily combustion-formed CO
(iii) For coal-fired units, flag indicating whether optional procedure to adjust combustion-formed CO
(iv) For a unit with a wet flue gas desulfurization system or other controls generating CO
(v) For a unit with a wet flue gas desulfurization system or other controls generating CO
(f)
(1) Component/system identification code;
(2) Date, hour, and minute;
(3) Average opacity of emissions for each six minute averaging period (in percent opacity);
(4) If the average opacity of emissions exceeds the applicable standard, then a code indicating such an exceedance has occurred; and
(5) Percent monitor data availability, recorded to the nearest tenth of a percent, calculated according to the requirements of the procedure recommended for State Implementation Plans in appendix M of part 51 of this chapter.
(g)
Before April 1, 2000, the owner or operator shall meet the requirements of either this section or § 75.58. On and after April 1, 2000, the owner or operator shall meet the requirements of § 75.58.
(a)
(1) For units with post-combustion emission controls:
(i) Component/system identification codes for each inlet and outlet SO
(ii) Date and hour;
(iii) Hourly average inlet SO
(iv) Hourly average outlet SO
(v) Percent data availability for both inlet and outlet SO
(vi) Identification code for emissions formula used to derive hourly average inlet and outlet SO
(2) For units with combustion and/or pre-combustion emission controls:
(i) Component/system identification codes for each outlet SO
(ii) Date and hour;
(iii) Hourly average outlet SO
(iv) For units with combustion controls, average daily inlet SO
(v) For units with pre-combustion controls (i.e., fuel pretreatment), fuel analysis demonstrating the weight, sulfur content, and gross calorific value of the product and raw fuel lots.
(b)
(1) For units with add-on SO
(i) The information required in § 75.54(c) for SO
(ii) Date and hour;
(iii) Number of operating scrubber modules;
(iv) Total feedrate of slurry to each operating scrubber module (gal/min);
(v) Pressure differential across each operating scrubber module (inches of water column);
(vi) For a unit with a wet flue gas desulfurization system, an inline measure of absorber pH for each operating scrubber module;
(vii) For a unit with a dry flue gas desulfurization system, the inlet and
(viii) For a unit with a wet flue gas desulfurization system, the percent solids in slurry for each scrubber module.
(ix) For a unit with a dry flue gas desulfurization system, the slurry feed rate (gal/min) to the atomizer nozzle;
(x) For a unit with SO
(xi) Method of determination of SO
(xii) Inlet and outlet SO
(2) For units with add-on NO
(i) Date and hour;
(ii) Inlet air flow rate (acfh, rounded to the nearest thousand);
(iii) Excess O
(iv) Carbon monoxide concentration of flue gas at stack outlet (ppm, rounded to the nearest tenth);
(v) Temperature of flue gas at furnace exit or economizer outlet duct ( °F); and
(vi) Other parameters specific to NO
(vii) Method of determination of NO
(viii) Inlet and outlet NO
(3) For units with add-on SO
(i) Parametric data which demonstrate the proper operation of the add-on emission controls, as described in the quality assurance/quality control program for the unit. The parametric data shall be maintained on site, and shall be submitted upon request to the Administrator, an EPA Regional office, State, or local agency;
(ii) A flag indicating either that the add-on emission controls are operating properly, as evidenced by all parameters being within the ranges specified in the quality assurance/quality control program, or that the add-on emission controls are not operating properly;
(iii) For units petitioning under § 75.66 for substituting a representative SO
(iv) For units petitioning under § 75.66 for substituting a representative NO
(c)
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average flow rate of oil with the units in which oil flow is recorded, (gal/hr, lb/hr, m
(iii) Sulfur content of oil sample used to determine SO
(iv) Method of oil sampling (flow proportional, continuous drip, as delivered or manual);
(v) Mass of oil combusted each hour (lb/hr, rounded to the nearest tenth);
(vi) SO
(vii) For units using volumetric oil flowmeters, density of oil (flag value if derived from missing data procedures);
(viii) Gross calorific value (heat content) of oil, used to determine heat input (Btu/mass unit) (flag value if derived from missing data procedures);
(ix) Hourly heat input rate from oil according to procedures in appendix F of this part (mmBtu/hr, to the nearest tenth); and
(x) Fuel usage time for combustion of oil during the hour, rounded up to the nearest 15 min.
(2) For gas-fired units or oil-fired units using the optional protocol in appendix D of this part of daily manual oil sampling, when the unit is combusting oil, the highest sulfur content recorded from the most recent 30 daily oil samples rounded to nearest tenth of a percent.
(3) For each hour when the unit is combusting gaseous fuel,
(i) Date and hour;
(ii) Hourly heat input rate from gaseous fuel according to procedures in appendix F to this part (mmBtu/hr, rounded to the nearest tenth);
(iii) Sulfur content or SO
(A) Sulfur content of gas sample, (rounded to the nearest 0.1 grains/100 scf) (flag value if derived from missing data procedures); or
(B) SO
(iv) Hourly flow rate of gaseous fuel, in 100 scfh (flag value if derived from missing data procedures);
(v) Gross calorific value (heat content) of gaseous fuel, used to determine heat input (Btu/scf) (flag value if derived from missing data procedures);
(vi) Heat input rate from gaseous fuel (mmBtu/hr, rounded to the nearest tenth);
(vii) SO
(viii) Fuel usage time for combustion of gaseous fuel during the hour, rounded up to the nearest 15 min.
(4) For each oil sample or sample of diesel fuel:
(i) Date of sampling;
(ii) Sulfur content (percent, rounded to the nearest hundredth for diesel fuel and to the nearest tenth for other fuel oil) (flag value if derived from missing data procedures);
(iii) Gross calorific value or heat content (Btu/lb) (flag value if derived from missing data procedures); and
(iv) Density or specific gravity, if required to convert volume to mass (flag value if derived from missing data procedures).
(5) For each daily sample of gaseous fuel:
(i) Date of sampling;
(ii) Sulfur content (grains/100 scf, rounded to the nearest tenth) (flag value if derived from missing data procedures);
(6) For each monthly sample of gaseous fuel:
(i) Date of sampling;
(ii) Gross calorific value or heat content (Btu/scf) (flag value if derived from missing data procedures).
(d)
(1) For each hour when the unit is combusting oil,
(i) Date and hour;
(ii) Hourly average fuel flow rate of oil with the units in which oil flow is recorded (gal/hour, lb/hr or bbl/hour) (flag value if derived from missing data procedures);
(iii) Gross calorific value (heat content) of oil, used to determine heat input (Btu/lb) (flag value if derived from missing data procedures);
(iv) Hourly average NO
(v) Heat input rate of oil (mmBtu/hr, rounded to the nearest tenth); and
(vi) Fuel usage time for combustion of oil during the hour, rounded to the nearest 15 min.
(2) For each hour when the unit is combusting gaseous fuel,
(i) Date and hour;
(ii) Hourly average fuel flow rate of gaseous fuel (100 scfh) (flag value if derived from missing data procedures);
(iii) Gross calorific value (heat content) of gaseous fuel, used to determine heat input (Btu/scf) (flag value if derived from missing data procedures);
(iv) Hourly average NO
(v) Heat input rate from gaseous fuel (mmBtu/hr, rounded to the nearest tenth); and
(vi) Fuel usage time for combustion of gaseous fuel during the hour, rounded to the nearest 15 min.
(3) For each hour when the unit combusts any fuel:
(i) Date and hour;
(ii) Total heat input from all fuels (mmBtu, rounded to the nearest tenth);
(iii) Hourly average NO
(iv) For stationary gas turbines and diesel or dual-fuel reciprocating engines, hourly averages of operating parameters under section 2.3 of appendix E (flag if value is outside of manufacturer's recommended range);
(v) For boilers, hourly average boiler O
(4) For each fuel sample:
(i) Date of sampling;
(ii) Gross calorific value (heat content) (Btu/lb for oil, Btu/scf for gaseous fuel); and
(iii) Density or specific gravity, if required to convert volume to mass.
(e)
(2) The provisions of this paragraph apply to a unit which, in accordance with the provisions of § 75.11(e)(3), uses an SO
Before April 1, 2000, the owner or operator shall meet the requirements of either this section or § 75.59. On and after April 1, 2000, the owner or operator shall meet the requirements of § 75.59.
(a)
(1) For each SO
(i) Component/system identification code;
(ii) Instrument span;
(iii) Date and hour;
(iv) Reference value, (i.e., calibration gas concentration or reference signal value, in ppm or other appropriate units);
(v) Observed value (monitor response during calibration, in ppm or other appropriate units);
(vi) Percent calibration error (rounded to nearest tenth of a percent); and
(vii) For 7-day calibration tests for certification or recertification, a certification from the cylinder gas vendor or CEMS vendor, that calibration gas as defined in § 72.2 and appendix A of this part, were used to conduct calibration error testing; and
(viii) Description of any adjustments, corrective actions, or maintenance following test.
(2) For each flow monitor, the owner or operator shall record the following for all daily interference checks, including any follow-up tests after corrective action:
(i) Code indicating whether monitor passes or fails the interference check; and
(ii) Description of any adjustments, corrective actions, or maintenance following test.
(3) For each SO
(i) Component/system identification code;
(ii) Instrument span;
(iii) Date and hour;
(iv) Reference value (i.e., reference gas concentration, in ppm or other appropriate units);
(v) Observed value (average monitor response at each reference gas concentration, in ppm or other appropriate units);
(vi) Percent error at each of three reference gas concentrations (rounded to nearest tenth of a percent); and
(vii) Description of any adjustments, corrective action, or maintenance following test.
(4) For each flow monitor, where applicable, the owner or operator shall record the following for all quarterly leak checks, including any follow-up tests after corrective action:
(i) Code indicating whether monitor passes or fails the quarterly leak check; and
(ii) Description of any adjustments, corrective actions, or maintenance following test.
(5) For each SO
(i) Date and hour;
(ii) Reference method(s) used;
(iii) Individual test run data from the relative accuracy test audit for the SO
(A) Date, hour, and minute of beginning of test run,
(B) Date, hour, and minute of end of test run,
(C) Component/system identification code,
(D) Run number,
(E) Run data for monitor;
(F) Run data for reference method; and
(G) Flag value (0 or 1) indicating whether run has been used in calculating relative accuracy and bias values.
(iv) Calculations and tabulated results, as follows:
(A) Arithmetic mean of the monitoring system measurement values, reference method values, and of their differences, as specified in equation A-7 in appendix A to this part.
(B) Standard deviation, as specified in equation A-8 in appendix A to this part.
(C) Confidence coefficient, as specified in equation A-9 in appendix A to this part.
(D) Relative accuracy test results, as specified in equation A-10 in appendix
(E) Bias test results as specified in section 7.6.4 in appendix A to this part.
(F) Bias adjustment factor from equations A-11 and A-12 in appendix A to this part for any monitoring system or component that failed the bias test and 1.0 for any monitoring system or component that passed the bias test. (For flow monitors only, bias adjustment factors should be recorded at each of three gas velocities).
(v) Description of any adjustment, corrective action, or maintenance following test.
(vi) F-factor value(s) used to convert NO
(vii) For flow monitors, the equation used to linearize the flow monitor and the numerical values of the polynomial coefficients or K factor(s) of that equation.
(viii) The raw data and calculated results for any stratification tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 in appendix A to this part.
(ix) For moisture monitoring systems, the coefficient or “K” factor or other mathematical algorithm used to adjust the monitoring system with respect to the reference method.
(6) [Reserved]
(7) Results of all trial runs and certification tests and quality assurance activities and measurements (including all reference method field test sheets, charts, records of combined system responses, laboratory analyses, and example calculations) necessary to substantiate compliance with all relevant appendices in this part. This information shall include, but shall not be limited to, the following reference method data:
(i) For each run of each test using method 2 in appendix A of part 60 of this chapter to determine volumetric flow rate:
(A) Pitot tube coefficient;
(B) Date of pitot tube calibration;
(C) Average square root of velocity head of stack gas (inches of water) for the run;
(D) Average absolute stack gas temperature, °R;
(E) Barometric pressure at test port, inches of mercury;
(F) Stack static pressure, inches of H
(G) Absolute stack gas pressure, inches of mercury;
(H) Moisture content of stack gas, percent;
(I) Molecular weight of stack gas, wet basis (lb/lb-mole);
(J) Number of reference method measurements during the run; and
(K) Total volumetric flowrate (scfh, wet basis).
(ii) For each test using method 2 in appendix A of part 60 of this chapter to determine volumetric flow rate:
(A) Information indicating whether or not the location meets requirements of method 1 in appendix A of part 60 of this chapter;
(B) Information indicating whether or not the equipment passed the leak check after every run included in the relative accuracy test;
(C) Stack inside diameter at test port (ft);
(D) Duct side height and width at test port (ft);
(E) Stack or duct cross-sectional area at test port (ft
(F) Designation as to the load level of the test.
(iii) For each run of each test using method 6C, 7E, or 3A in appendix A of part 60 of this chapter to determine SO
(A) Run start date;
(B) Run start time;
(C) Run end date;
(D) Run end time;
(E) Span of reference method analyzer;
(F) Reference gas concentration (low, mid-, and high gas levels);
(G) Initial and final analyzer calibration response (low, mid- and high gas levels);
(H) Analyzer calibration error (low, mid-, and high gas levels);
(I) Pre-test and post-test analyzer bias (zero and upscale gas levels);
(J) Calibration drift and zero drift of analyzer;
(K) Indication as to which data are from a pretest and which are from a posttest;
(L) Calibration gas level (zero, mid-level, or high); and
(M) Moisture content of stack gas, in percent, if needed to convert to moisture basis of CEMS being tested.
(iv) For each test using method 6C, 7E, or 3A in appendix A of part 60 of this chapter to determine SO
(A) Pollutant being measured;
(B) Test number;
(C) Date of interference test;
(D) Results of interference test;
(E) Date of NO
(F) Results of NO
(v) For each calibration gas cylinder used to test using method 6C, 7E, or 3A in appendix A of part 60 of this chapter to determine SO
(A) Cylinder gas vendor name from certification;
(B) Cylinder number;
(C) Cylinder expiration date;
(D) Pollutant(s) in cylinder; and
(E) Cylinder gas concentration(s).
(b)
(1) For each oil-fired unit or gas-fired unit using the optional procedures of appendix D of this part for determining SO
(i) Date of test,
(ii) Upper range value of the fuel flowmeter,
(iii) Flowmeter measurements during accuracy test,
(iv) Reference flow rates during accuracy test,
(v) Average flowmeter accuracy as a percent of upper range value,
(vi) Fuel flow rate level (low, mid-level, or high); and
(vii) Description of fuel flowmeter calibration specification or procedure (in the certification application, or periodically if a different method is used for annual quality assurance testing).
(2) For gas-fired peaking units or oil-fired peaking units using the optional procedures of appendix E of this part, for each initial performance, periodic, or quality assurance/quality control-related test:
(i) For each run of emissions data;
(A) Run start date and time;
(B) Run end date and time;
(C) Fuel flow (lb/hr, gal/hr, scf/hr, bbl/hr, or m
(D) Gross calorific value (heat content) of fuel (Btu/lb or Btu/scf);
(E) Density of fuel (if needed to convert mass to volume);
(F) Total heat input during the run (mmBtu);
(G) Hourly heat input rate for run (mmBtu/hr);
(H) Response time of the O
(I) NO
(J) O
(K) NO
(L) Fuel or fuel combination (by heat input fraction) combusted.
(ii) For each unit load and heat input;
(A) Average NO
(B) F-factor used in calculations;
(C) Average heat input rate (mmBtu/hr);
(D) Unit operating parametric data related to NO
(E) Fuel or fuel combination (by heat input fraction) combusted.
(iii) For each test report;
(A) Graph of NO
(B) Results of the tests for verification of the accuracy of emissions calculations and missing data procedures performed by the automated data acquisition and handling system, and the calculations used to
(C) Results of all certification tests and quality assurance activities and measurements (including reference method field test sheets, charts, laboratory analyses, example calculations, or other data as appropriate), necessary to substantiate compliance with the requirements of appendix E of this part.
(c) For units with add-on SO
(1) A list of operating parameters for the add-on emission controls, including parameters in § 75.55 (b), appropriate to the particular installation of add-on emission controls; and
(2) The range of each operating parameter in the list that indicates the add-on emission controls are properly operating.
Before April 1, 2000, the owner or operator shall meet the requirements of either this section or § 75.54. However, the provisions of this section which support a regulatory option provided in another section of this part must be followed if that regulatory option is used prior to April 1, 2000. On or after April 1, 2000, the owner or operator shall meet the requirements of this section.
(a)
(1) The data and information required in paragraphs (b) through (h) of this section, beginning with the earlier of the date of provisional certification or the deadline in § 75.4(a), (b), or (c);
(2) The supporting data and information used to calculate values required in paragraphs (b) through (g) of this section, excluding the subhourly data points used to compute hourly averages under § 75.10(d), beginning with the earlier of the date of provisional certification or the deadline in § 75.4(a), (b), or (c);
(3) The data and information required in § 75.55 or § 75.58 for specific situations, as applicable, beginning with the earlier of the date of provisional certification or the deadline in § 75.4(a), (b), or (c);
(4) The certification test data and information required in § 75.56 or § 75.59 for tests required under § 75.20, beginning with the date of the first certification test performed, the quality assurance and quality control data and information required in § 75.56 or § 75.59 for tests, and the quality assurance/quality control plan required under § 75.21 and appendix B to this part, beginning with the date of provisional certification;
(5) The current monitoring plan as specified in § 75.53, beginning with the initial submission required by § 75.62; and
(6) The quality control plan as described in section 1 of appendix B to this part, beginning with the date of provisional certification.
(b)
(1) Date and hour;
(2) Unit operating time (rounded up to the nearest fraction of an hour (in
(3) Hourly gross unit load (rounded to nearest MWge) (or steam load in 1000 lb/hr at stated temperature and pressure, rounded to the nearest 1000 lb/hr, if elected in the monitoring plan);
(4) Operating load range corresponding to hourly gross load of 1 to 10, except for units using a common stack or common pipe header, which may use up to 20 load ranges for stack or fuel flow, as specified in the monitoring plan;
(5) Hourly heat input rate (mmBtu/hr, rounded to the nearest tenth);
(6) Identification code for formula used for heat input, as provided in § 75.53; and
(7) For CEMS units only, F-factor for heat input calculation and indication of whether the diluent cap was used for heat input calculations for the hour.
(c)
(1) For SO
(i) Component-system identification code, as provided in § 75.53;
(ii) Date and hour;
(iii) Hourly average SO
(iv) Hourly average SO
(v) Percent monitor data availability (recorded to the nearest tenth of a percent), calculated pursuant to § 75.32; and
(vi) Method of determination for hourly average SO
(2) For flow rate during unit operation, as measured and reported from each certified primary monitor, certified back-up monitor, or other approved method of emissions determination:
(i) Component-system identification code, as provided in § 75.53;
(ii) Date and hour;
(iii) Hourly average volumetric flow rate (in scfh, rounded to the nearest thousand);
(iv) Hourly average volumetric flow rate (in scfh, rounded to the nearest thousand), adjusted for bias if bias adjustment factor required, as provided in § 75.24(d);
(v) Percent monitor data availability (recorded to the nearest tenth of a percent) for the flow monitor, calculated pursuant to § 75.32; and
(vi) Method of determination for hourly average flow rate using Codes 1-55 in Table 4a of this section.
(3) For flue gas moisture content during unit operation (where SO
(i) Component-system identification code, as provided in § 75.53;
(ii) Date and hour;
(iii) Hourly average moisture content of flue gas (percent, rounded to the nearest tenth). If the continuous moisture monitoring system consists of wet- and dry-basis oxygen analyzers, also record both the wet- and dry-basis oxygen hourly averages (in percent O
(iv) Percent monitor data availability (recorded to the nearest tenth of a percent) for the moisture monitoring system, calculated pursuant to § 75.32; and
(v) Method of determination for hourly average moisture percentage, using Codes 1-55 in Table 4a of this section.
(4) For SO
(i) Date and hour;
(ii) Hourly SO
(iii) Hourly SO
(iv) Identification code for emissions formula used to derive hourly SO
(d)
(1) Component-system identification code, as provided in § 75.53 (including identification code for the moisture monitoring system, if applicable);
(2) Date and hour;
(3) Hourly average NO
(4) Hourly average diluent gas concentration (for NO
(5) If applicable, the hourly average moisture content of the stack gas (percent H
(6) Hourly average NO
(7) Hourly average NO
(8) Percent monitoring system data availability (recorded to the nearest tenth of a percent), for the NO
(9) Method of determination for hourly average NO
(10) Identification codes for emissions formulas used to derive hourly average NO
(e)
(1) If the owner or operator chooses to use a CO
(i) Component-system identification code, as provided in § 75.53 (including
(ii) Date and hour;
(iii) Hourly average CO
(iv) Hourly average volumetric flow rate (scfh, rounded to the nearest thousand scfh);
(v) Hourly average moisture content of flue gas (percent, rounded to the nearest tenth), where CO
(vi) Hourly average CO
(vii) Percent monitor data availability for both the CO
(viii) Method of determination for hourly average CO
(ix) Identification code for emissions formula used to derive hourly average CO
(x) Indication of whether the diluent cap was used for CO
(2) As an alternative to paragraph (e)(1) of this section, the owner or operator may use the procedures in § 75.13 and in appendix G to this part, and shall record daily the following information for CO
(i) Date;
(ii) Daily combustion-formed CO
(iii) For coal-fired units, flag indicating whether optional procedure to adjust combustion-formed CO
(iv) For a unit with a wet flue gas desulfurization system or other controls generating CO
(v) For a unit with a wet flue gas desulfurization system or other controls generating CO
(f)
(1) Component/system identification code;
(2) Date, hour, and minute;
(3) Average opacity of emissions for each six minute averaging period (in percent opacity);
(4) If the average opacity of emissions exceeds the applicable standard, then a code indicating such an exceedance has occurred; and
(5) Percent monitor data availability (recorded to the nearest tenth of a percent), calculated according to the requirements of the procedure recommended for State Implementation Plans in appendix M to part 51 of this chapter.
(g)
(1) Component-system identification code, as provided in § 75.53;
(2) Date and hour;
(3) Hourly average diluent gas (O
(4) Percent monitor data availability for the diluent monitor (recorded to the nearest tenth of a percent), calculated pursuant to § 75.32; and
(5) Method of determination code for diluent gas (O
(h)
Before April 1, 2000, the owner or operator shall meet the requirements of either this section or § 75.55. However, the provisions of this section which support a regulatory option provided in another section of this part must be followed if that regulatory option is exercised prior to April 1, 2000. On or after April 1, 2000, the owner or operator shall meet the requirements of this section.
(a) [Reserved]
(b)
(1) For units with add-on SO
(i) The information required in § 75.54(c) or § 75.57(c) for SO
(ii) Date and hour;
(iii) Number of operating scrubber modules;
(iv) Total feedrate of slurry to each operating scrubber module (gal/min);
(v) Pressure differential across each operating scrubber module (inches of water column);
(vi) For a unit with a wet flue gas desulfurization system, an in-line measure of absorber pH for each operating scrubber module;
(vii) For a unit with a dry flue gas desulfurization system, the inlet and outlet temperatures across each operating scrubber module;
(viii) For a unit with a wet flue gas desulfurization system, the percent solids in slurry for each scrubber module;
(ix) For a unit with a dry flue gas desulfurization system, the slurry feed rate (gal/min) to the atomizer nozzle;
(x) For a unit with SO
(xi) Method of determination of SO
(xii) Inlet and outlet SO
(2) For units with add-on NO
(i) Date and hour;
(ii) Inlet air flow rate (scfh, rounded to the nearest thousand);
(iii) Excess O
(iv) Carbon monoxide concentration of flue gas at stack outlet (ppm, rounded to the nearest tenth);
(v) Temperature of flue gas at furnace exit or economizer outlet duct (°F);
(vi) Other parameters specific to NO
(vii) Method of determination of NO
(viii) Inlet and outlet NO
(3) For units with add-on SO
(i) Parametric data which demonstrate the proper operation of the add-on emission controls, as described in the quality assurance/quality control program for the unit. The parametric data shall be maintained on site and shall be submitted, upon request, to the Administrator, EPA Regional office, State, or local agency;
(ii) A flag indicating either that the add-on emission controls are operating properly, as evidenced by all parameters being within the ranges specified in the quality assurance/quality control program, or that the add-on emission controls are not operating properly;
(iii) For units substituting a representative SO
(iv) For units substituting a representative NO
(c)
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average volumetric flow rate of oil, while the unit combusts oil, with the units in which oil flow is recorded (gal/hr, scf/hr, m
(iii) Sulfur content of oil sample used to determine SO
(iv) [Reserved];
(v) Mass flow rate of oil combusted each hour and method of determination (lb/hr, rounded to the nearest tenth) (flag value if derived from missing data procedures);
(vi) SO
(vii) For units using volumetric oil flowmeters, density of oil with the units in which oil density is recorded and method of determination (flag value if derived from missing data procedures);
(viii) Gross calorific value of oil used to determine heat input and method of determination (Btu/lb) (flag value if derived from missing data procedures);
(ix) Hourly heat input rate from oil, according to procedures in appendix D to this part (mmBtu/hr, to the nearest tenth);
(x) Fuel usage time for combustion of oil during the hour (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator)) (flag to indicate multiple/single fuel types combusted);
(xi) Monitoring system identification code;
(xii) Operating load range corresponding to gross unit load (01-20); and
(xiii) Type of oil combusted.
(2) For gas-fired units or oil-fired units using the optional protocol in appendix D to this part for daily manual oil sampling, when the unit is combusting oil, the highest sulfur content recorded from the most recent 30 daily oil samples (rounded to the nearest tenth of a percent).
(3) For gas-fired units or oil-fired units using the optional protocol in appendix D to this part, when either an assumed oil sulfur content or density value is used, or when as-delivered oil sampling is performed:
(i) Record the measured sulfur content, gross calorific value, and, if applicable, density from each fuel sample; and
(ii) Record and report the assumed sulfur content, gross calorific value, and, if applicable, density used to calculate SO
(4) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour.
(ii) Hourly heat input rate from gaseous fuel, according to procedures in appendix F to this part (mmBtu/hr, rounded to the nearest tenth).
(iii) Sulfur content or SO
(A) Sulfur content of gas sample and method of determination (rounded to the nearest 0.1 grains/100 scf) (flag value if derived from missing data procedures); or
(B) Default SO
(iv) Hourly flow rate of gaseous fuel, while the unit combusts gas (100 scfh) and source of data code for gas flow rate.
(v) Gross calorific value of gaseous fuel used to determine heat input rate (Btu/100 scf) (flag value if derived from missing data procedures).
(vi) SO
(vii) Fuel usage time for combustion of gaseous fuel during the hour (rounded up to the nearest fraction of an hour (in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator)) (flag to indicate multiple/single fuel types combusted).
(viii) Monitoring system identification code.
(ix) Operating load range corresponding to gross unit load (01-20).
(x) Type of gas combusted.
(5) For each oil sample or sample of diesel fuel:
(i) Date of sampling;
(ii) Sulfur content (percent, rounded to the nearest hundredth for diesel fuel and to the nearest tenth for other fuel oil);
(iii) Gross calorific value (Btu/lb); and
(iv) Density or specific gravity, if required to convert volume to mass.
(6) For each sample of gaseous fuel for sulfur content:
(i) Date of sampling; and
(ii) Sulfur content (grains/100 scf, rounded to the nearest tenth).
(7) For each sample of gaseous fuel for gross calorific value:
(i) Date of sampling; and
(ii) Gross calorific value (Btu/100 scf)
(8) For each oil sample or sample of gaseous fuel:
(i) Type of oil or gas; and
(ii) Type of sulfur sampling (using codes in tables D-4 and D-5 of appendix D to this part) and value used in calculations, and type of GCV or density sampling (using codes in tables D-4 and D-5 of appendix D to this part).
(d)
(1) For each hour when the unit is combusting oil:
(i) Date and hour;
(ii) Hourly average mass flow rate of oil while the unit combusts oil with
(iii) Gross calorific value of oil used to determine heat input (Btu/lb);
(iv) Hourly average NO
(v) Heat input rate of oil (mmBtu/hr, rounded to the nearest tenth);
(vi) Fuel usage time for combustion of oil during the hour (rounded up to the nearest fraction of an hour, in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator);
(vii) NO
(viii) NO
(ix) Fuel flow monitoring system identification code; and
(x) Segment identification of the correlation curve.
(2) For each hour when the unit is combusting gaseous fuel:
(i) Date and hour;
(ii) Hourly average fuel flow rate of gaseous fuel, while the unit combusts gas (100 scfh);
(iii) Gross calorific value of gaseous fuel used to determine heat input (Btu/100 scf) (flag value if derived from missing data procedures);
(iv) Hourly average NO
(v) Heat input rate from gaseous fuel, while the unit combusts gas (mmBtu/hr, rounded to the nearest tenth);
(vi) Fuel usage time for combustion of gaseous fuel during the hour (rounded up to the nearest fraction of an hour, in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator);
(vii) NO
(viii) NO
(ix) Fuel flow monitoring system identification code; and
(x) Segment identification of the correlation curve.
(3) For each hour when the unit combusts multiple fuels:
(i) Date and hour;
(ii) Hourly average heat input rate from all fuels (mmBtu/hr, rounded to the nearest tenth); and
(iii) Hourly average NO
(4) For each hour when the unit combusts any fuel(s):
(i) For stationary gas turbines and diesel or dual-fuel reciprocating engines, hourly averages of operating parameters under section 2.3 of appendix E to this part (flag if value is outside of manufacturer's recommended range); and
(ii) For boilers, hourly average boiler O
(5) For each fuel sample:
(i) Date of sampling;
(ii) Gross calorific value (Btu/lb for oil, Btu/100 scf for gaseous fuel); and
(iii) Density or specific gravity, if required to convert volume to mass.
(6) Flag to indicate multiple or single fuels combusted.
(e)
(2) The provisions of this paragraph apply to a unit which, in accordance with the provisions of § 75.11(e)(3), uses an SO
(f)
(1) All low mass emission units shall report for each hour:
(i) Date and hour;
(ii) Unit operating time (units using the long term fuel flow methodology report operating time to be 1);
(iii) Fuel type (pipeline natural gas, natural gas, residual oil, or diesel fuel) (note: if more than one type of fuel is combusted in the hour, indicate the fuel type which results in the highest emission factors for NO
(iv) Average hourly NO
(v) Hourly NO
(vi) Hourly SO
(vii) Hourly CO
(viii) Hourly calculated unit heat input in mmBtu;
(ix) Hourly unit output in gross load or steam load;
(x) The method of determining hourly heat input: unit maximum rated heat input, unit long term fuel flow or group long term fuel flow;
(xi) The method of determining NO
(xii) Control status of the unit.
(2) Low mass emission units using the optional long term fuel flow methodology to determine unit heat input shall report for each quarter:
(i) Type of fuel;
(ii) Beginning date and hour of long term fuel flow measurement period;
(iii) End date and hour of long term fuel flow period;
(iv) Quantity of fuel measured;
(v) Units of measure;
(vi) Fuel GCV value used to calculate heat input;
(vii) Units of GCV;
(viii) Method of determining fuel GCV used;
(ix) Method of determining fuel flow over period;
(x) Component-system identification code;
(xi) Quarter and year;
(xii) Total heat input (mmBtu); and
(xiii) Operating hours in period.
Before April 1, 2000, the owner or operator shall meet the requirements of this section or § 75.56. However, the provisions of this section which support a regulatory option provided in another section of this part must be followed if that regulatory option is exercised prior to April 1, 2000. On or after April 1, 2000, the owner or operator shall meet the requirements of this section.
(a)
(1) For each SO
(i) Component-system identification code;
(ii) Instrument span and span scale;
(iii) Date and hour;
(iv) Reference value (i.e., calibration gas concentration or reference signal value, in ppm or other appropriate units);
(v) Observed value (monitor response during calibration, in ppm or other appropriate units);
(vi) Percent calibration error (rounded to the nearest tenth of a percent) (flag if using alternative performance specification for low emitters or differential pressure flow monitors);
(vii) Calibration gas level;
(viii) Test number and reason for test;
(ix) For 7-day calibration tests for certification or recertification, a certification from the cylinder gas vendor or CEMS vendor that calibration gas, as defined in § 72.2 of this chapter and appendix A to this part, was used to conduct calibration error testing;
(x) Description of any adjustments, corrective actions, or maintenance prior to a passed test or following a failed test; and
(xi) For the qualifying test for off-line calibration, the owner or operator shall indicate whether the unit is off-line or on-line.
(2) For each flow monitor, the owner or operator shall record the following for all daily interference checks, including any follow-up tests after corrective action.
(i) Component-system identification code;
(ii) Date and hour;
(iii) Code indicating whether monitor passes or fails the interference check; and
(iv) Description of any adjustments, corrective actions, or maintenance prior to a passed test or following a failed test.
(3) For each SO
(i) Component-system identification code;
(ii) Instrument span and span scale;
(iii) Calibration gas level;
(iv) Date and time (hour and minute) of each gas injection at each calibration gas level;
(v) Reference value (i.e., reference gas concentration for each gas injection at each calibration gas level, in ppm or other appropriate units);
(vi) Observed value (monitor response to each reference gas injection at each calibration gas level, in ppm or other appropriate units);
(vii) Mean of reference values and mean of measured values at each calibration gas level;
(viii) Linearity error at each of the reference gas concentrations (rounded to nearest tenth of a percent) (flag if using alternative performance specification);
(ix) Test number and reason for test (flag if aborted test); and
(x) Description of any adjustments, corrective action, or maintenance prior to a passed test or following a failed test.
(4) For each differential pressure type flow monitor, the owner or operator shall record items in paragraphs (a)(4) (i) through (v) of this section, for all quarterly leak checks, including any follow-up tests after corrective action. For each flow monitor, the owner or operator shall record items in paragraphs (a)(4) (vi) and (vii) for all flow-to-load ratio and gross heat rate tests:
(i) Component-system identification code.
(ii) Date and hour.
(iii) Reason for test.
(iv) Code indicating whether monitor passes or fails the quarterly leak check.
(v) Description of any adjustments, corrective actions, or maintenance prior to a passed test or following a failed test.
(vi) Test data from the flow-to-load ratio or gross heat rate (GHR) evaluation, including:
(A) Monitoring system identification code;
(B) Calendar year and quarter;
(C) Indication of whether the test is a flow-to-load ratio or gross heat rate evaluation;
(D) Indication of whether bias adjusted flow rates were used;
(E) Average absolute percent difference between reference ratio (or GHR) and hourly ratios (or GHR values);
(F) Test result;
(G) Number of hours used in final quarterly average;
(H) Number of hours exempted for use of a different fuel type;
(I) Number of hours exempted for load ramping up or down;
(J) Number of hours exempted for scrubber bypass;
(K) Number of hours exempted for hours preceding a normal-load flow RATA;
(L) Number of hours exempted for hours preceding a successful diagnostic test, following a documented monitor repair or major component replacement; and
(M) Number of hours excluded for flue gases discharging simultaneously thorough a main stack and a bypass stack.
(vii) Reference data for the flow-to-load ratio or gross heat rate evaluation, including (as applicable):
(A) Reference flow RATA end date and time;
(B) Test number of the reference RATA;
(C) Reference RATA load and load level;
(D) Average reference method flow rate during reference flow RATA;
(E) Reference flow/load ratio;
(F) Average reference method diluent gas concentration during flow RATA and diluent gas units of measure;
(G) Fuel specific F
(H) Reference gross heat rate value;
(I) Monitoring system identification code;
(J) Average hourly heat input rate during RATA;
(K) Average gross unit load; and
(L) Operating load level.
(5) For each SO
(i) Reference method(s) used.
(ii) Individual test run data from the relative accuracy test audit for the SO
(A) Date, hour, and minute of beginning of test run;
(B) Date, hour, and minute of end of test run;
(C) Monitoring system identification code;
(D) Test number and reason for test;
(E) Operating load level (low, mid, high, or normal, as appropriate) and number of load levels comprising test;
(F) Normal load indicator for flow RATAs (except for peaking units);
(G) Units of measure;
(H) Run number;
(I) Run value from CEMS being tested, in the appropriate units of measure;
(J) Run value from reference method, in the appropriate units of measure;
(K) Flag value (0, 1, or 9, as appropriate) indicating whether run has been used in calculating relative accuracy and bias values or whether the test was aborted prior to completion;
(L) Average gross unit load, expressed as a total gross unit load, rounded to the nearest MWe, or as steam load, rounded to the nearest thousand lb/hr); and
(M) Flag to indicate whether an alternative performance specification has been used.
(iii) Calculations and tabulated results, as follows:
(A) Arithmetic mean of the monitoring system measurement values, of the reference method values, and of their differences, as specified in Equation A-7 in appendix A to this part;
(B) Standard deviation, as specified in Equation A-8 in appendix A to this part;
(C) Confidence coefficient, as specified in Equation A-9 in appendix A to this part;
(D) Statistical “t” value used in calculations;
(E) Relative accuracy test results, as specified in Equation A-10 in appendix A to this part. For multi-level flow monitor tests the relative accuracy test results shall be recorded at each load level tested. Each load level shall be expressed as a total gross unit load, rounded to the nearest MWe, or as steam load, rounded to the nearest thousand lb/hr;
(F) Bias test results as specified in section 7.6.4 in appendix A to this part; and
(G) Bias adjustment factor from Equation A-12 in appendix A to this part for any monitoring system that failed the bias test (except as otherwise provided in section 7.6.5 of appendix A to this part) and 1.000 for any monitoring system that passed the bias test.
(iv) Description of any adjustment, corrective action, or maintenance prior to a passed test or following a failed or aborted test.
(v) F-factor value(s) used to convert NO
(vi) For flow monitors, the equation used to linearize the flow monitor and the numerical values of the polynomial coefficients or K factor(s) of that equation.
(vii) For moisture monitoring systems, the coefficient or “K” factor or other mathematical algorithm used to adjust the monitoring system with respect to the reference method.
(6) For each SO
(i) Component-system identification code;
(ii) Date;
(iii) Start and end times;
(iv) Upscale and downscale cycle times for each component;
(v) Stable start monitor value;
(vi) Stable end monitor value;
(vii) Reference value of calibration gas(es);
(viii) Calibration gas level;
(ix) Cycle time result for the entire system;
(x) Reason for test; and
(xi) Test number.
(7) In addition to the information in paragraph (a)(5) of this section, the owner or operator shall record, for each relative accuracy test audit, supporting information sufficient to substantiate compliance with all applicable sections and appendices in this part. Unless otherwise specified in this part or in an applicable test method, the information in paragraphs (a)(7)(i) through (a)(7)(vi) may be recorded either in hard copy format, electronic format or a combination of the two, and the owner or operator shall maintain this information in a format suitable for inspection and audit purposes. This RATA supporting information shall include, but shall not be limited to, the following data elements:
(i) For each RATA using Reference Method 2 (or its allowable alternatives) in appendix A to part 60 of this chapter to determine volumetric flow rate:
(A) Information indicating whether or not the location meets requirements of Method 1 in appendix A to part 60 of this chapter; and
(B) Information indicating whether or not the equipment passed the required leak checks.
(ii) For each run of each RATA using Reference Method 2 (or its allowable alternatives in appendix A to part 60 of this chapter) to determine volumetric
(A) Operating load level (low, mid, high, or normal, as appropriate);
(B) Number of reference method traverse points;
(C) Average stack gas temperature (°F);
(D) Barometric pressure at test port (inches of mercury);
(E) Stack static pressure (inches of H
(F) Absolute stack gas pressure (inches of mercury);
(G) Percent CO
(H) CO
(I) Moisture content of stack gas (percent H
(J) Molecular weight of stack gas, dry basis (lb/lb-mole);
(K) Molecular weight of stack gas, wet basis (lb/lb-mole);
(L) Stack diameter (or equivalent diameter) at the test port (ft);
(M) Average square root of velocity head of stack gas (inches of H
(N) Stack or duct cross-sectional area at test port (ft
(O) Average velocity (ft/sec);
(P) Total volumetric flow rate (scfh, wet basis);
(Q) Flow rate reference method used;
(R) Average velocity, adjusted for wall effects;
(S) Calculated (site-specific) wall effects adjustment factor determined during the run, and, if different, the wall effects adjustment factor used in the calculations; and
(T) Default wall effects adjustment factor used.
(iii) For each traverse point of each run of each RATA using Reference Method 2 (or its allowable alternatives in appendix A to part 60 of this chapter) to determine volumetric flow rate, record the following data elements (as applicable to the measurement method used):
(A) Reference method probe type;
(B) Pressure measurement device type;
(C) Traverse point ID;
(D) Probe or pitot tube calibration coefficient;
(E) Date of latest probe or pitot tube calibration;
(F) Velocity differential pressure at traverse point (inches of H
(G) T
(H) Composite (wall effects) traverse point identifier;
(I) Number of points included in composite traverse point;
(J) Yaw angle of flow at traverse point (degrees);
(K) Pitch angle of flow at traverse point (degrees);
(L) Calculated velocity at traverse point both accounting and not accounting for wall effects (ft/sec); and
(M) Probe identification number.
(iv) For each RATA using Method 6C, 7E, or 3A in appendix A to part 60 of this chapter to determine SO
(A) Pollutant or diluent gas being measured;
(B) Span of reference method analyzer;
(C) Type of reference method system (e.g., extractive or dilution type);
(D) Reference method dilution factor (dilution type systems, only);
(E) Reference gas concentrations (zero, mid, and high gas levels) used for the 3-point pre-test analyzer calibration error test (or, for dilution type reference method systems, for the 3-point pre-test system calibration error test) and for any subsequent recalibrations;
(F) Analyzer responses to the zero-, mid-, and high-level calibration gases during the 3-point pre-test analyzer (or system) calibration error test and during any subsequent recalibration(s);
(G) Analyzer calibration error at each gas level (zero, mid, and high) for the 3-point pre-test analyzer (or system) calibration error test and for any subsequent recalibration(s) (percent of span value);
(H) Upscale gas concentration (mid or high gas level) used for each pre-run or post-run system bias check or (for dilution type reference method systems) for each pre-run or post-run system calibration error check;
(I) Analyzer response to the calibration gas for each pre-run or post-run system bias (or system calibration error) check;
(J) The arithmetic average of the analyzer responses to the zero-level gas, for each pair of pre- and post-run system bias (or system calibration error) checks;
(K) The arithmetic average of the analyzer responses to the upscale calibration gas, for each pair of pre- and post-run system bias (or system calibration error) checks;
(L) The results of each pre-run and each post-run system bias (or system calibration error) check using the zero-level gas (percentage of span value);
(M) The results of each pre-run and each post-run system bias (or system calibration error) check using the upscale calibration gas (percentage of span value);
(N) Calibration drift and zero drift of analyzer during each RATA run (percentage of span value);
(O) Moisture basis of the reference method analysis;
(P) Moisture content of stack gas, in percent, during each test run (if needed to convert to moisture basis of CEMS being tested);
(Q) Unadjusted (raw) average pollutant or diluent gas concentration for each run;
(R) Average pollutant or diluent gas concentration for each run, corrected for calibration bias (or calibration error) and, if applicable, corrected for moisture;
(S) The F-factor used to convert reference method data to units of lb/mmBtu (if applicable);
(T) Date(s) of the latest analyzer interference test(s);
(U) Results of the latest analyzer interference test(s);
(V) Date of the latest NO
(W) Results of the latest NO
(X) For each calibration gas cylinder used during each RATA, record the cylinder gas vendor, cylinder number, expiration date, pollutant(s) in the cylinder, and certified gas concentration(s).
(v) For each test run of each moisture determination using Method 4 in appendix A to part 60 of this chapter (or its allowable alternatives), whether the determination is made to support a gas RATA, to support a flow RATA, or to quality assure the data from a continuous moisture monitoring system, record the following data elements (as applicable to the moisture measurement method used):
(A) Test number;
(B) Run number;
(C) The beginning date, hour, and minute of the run;
(D) The ending date, hour, and minute of the run;
(E) Unit operating level (low, mid, high, or normal, as appropriate);
(F) Moisture measurement method;
(G) Volume of H
(H) Mass of H
(I) Dry gas meter calibration factor;
(J) Average dry gas meter temperature (°F);
(K) Barometric pressure (inches of mercury);
(L) Differential pressure across the orifice meter (inches of H
(M) Initial and final dry gas meter readings (ft
(N) Total sample gas volume, corrected to standard conditions (dscf); and
(O) Percentage of moisture in the stack gas (percent H
(vi) The raw data and calculated results for any stratification tests performed in accordance with sections 6.5.6.1 through 6.5.6.3 of appendix A to this part.
(8) For each certified continuous emission monitoring system, continuous opacity monitoring system, or alternative monitoring system, the date and description of each event which requires recertification of the system and the date and type of each test performed to recertify the system in accordance with § 75.20(b).
(9) When hardcopy relative accuracy test reports, certification reports, recertification reports, or semiannual or annual reports for gas or flow rate CEMS are required or requested under § 75.60(b)(6) or § 75.63, the reports shall include, at a minimum, the following elements (as applicable to the type(s) of test(s) performed):
(i) Summarized test results.
(ii) DAHS printouts of the CEMS data generated during the calibration
(iii) For pollutant concentration monitor or diluent monitor relative accuracy tests at normal operating load:
(A) The raw reference method data from each run, i.e., the data under paragraph (a)(7)(iv)(Q) of this section (usually in the form of a computerized printout, showing a series of one-minute readings and the run average);
(B) The raw data and results for all required pre-test, post-test, pre-run and post-run quality assurance checks (i.e., calibration gas injections) of the reference method analyzers, i.e., the data under paragraphs (a)(7)(iv)(E) through (a)(7)(iv)(N) of this section;
(C) The raw data and results for any moisture measurements made during the relative accuracy testing, i.e., the data under paragraphs (a)(7)(v)(A) through (a)(7)(v)(O) of this section; and
(D) Tabulated, final, corrected reference method run data (i.e., the actual values used in the relative accuracy calculations), along with the equations used to convert the raw data to the final values and example calculations to demonstrate how the test data were reduced.
(iv) For relative accuracy tests for flow monitors:
(A) The raw flow rate reference method data, from Reference Method 2 (or its allowable alternatives) under appendix A to part 60 of this chapter, including auxiliary moisture data (often in the form of handwritten data sheets), i.e., the data under paragraphs (a)(7)(ii)(A) through (a)(7)(ii)(T), paragraphs (a)(7)(iii)(A) through (a)(7)(iii)(M), and, if applicable, paragraphs (a)(7)(v)(A) through (a)(7)(v)(O) of this section; and
(B) The tabulated, final volumetric flow rate values used in the relative accuracy calculations (determined from the flow rate reference method data and other necessary measurements, such as moisture, stack temperature and pressure), along with the equations used to convert the raw data to the final values and example calculations to demonstrate how the test data were reduced.
(v) Calibration gas certificates for the gases used in the linearity, calibration error, and cycle time tests and for the calibration gases used to quality assure the gas monitor reference method data during the relative accuracy test audit.
(vi) Laboratory calibrations of the source sampling equipment.
(vii) A copy of the test protocol used for the CEMS certifications or recertifications, including narrative that explains any testing abnormalities, problematic sampling, and analytical conditions that required a change to the test protocol, and/or solutions to technical problems encountered during the testing program.
(viii) Diagrams illustrating test locations and sample point locations (to verify that locations are consistent with information in the monitoring plan). Include a discussion of any special traversing or measurement scheme. The discussion shall also confirm that sample points satisfy applicable acceptance criteria.
(ix) Names of key personnel involved in the test program, including test team members, plant contacts, agency representatives and test observers on site.
(10) Whenever reference methods are used as backup monitoring systems pursuant to § 75.20(d)(3), the owner or operator shall record the following information:
(i) For each test run using Reference Method 2 (or its allowable alternatives in appendix A to part 60 of this chapter) to determine volumetric flow rate, record the following data elements (as applicable to the measurement method used):
(A) Unit or stack identification number;
(B) Reference method system and component identification numbers;
(C) Run date and hour;
(D) The data in paragraph (a)(7)(ii) of this section, except for paragraphs (a)(7)(ii)(A), (F), (H), (L) and (Q) through (T); and
(E) The data in paragraph (a)(7)(iii)(A), except on a run basis.
(ii) For each reference method test run using Method 6C, 7E, or 3A in appendix A to part 60 of this chapter to determine SO
(A) Unit or stack identification number;
(B) The reference method system and component identification numbers;
(C) Run number;
(D) Run start date and hour;
(E) Run end date and hour;
(F) The data in paragraphs (a)(7)(iv)(B) through (I) and (L) through (O); and (G) Stack gas density adjustment factor (if applicable).
(iii) For each hour of each reference method test run using Method 6C, 7E, or 3A in appendix A to part 60 of this chapter to determine SO
(A) Unit or stack identification number;
(B) The reference method system and component identification numbers;
(C) Run number;
(D) Run date and hour;
(E) Pollutant or diluent gas being measured;
(F) Unadjusted (raw) average pollutant or diluent gas concentration for the hour; and
(G) Average pollutant or diluent gas concentration for the hour, adjusted as appropriate for moisture, calibration bias (or calibration error) and stack gas density.
(11) For each other quality-assurance test or other quality assurance activity, the owner or operator shall record the following (as applicable):
(i) Component/system identification code;
(ii) Parameter;
(iii) Test or activity completion date and hour;
(iv) Test or activity description;
(v) Test result;
(vi) Reason for test; and
(vii) Test code.
(12) For each request for a quality assurance test extension or exemption, for any loss of exempt status, and for each single-load flow RATA claim pursuant to section 2.3.1.3(c)(3) of appendix B to this part, the owner or operator shall record the following (as applicable):
(i) For a RATA deadline extension or exemption request:
(A) Monitoring system identification code;
(B) Date of last RATA;
(C) RATA expiration date without extension;
(D) RATA expiration date with extension;
(E) Type of RATA extension of exemption claimed or lost;
(F) Year to date hours of usage of fuel other than very low sulfur fuel;
(G) Year to date hours of non-redundant back-up CEMS usage at the unit/stack; and
(H) Quarter and year.
(ii) For a linearity test or flow-to-load ratio test quarterly exemption:
(A) Component-system identification code;
(B) Type of test;
(C) Basis for exemption;
(D) Quarter and year; and
(E) Span scale.
(iii) For a quality assurance test extension claim based on a grace period:
(A) Component-system identification code;
(B) Type of test;
(C) Beginning of grace period;
(D) Date and hour of completion of required quality assurance test;
(E) Number of unit or stack operating hours from the beginning of the grace period to the completion of the quality assurance test or the maximum allowable grace period; and
(F) Date and hour of end of grace period.
(iv) For a fuel flowmeter accuracy test extension:
(A) Component-system identification code;
(B) Date of last accuracy test;
(C) Accuracy test expiration date without extension;
(D) Accuracy test expiration date with extension;
(E) Type of extension; and
(F) Quarter and year.
(v) For a single-load flow RATA claim:
(A) Monitoring system identification code;
(B) Ending date of last annual flow RATA;
(C) The relative frequency (percentage) of unit or stack operation at each load level (low, mid, and high) since the previous annual flow RATA, to the nearest 0.1 percent.
(D) End date of the historical load data collection period; and
(E) Indication of the load level (low, mid or high) claimed for the single-load flow RATA.
(13) An indication that data have been excluded from a periodic span and range evaluation of an SO
(b)
(1) For certification and quality assurance testing of fuel flowmeters tested against a reference fuel flow rate (i.e., flow rate from another fuel flowmeter under section 2.1.5.2 of appendix D to this part or flow rate from a procedure according to a standard incorporated by reference under section 2.1.5.1 of appendix D to this part):
(i) Unit or common pipe header identification code;
(ii) Component and system identification codes of the fuel flowmeter being tested;
(iii) Date and hour of test completion, for a test performed in-line at the unit;
(iv) Date and hour of flowmeter reinstallation, for laboratory tests;
(v) Test number;
(vi) Upper range value of the fuel flowmeter;
(vii) Flowmeter measurements during accuracy test (and mean of values), including units of measure;
(viii) Reference flow rates during accuracy test (and mean of values), including units of measure;
(ix) Level of fuel flowrate test during runs (low, mid or high);
(x) Average flowmeter accuracy for low and high fuel flowrates and highest flowmeter accuracy of any level designated as mid, expressed as a percent of upper range value;
(xi) Indicator of whether test method was a lab comparison to reference meter or an in-line comparison against a master meter;
(xii) Test result (aborted, pass, or fail); and
(xiii) Description of fuel flowmeter calibration specification or procedure (in the certification application, or periodically if a different method is used for annual quality assurance testing).
(2) For each transmitter or transducer accuracy test for an orifice-, nozzle-, or venturi-type flowmeter used under section 2.1.6 of appendix D to this part:
(i) Component and system identification codes of the fuel flowmeter being tested;
(ii) Completion date and hour of test;
(iii) For each transmitter or transducer: transmitter or transducer type (differential pressure, static pressure, or temperature); the full-scale value of the transmitter or transducer, transmitter input (pre-calibration) prior to accuracy test, including units of measure; and expected transmitter output during accuracy test (reference value from NIST-traceable equipment), including units of measure;
(iv) For each transmitter or transducer tested: output during accuracy test, including units of measure; transmitter or transducer accuracy as a percent of the full-scale value; and transmitter output level as a percent of the full-scale value;
(v) Average flowmeter accuracy at low and high fuel flowrates and highest flowmeter accuracy of any level designated as mid fuel flowrate, expressed as a percent of upper range value;
(vi) Test result (pass, fail, or aborted);
(vii) Test number; and
(viii) Accuracy determination methodology.
(3) For each visual inspection of the primary element or transmitter or transducer accuracy test for an
(i) Date of inspection/test;
(ii) Hour of completion of inspection/test;
(iii) Component and system identification codes of the fuel flowmeter being inspected/tested; and
(iv) Results of inspection/test (pass or fail).
(4) For fuel flowmeters that are tested using the optional fuel flow-to-load ratio procedures of section 2.1.7 of appendix D to this part:
(i) Test data for the fuel flowmeter flow-to-load ratio or gross heat rate check, including:
(A) Component/system identification code;
(B) Calendar year and quarter;
(C) Indication of whether the test is for fuel flow-to-load ratio or gross heat rate;
(D) Quarterly average absolute percent difference between baseline for fuel flow-to-load ratio (or baseline gross heat rate and hourly quarterly fuel flow-to-load ratios (or gross heat rate value);
(E) Test result;
(F) Number of hours used in the analysis;
(G) Number of hours excluded due to co-firing;
(H) Number of hours excluded due to ramping; and
(I) Number of hours excluded in lower 25.0 percent range of operation.
(ii) Reference data for the fuel flowmeter flow-to-load ratio or gross heat rate evaluation, including:
(A) Completion date and hour of most recent primary element inspection;
(B) Completion date and hour of most recent flowmeter or transmitter accuracy test;
(C) Beginning date and hour of baseline period;
(D) Completion date and hour of baseline period;
(E) Average fuel flow rate, in 100 scfh for gas and lb/hr for oil;
(F) Average load, in megawatts or 1000 lb/hr of steam;
(G) Baseline fuel flow-to-load ratio, in the appropriate units of measure (if using fuel flow-to-load ratio);
(H) Baseline gross heat rate if using gross heat rate, in the appropriate units of measure (if using gross heat rate check);
(I) Number of hours excluded from baseline data due to ramping;
(J) Number of hours excluded from baseline data in lower 25.0 percent of range of operation;
(K) Average hourly heat input rate; and
(L) Flag indicating baseline data collection is in progress and that fewer than four calendar quarters have elapsed since the quarter of the last flowmeter QA test.
(5) For gas-fired peaking units or oil-fired peaking units using the optional procedures of appendix E to this part, for each initial performance, periodic, or quality assurance/quality control-related test:
(i) For each run of emission data, record the following data:
(A) Unit or common pipe identification code;
(B) Monitoring system identification code for appendix E system;
(C) Run start date and time;
(D) Run end date and time;
(E) Total heat input during the run (mmBtu);
(F) NO
(G) Response time of the O
(H) Type of fuel(s) combusted during the run;
(I) Heat input rate (mmBtu/hr) during the run;
(J) Test number;
(K) Run number;
(L) Operating level during the run;
(M) NO
(N) Diluent concentration recorded by the reference method during the run; and
(O) Moisture measurement for the run (if applicable).
(ii) For each run during which oil or mixed fuels are combusted record the following data:
(A) Unit or common pipe identification code;
(B) Monitoring system identification code for oil monitoring system;
(C) Run start date and time;
(D) Run end date and time;
(E) Mass flow or volumetric flow of oil, in the units of measure for the type of fuel flowmeter;
(F) Gross calorific value of oil in the appropriate units of measure;
(G) Density of fuel oil in the appropriate units of measure (if density is used to convert oil volume to mass);
(H) Hourly heat input (mmBtu) during run from oil;
(I) Test number;
(J) Run number; and
(K) Operating level during the run.
(iii) For each run during which gas or mixed fuels are combusted record the following data:
(A) Unit or common pipe identification code;
(B) Monitoring system identification code for gas monitoring system;
(C) Run start date and time;
(D) Run end date and time;
(E) Volumetric flow of gas (100 scf);
(F) Gross calorific value of gas (Btu/100 scf);
(G) Hourly heat input (mmBtu) during run from gas;
(H) Test number;
(I) Run number; and
(J) Operating level during the run.
(iv) For each operating level at which runs were performed:
(A) Completion date and time of last run for operating level;
(B) Type of fuel(s) combusted during test;
(C) Average heat input rate at that operating level (mmBtu/hr);
(D) Arithmetic mean of NO
(E) F-factor used in calculations of NO
(F) Unit operating parametric data related to NO
(G) Test number; and
(H) Operating level for runs.
(c) For units with add-on SO
(1) A list of operating parameters for the add-on emission controls, including parameters in § 75.55(b) or § 75.58(b), appropriate to the particular installation of add-on emission controls; and
(2) The range of each operating parameter in the list that indicates the add-on emission controls are properly operating.
(d)
(1) For each run of each test performed under section 2.1 of appendix E to this part, record the following data:
(i) Unit or common pipe identification code;
(ii) Run start date and time;
(iii) Run end date and time;
(iv) NO
(v) Response time of the O
(vi) Type of fuel(s) combusted during the run;
(vii) Test number;
(viii) Run number;
(ix) Operating level during the run;
(x) NO
(xi) Diluent concentration recorded by the reference method during the run;
(xii) Moisture measurement for the run (if applicable);
(xiii) An indicator that the resulting NO
(xiv) The default NO
(xv) An indicator that control equipment was operating or not operating during each run of the test; and
(xvi) Parameter data indicating the use and efficacy of control equipment during the test.
(2) For each unit in a group of identical units qualifying for reduced testing under § 75.19(c)(1)(iv)(B), record the following data:
(i) The unique group identification code assigned to the group. This code must include the ORIS code of one of the units in the group;
(ii) The ORIS code or facility identification code for the unit;
(iii) The plant name of the facility at which the unit is located, consistent with the facility's monitoring plan;
(iv) The identification code for the unit, consistent with the facility's monitoring plan;
(v) A record of whether or not the unit underwent fuel and unit-specific testing for purposes of establishing a fuel and unit-specific NO
(vi) The completion date of the fuel and unit-specific test performed for purposes of establishing a fuel and unit-specific NO
(vii) The fuel and unit-specific NO
(viii) The type of fuel combusted for the units during testing and represented by the resulting default NO
(ix) The control status for the units during testing and represented by the resulting default NO
(x) Documentation supporting the qualification of all units in the group for reduced testing based on the criteria established in §§ 75.19(c)(1)(iv)(B)(
(xi) Purpose of group tests.
(a) The designated representative for any affected unit subject to the requirements of this part shall comply with all reporting requirements in this section and with the signatory requirements of § 72.21 of this chapter for all submissions.
(b)
(1)
(2)
(3)
(4)
(5)
(6)
(c)
(1) All emission data reported in quarterly reports under § 75.64 shall remain public information.
(2) For information submitted under this part other than emission data submitted in quarterly reports, the designated representative must assert a claim of confidentiality at the time of submission for any information he or she wishes to have treated as confidential business information (CBI) under subpart B of part 2 of this chapter. Failure to assert a claim of confidentiality at the time of submission may result in disclosure of the information by EPA without further notice to the designated representative.
(3) Any claim of confidentiality for information submitted in quarterly reports under § 75.64 must include substantiation of the claim. Failure to provide substantiation may result in disclosure of the information by EPA without further notice.
(4) As provided under subpart B of part 2 of this chapter, EPA may review information submitted to determine
(a)
(1)
(i)
(ii)
(iii)
(iv)
(2)
(i) Notification of the planned date shall be submitted not later than 45 days prior to the date the unit commences commercial operation, or not later than 45 days prior to the date when a new stack or flue gas
(ii) If the date when the unit commences commercial operation or the date when the new stack or flue gas desulfurization system exhausts emissions to the atmosphere, whichever is applicable, changes from the planned date, a notification of the actual date shall be submitted not later than 7 days following: The date the unit commences commercial operation or, the date when a new stack or flue gas desulfurization system exhausts emissions to the atmosphere.
(3)
(i) For planned unit shutdowns, written notification of the planned shutdown date and planned date of recommencement of commercial operation shall be submitted 45 calendar days prior to the deadline in § 75.4(a). For unit shutdowns that are not planned 45 days prior to the deadline in § 75.4(a), written notification of the planned shutdown date and planned date of recommencement of commercial operation shall be submitted no later than 7 days after the date the owner or operator is able to schedule the shutdown date and date of recommencement of commercial operation. If the actual shutdown date or the actual date of recommencement of commercial operation differs from the planned date, written notice of the actual date shall be submitted no later than 7 days following the actual date of shutdown or of recommencement of commercial operation, as applicable;
(ii) For unplanned unit shutdowns, written notification of actual shutdown date and the expected date of recommencement of commercial operation shall be submitted no later than 7 days after the shutdown. If the actual date of recommencement of commercial operation differs from the expected date, written notice of the actual date shall be submitted no later than 7 days following the actual date of recommencement of commercial operation.
(4)
(5)
(i) Written notification under paragraph (a) (5) of this section may be provided either by mail or by facsimile. In addition, written notification may be provided by electronic mail, provided that the respective State agency or office of EPA agrees that this is an acceptable form of notification.
(ii) Notwithstanding the notice requirements under paragraph (a)(5) of this section, the owner or operator may elect to repeat a periodic relative accuracy test immediately, without additional notification whenever the owner or operator has determined that
(iii)
(6)
(i) For an affected oil-fired or gas-fired unit that is using an excepted monitoring system under appendix D or E of this part, where the owner or operator is postponing installation or testing of a fuel flowmeter for emergency fuel under § 75.4(g), the designated representative shall submit written notification of postponement of installation or testing no later than 45 days prior to the deadline in § 75.4(a). The designated representative shall also submit a notification that emergency fuel has been combusted no later than 7 days after the first date of combustion of the emergency fuel after the deadline in § 75.4(a).
(ii) The designated representative of a unit that has received approval of a petition under § 75.66 for exemption from one or more of the requirements of appendix E of this part for certification of an excepted monitoring system under appendix E of this part for a unit combusting emergency fuel shall submit written notice of each period of combustion of the emergency fuel with the next quarterly report submitted under § 75.64 for each calendar quarter in which emergency fuel is combusted, including notice specifying the exact dates and hours during which the emergency fuel was combusted. The reporting requirements of this paragraph (a)(6)(ii) also shall apply if the designated representative of a unit is exempt from certifying a fuel flowmeter for use during the combustion of emergency fuel under section 2.1.4.3 of appendix D to this part.
(b) The owner or operator or designated representative shall submit notification of certification tests and recertification tests for continuous opacity monitoring systems as specified in § 75.20(c)(8) to the State or local air pollution control agency.
(c) If the Administrator determines that notification substantially similar to that required in this section is required by any other State or local agency, the owner or operator or designated representative may send the Administrator a copy of that notification to satisfy the requirements of this section, provided the ORISPL unit identification number(s) is denoted.
(a)
(2)
(b)
(c)
(a)
(1)
(ii) Within 45 days after completing all initial certification tests, submit the hardcopy information required by paragraph (b)(2) to the applicable EPA Regional Office and the appropriate State and/or local air pollution control agency.
(iii) For units for which the owner or operator is applying for certification approval of the optional excepted methodology under § 75.19 for low mass emissions units, submit:
(A) To the Administrator, the electronic information required by paragraph (b)(1)(i), the hardcopy information required by paragraph (b)(2), and a hardcopy certification application form (EPA form 7610-14); and
(B) To the applicable EPA Regional Office and appropriate State and/or local air pollution control agency, the hardcopy information required by paragraphs (b)(2)(i), (iii), and (iv).
(2)
(ii) Within 45 days after completing all recertification tests, submit the hardcopy information required by paragraph (b)(2) to the applicable EPA Regional Office and the appropriate State and/or local air pollution control agency. The applicable EPA Regional Office or appropriate State or local air pollution control agency may waive the requirement for submission to it of a hardcopy recertification. The applicable EPA Regional Office or the appropriate State or local air pollution control agency may also discontinue the waiver and reinstate the requirement of this paragraph to provide a hardcopy report of the recertification test data and results.
(iii) Notwithstanding the requirements of paragraphs (a)(2)(i) and (a)(2)(ii) of this section, for an event for which the Administrator determines that only diagnostic tests (see § 75.20(b)) are required, no hardcopy submittal is required; however, the results of all diagnostic test(s) shall be submitted in the electronic quarterly report required under § 75.64. For DAHS (missing data and formula) verifications, neither a hardcopy nor an electronic submittal of any kind is required; the owner or operator shall keep these test results on-site in a format suitable for inspection.
(b)
(1)
(ii) The results of the test(s) required by § 75.20, including the type of test conducted, testing date, information required by § 75.56 or § 75.59, as applicable, and the results of any failed tests that affect data validation.
(2)
(ii) The results of the test(s) required by § 75.20, including the type of test conducted, testing date, information required by § 75.59(a)(9), and the results of any failed tests that affect data validation.
(iii) Certification or recertification application form (EPA form 7610-14).
(iv) Designated representative signature.
(c)
(a)
(1) Facility information:
(i) Identification, including:
(A) Facility/ORISPL number;
(B) Calendar quarter and year for the data contained in the report; and
(C) Version of the electronic data reporting format used for the report.
(ii) Location, including:
(A) Plant name and facility ID;
(B) EPA AIRS facility system ID;
(C) State facility ID;
(D) Source category/type;
(E) Primary SIC code;
(F) State postal abbreviation;
(G) County code; and
(H) Latitude and longitude.
(2) The information and hourly data required in §§ 75.53 through 75.59, excluding the following:
(i) Descriptions of adjustments, corrective action, and maintenance;
(ii) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan);
(iii) Opacity data listed in § 75.54(f) or § 75.57(f), and in § 75.59(a)(8);
(iv) For units with SO
(v) The information recorded under § 75.56(a)(7) for the period prior to April 1, 2000;
(vi) Information required by § 75.54(g) or § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes;
(vii) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.56 or § 75.59;
(viii) Records of flow monitor and moisture monitoring system polynomial equations, coefficients or “K” factors required by § 75.56(a)(5)(vii), § 75.56(a)(5)(ix), § 75.59(a)(5)(vi) or § 75.59(a)(5)(vii);
(ix) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D;
(x) Information required by §§ 75.59(b)(1)(vi), (vii), (viii), (ix), and (xiii), and (b)(2)(iii) and (iv) concerning fuel flowmeter accuracy tests and transmitter/transducer accuracy tests;
(xi) Stratification test results required as part of the RATA supplementary records under §§ 75.56(a)(7) or 75.59(a)(7);
(xii) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to problems unrelated to monitor performance; and
(xiv) Supplementary RATA information required under § 75.59(a)(7)(i) through § 75.59(a)(7)(v), except that: the data under § 75.59(a)(7)(ii)(A) through (T) and the data under § 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported for flow RATAs in which angular compensation (measurement of pitch and/or yaw angles) is used and for flow RATAs in which a site-specific wall effects adjustment factor is determined by direct measurement; and the data under § 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs in which a default wall effects adjustment factor is applied.
(3) Tons (rounded to the nearest tenth) of SO
(4) Average NO
(5) Tons of CO
(6) Total heat input (mmBtu) for quarter and cumulative heat input for calendar year.
(7) Unit or stack or common pipe header operating hours for quarter and cumulative unit or stack or common pipe header operating hours for calendar year.
(8) If the affected unit is using a qualifying Phase I technology, then the quarterly report shall include the information required in paragraph (e) of this section.
(9) For low mass emissions units for which the owner or operator is using the optional low mass emissions methodology in § 75.19(c) to calculate NO
(10) For low mass emissions units using the optional long term fuel flow methodology under § 75.19(c), for each quarter report the long term fuel flow for each fuel according to § 75.59.
(11) For units using the optional fuel flow to load procedure in section 2.1.7 of appendix D to this part, report both the fuel flow-to-load baseline data and the results of the fuel flow-to-load test each quarter.
(b) The designated representative shall affirm that the component/system identification codes and formulas in the quarterly electronic reports, submitted to the Administrator pursuant to § 75.53, represent current operating conditions.
(c)
(d)
(e)
(f)
(g) Any cover letter text accompanying a quarterly report shall either be submitted in hardcopy to the Agency or be provided in electronic format compatible with the other data required to be reported under this section.
The owner or operator or designated representative shall report excess emissions of opacity recorded under § 75.54(f) or § 75.57(f), as applicable, to the applicable State or local air pollution control agency.
(a)
(b)
(1) Identification of the affected unit(s);
(2) Description of why the minimum siting criteria cannot be met within the existing ductwork or stack(s). This description shall include diagrams of the existing ductwork or stack, as well as documentation of any attempts to locate a flow monitor; and
(3) Description of proposed alternative method for monitoring flow.
(c)
(1) A description of why the prescribed standard is not being used;
(2) A description and diagram(s) of any equipment and procedures used in the proposed alternative;
(3) Information demonstrating that the proposed alternative produces data acceptable for use in the Acid Rain Program, including accuracy and precision statements, NIST traceability certificates or protocols, or other supporting data, as applicable to the proposed alternative.
(d)
(e)
(1) Publish a notice in the
(2) Notify interested parties of receipt of a parametric monitoring petition.
(f)
(1) Data demonstrating that the affected unit's monitor data availability for the time period under petition was less than 90.0 percent;
(2) Data demonstrating that the add-on emission controls were operating properly during the time period under petition (i.e., operating parameters were within the ranges specified for proper operation of the add-on emission controls in the quality assurance/quality control program for the unit);
(3) A list of the average hourly values for the previous 720 quality-assured monitor operating hours, highlighting both the maximum recorded value and the value corresponding to the maximum controlled emission rate; and
(4) An explanation and information on operation of the add-on emission controls demonstrating that the selected historical SO
(g)
(1) A description of the units, including their fuel type, their boiler type, and their categorization as Phase I units, substitution units, compensating
(2) A formula describing how the emissions or heat input are to be apportioned to which units;
(3) A description of the methods and parameters used to apportion the emissions or heat input; and
(4) Any other information necessary to demonstrate that the apportionment method accurately measures emissions or heat input and does not underestimate emissions or heat input from affected units.
(h)
(1) Identification of the monitoring system(s) being changed;
(2) A description of the changes being made to the system;
(3) An explanation of why the changes are being made; and
(4) A description of the possible effect upon the monitoring system's ability to measure, record, and report emissions.
(i)
(1) Identification of the affected plant and unit(s);
(2) A procedure for determining the NO
(3) A demonstration that the permit restricts use of the fuel to emergencies only.
(j)
(1) Identification of the affected unit(s);
(2) A detailed explanation of the alternative method to account for emissions of the following parameters, as applicable: SO
(3) A demonstration that the proposed alternative does not underestimate emissions.
(k)
(l)
(1) Identification of the affected plant and unit(s);
(2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used in the proposed alternative, if applicable;
(4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and is consistent with the purposes of this part and of section 412 of the Act and that any adverse effect of approving such alternative will be
(5) Any other relevant information that the Administrator may require.
(a) [Reserved]
(b) For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter that will be permanently retired and governed upon entry into the Opt-in Program by a thermal energy plan in accordance with § 74.47 of this chapter, an exemption from the requirements of this part, including the requirement to install and certify a continuous emissions monitoring system, may be obtained from the Administrator if the designated representative submits to the Administrator a petition for such an exemption prior to the deadline in § 75.4 by which the continuous emission or opacity monitoring systems must complete the required certification tests.
(a)
(1) For purposes of this subpart, the term “affected unit” shall mean any unit that is subject to a State or federal NO
(2) In addition, the provisions of subparts A, C, D, E, F, and G and appendices A through G of this part applicable to NO
(b)
(c)
(2) No owner or operator of an affected unit or a non-affected unit under
(3) No owner or operator of an affected unit or a non-affected unit under § 75.72(b)(2)(ii) shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording NO
(4) No owner or operator of an affected unit or a non-affected unit under § 75.72(b)(2)(ii) shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, or any other approved emission monitoring system under this part, except under any one of the following circumstances:
(i) During the period that the unit is covered by a retired unit exemption that is in effect under the State or federal NO
(ii) The owner or operator is monitoring NO
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system in accordance with § 75.61.
(d)
(2) The owner or operator of an affected unit that is not subject to an Acid Rain emissions limitation shall comply with the initial certification and recertification procedures established by an applicable State or federal NO
(e)
(f)
(1) For an owner or operator using a continuous emissions monitoring system, substitute for missing data in accordance with the missing data procedures in subpart D of this part whenever the unit combusts fuel and:
(i) A valid quality assured hour of NO
(ii) A valid quality assured hour of flow data (in scfh) has not been measured and recorded for a unit from a certified flow monitor or by an approved alternative monitoring system under subpart E of this part; or
(iii) A valid quality assured hour of heat input data (in mmBtu) has not been measured and recorded for a unit from a certified flow monitor and a certified diluent (CO
(iv) A valid, quality-assured hour of NO
(2) For an owner or operator using an excepted monitoring system under appendix D or E of this part, substitute for missing data in accordance with the missing data procedures in section 2.4 of appendix D to this part or in section 2.5 of appendix E to this part whenever the unit combusts fuel and:
(i) A valid, quality-assured hour of fuel flow rate data has not been measured and recorded by a certified fuel flowmeter that is part of an excepted monitoring system under appendix D or E of this part; or
(ii) A fuel sample value for gross calorific value, or if necessary, density or specific gravity, from a sample taken an analyzed in accordance with appendix D of this part is not available; or
(iii) A valid, quality-assured hour of NO
(g)
(1) For units that the owner or operator intends to monitor for NO
(2) For units that the owner or operator intends to monitor for NO
(3) For any unit, the reference methods under § 75.22 of this part.
(4) For any unit using the low mass emission excepted monitoring methodology under § 75.19, the procedures in paragraphs (g)(1) or (2) of this section.
(5) Any unit using the procedures in paragraph (g)(2) of this section that is
(6) For any unit using continuous emissions monitors, the procedures in § 75.20(b)(3).
(h)
(2) Notwithstanding paragraph (h)(1) of this section, petitions requesting an alternative to a requirement concerning any additional CEMS required solely to meet the common stack provisions of § 75.72 shall be submitted to the permitting authority and the Administrator and shall be governed by paragraph (h)(3)(ii) of this section. Such a petition shall meet the requirements of § 75.66 and any additional requirements established by an applicable State or federal NO
(3)(i) The designated representative of an affected unit that is not subject to an Acid Rain emissions limitation may submit a petition to the permitting authority and the Administrator requesting an alternative to any requirement of this subpart. Such a petition shall meet the requirements of § 75.66 and any additional requirements established by an applicable State or federal NO
(ii) Use of an alternative to any requirement of this subpart is in accordance with this subpart only to the extent that it is approved by the Administrator and by the permitting authority if required by an applicable State or federal NO
(a)
(1) Meet the general operating requirements in § 75.10 for a NO
(2) Meet the general operating requirements in § 75.10 for a NO
(b)
(2) If a correction for the stack gas moisture content is needed to properly calculate NO
(3) If a correction for the stack gas moisture content is needed to properly calculate NO
(c)
(1) Meet the requirements of paragraph (a) of this section and, if applicable, paragraph (b) of this section; or
(2) Meet the general operating requirements in § 75.10 for a NO
(3) Meet the requirements of the low mass emission excepted methodology under paragraph (e)(2) of this section and under § 75.19, if applicable.
(d)
(1) Meet the requirements of paragraph (c) of this section; or
(2) Use the procedures in appendix D to this part for determining hourly heat input and the procedure specified in appendix E to this part for estimating hourly NO
(e)
(1) Meet the applicable requirements specified in paragraphs (c) or (d) of this section; or
(2) Use the low mass emissions excepted methodology in § 75.19(c) for estimating hourly emission rate, hourly heat input, and hourly NO
(f)
Except as provided in paragraphs (e) and (f) of this section, the owner or operator of an affected unit shall calculate hourly NO
(a)
(1) Record the combined NO
(i) Install, certify, operate, and maintain a flow monitoring system at the common stack. The owner or operator also shall provide heat input values for each unit, either by monitoring each unit individually using a flow monitor and a diluent monitor or by apportioning heat input according to the procedures in § 75.16(e)(5); or
(ii) If any of the units using the common stack are eligible to use the procedures in appendix D to this part,
(A) Use the procedures in appendix D to this part to determine heat input for that unit; and
(B) Install, certify, operate, and maintain a flow monitoring system in the duct to the common stack for each remaining unit; or
(2) Install, certify, operate, and maintain a NO
(i) Install, certify, operate, and maintain a flow monitoring system in the duct to the common stack from each unit; or
(ii) For any unit using the common stack and eligible to use the procedures in appendix D to this part,
(A) Use the procedures in appendix D to determine heat input for that unit; and
(B) Install, certify, operate, and maintain a flow monitoring system in the duct to the common stack for each remaining unit.
(b)
(1) Install, certify, operate, and maintain a NO
(i) Install, certify, operate, and maintain a flow monitoring system in the duct to the common stack from each affected unit; or
(ii) For any affected unit using the common stack and eligible to use the procedures in appendix D to this part,
(A) Use the procedures in appendix D to determine heat input for that unit; however, the heat input apportionment provisions in section 2.1.2 of appendix D to this part shall not be used to meet the NO
(B) Install, certify, operate, and maintain a flow monitoring system in the duct to the common stack for each remaining affected unit that exhausts to the common stack; or
(2) Install, certify, operate, and maintain a NO
(i) Designate the nonaffected units as affected units in accordance with the applicable State or federal NO
(ii) Install, certify, operate, and maintain a flow monitoring system in the common stack and a NO
(A) Install, certify, operate, and maintain a flow monitoring system in the duct from each nonaffected unit or,
(B) For any nonaffected unit exhausting to the common stack and otherwise eligible to use the procedures in appendix D to this part, determine heat input using the procedures in appendix D for that unit. However, the heat input apportionment provisions in section 2.1.2 of appendix D to this part shall not be used to meet the NO
(iii) Install a flow monitoring system in the common stack and record the combined emissions from all units as the combined NO
(iv) Submit a petition to the permitting authority and the Administrator to allow use of a method for apportioning NO
(c)
(1) Install, certify, operate, and maintain a NO
(2) Monitor NO
(d)
(1) Install, certify, operate, and maintain a NO
(2) Install, certify, operate, and maintain a NO
(3) If the unit is eligible to use the procedures in appendix D to this part, install, certify, operate, and maintain a NO
(i) There are no add-on NO
(ii) The unit is not capable of emitting solely through an unmonitored stack (e.g., has no dampers); and
(iii) The owner or operator of the unit demonstrates to the satisfaction of the permitting authority and the Administrator that the NO
(e)
(1) Install, certify, operate, and maintain a CO
(i) Apportion heat input from the common stack to each unit according to § 75.16(e)(5), where all units utilizing the common stack are affected units, or
(ii) Measure heat input from each affected unit, using a flow monitor and a CO
(2) For units that are eligible to use appendix D to this part, use the procedures in appendix D to this part to determine heat input for the unit. However, the use of a fuel flowmeter in a common pipe header and the provisions of sections 2.1.2.1 and 2.1.2.2 of appendix D of this part are not applicable to any unit that is using the provisions of this subpart to monitor, record, and report NO
(f)
(g)
(a)
(1) The information required in §§ 75.57(a)(2), (a)(4), (a)(5), (a)(6), (b), (c)(2), (d), (g), and (h).
(2) The information required in §§ 75.58(b)(2) or (b)(3) (for units with add-on NO
(3) For each hour when the unit is operating, NO
(4) During the second and third calendar quarters, cumulative ozone season heat input and cumulative ozone season operating hours.
(5) Heat input and NO
(6)
(i) For each hour when the unit is combusting oil:
(A) Date and hour;
(B) Hourly average mass flow rate of oil, while the unit combusts oil (in lb/hr, rounded to the nearest tenth) (flag value if derived from missing data procedures);
(C) Method of oil sampling (flow proportional, continuous drip, as delivered, manual from storage tank, or daily manual);
(D) For units using volumetric flowmeters, volumetric flow rate of oil combusted each hour (in gal/hr, lb/hr, m
(E) For units using volumetric oil flowmeters, density of oil (flag value if derived from missing data procedures);
(F) Gross calorific value of oil used to determine heat input (in Btu/lb);
(G) Hourly heat input rate during combustion of oil, according to procedures in appendix F to this part (in mmBtu/hr, to the nearest tenth);
(H) Fuel usage time for combustion of oil during the hour (rounded up to the nearest fraction of an hour, in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator) (flag to indicate multiple/single fuel types combusted); and
(I) Monitoring system identification code.
(ii) For gas-fired units or oil-fired units, using the procedures in appendix D to this part with an assumed density or for as-delivered fuel sampled from each delivery:
(A) Measured gross calorific value and, if measuring with volumetric oil flowmeters, density from each fuel sample; and
(B) Assumed gross calorific value and, if measuring with volumetric oil flowmeters, density used to calculate heat input rate.
(iii) For each hour when the unit is combusting gaseous fuel:
(A) Date and hour;
(B) Hourly heat input rate from gaseous fuel, according to procedures in appendix F to this part (in mmBtu/hr, rounded to the nearest tenth);
(C) Hourly flow rate of gaseous fuel, while the unit combusts gas (in 100 scfh) (flag value if derived from missing data procedures);
(D) Gross calorific value of gaseous fuel used to determine heat input rate (in Btu/100 scf) (flag value if derived from missing data procedures);
(E) Fuel usage time for combustion of gaseous fuel during the hour (rounded up to the nearest fraction of an hour, in equal increments that can range from one hundredth to one quarter of an hour, at the option of the owner or operator) (flag to indicate multiple/single fuel types combusted); and
(F) Monitoring system identification code.
(iv) For each oil sample or sample of diesel fuel:
(A) Date of sampling;
(B) Gross calorific value (in Btu/lb) (flag value if derived from missing data procedures); and
(C) Density or specific gravity, if required to convert volume to mass (flag value if derived from missing data procedures).
(v) For each sample of gaseous fuel:
(A) Date of sampling; and
(B) Gross calorific value (in Btu/100 scf) (flag value if derived from missing data procedures).
(vi) For each oil sample or sample of gaseous fuel:
(A) Type of oil or gas; and
(B) Percent carbon or F-factor of fuel.
(7)
(i) Date and hour;
(ii) If one type of fuel is combusted in the hour, fuel type (pipeline natural gas, natural gas, residual oil, or diesel fuel) or, if more than one type of fuel is combusted in the hour, the fuel type which results in the highest emission factors for NO
(iii) Average hourly NO
(iv) Hourly NO
(b)
(c)
(2) Whenever the owner or operator makes a replacement, modification, or change in the certified continuous emission monitoring system, excepted methodology under § 75.19, excepted monitoring system under appendix D or E to this part, or alternative monitoring system under subpart E of this part, including a change in the automated data acquisition and handling system or in the flue gas handling system, that affects information reported in the monitoring plan (e.g., a change to a serial number for a component of a monitoring system), then the owner or operator shall update the monitoring plan.
(3)
(d)
(2) The designated representative for an affected unit shall submit the following for each affected unit or group of units monitored at a common stack and each non-affected unit under § 75.72(b)(2)(ii):
(i) Initial certification and recertification applications in accordance with § 75.70(d);
(ii) Monitoring plans in accordance with paragraph (e) of this section; and
(iii) Quarterly reports in accordance with paragraph (f) of this section.
(3)
(4)
(5)
(e)
(i) To the permitting authority, no later than 45 days prior to the initial certification test and at the time of recertification application submission; and
(ii) To the Administrator, no later than 45 days prior to the initial certification test, at the time of submission of a recertification application, and in each electronic quarterly report.
(2)
(f)
(i) Facility information:
(A) Identification, including:
(
(
(
(B) Location of facility, including:
(
(
(
(
(
(
(
(
(ii) The information and hourly data required in paragraph (a) of this section, except for:
(A) Descriptions of adjustments, corrective action, and maintenance;
(B) Information which is incompatible with electronic reporting (e.g., field data sheets, lab analyses, quality control plan);
(C) For units with NO
(D) Information required by § 75.57(h) concerning the causes of any missing data periods and the actions taken to cure such causes;
(E) Hardcopy monitoring plan information required by § 75.53 and hardcopy test data and results required by § 75.59;
(F) Records of flow polynomial equations and numerical values required by § 75.59(a)(5)(vi);
(G) Daily fuel sampling information required by § 75.58(c)(3)(i) for units using assumed values under appendix D;
(H) Information required by § 75.59(b)(2) concerning transmitter or transducer accuracy tests;
(I) Stratification test results required as part of the RATA supplementary records under § 75.59(a)(7);
(J) Data and results of RATAs that are aborted or invalidated due to problems with the reference method or operational problems with the unit and data and results of linearity checks that are aborted or invalidated due to operational problems with the unit; and
(K) Supplementary RATA information required under § 75.59(a)(7)(i) through § 75.59(a)(7)(v), except that: the data under § 75.59(a)(7)(ii)(A) through (T) and the data under § 75.59(a)(7)(iii)(A) through (M) shall, as applicable, be reported for flow RATAs in which angular compensation (measurement of pitch and/or yaw angles) is used and for flow RATAs in which a site-specific wall effects adjustment factor is determined by direct measurement; and the data under § 75.59(a)(7)(ii)(T) shall be reported for all flow RATAs in which a default wall effects adjustment factor is applied.
(iii) Average NO
(iv) Tons of NO
(v) During the second and third calendar quarters, cumulative heat input for the ozone season.
(vi) Unit or stack or common pipe header operating hours for quarter, cumulative unit, stack or common pipe header operating hours for calendar year, and, during the second and third calendar quarters, cumulative operating hours during the ozone season.
(2) The designated representative shall certify that the component and system identification codes and formulas in the quarterly electronic reports submitted to the Administrator pursuant to paragraph (e) of this section represent current operating conditions.
(3)
(i) The monitoring data submitted were recorded in accordance with the applicable requirements of this part, including the quality assurance procedures and specifications; and
(ii) With regard to a unit with add-on emission controls and for all hours where data are substituted in accordance with § 75.34(a)(1), the add-on emission controls were operating within the
(4) The designated representative shall comply with all of the quarterly reporting requirements in §§ 75.64(d), (f), and (g).
(a)
(2) The owner or operator of an affected unit subject to a State or federal NO
(b)
(1) Meet the requirements of this subpart on an annual basis; or
(2) Meet the requirements of this subpart during the ozone season, except as specified in paragraph (c) of this section.
(c) If the owner or operator of an affected unit chooses to meet the requirements of this subpart on less than an annual basis in accordance with paragraph (b)(2) of this section, then:
(1) The owner or operator of a unit that uses continuous emissions monitoring systems or a fuel flowmeter to meet any of the requirements of this subpart shall quality assure the hourly ozone season emission data required by this subpart. To achieve this, the owner or operator shall operate, maintain and calibrate each required CEMS and shall perform diagnostic testing and quality assurance testing of each required CEMS or fuel flowmeter according to the applicable provisions of paragraphs (c)(2) through (c)(5) of this section. Except where otherwise noted, the provisions of paragraphs (c)(2) and (c)(3) of this section apply instead of the quality assurance provisions in sections 2.1 through 2.3 of appendix B to this part, and shall be used in lieu of those appendix B provisions.
(2)
(i) For each required gas monitor (i.e., for each NO
(A) Conduct each linearity check in accordance with the general procedures in section 6.2 of appendix A to this part, except that the data validation procedures in sections 6.2(a) through (f) of appendix A do not apply.
(B) Each linearity check shall be done “hands-off,” as described in section 2.2.3(c) of appendix B to this part.
(C) In the time period extending from the date and hour in which the linearity check is passed through April 30 of the current calendar year, the owner or operator shall operate and maintain the CEMS and shall perform daily calibration error tests of the CEMS in accordance with section 2.1 of appendix B to this part. When a calibration error test is failed, as described in section 2.1.4 of appendix B to this part, corrective actions shall be taken. The additional calibration error test provisions of section 2.1.3 of appendix B to this part shall be followed. Records of the required daily calibration error tests
(D)
(
(ii) For each required CEMS (i.e., for each NO
(A) Conduct each RATA in accordance with the applicable procedures in sections 6.5 through 6.5.10 of appendix A to this part, except that the data validation procedures in sections 6.5(f)(1) through (f)(6) do not apply, and, for flow rate monitoring systems, the required RATA load level(s) shall be as specified in this paragraph.
(B) Each RATA shall be done “hands-off,” as described in section 2.3.2 (c) of appendix B to this part. The provisions in section 2.3.1.4 of appendix B to this part, pertaining to the number of allowable RATA attempts, shall apply.
(C) For flow rate monitoring systems installed on peaking units or bypass stacks, a single-load RATA is required. For all other flow rate monitoring systems, a 2-load RATA is required at the two most frequently-used load levels (as defined under section 6.5.2.1 of appendix A to this part), with the following exceptions. A 3-load flow RATA is required at least once in every period of five consecutive calendar years. A 3-load RATA is also required if the flow monitor polynomial coefficients or K factor(s) are changed prior to conducting the flow RATA required under this paragraph.
(D) A bias test of each required NO
(E) In the time period extending from the hour of completion of the required RATA through April 30 of the current calendar year, the owner or operator shall operate and maintain the CEMS by performing, at a minimum, the following activities:
(
(
(F) If the results of a RATA performed according to the provisions of this paragraph indicate that the CEMS qualifies for an annual RATA frequency (see Figure 2 in appendix B to this part), the RATA may be used to quality assure data for the entire current ozone season.
(G) If the results of a RATA performed according to the provisions of this paragraph indicate that the CEMS qualifies for a semiannual RATA frequency rather than an annual frequency, provided that the RATA was completed on or after January 1 of the current calendar year, the RATA may be used to quality assure data for the entire current ozone season. However, if the RATA was performed in the fourth calendar quarter of the previous year, the RATA may only be used to quality assure data for a part of the current ozone season, from May 1 through June 30. An additional RATA is then required by June 30 of the current calendar year to quality assure the remainder of the data (from June 30 through September 30) for the current ozone season. If such an additional RATA is required but is not completed by June 30 of the current calendar year, data from the CEMS shall be considered invalid as of the first unit or stack operating hour subsequent to June 30 of the current calendar year and shall remain invalid until the required RATA is performed and passed.
(H)
(
(3)
(i) Daily calibration error tests and (if applicable) interference checks of each CEMS required by this subpart shall be performed in accordance with sections 2.1.1 and 2.1.2 of appendix B to this part. The applicable provisions in sections 2.1.3, 2.1.4 and 2.1.5 of appendix B to this part, pertaining, respectively, to additional calibration error tests and calibration adjustments, data validation, and quality assurance of data with respect to daily assessments, shall also apply.
(ii) For each gas monitor required by this subpart, linearity checks shall be performed in the second and third calendar quarters, in accordance with section 2.2.1 of appendix B to this part (see also paragraph (c)(3)(vii) of this section). For the second calendar quarter of the year, only unit or stack operating hours in the months of May and June shall be included when determining whether the second calendar quarter is a “QA operating quarter” (as defined in § 72.2 of this chapter). Data validation for these linearity checks shall be done in accordance with sections 2.2.3(a) through (e) of appendix B to this part. The grace period provision in section 2.2.4 of appendix B to this part does not apply to these linearity checks. If the required linearity check
(iii) For each flow monitoring system required by this subpart, flow-to-load ratio tests are required in the second and third calendar quarters, in accordance with section 2.2.5 of appendix B to this part. If the flow-to-load ratio test for the second calendar quarter is failed, the owner or operator shall declare the flow monitor out-of-control as of the first unit or stack operating hour following the second calendar quarter and shall either implement Option 1 in section 2.2.5.1 of appendix B to this part or Option 2 in section 2.2.5.2 of appendix B to this part. If the flow-to-load ratio test for the third calendar quarter is failed, data from the flow monitor shall be considered invalid at the beginning of the next ozone season unless, prior to May 1 of the next calendar year, the owner or operator has either successfully implemented Option 1 in section 2.2.5.1 of appendix B to this part or Option 2 in section 2.2.5.2 of appendix B to this part, or unless a flow RATA has been performed and passed in accordance with paragraph (c)(2)(ii) of this section.
(iv) For each differential pressure-type flow monitor used to meet the requirements of this subpart, quarterly leak checks are required in the second and third calendar quarters, in accordance with section 2.2.2 of appendix B to this part. For the second calendar quarter of the year, only unit or stack operating hours in the months of May and June shall be included when determining whether the second calendar quarter is a QA operating quarter (as defined in § 72.2 of this chapter). Data validation for quarterly flow monitor leak checks shall be done in accordance with section 2.2.3(g) of appendix B to this part. If the leak check for the third calendar quarter is failed and a subsequent leak check is not passed by the end of the ozone season, then data from the flow monitor shall be considered invalid at the beginning of the next ozone season unless a leak check is passed prior to May 1 of the next calendar year.
(v) A fuel flow-to-load ratio test in section 2.1.7 of appendix D to this part shall be performed in the second and third calendar quarters if, for a unit using a fuel flowmeter to determine heat input under this subpart, the owner or operator has elected to use the fuel flow-to-load ratio test to extend the deadline for the next fuel flowmeter accuracy test. If a fuel flow-to-load ratio test is failed, follow the applicable procedures and data validation provisions in section 2.1.7.4 of appendix D to this part. If the fuel flow-to-load ratio test for the third calendar quarter is failed, data from the fuel flowmeter shall be considered invalid at the beginning of the next ozone season unless the requirements of section 2.1.7.4 of appendix D to this part have been fully met prior to May 1 of the next calendar year.
(vi) If, at the start of the current ozone season (i.e., as of May 1 of the current calendar year), the linearity check or RATA required under paragraph (c)(2)(i) or (c)(2)(ii) of this section has not been performed for a particular monitor or monitoring system, and if, during the previous ozone season, the unit or stack on which the monitoring system is installed operated for 336 hours or more the owner or operator shall invalidate all data from the CEMS until either:
(A) The required linearity check or RATA of the CEMS has been performed and passed; or
(B) A “probationary calibration error test” of the CEMS is passed in accordance with § 75.20(b)(3). Note that a calibration error test passed on April 30 may be used as the probationary calibration error test, to ensure that emission data recorded by the CEMS at the beginning of the ozone season will have a conditionally valid status. Once the probationary calibration error test has been passed, the owner or operator shall perform the required linearity check or RATA in accordance with the conditional data validation provisions and within the associated timelines in § 75.20(b)(3), with the term “diagnostic”
(vii) A RATA which is performed and passed during the second or third quarter of the current calendar year may be used to quality assure data in the next ozone season, provided that:
(A) The results of the RATA indicate that the CEMS qualifies for an annual RATA frequency (see Figure 2 in appendix B to this part); and
(B) The CEMS is continuously operated and maintained, and daily calibration error tests and (if applicable) interference checks of the CEMS are performed in the time period extending from the end of the current ozone season (October 1 of the current calendar year) through April 30 of the next calendar year; and
(C) For a gas monitoring system, the linearity check requirement of paragraph (c)(2)(i) of this section is met prior to May 1 of the next calendar year.
(D) If conditions in paragraphs (c)(3)(vii)(A), (B) and, if applicable, (c)(3)(vii)(C) of this section are met, then a RATA completed and passed in the second or third calendar quarter of the current year may be used to quality assure data for the next ozone season, as follows:
(
(
(viii) If a linearity check performed to meet the requirement of paragraph (c)(2)(i) of this section is completed and passed in the second calendar quarter of the current year, provided that the date and hour of completion of the test is within the first 168 unit or stack operating hours of the current ozone season, the linearity check may be used to satisfy both the requirement of paragraph (c)(2)(i) of this section and to meet the second quarter linearity check requirement of paragraph (c)(3)(ii) of this section.
(ix) If, for any required CEMS, diagnostic linearity checks or RATAs other than those required by this section are performed during the ozone season, use the applicable data validation procedures in section 2.2.3 (for linearity checks) or 2.3.2 (for RATAs) of appendix B to this part.
(x) If any required CEMS is recertified within the ozone season, use the data validation provisions in § 75.20(b)(3) and paragraphs (c)(3)(xi) and (c)(3)(xii) of this section.
(xi) If, at the end of the second quarter of any calendar year, a required quality assurance, diagnostic or recertification test of a monitoring system has not been completed, and if data contained in the quarterly report are conditionally valid pending the results of test(s) to be completed in a subsequent quarter, the owner or operator shall indicate this by means of a suitable conditionally valid data flag in the electronic quarterly report for the second calendar quarter. The owner or operator shall resubmit the report for the second quarter if the required quality assurance, diagnostic or recertification test is subsequently failed. In the resubmitted report, the owner or operator shall use the appropriate missing data routine in § 75.31 or § 75.33 to replace with substitute data each hour of conditionally valid data that was invalidated by the failed quality assurance, diagnostic or recertification test. Alternatively, if any required quality assurance, diagnostic or recertification test is not completed by the end of the second calendar quarter but is completed no later than 30 days after the end of that quarter (i.e., prior to the deadline for submitting the quarterly report under § 75.73), the test data and results may be submitted with the second quarter report even though the test date(s) are from the third calendar quarter. In such instances, if the quality assurance, diagnostic or recertification test(s) are passed in accordance with the provisions of § 75.20(b)(3), conditionally valid data may be reported as quality-assured, in lieu of reporting a conditional data flag. If the tests are
(xii) If, at the end of the third quarter of any calendar year, a required quality assurance, diagnostic or recertification test of a monitoring system has not been completed, and if data contained in the quarterly report are conditionally valid pending the results of test(s) to be completed, the owner or operator shall do one of the following:
(A) If the results of the required tests are not available within 30 days of the end of the third calendar quarter and cannot be submitted with the quarterly report for the third calendar quarter, then the test results are considered to be missing and the owner or operator shall use the appropriate missing data routine in § 75.31 or § 75.33 to replace with substitute data each hour of conditionally valid data in the third quarter report. In addition, if the data in the second quarterly report were flagged as conditionally valid at the end of the quarter, pending the results of the same missing tests, the owner or operator shall resubmit the report for the second quarter and shall use the appropriate missing data routine in § 75.31 or § 75.33 to replace with substitute data each hour of conditionally valid data associated with the missing quality assurance, diagnostic or recertification tests; or
(B) If the required quality assurance, diagnostic or recertification tests are completed no later than 30 days after the end of the third calendar quarter, the test data and results may be submitted with the third quarter report even though the test date(s) are from the fourth calendar quarter. In this instance, if the required tests are passed in accordance with the provisions of § 75.20(b)(3), all conditionally valid data associated with the tests shall be reported as quality assured. If the tests are failed, the owner or operator shall use the appropriate missing data routine in § 75.31 or § 75.33 to replace with substitute data each hour of conditionally valid data associated with the failed test(s). In addition, if the data in the second quarterly report were flagged as conditionally valid at the end of the quarter, pending the results of the same failed test(s), the owner or operator shall resubmit the report for the second quarter and shall use the appropriate missing data routine in § 75.31 or § 75.33 to replace with substitute data each hour of conditionally valid data associated with the failed test(s).
(4) The owner or operator of a unit using the procedures in appendix D of this part to determine heat input is required to maintain fuel flowmeters only during the ozone season, except that for purposes of determining the deadline for the next periodic quality assurance test on the fuel flowmeter, the owner or operator shall include all fuel flowmeter QA operating quarters (as defined in § 72.2) for the entire calendar year, not just fuel flowmeter QA operating quarters in the ozone season. For each calendar year, the owner or operator shall record, for each fuel flowmeter, the number of fuel flowmeter QA operating quarters.
(5) The owner or operator of a unit using the procedures in appendix D of this part to determine heat input is only required to sample fuel for the purposes of determining density and GCV during the ozone season, except that:
(i) The owner or operator of a unit that performs sampling from the fuel storage tank upon delivery must sample the tank between the date and hour of the most recent delivery before the first date and hour that the unit operates in the ozone season and the first date and hour that the unit operates in the ozone season.
(ii) The owner or operator of a unit that performs sampling upon delivery from the delivery vehicle must ensure that all shipments received during the calendar year are sampled.
(iii) The owner or operator of a unit that performs sampling on each day the unit combusts fuel or that performs fuel sampling continuously must sample the fuel starting on the first day the unit operates during the ozone season. The owner or operator then shall use that sampled value for all hours of combustion during the first day of unit operation, continuing until the date and hour of the next sample.
(6) The owner or operator shall, in accordance with § 75.73, record and report the hourly data required by this subpart and shall record and report the results of all required quality assurance tests, as follows:
(i) All hourly emission data for the period of time from May 1 through September 30 of each calendar year shall be recorded and reported. For missing data purposes, only the data recorded in the time period from May 1 through September 30 shall be considered quality-assured;
(ii) The results of all daily calibration error tests and flow monitor interference checks performed in the time period from May 1 through September 30 shall be recorded and reported;
(iii) For the time periods described in paragraphs (c)(2)(i)(C) and (c)(2)(ii)(E) of this section, hourly emission data and the results of all daily calibration error tests and flow monitor interference checks shall be recorded. The results of all daily calibration error tests and flow monitor interference checks performed in the time period from April 1 through April 30 shall be reported. The owner or operator may also report the hourly emission data and unit operating data recorded in the time period from April 1 through April 30. However, only the emission data recorded in the time period from May 1 through September 30 shall be used for NO
(iv) The results of all required quality assurance tests (RATAs, linearity checks, flow-to-load ratio tests and leak checks) performed during the ozone season shall be reported in the appropriate ozone season quarterly report; and
(v) The results of RATAs (and any other quality assurance test(s) required under paragraph (c)(2) or (c)(3) of this section) which affect data validation for the current ozone season, but which were performed outside the ozone season (i.e., between October 1 of the previous calendar year and April 30 of the current calendar year), shall be reported in the quarterly report for the second quarter of the current calendar year.
(7) The owner or operator shall use only quality-assured data from within ozone seasons in the substitute data procedures under subpart D of this part and section 2.4.2 of appendix D to this part.
(i) The lookback periods (e.g., 2160 quality-assured monitor operating hours for a NO
(ii) The missing data procedures of §§ 75.31 through 75.33 shall be used, with two exceptions. First, when the NO
(A) For a unit that changed fuels, substitute the maximum potential values until the first hour when the unit combusts a fuel that produces the same or less NO
(B) For a unit with add-on emission controls that are not working properly, substitute the maximum potential values until the first hour in which the add-on emission controls are documented to be operating properly, according to paragraph (c)(8) of this section.
(8) The owner or operator of a unit with NO
(i) For units that can combust more than one fuel, the fuel or fuels combusted each hour; and
(ii) For units with add-on emission controls, the range of operating parameters for add-on emission controls, as described in § 75.34(a) and information for verifying proper operation of the add-on emission controls, as described in § 75.34(d).
(9) The designated representative shall certify with each quarterly report that NO
(10) Units may qualify to use the low mass emission excepted monitoring methodology in § 75.19 on an ozone season basis. In order to be allowed to use this methodology, a unit may not emit more than 25 tons of NO
(i) The phrase “50 tons of NO
(ii) If any low mass emission unit fails to provide a demonstration that its ozone season NO
(11) Units may qualify to use the optional NO
(a) The owner or operator of a unit that is required to calculate ozone season heat input for purposes of providing data needed for determining allocations, shall do so by summing the unit's hourly heat input determined according to the procedures in this part for all hours in which the unit operated during the ozone season.
(b) The owner or operator of a unit that is required to determine ozone season NO
Following the procedures in section 3.1 of Performance Specification 2 in appendix B to part 60 of this chapter, install the pollutant concentration monitor or monitoring system at a location where the pollutant concentration and emission rate measurements are directly representative of the total emissions
It is recommended that monitor measurements be made at locations where the exhaust gas temperature is above the dew-point temperature. If the cause of failure to meet the relative accuracy tests is determined to be the measurement location, relocate the monitor probe(s).
Locate the measurement point (1) within the centroidal area of the stack or duct cross section, or (2) no less than 1.0 meter from the stack or duct wall.
Locate the measurement path (1) totally within the inner area bounded by a line 1.0 meter from the stack or duct wall, or (2) such that at least 70.0 percent of the path is within the inner 50.0 percent of the stack or duct cross-sectional area, or (3) such that the path is centrally located within any part of the centroidal area.
Install the flow monitor in a location that provides representative volumetric flow over all operating conditions. Such a location is one that provides an average velocity of the flue gas flow over the stack or duct cross section, provides a representative SO
The installation of a flow monitor is acceptable if either (1) the location satisfies the minimum siting criteria of method 1 in appendix A to part 60 of this chapter (i.e., the location is greater than or equal to eight stack or duct diameters downstream and two diameters upstream from a flow disturbance; or, if necessary, two stack or duct diameters downstream and one-half stack or duct diameter upstream from a flow disturbance), or (2) the results of a flow profile study, if performed, are acceptable (i.e., there are no cyclonic (or swirling) or stratified flow conditions), and the flow monitor also satisfies the performance specifications of this part. If the flow monitor is installed in a location that does not satisfy these physical criteria, but nevertheless the monitor achieves the performance specifications of this part, then the location is acceptable, notwithstanding the requirements of this section.
Whenever the designated representative successfully demonstrates that modifications to the exhaust duct or stack (such as installation of straightening vanes, modifications of ductwork, and the like) are necessary for the flow monitor to meet the performance specifications, the Administrator may approve an interim alternative flow monitoring methodology and an extension to the required certification date for the flow monitor.
Whenever the owner or operator successfully demonstrates that modifications to the exhaust duct or stack (such as installation of straightening vanes, modifications of ductwork, and the like) are necessary for the flow monitor to meet the performance specifications, the Administrator may approve an interim alternative flow monitoring methodology and an extension to the required certification date for the flow monitor.
Where no location exists that satisfies the physical siting criteria in section 1.2.1, where the results of flow profile studies performed
In implementing sections 2.1.1 through 2.1.6 of this appendix, set the measurement range for each parameter (SO
Determine, as indicated in this section 2, the span value(s) and range(s) for an SO
(a) Make an initial determination of the maximum potential concentration (MPC) of SO
(b) Alternatively, if a certified SO
(c) When performing fuel sampling to determine the MPC, use ASTM Methods: ASTM D3177-89, “Standard Test Methods for Total Sulfur in the Analysis Sample of Coal and Coke”; ASTM D4239-85, “Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High Temperature Tube Furnace Combustion Methods”; ASTM D4294-90, “Standard Test Method for Sulfur in Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectroscopy”; ASTM D1552-90, “Standard Test Method for Sulfur in Petroleum Products (High Temperature Method)”; ASTM D129-91, “Standard Test Method for Sulfur in Petroleum Products (General Bomb Method)”; ASTM D2622-92, “Standard Test Method for Sulfur in Petroleum Products by X-Ray Spectrometry” for sulfur content of solid or liquid fuels; ASTM D3176-89, “Standard Practice for Ultimate Analysis of Coal and Coke”; ASTM D240-87 (Reapproved 1991), “Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter”; or ASTM D2015-91, “Standard Test Method for Gross Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter” for GCV (incorporated by reference under § 75.6).
All percent values to be inserted in the equations of this section are to be expressed as a percentage, not a fractional value (e.g., 3, not .03).
(a) Make an initial determination of the maximum expected concentration (MEC) of SO
(b) For each MEC determination, substitute into Equation A-1a or A-1b the highest sulfur content and minimum GCV value for that fuel or blend, based upon all available fuel sampling and analysis results from the previous 12 months (or more), or, if fuel sampling data are unavailable, based upon fuel contract(s).
(c) Alternatively, if a certified SO
Determine the high span value and the high full-scale range of the SO
For most units, the high span value based on the MPC, as determined under section 2.1.1.3 of this appendix will suffice to measure and record SO
(a) For units with SO
(b) For units that combust high- and low-sulfur primary and backup fuels (or blends) and have no SO
(c) When two SO
(d) The owner or operator shall designate the monitoring systems and components in the monitoring plan under § 75.53 as follows: designate the low and high monitor ranges as separate SO
(e) Each monitoring system designated as primary or redundant backup shall meet the initial certification and quality assurance requirements for primary monitoring systems in § 75.20(c) or § 75.20(d)(1), as applicable, and appendices A and B to this part, with one exception: relative accuracy test audits (RATAs) are required only on the normal range (for units with SO
(f) For dual span units with SO
(g) The high span value and range shall be determined in accordance with section 2.1.1.3 of this appendix. The low span value shall be obtained by multiplying the MEC by a factor no less than 1.00 and no greater than 1.25, and rounding the result upward to the next highest multiple of 10 ppm (or 100 ppm, as appropriate). For units that burn high- and low-sulfur primary and backup fuels or blends and have no SO
For each affected unit or common stack, the owner or operator shall make a periodic evaluation of the MPC, MEC, span, and range values for each SO
(a) If the fuel supply, the composition of the fuel blend(s), the emission controls, or the manner of operation change such that the maximum expected or potential concentration changes significantly, adjust the span and range setting to assure the continued accuracy of the monitoring system. A “significant” change in the MPC or MEC means that the guidelines in section 2.1 of this appendix can no longer be met, as determined by either a periodic evaluation by the owner or operator or from the results of an audit by the Administrator. The owner or operator should evaluate whether any planned changes in operation of the unit may affect the concentration of emissions being emitted from the unit or stack and should plan any necessary span and range changes needed to account for these changes, so that they are made in as timely a manner as practicable to coordinate with the operational changes. Determine the adjusted span(s) using the procedures in sections 2.1.1.3 and 2.1.1.4 of this appendix (as applicable). Select the full-scale range(s) of the instrument to be greater than or equal to the new span value(s) and to be consistent with the guidelines of section 2.1 of this appendix.
(b) Whenever a full-scale range is exceeded during a quarter and the exceedance is not caused by a monitor out-of-control period, proceed as follows:
(1) For exceedances of the high range, report 200.0 percent of the current full-scale range as the hourly SO
(2) For units with two SO
(c) Whenever changes are made to the MPC, MEC, full-scale range, or span value of the SO
Determine, as indicated in section 2.1.2.1, the span and range value(s) for the NO
(a) The maximum potential concentration (MPC) of NO
Option 1: Use 800 ppm for coal-fired and 400 ppm for oil- or gas-fired units as the maximum potential concentration of NO
Option 2: Use the specific values based on boiler type and fuel combusted, listed in Table 2-1 or Table 2-2;
Option 3: Use NO
Option 4: Use historical CEM data over the previous 720 (or more) unit operating hours when combusting the fuel or blend with the highest NO
(b) For the purpose of providing substitute data during NO
(c) Report the method of determining the initial MPC and the calculation of the maximum potential NO
(d) For units with add-on NO
(e) If historical CEM data are used to determine the MPC, the data must, for uncontrolled units or units equipped with low-NO
(a) Make an initial determination of the maximum expected concentration (MEC) of NO
(b) If NO
(c)If historical CEM data are used to determine the MEC value(s), the MEC for each type of fuel shall be based upon 720 (or more) hours of quality assured data representing the entire load range under stable operating conditions. The data base for the MEC shall not include any CEM data recorded during unit startup, shutdown, or malfunction or during any NO
(a) Determine the high span value of the NO
(b) If an existing State, local, or federal requirement for span of a NO
(c) Select the full-scale range of the instrument to be consistent with section 2.1 of this appendix and to be greater than or equal to the high span value. Include the full-scale range setting and calculations of the MPC and span in the monitoring plan for the unit.
For most units, the high span value based on the MPC, as determined under section 2.1.2.3 of this appendix will suffice to measure and record NO
(a) Compare the MEC value(s) determined in section 2.1.2.2 of this appendix to the high full-scale range value determined in section 2.1.2.3 of this appendix. If the MEC values for all fuels (or blends) are ≥20.0 percent of the high range value, the high span and range values determined under section 2.1.2.3 of this appendix are sufficient, irrespective of which fuel or blend is combusted in the unit. If any of the MEC values is <20.0 percent of the high range value, two spans (low and high) are required, one based on the MPC and the other based on the MEC.
(b) When two NO
(c) The owner or operator shall designate the monitoring systems and components in the monitoring plan under § 75.53 as follows: designate the low and high ranges as separate NO
(d) Each monitoring system designated as primary or redundant backup shall meet the initial certification and quality assurance requirements in § 75.20(c) (for primary monitoring systems), in § 75.20(d)(1) (for redundant backup monitoring systems) and appendices A and B to this part, with one exception: relative accuracy test audits (RATAs) are required only on the normal range (for dual span units with add-on NO
(e) For dual span units with add-on NO
(f) The high span and range shall be determined in accordance with section 2.1.2.3 of this appendix. The low span value shall be 100.0 to 125.0 percent of the MEC, rounded up to the next highest multiple of 10 ppm (or 100 ppm, if appropriate). If more than one MEC value (as determined in section 2.1.2.2 of this appendix) is <20.0 percent of the high full-scale range value, the low span value shall be based upon whichever MEC value is closest to 20.0 percent of the high range value. The low range must be greater than or equal to the low span value, and the required calibration gases for the low range must be selected based on the low span value. For units with two NO
For each affected unit or common stack, the owner or operator shall make a periodic evaluation of the MPC, MEC, span, and range values for each NO
(a) If the fuel supply, emission controls, or other process parameters change such that the maximum expected concentration or the maximum potential concentration changes significantly, adjust the NO
(b) Whenever a full-scale range is exceeded during a quarter and the exceedance is not caused by a monitor out-of-control period, proceed as follows:
(1) For exceedances of the high range, report 200.0 percent of the current full-scale range as the hourly NO
(2) For units with two NO
(c) Whenever changes are made to the MPC, MEC, full-scale range, or span value of the NO
For an O
For CO
The owner or operator of a unit that uses a flow monitor and an O
Adjust the span value and range of a CO
Select the full-scale range of the flow monitor so that it is consistent with section 2.1 of this appendix and can accurately measure all potential volumetric flow rates at the flow monitor installation site.
For this purpose, determine the span value of the flow monitor using the following procedure. Calculate the maximum potential velocity (MPV) using Equation A-3a or A-3b or determine the MPV (wet basis) from velocity traverse testing using Reference Method 2 (or its allowable alternatives) in appendix A to part 60 of this chapter. If using test values, use the highest average velocity (determined from the Method 2 traverses) measured at or near the maximum unit operating load. Express the MPV in units of wet standard feet per minute (fpm). For the purpose of providing substitute data during periods of missing flow rate data in accordance with §§ 75.31 and 75.33 and as required elsewhere in this part, calculate the maximum potential stack gas flow rate (MPF) in units of standard cubic feet per hour (scfh), as the product of the MPV (in units of wet, standard fpm) times 60, times the cross-sectional area of the stack or duct (in ft
Determine the span and range of the flow monitor as follows. Convert the MPV, as determined in section 2.1.4.1 of this appendix, to the same measurement units of flow rate that are used for daily calibration error tests (e.g., scfh, kscfh, kacfm, or differential pressure (inches of water)). Next, determine the “calibration span value” by multiplying the MPV (converted to equivalent daily calibration error units) by a factor no less than 1.00 and no greater than 1.25, and rounding up the result to at least two significant figures. For calibration span values in inches of water, retain at least two decimal places. Select appropriate reference signals for the daily calibration error tests as percentages of the calibration span value. Finally, calculate the “flow rate span value” (in scfh) as the product of the MPF, as determined in section 2.1.4.1 of this appendix, times the same factor (between 1.00 and 1.25) that was used to calculate the calibration span value. Round off the flow rate span value to the nearest 1000 scfh. Select the full-scale range of the flow monitor so that it is greater than or equal to the span value and is consistent with section 2.1 of this appendix. Include in the monitoring plan for the unit: calculations of the MPV, MPF, calibration span value, flow rate span value, and full-scale range (expressed both in scfh and, if different, in the measurement units of calibration).
For each affected unit or common stack, the owner or operator shall make a periodic evaluation of the MPV, MPF, span, and range values for each flow rate monitor (at a minimum, an annual evaluation is required) and shall make any necessary span and range adjustments with corresponding monitoring plan updates, as described in paragraphs (a) through (c) of this section 2.1.4.3. Span and range adjustments may be required, for example, as a result of changes in the fuel supply, changes in the stack or ductwork configuration, changes in the manner of operation of the unit, or installation or removal of emission controls. In implementing the provisions in paragraphs (a) and (b) of this section 2.1.4.3, note that flow rate data recorded during short-term, non-representative operating conditions (e.g., a trial burn of a different type of fuel) shall be excluded from consideration. The owner or operator shall keep the results of the most recent span and range evaluation on-site, in a format suitable for inspection. Make each required span or range adjustment no later than 45 days after the end of the quarter in which the need to adjust the span or range is identified.
(a) If the fuel supply, stack or ductwork configuration, operating parameters, or other conditions change such that the maximum potential flow rate changes significantly, adjust the span and range to assure the continued accuracy of the flow monitor. A “significant” change in the MPV or MPF means that the guidelines of section 2.1 of this appendix can no longer be met, as determined by either a periodic evaluation by the owner or operator or from the results of an audit by the Administrator. The owner or operator should evaluate whether any planned changes in operation of the unit may affect the flow of the unit or stack and should plan any necessary span and range changes needed to account for these changes, so that they are made in as timely a manner as practicable to coordinate with the operational changes. Calculate the adjusted calibration span and flow rate span values using the procedures in section 2.1.4.2 of this appendix.
(b) Whenever the full-scale range is exceeded during a quarter, provided that the exceedance is not caused by a monitor out-of-control period, report 200.0 percent of the current full-scale range as the hourly flow rate for each hour of the full-scale exceedance. If the range is exceeded, make appropriate adjustments to the MPF, flow rate
(c) Whenever changes are made to the MPV, MPF, full-scale range, or span value of the flow monitor, as described in paragraphs (a) and (b) of this section, record and report (as applicable) the new full-scale range setting, calculations of the flow rate span value, calibration span value, MPV, and MPF in an updated monitoring plan for the unit. The monitoring plan update shall be made in the quarter in which the changes become effective. Record and report the adjusted calibration span and reference values as parts of the records for the calibration error test required by appendix B to this part. Whenever the calibration span value is adjusted, use reference values for the calibration error test that meet the requirements of section 2.2.2.1 of this appendix, based on the most recent adjusted calibration span value. Perform a calibration error test according to section 2.1.1 of appendix B to this part whenever making a change to the flow monitor span or range, unless the range change also triggers a recertification under § 75.20(b).
Except as provided in section 2.1.6 of this appendix, the owner or operator of a unit that uses a continuous moisture monitoring system to correct emission rates and heat inputs from a dry basis to a wet basis (or vice-versa) shall, for the purpose of providing substitute data under § 75.37, use a default value of 3.0 percent H
When Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to determine NO
(a) The calibration error performance specifications in this section apply only to 7-day calibration error tests under sections 6.3.1 and 6.3.2 of this appendix and to the offline calibration demonstration described in section 2.1.1.2 of appendix B to this part. The calibration error limits for daily operation of the continuous monitoring systems required under this part are found in section 2.1.4(a) of appendix B to this part.
(b) The calibration error of SO
For SO
(1) The error in linearity for each calibration gas concentration (low-, mid-, and high-levels) shall not exceed or deviate from the reference value by more than 5.0 percent as calculated using equation A-4 of this appendix; or
(2) The absolute value of the difference between the average of the monitor response values and the average of the reference values,
The relative accuracy for SO
For affected units where the average of the monitor measurements of SO
(a) The relative accuracy for NO
(b) For affected units where the average of the monitoring system measurements of NO
The relative accuracy for CO
Except as provided below in this section, the relative accuracy for flow monitors, where volumetric gas flow is measured in scfh, shall not exceed 15.0 percent through December 31, 1999. Beginning on January 1, 2000 (except as provided below in this section), the relative accuracy of flow monitors shall not exceed 10.0 percent.
For affected units where the average of the flow monitor measurements of gas velocity during one or more operating levels of the relative accuracy test audit is less than or equal to 10.0 fps, the mean value of the flow monitor velocity measurements shall not exceed
The relative accuracy of a moisture monitoring system shall not exceed 10.0 percent. The relative accuracy test results are also acceptable if the mean difference of the reference method measurements (in percent H
(a) The following requirement applies only to NO
(b) The relative accuracy for NO
SO
Flow monitors shall not be biased low as determined by the test procedure in section 7.6 of this appendix. The bias specification applies to all flow monitors including those measuring an average gas velocity of 10.0 fps or less.
The cycle time for pollutant concentration monitors, oxygen monitors used to determine percent moisture, and any other continuous emission monitoring system(s) required to perform a cycle time test shall not exceed 15 minutes.
Automated data acquisition and handling systems shall read and record the full range of pollutant concentrations and volumetric flow from zero through span and provide a continuous, permanent record of all measurements and required information as an ASCII flat file capable of transmission both by direct computer-to-computer electronic transfer via modem and EPA-provided software and by an IBM-compatible personal computer diskette.
Data acquisition and handling systems shall also compute and record monitor calibration error; any bias adjustments to pollutant concentration, flow rate, or NO
For an excepted monitoring system under appendix D or E of this part, data acquisition and handling systems shall:
(1) Read and record the full range of fuel flowrate through the upper range value;
(2) Calculate and record intermediate values necessary to obtain emissions, such as mass fuel flowrate and heat input rate;
(3) Calculate and record emissions in units of the standard (lb/hr of SO
(4) Predict and record NO
(5) Calculate and record all missing data substitution values specified in appendix D or E of this part; and
(6) Provide a continuous, permanent record of all measurements and required information as an ASCII flat file capable of transmission both by direct computer-to-computer electronic transfer via modem and EPA-provided software and by an IBM-compatible personal computer diskette.
For the purposes of part 75, calibration gases include the following:
These calibration gases may be obtained from the National Institute of Standards and Technology (NIST) at the following address: Quince Orchard and Cloppers Road, Gaithersburg, MD 20899-0001.
Contact the Gas Metrology Team, Analytical Chemistry Division, Chemical Science and Technology Laboratory of NIST, at the address in section 5.1.1, for a list of vendors and cylinder gases.
Contact the Gas Metrology Team, Analytical Chemistry Division, Chemical Science and Technology Laboratory of NIST, at the address in section 5.1.1, for a list of vendors and cylinder gases.
(a) EPA Protocol gases must be vendor-certified to be within 2.0 percent of the concentration specified on the cylinder label (tag value), using the uncertainty calculation procedure in section 2.1.8 of the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, EPA-600/R-97/121.
(b) A copy of EPA-600/R-97/121 is available from the National Technical Information Service, 5285 Port Royal Road, Springfield, VA, 703-487-4650 and from the Office of Research and Development, (MD-77B), U.S. Environmental Protection Agency, Research Triangle Park, NC 27711.
Research gas mixtures must be vendor-certified to be within 2.0 percent of the concentration specified on the cylinder label (tag value), using the uncertainty calculation procedure in section 2.1.8 of the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, EPA-600/R-97/121. Inquiries about the RGM program should be directed to: National Institute of Standards and Technology, Analytical Chemistry Division, Chemical Science and Technology Laboratory, B-324 Chemistry, Gaithersburg, MD 20899.
Zero air material is defined in § 72.2 of this chapter.
Existing certified reference materials (CRMs) that are still within their certification period may be used as calibration gas.
Gas manufacturer's intermediate standards is defined in § 72.2 of this chapter.
Four concentration levels are required as follows.
0.0 to 20.0 percent of span, including span for high-scale or both low- and high-scale for SO
20.0 to 30.0 percent of span, including span for high-scale or both low- and high-scale for SO
50.0 to 60.0 percent of span, including span for high-scale or both low- and high-scale for SO
80.0 to 100.0 percent of span, including span for high-scale or both low-and high-scale for SO
Install the components of the continuous emission monitoring system (i.e., pollutant concentration monitors, CO
Check the linearity of each SO
(a) For the initial certification of a CEMS, data from the monitoring system are considered invalid until all certification tests, including the linearity test, have been successfully completed, unless the data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial certification” apply instead of “recertification,” and complete all of the initial certification tests by the applicable deadline in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv) for the individual tests.
(b) For the routine quality assurance linearity checks required by section 2.2.1 of appendix B to this part, use the data validation procedures in section 2.2.3 of appendix B to this part.
(c) When a linearity test is required as a diagnostic test or for recertification, use the data validation procedures in § 75.20(b)(3).
(d) For linearity tests of non-redundant backup monitoring systems, use the data validation procedures in § 75.20(d)(2)(iii).
(e) For linearity tests performed during a grace period and after the expiration of a grace period, use the data validation procedures in sections 2.2.3 and 2.2.4, respectively, of appendix B to this part.
(f) For all other linearity checks, use the data validation procedures in section 2.2.3 of appendix B to this part.
Measure the calibration error of each SO
(a) For initial certification, data from the monitor are considered invalid until all certification tests, including the 7-day calibration error test, have been successfully completed, unless the data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial
(b) When a 7-day calibration error test is required as a diagnostic test or for recertification, use the data validation procedures in § 75.20(b)(3).
Perform the 7-day calibration error test of a flow monitor, when required for certification, recertification or diagnostic testing, according to the following procedures. Introduce the reference signal corresponding to the values specified in section 2.2.2.1 of this appendix to the probe tip (or equivalent), or to the transducer. During the 7-day certification test period, conduct the calibration error test while the unit is operating once each unit operating day (as close to 24-hour intervals as practicable). In the event that extended unit outages occur after the commencement of the test, the 7 consecutive operating days need not be 7 consecutive calendar days. Record the flow monitor responses by means of the data acquisition and handling system. Calculate the calibration error using Equation A-6 of this appendix. Do not perform any corrective maintenance, repair, or replacement upon the flow monitor during the 7-day test period other than that required in the quality assurance/quality control plan required by appendix B to this part. Do not make adjustments between the zero and high reference level measurements on any day during the 7-day test. If the flow monitor operates within the calibration error performance specification (i.e., less than or equal to 3.0 percent error each day and requiring no corrective maintenance, repair, or replacement during the 7-day test period), the flow monitor passes the calibration error test. Record all maintenance activities and the magnitude of any adjustments. Record output readings from the data acquisition and handling system before and after all adjustments. Record and report all calibration error test results using the unadjusted flow rate measured in the calibration error test prior to resetting the calibration. Record all adjustments made during the 7-day period at the time the adjustment is made, and report them in the certification or recertification application. The status of emissions data from a flow monitor prior to and during a 7-day calibration error test period shall be determined as follows:
(a) For initial certification, data from the monitor are considered invalid until all certification tests, including the 7-day calibration error test, have been successfully completed, unless the data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial certification” apply instead of “recertification,” and complete all of the initial certification tests by the applicable deadline in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv) for the individual tests.
(b) When a 7-day calibration error test is required as a diagnostic test or for recertification, use the data validation procedures in § 75.20(b)(3).
Perform cycle time tests for each pollutant concentration monitor and continuous emission monitoring system while the unit is operating, according to the following procedures (see also Figure 6 at the end of this appendix). Use a zero-level and a high-level calibration gas (as defined in section 5.2 of this appendix) alternately. To determine the upscale elapsed time, inject a zero-level concentration calibration gas into the probe tip (or injection port leading to the calibration cell, for in situ systems with no probe). Record the stable starting gas value and start time, using the data acquisition and handling system (DAHS). Next, allow the monitor to measure the concentration of flue gas emissions until the response stabilizes. Record the stable ending stack emissions value and the end time of the test using the DAHS. Determine the upscale elapsed time as the time it takes for 95.0 percent of the step change to be achieved between the stable starting gas value and the stable ending stack emissions value. Then repeat the procedure, starting by injecting the high-level gas concentration to determine the downscale elapsed time, which is the time it takes for 95.0 percent of the step change to be achieved between the stable starting gas value and the stable ending stack emissions value. End the downscale test by measuring the stable concentration of flue gas emissions. Record the stable starting and ending monitor values, the start and end times, and the downscale elapsed time for the monitor using the DAHS. A stable value is equivalent to a reading with a change of less than 2.0 percent of the span value for 2 minutes, or a reading with a change of less than 6.0 percent from the measured average concentration over 6 minutes. (Owners or operators of systems which do not record data in 1-minute or 3-minute intervals may petition the Administrator under § 75.66 for alternative stabilization criteria). For monitors or monitoring systems that perform a series of operations (such as purge, sample, and analyze), time the injections of the calibration gases so they will produce the longest possible cycle time. Report the slower of the two elapsed times (upscale or downscale) as the cycle time for the analyzer. (See Figure
(a) For initial certification, data from the monitor are considered invalid until all certification tests, including the cycle time test, have been successfully completed, unless the data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial certification” apply instead of “recertification,” and complete all of the initial certification tests by the applicable deadline in § 75.4, rather than within the time periods specified in § 75.20(b)(3)(iv) for the individual tests.
(b) When a cycle time test is required as a diagnostic test or for recertification, use the data validation procedures in § 75.20(b)(3).
Perform the required relative accuracy test audits (RATAs) as follows for each CO
(a) Except as provided in § 75.21(a)(5), perform each RATA while the unit (or units, if more than one unit exhausts into the flue) is combusting the fuel that is normal for that unit (for some units, more than one type of fuel may be considered normal, e.g., a unit that combusts gas or oil on a seasonal basis). When relative accuracy test audits are performed on continuous emission monitoring systems or component(s) on bypass stacks/ducts, use the fuel normally combusted by the unit (or units, if more than one unit exhausts into the flue) when emissions exhaust through the bypass stack/ducts.
(b) Perform each RATA at the load level(s) specified in section 6.5.1 or 6.5.2 of this appendix or in section 2.3.1.3 of appendix B to this part, as applicable.
(c) For monitoring systems with dual ranges, perform the relative accuracy test on the range normally used for measuring emissions. For units with add-on SO
(d) Record monitor or monitoring system output from the data acquisition and handling system.
(e) Complete each single-load relative accuracy test audit within a period of 168 consecutive unit operating hours, as defined in § 72.2 of this chapter (or, for CEMS installed on common stacks or bypass stacks, 168 consecutive stack operating hours, as defined in § 72.2 of this chapter). For 2-level and 3-level flow monitor RATAs, complete all of the RATAs at all levels, to the extent practicable, within a period of 168 consecutive unit (or stack) operating hours; however, if this is not possible, up to 720 consecutive unit (or stack) operating hours may be taken to complete a multiple-load flow RATA.
(f) The status of emission data from the CEMS prior to and during the RATA test period shall be determined as follows:
(1) For the initial certification of a CEMS, data from the monitoring system are considered invalid until all certification tests, including the RATA, have been successfully completed, unless the data validation procedures in § 75.20(b)(3) are used. When the procedures in § 75.20(b)(3) are followed, the words “initial certification” apply instead of “recertification,” and complete all of the initial certification tests by the applicable deadline in § 75.4, rather than within the time periods
(2) For the routine quality assurance RATAs required by section 2.3.1 of appendix B to this part, use the data validation procedures in section 2.3.2 of appendix B to this part.
(3) For recertification RATAs, use the data validation procedures in § 75.20(b)(3).
(4) For quality assurance RATAs of non-redundant backup monitoring systems, use the data validation procedures in §§ 75.20(d)(2)(v) and (vi).
(5) For RATAs performed during and after the expiration of a grace period, use the data validation procedures in sections 2.3.2 and 2.3.3, respectively, of appendix B to this part.
(6) For all other RATAs, use the data validation procedures in section 2.3.2 of appendix B to this part.
(g) For each SO
(a) Perform the required relative accuracy test audits for each SO
(b) For the initial certification of a gas monitoring system and for recertifications in which, in addition to a RATA, one or more other tests are required (i.e., a linearity test, cycle time test, or 7-day calibration error test), EPA recommends that the RATA not be commenced until the other required tests of the CEMS have been passed.
(a) Except for flow monitors on bypass stacks/ducts and peaking units, perform relative accuracy test audits for the initial certification of each flow monitor at three different exhaust gas velocities (low, mid, and high), corresponding to three different load levels within the range of operation, as defined in section 6.5.2.1 of this appendix. For a common stack/duct, the three different exhaust gas velocities may be obtained from frequently used unit/load combinations for the units exhausting to the common stack. Select the three exhaust gas velocities such that the audit points at adjacent load levels (i.e., low and mid or mid and high), in megawatts (or in thousands of lb/hr of steam production), are separated by no less than 25.0 percent of the range of operation, as defined in section 6.5.2.1 of this appendix.
(b) For flow monitors on bypass stacks/ducts and peaking units, the flow monitor relative accuracy test audits for initial certification and recertification shall be single-load tests, performed at the normal load, as defined in section 6.5.2.1 of this appendix.
(c) Flow monitor recertification RATAs shall be done at three load level(s), unless otherwise specified in paragraph (b) of this section or unless otherwise specified or approved by the Administrator.
(d) The semiannual and annual quality assurance flow monitor RATAs required under appendix B to this part shall be done at the load level(s) specified in section 2.3.1.3 of appendix B to this part.
(a) The owner or operator shall determine the upper and lower boundaries of the “range of operation” for each unit (or combination of units, for common stack configurations) that uses CEMS to account for its emissions and for each unit that uses the optional fuel flow-to-load quality assurance test in section 2.1.7 of appendix D to this part. The lower boundary of the range of operation of a unit shall be the minimum safe, stable load. For common stacks, the minimum safe, stable load shall be the lowest of the minimum safe, stable loads for any of the units discharging through the stack. Alternatively, for a group of frequently-operated units that serve a common stack, the sum of the minimum safe, stable loads for the individual units may be used as the lower boundary of the range of operation. The upper boundary of the range of operation of a unit shall be the maximum sustainable load. The “maximum sustainable load” is the higher of either: the nameplate or rated capacity of the unit, less any physical or regulatory limitations or other deratings; or the highest sustainable unit load, based on at least four
(b) The operating levels for relative accuracy test audits shall, except for peaking units, be defined as follows: the “low” operating level shall be the first 30.0 percent of the range of operation; the “mid” operating level shall be the middle portion (30.0 to 60.0 percent) of the range of operation; and the “high” operating level shall be the upper end (60.0 to 100.0 percent) of the range of operation. For example, if the upper and lower boundaries of the range of operation are 100 and 1100 megawatts, respectively, then the low, mid, and high operating levels would be 100 to 400 megawatts, 400 to 700 megawatts, and 700 to 1100 megawatts, respectively.
(c) The owner or operator shall identify, for each affected unit or common stack (except for peaking units), the “normal” load level or levels (low, mid or high), based on the operating history of the unit(s). This requirement becomes effective on April 1, 2000; however, the owner or operator may choose to comply with this requirement prior to April 1, 2000. To identify the normal load level(s), the owner or operator shall, at a minimum, determine the relative number of operating hours at each of the three load levels, low, mid and high over the past four representative operating quarters. The owner or operator shall determine, to the nearest 0.1 percent, the percentage of the time that each load level (low, mid, high) has been used during that time period. A summary of the data used for this determination and the calculated results shall be kept on-site in a format suitable for inspection.
(d) Based on the analysis of the historical load data the owner or operator shall designate the most frequently used load level as the normal load level for the unit (or combination of units, for common stacks). The owner or operator may also designate the second most frequently used load level as an additional normal load level for the unit or stack. For peaking units, normal load designations are unnecessary; the entire operating load range shall be considered normal. If the manner of operation of the unit changes significantly, such that the designated normal load(s) or the two most frequently used load levels change, the owner or operator shall repeat the historical load analysis and shall redesignate the normal load(s) and the two most frequently used load levels, as appropriate. A minimum of two representative quarters of historical load data are required to document that a change in the manner of unit operation has occurred.
(e) Beginning on April 1, 2000, the owner or operator shall report the upper and lower boundaries of the range of operation for each unit (or combination of units, for common stacks), in units of megawatts or thousands of lb/hr of steam production, in the electronic quarterly report required under § 75.64. Except for peaking units, the owner or operator shall indicate, in the electronic quarterly report (as part of the electronic monitoring plan) the load level (or levels) designated as normal under this section and shall also indicate the two most frequently used load levels..
For each multi-load flow RATA, calculate the flow monitor relative accuracy at each operating level. If a flow monitor relative accuracy test is failed or aborted due to a problem with the monitor on any level of a 2-level (or 3-level) relative accuracy test audit, the RATA must be repeated at that load level. However, the entire 2-level (or 3-level) relative accuracy test audit does not have to be repeated unless the flow monitor polynomial coefficients or K-factor(s) are changed, in which case a 3-level RATA is required.
Perform relative accuracy test audits for each CO
Using the data from the relative accuracy test audits, calculate relative accuracy and bias in accordance with the procedures and equations specified in section 7 of this appendix.
Select a location for reference method measurements that is (1) accessible; (2) in the same proximity as the monitor or monitoring system location; and (3) meets the requirements of Performance Specification 2 in appendix B of part 60 of this chapter for SO
Select traverse points that ensure acquisition of representative samples of pollutant and diluent concentrations, moisture content, temperature, and flue gas flow rate over the flue cross section. To achieve this, the reference method traverse points shall meet the requirements of section 3.2 of Performance Specification 2 (“PS No. 2”) in appendix B to part 60 of this chapter (for SO
(a) For moisture determinations where the moisture data are used only to determine stack gas molecular weight, a single reference method point, located at least 1.0 meter from the stack wall, may be used. For moisture monitoring system RATAs and for gas monitor RATAs in which moisture data are used to correct pollutant or diluent concentrations from a dry basis to a wet basis (or vice-versa), single-point moisture sampling may only be used if the 12-point stratification test described in section 6.5.6.1 of this appendix is performed prior to the RATA for at least one pollutant or diluent gas, and if the test is passed according to the acceptance criteria in section 6.5.6.3(b) of this appendix.
(b) For gas monitoring system RATAs, the owner or operator may use any of the following options:
(1) At any location (including locations where stratification is expected), use a minimum of six traverse points along a diameter, in the direction of any expected stratification. The points shall be located in accordance with Method 1 in appendix A to part 60 of this chapter.
(2) At locations where section 3.2 of PS No. 2 allows the use of a short reference method measurement line (with three points located at 0.4, 1.0, and 2.0 meters from the stack wall), the owner or operator may use an alternative:3-point measurement line, locating the three points at 4.4, 14.6, and 29.6 percent of the way across the stack, in accordance with Method 1 in appendix A to part 60 of this chapter.
(3) At locations where stratification is likely to occur (e.g., following a wet scrubber or when dissimilar gas streams are combined), the short measurement line from section 3.2 of PS No. 2 (or the alternative line described in paragraph (b)(2) of this section) may be used in lieu of the prescribed “long” measurement line in section 3.2 of PS No. 2, provided that the 12-point stratification test described in section 6.5.6.1 of this appendix is performed and passed one time at the location (according to the acceptance criteria of section 6.5.6.3(a) of this appendix) and provided that either the 12-point stratification test or the alternative (abbreviated) stratification test in section 6.5.6.2 of this appendix is performed and passed prior to each subsequent RATA at the location (according to the acceptance criteria of section 6.5.6.3(a) of this appendix).
(4) A single reference method measurement point, located no less than 1.0 meter from the stack wall and situated along one of the measurement lines used for the stratification test, may be used at any sampling location if the 12-point stratification test described in section 6.5.6.1 of this appendix is performed and passed prior to each RATA at the location (according to the acceptance criteria of section 6.5.6.3(b) of this appendix).
(a) With the unit(s) operating under steady-state conditions at normal load, as defined in section 6.5.2.1 of this appendix, use a traversing gas sampling probe to measure the pollutant (SO
(b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this chapter to make the measurements. Data from the reference method analyzers must be quality assured by performing analyzer calibration error and system bias checks before the series of measurements and by conducting system bias and calibration drift checks after the measurements, in accordance with the procedures of Methods 6C, 7E, and 3A.
(c) Measure for a minimum of 2 minutes at each traverse point. To the extent practicable, complete the traverse within a 2-hour period.
(d) If the load has remained constant (
(e) Calculate the average NO
(a) With the unit(s) operating under steady-state conditions at normal load, as
(b) Use Methods 6C, 7E, and 3A in appendix A to part 60 of this chapter to make the measurements. Data from the reference method analyzers must be quality assured by performing analyzer calibration error and system bias checks before the series of measurements and by conducting system bias and calibration drift checks after the measurements, in accordance with the procedures of Methods 6C, 7E, and 3A.
(c) Measure for a minimum of 2 minutes at each traverse point. To the extent practicable, complete the traverse within a 1-hour period.
(d) If the load has remained constant (
(e) Calculate the average NO
(a) For each pollutant or diluent gas, the short reference method measurement line described in section 3.2 of PS No. 2 may be used in lieu of the long measurement line prescribed in section 3.2 of PS No. 2 if the results of a stratification test, conducted in accordance with section 6.5.6.1 or 6.5.6.2 of this appendix (as appropriate; see section 6.5.6(b)(3) of this appendix), show that the concentration at each individual traverse point differs by no more than
(b) For each pollutant or diluent gas, a single reference method measurement point, located at least 1.0 meter from the stack wall and situated along one of the measurement lines used for the stratification test, may be used for that pollutant or diluent gas if the results of a stratification test, conducted in accordance with section 6.5.6.1 of this appendix, show that the concentration at each individual traverse point differs by no more than
(c) The owner or operator shall keep the results of all stratification tests on-site, in a format suitable for inspection, as part of the supplementary RATA records required under § 75.56(a)(7) or § 75.59(a)(7), as applicable.
(a) Conduct the reference method tests so they will yield results representative of the pollutant concentration, emission rate, moisture, temperature, and flue gas flow rate from the unit and can be correlated with the pollutant concentration monitor, CO
(b) To properly correlate individual SO
Confirm that the monitor or monitoring system and reference method test results are on consistent moisture, pressure, temperature, and diluent concentration basis (e.g., since the flow monitor measures flow rate on a wet basis, method 2 test results must also be on a wet basis). Compare flow-monitor and reference method results on a scfh basis. Also, consider the response times of the pollutant concentration monitor, the continuous emission monitoring system, and the flow monitoring system to ensure comparison of simultaneous measurements.
For each relative accuracy test audit run, compare the measurements obtained from the monitor or continuous emission monitoring system (in ppm, percent CO
Perform a minimum of nine sets of paired monitor (or monitoring system) and reference method test data for every required (i.e., certification, recertification, diagnostic, semiannual, or annual) relative accuracy test audit. For 2-level and 3-level relative accuracy test audits of flow monitors, perform a minimum of nine sets at each of the operating levels.
The tester may choose to perform more than nine sets of reference method tests. If this option is chosen, the tester may reject a maximum of three sets of the test results, as long as the total number of test results used to determine the relative accuracy or bias is greater than or equal to nine. Report all data, including the rejected CEMS data and corresponding reference method test results.
The following methods from appendix A to part 60 of this chapter or their approved alternatives are the reference methods for performing relative accuracy test audits: Method 1 or 1A for siting; Method 2 or its allowable alternatives in appendix A to part 60 of this chapter (except for Methods 2B and 2E) for stack gas velocity and volumetric flow rate; Methods 3, 3A, or 3B for O
Analyze the linearity data for pollutant concentration and CO
For each reference value, calculate the percentage calibration error based upon instrument span for daily calibration error tests using the following equation:
For each reference value, calculate the percentage calibration error based upon span using the following equation:
Analyze the relative accuracy test audit data from the reference method tests for SO
Calculate the arithmetic mean of the differences, d
When calculating the arithmetic mean of the difference of a flow monitor data set, be sure to correct the monitor measurements for moisture if applicable.
Calculate the standard deviation, S
Calculate the confidence coefficient (one-tailed), cc, of a data set as follows.
Calculate the relative accuracy of a data set using the following equation.
Analyze the relative accuracy test audit data from the reference method tests for NO
If C
For each test run in a data set, calculate the average NO
Use the equations and procedures in section 7.3 above to calculate the relative accuracy for the NO
Test the following relative accuracy test audit data sets for bias: SO
Calculate the arithmetic mean of the difference, d
Calculate the standard deviation, S
Calculate the confidence coefficient, cc, of the data set using equation A-9.
If, for the relative accuracy test audit data set being tested, the mean difference, d
(a) If the monitor or monitoring system fails to meet the bias test requirement, adjust the value obtained from the monitor using the following equation:
(b) For single-load RATAs of SO
(c) For 2-load or 3-load flow RATAs, when only one load level (low, mid or high) has been designated as normal under section 6.5.2.1 of this appendix and the bias test is passed at the normal load level, apply a BAF of 1.000 to the subsequent flow rate data. If the bias test is failed at the normal load level, use Equation A-12 to calculate the normal load BAF and then perform an additional bias test at the second most frequently-used load level, as determined under section 6.5.2.1 of this appendix. If the bias test is passed at this second load level, apply the normal load BAF to the subsequent flow rate data. If the bias test is failed at this second load level, use Equation A-12 to calculate the BAF at the second load level and apply the higher of the two BAFs (either from the normal load level or from the second load level) to the subsequent flow rate data.
(d) For 2-load or 3-load flow RATAs, when two load levels have been designated as normal under section 6.5.2.1 of this appendix and the bias test is passed at both normal load levels, apply a BAF of 1.000 to the subsequent flow rate data. If the bias test is failed at one of the normal load levels but not at the other, use Equation A-12 to calculate the BAF for the normal load level at which the bias test was failed and apply that BAF to the subsequent flow rate data. If the bias test is failed at both designated normal load levels, use Equation A-12 to calculate the BAF at each normal load level and apply the higher of the two BAFs to the subsequent flow rate data.
(e) Each time a RATA is passed and the appropriate bias adjustment factor has been determined, apply the BAF prospectively to all monitoring system data, beginning with the first clock hour following the hour in which the RATA was completed. For a 2-load flow RATA, the “hour in which the RATA was completed” refers to the hour in which the testing at both loads was completed; for a 3-load RATA, it refers to the hour in which the testing at all three loads was completed.
(f) Use the bias-adjusted values in computing substitution values in the missing data procedure, as specified in subpart D of this part, and in reporting the concentration of SO
(a) Except as provided in section 7.8 of this appendix, the owner or operator shall determine R
(b) In Equation A-13, for a common stack, L
(c) In addition to determining R
(d) In the calculation of (Heat Input)
The requirements of this section apply beginning on April 1, 2000. For complex stack configurations (e.g., when the effluent from a unit is divided and discharges through multiple stacks in such a manner that the flow rate in the individual stacks cannot be correlated with unit load), the owner or operator may petition the Administrator under § 75.66 for an exemption from the requirements of section 7.7 of this appendix. The petition must include sufficient information and data to demonstrate that a flow-to-load or gross heat rate evaluation is infeasible for the complex stack configuration.
A. To determine the downscale cycle time, inject a high level calibration gas into the port leading to the calibration cell or thimble.
B. Allow the analyzer to stabilize. Record the stabilized value. Stop the calibration gas flow and allow the monitor to measure the
C. Record the stabilized value. A stable reading is achieved when the concentration reading deviates less than 6% from the measured average concentration in 6 minutes or if it deviates less than 2% of the monitor's span value in 2 minutes. (Owners and operators of units that do not record data in 1 minute or 3 minute intervals may petition the Administrator under section 75.66 for alternative stabilization criteria.)
D. Determine the step change. The step change is equal to the difference between the stabilized calibration gas value (Point B) and the final stable value (Point C). Take 95% of the step change value and subtract the result from the stabilized calibration gas value (Point B). Determine the time at which 95% of the step change occurred (Point D).
E. Determine the cycle time. The cycle time is equal to the downscale elapsed time, i.e. the time at which 95% of the step change occurred (point D) minus the time at which the calibration gas flow was stopped (Point B). In this example, cycle time=(6.5−4)=2.5 minutes (Report as 3 minutes).
F. To determine the cycle time for the upscale test, inject a zero scale calibration gas into the probe and repeat the procedures described above, except that 95% of the step change in concentration is added to the stabilized calibration gas value. Afterwards, compare the two cycle times achieved for both the upscale and downscale tests. The longer of these two times equals the cycle time for the analyzer.
Develop and implement a quality assurance/quality control (QA/QC) program for the continuous emission monitoring systems, excepted monitoring systems approved under appendix D or E to this part, and alternative monitoring systems under subpart E of this part, and their components. At a minimum, include in each QA/QC program a written plan that describes in detail (or that refers to separate documents containing) complete, step-by-step procedures and operations for each of the following activities. Upon request from regulatory authorities, the source shall make all procedures, maintenance records, and ancillary supporting documentation from the manufacturer (e.g., software coefficients and troubleshooting diagrams) available for review during an audit.
Keep a written record of procedures needed to maintain the monitoring system in proper operating condition and a schedule for those procedures. This shall, at a minimum, include procedures specified by the manufacturers of the equipment and, if applicable, additional or alternate procedures developed for the equipment.
Keep a written record describing procedures that will be used to implement the recordkeeping and reporting requirements in subparts E, F, and G and appendices D and E to this part, as applicable.
Keep a record of all testing, maintenance, or repair activities performed on any monitoring system or component in a location and format suitable for inspection. A maintenance log may be used for this purpose. The following records should be maintained: date, time, and description of any testing, adjustment, repair, replacement, or preventive maintenance action performed on any monitoring system and records of any corrective actions associated with a monitor's outage period. Additionally, any adjustment that recharacterizes a system's ability to record and report emissions data must be recorded (e.g., changing of flow monitor or moisture monitoring system polynomial coefficients, K factors or mathematical algorithms, changing of temperature and pressure coefficients and dilution ratio settings), and a written explanation of the procedures used to make the adjustment(s) shall be kept.
Keep a written record of the procedures used for daily calibration error tests and linearity checks (e.g., how gases are to be injected, adjustments of flow rates and pressure, introduction of reference values, length of time for injection of calibration gases, steps for obtaining calibration error or error in linearity, determination of interferences, and when calibration adjustments should be made). Identify any calibration error test and linearity check procedures specific to the continuous emission monitoring system that vary from the procedures in appendix A to this part.
Explain how each component of the continuous emission monitoring system will be adjusted to provide correct responses to calibration gases, reference values, and/or indications of interference both initially and after repairs or corrective action. Identify equations, conversion factors and other factors affecting calibration of each continuous emission monitoring system.
Keep a written record of procedures and details peculiar to the installed continuous emission monitoring systems that are to be used for relative accuracy test audits, such as sampling and analysis methods.
The owner or operator shall keep a written (or electronic) record including a list of operating parameters for the add-on SO
Keep a written record of the specific fuel flowmeter accuracy test procedures. These may include: standard methods or specifications listed in and section 2.1.5.1 of appendix D to this part and incorporated by reference under § 75.6; the procedures of sections 2.1.5.2 or 2.1.7 of appendix D to this part; or other methods approved by the Administrator through the petition process of § 75.66(c).
Keep a written record of the procedures for testing the accuracy of transducers or transmitters of an orifice-, nozzle-, or venturi-type fuel flowmeter under section 2.1.6 of appendix D to this part. These procedures should include a description of equipment used, steps in testing, and frequency of testing.
Keep a record of adjustments, maintenance, or repairs performed on the fuel flowmeter monitoring system. Keep records of the data and results for fuel flowmeter accuracy tests and transducer accuracy tests, consistent with appendix D to this part.
Keep a written record of the standard operating procedures for inspection of the primary element (i.e., orifice, venturi, or nozzle) of an orifice-, venturi-, or nozzle-type fuel flowmeter. Examples of the types of information to be included are: what to examine on the primary element; how to identify if there is corrosion sufficient to affect the accuracy of the primary element; and what inspection tools (e.g., baroscope), if any, are used.
Keep a written record of the standard procedures used to perform fuel sampling, either by utility personnel or by fuel supply company personnel. These procedures should specify the portion of the ASTM method used, as incorporated by reference under § 75.6, or other methods approved by the Administrator through the petition process of § 75.66(c). These procedures should describe safeguards for ensuring the availability of an oil sample (e.g., procedure and location for splitting samples, procedure for maintaining sample splits on site, and procedure for transmitting samples to an analytical laboratory). These procedures should identify the ASTM analytical methods used to analyze sulfur content, gross calorific value, and density, as incorporated by reference under § 75.6, or other methods approved by the Administrator through the petition process of § 75.66(c).
Identify the unit manufacturer's recommended range of quality assurance- and quality control-related operating parameters. Keep records of these operating parameters for each hour of unit operation (i.e., fuel combustion). Keep a written record of the procedures used to perform NO
Explain how the daily assessment procedures specific to the alternative monitoring system are to be performed.
Explain how each component of the alternative monitoring system will be adjusted in response to the results of the daily assessments.
Keep a written record of procedures and details peculiar to the installed alternative monitoring system that are to be used for relative accuracy test audits, such as sampling and analysis methods.
A summary chart showing each quality assurance test and the frequency at which each test is required is located at the end of this appendix in Figure 1.
Perform the following daily assessments to quality-assure the hourly data recorded by the monitoring systems during each period of unit operation, or, for a bypass stack or duct, each period in which emissions pass through the bypass stack or duct. These requirements are effective as of the date when the monitor or continuous emission monitoring system completes certification testing.
Except as provided in section 2.1.1.2 of this appendix, perform the daily calibration error test of each gas monitoring system (including moisture monitoring systems consisting of wet- and dry-basis O
For units with add-on emission controls and dual-span or auto-ranging monitors, and other units that use the maximum expected concentration to determine calibration gas values, perform the daily calibration error tests on each scale that has been used since the previous calibration error test. For example, if the pollutant concentration has not exceeded the low-scale value (based on the maximum expected concentration) since the previous calibration error test, the calibration error test may be performed on the low-scale only. If, however, the concentration has exceeded the low-scale span value for one hour or longer since the previous calibration error test, perform the calibration error test on both the low- and high-scales.
(1) An initial demonstration test of the monitoring system is successfully completed and the results are reported in the quarterly report required under § 75.64 of this part. The initial demonstration test, hereafter called the “off-line calibration demonstration”, consists of an off-line calibration error test followed by an on-line calibration error test. Both the off-line and on-line portions of the off-line calibration demonstration must meet the calibration error performance specification in section 3.1 of appendix A of this part. Upon completion of the off-line portion of the demonstration, the zero and upscale monitor responses may be adjusted, but only toward the true values of the calibration gases or reference signals used to perform the test and only in accordance with the routine calibration adjustment procedures specified in the quality control program required under section 1 of appendix B to this part. Once these adjustments are made, no further adjustments may be made to the monitoring system until after completion of the on-line portion of the off-line calibration demonstration. Within 26 clock hours of the completion hour of the off-line portion of the demonstration, the monitoring system must successfully complete the first attempted calibration error test, i.e., the on-line portion of the demonstration.
(2) For each monitoring system that has passed the off-line calibration demonstration, a successful on-line calibration error test of the monitoring system must be completed no later than 26 unit operating hours after each off-line calibration error test used for data validation.
Perform the daily flow monitor interference checks specified in section 2.2.2.2 of appendix A of this part while the unit is in operation at normal, stable conditions.
(a) In addition to the daily calibration error tests required under section 2.1.1 of this appendix, a calibration error test of a monitor shall be performed in accordance with section 2.1.1 of this appendix, as follows: whenever a daily calibration error test is failed; whenever a monitoring system is returned to service following repair or corrective maintenance that could affect the monitor's ability to accurately measure and
(b) Routine calibration adjustments of a monitor are permitted after any successful calibration error test. These routine adjustments shall be made so as to bring the monitor readings as close as practicable to the known tag values of the calibration gases or to the actual value of the flow monitor reference signals. An additional calibration error test is required following routine calibration adjustments where the monitor's calibration has been physically adjusted (e.g., by turning a potentiometer) to verify that the adjustments have been made properly. An additional calibration error test is not required, however, if the routine calibration adjustments are made by means of a mathematical algorithm programmed into the data acquisition and handling system. The EPA recommends that routine calibration adjustments be made, at a minimum, whenever the daily calibration error exceeds the limits of the applicable performance specification in appendix A to this part for the pollutant concentration monitor, CO
(c) Additional (non-routine) calibration adjustments of a monitor are permitted prior to (but not during) linearity checks and RATAs and at other times, provided that an appropriate technical justification is included in the quality control program required under section 1 of this appendix. The allowable non-routine adjustments are as follows. The owner or operator may physically adjust the calibration of a monitor (e.g., by means of a potentiometer), provided that the post-adjustment zero and upscale responses of the monitor are within the performance specifications of the instrument given in section 3.1 of appendix A to this part. An additional calibration error test is required following such adjustments to verify that the monitor is operating within the performance specifications at both the zero and upscale calibration levels.
(a) An out-of-control period occurs when the calibration error of an SO
(b) An out-of-control period also occurs whenever interference of a flow monitor is identified. The out-of-control period begins with the hour of completion of the failed interference check and ends with the hour of completion of an interference check that is passed.
When a monitoring system passes a daily assessment (i.e., daily calibration error test or daily flow interference check), data from that monitoring system are prospectively validated for 26 clock hours (i.e., 24 hours plus a 2-hour grace period) beginning with the hour in which the test is passed, unless another assessment (i.e. a daily calibration error test, an interference check of a flow monitor, a quarterly linearity check, a quarterly leak check, or a relative accuracy test audit) is failed within the 26-hour period.
(1) Data from a monitoring system are invalid, beginning with the first hour following the expiration of a 26-hour data validation period or beginning with the first hour following the expiration of an 8-hour start-up grace period (as provided under section 2.1.5.2 of this appendix), if the required subsequent daily assessment has not been conducted.
(2) Beginning on January 1, 1999, for a monitoring system that has passed the off-line calibration demonstration, if an on-line daily calibration error test of the same monitoring system is not conducted and passed within 26 unit operating hours of an off-line calibration error test that is used for data
(1) The unit must have resumed operation after being in outage for 1 or more hours (i.e., the unit must be in a start-up condition) as evidenced by a change in unit operating time from zero in one clock hour to an operating time greater than zero in the next clock hour.
(2) For the monitoring system to be used to validate data during the grace period, the previous daily assessment of the same kind must have been passed on-line within 26 clock hours prior to the last hour in which the unit operated before the outage. In addition, the monitoring system must be in-control with respect to quarterly and semi-annual or annual assessments.
If both of the above conditions are met, then a start-up grace period of up to 8 clock hours applies, beginning with the first hour of unit operation following the outage. During the start-up grace period, data generated by the monitoring system are considered quality-assured. For each monitoring system, a start-up grace period for a calibration error test or flow interference check ends when either: (1) a daily assessment of the same kind (i.e., calibration error test or flow interference check) is performed; or (2) 8 clock hours have elapsed (starting with the first hour of unit operation following the outage), whichever occurs first.
Record and tabulate all calibration error test data according to month, day, clock-hour, and magnitude in either ppm, percent volume, or scfh. Program monitors that automatically adjust data to the corrected calibration values (e.g., microprocessor control) to record either: (1) The unadjusted concentration or flow rate measured in the calibration error test prior to resetting the calibration, or (2) the magnitude of any adjustment. Record the following applicable flow monitor interference check data: (1) Sample line/sensing port pluggage, and (2) malfunction of each RTD, transceiver, or equivalent.
For each primary and redundant backup monitor or monitoring system, perform the following quarterly assessments. This requirement is applies as of the calendar quarter following the calendar quarter in which the monitor or continuous emission monitoring system is provisionally certified.
Perform a linearity check, in accordance with the procedures in section 6.2 of appendix A to this part, for each primary and redundant backup SO
For differential pressure flow monitors, perform a leak check of all sample lines (a manual check is acceptable) at least once during each QA operating quarter. For this test, the unit does not have to be in operation. Conduct the leak checks no less than 30 days apart, to the extent practicable. If a leak check is failed, follow the applicable data validation procedures in section 2.2.3(f) of this appendix.
(a) A linearity check shall not be commenced if the monitoring system is operating out-of-control with respect to any of the daily or semiannual quality assurance assessments required by sections 2.1 and 2.3 of this appendix or with respect to the additional calibration error test requirements in section 2.1.3 of this appendix.
(b) Each required linearity check shall be done according to paragraph (b)(1), (b)(2) or (b)(3) of this section:
(1) The linearity check may be done “cold,” i.e., with no corrective maintenance, repair, calibration adjustments, re-linearization or reprogramming of the monitor prior to the test.
(2) The linearity check may be done after performing only the routine or non-routine calibration adjustments described in section 2.1.3 of this appendix at the various calibration gas levels (zero, low, mid or high), but no other corrective maintenance, repair, re-
(3) The linearity check may be done after repair, corrective maintenance or reprogramming of the monitor. In this case, the monitor shall be considered out-of-control from the hour in which the repair, corrective maintenance or reprogramming is commenced until the linearity check has been passed. Alternatively, the data validation procedures and associated timelines in §§ 75.20(b)(3)(ii) through (ix) may be followed upon completion of the necessary repair, corrective maintenance, or reprogramming. If the procedures in § 75.20(b)(3) are used, the words “quality assurance” apply instead of the word “recertification”.
(c) Once a linearity check has been commenced, the test shall be done hands-off. That is, no adjustments of the monitor are permitted during the linearity test period, other than the routine calibration adjustments following daily calibration error tests, as described in section 2.1.3 of this appendix.
(d) If a daily calibration error test is failed during a linearity test period, prior to completing the test, the linearity test must be repeated. Data from the monitor are invalidated prospectively from the hour of the failed calibration error test until the hour of completion of a subsequent successful calibration error test. The linearity test shall not be commenced until the monitor has successfully completed a calibration error test.
(e) An out-of-control period occurs when a linearity test is failed (i.e., when the error in linearity at any of the three concentrations in the quarterly linearity check (or any of the six concentrations, when both ranges of a single analyzer with a dual range are tested) exceeds the applicable specification in section 3.2 of appendix A to this part) or when a linearity test is aborted due to a problem with the monitor or monitoring system. For a NO
(f) No more than four successive calendar quarters shall elapse after the quarter in which a linearity check of a monitor or monitoring system (or range of a monitor or monitoring system) was last performed without a subsequent linearity test having been conducted. If a linearity test has not been completed by the end of the fourth calendar quarter since the last linearity test, then the linearity test must be completed within a 168 unit operating hour or stack operating hour “grace period” (as provided in section 2.2.4 of this appendix) following the end of the fourth successive elapsed calendar quarter, or data from the CEMS (or range) will become invalid.
(g) An out-of-control period also occurs when a flow monitor sample line leak is detected. The out-of-control period begins with the hour of the failed leak check and ends with the hour of a satisfactory leak check following corrective action.
(h) For each monitoring system, report the results of all completed and partial linearity tests that affect data validation (i.e., all completed, passed linearity checks; all completed, failed linearity checks; and all linearity checks aborted due to a problem with the monitor, including trial gas injections counted as failed test attempts under paragraph (b)(2) of this section or under § 75.20(b)(3)(vii)(F)), in the quarterly report required under § 75.64. Note that linearity attempts which are aborted or invalidated due to problems with the reference calibration gases or due to operational problems with the affected unit(s) need not be reported. Such partial tests do not affect the validation status of emission data recorded by the monitor. A record of all linearity tests, trial gas injections and test attempts (whether reported or not) must be kept on-site as part of the official test log for each monitoring system.
(a) When a required linearity test or flow monitor leak check has not been completed by the end of the QA operating quarter in which it is due or if, due to infrequent operation of a unit or infrequent use of a required high range of a monitor or monitoring
(b) If, at the end of the 168 unit (or stack) operating hour grace period, the required linearity test or leak check has not been completed, data from the monitoring system (or range) shall be invalid, beginning with the hour following the expiration of the grace period. Data from the monitoring system (or range) remain invalid until the hour of completion of a subsequent successful hands-off linearity test or leak check of the monitor or monitoring system (or range). Note that when a linearity test or a leak check is conducted within a grace period for the purpose of satisfying the linearity test or leak check requirement from a previous QA operating quarter, the results of that linearity test or leak check may only be used to meet the linearity check or leak check requirement of the previous quarter, not the quarter in which the missed linearity test or leak check is completed.
(a)
(1) In Equation B-1, the owner or operator may use either bias-adjusted flow rates or unadjusted flow rates, provided that all of the ratios are calculated the same way. For a common stack, L
(2) Alternatively, the owner or operator may calculate the hourly gross heat rates (GHR) in lieu of the hourly flow-to-load ratios. The hourly GHR shall be determined only for those hours in which quality assured flow rate data and diluent gas (CO
(3) In Equation B-1a, the owner or operator may either use bias-adjusted flow rates or unadjusted flow rates in the calculation of (Heat Input)
(4) The owner or operator shall evaluate the calculated hourly flow-to-load ratios (or gross heat rates) as follows. A separate data analysis shall be performed for each primary and each redundant backup flow rate monitor used to record and report data during the quarter. Each analysis shall be based on a minimum of 168 recorded hourly average flow rates. When two RATA load levels are designated as normal, the analysis shall be performed at the higher load level, unless there are fewer than 168 data points available at that load level, in which case the analysis shall be performed at the lower load level. If, for a particular flow monitor, fewer than 168 hourly flow-to-load ratios (or GHR values) are available at any of the load levels designated as normal, a flow-to-load (or GHR) evaluation is not required for that monitor for that calendar quarter.
(5) For each flow monitor, use Equation B-2 in this appendix to calculate E
(6) Equation B-2 shall be used in a consistent manner. That is, use R
(b)
(c)
(1) Any hour in which the type of fuel combusted was different from the fuel burned during the most recent normal-load RATA. For purposes of this determination, the type of fuel is different if the fuel is in a different state of matter (i.e., solid, liquid, or gas) than is the fuel burned during the RATA or if the fuel is a different classification of coal (e.g., bituminous versus sub-bituminous);
(2) For a unit that is equipped with an SO
(3) Any hour in which “ramping” occurred, i.e., the hourly load differed by more than
(4) For a unit with a multiple stack discharge configuration consisting of a main stack and a bypass stack, any hour in which the flue gases were discharged through both stacks;
(5) If a normal-load flow RATA was performed and passed during the quarter being analyzed, any hour prior to completion of that RATA; and
(6) If a problem with the accuracy of the flow monitor was discovered during the quarter and was corrected (as evidenced by passing the abbreviated flow-to-load test in section 2.2.5.3 of this appendix), any hour prior to completion of the abbreviated flow-to-load test.
(7) After identifying and excluding all non-representative hourly data in accordance with paragraphs (c)(1) through (6) of this section, the owner or operator may analyze the remaining data a second time. At least 168 representative hourly ratios or GHR values must be available to perform the analysis; otherwise, the flow-to-load (or GHR) analysis is not required for that monitor for that calendar quarter.
(8) If, after re-analyzing the data, E
Within two weeks of the end of the calendar quarter for which the E
(a) If the investigation fails to uncover a problem with the flow monitor, a RATA shall be performed in accordance with Option 2 in section 2.2.5.2 of this appendix.
(b) If a problem with the flow monitor is identified through the investigation (including the need to re-linearize the monitor by changing the polynomial coefficients or K factor(s)), corrective actions shall be taken. All corrective actions (e.g., non-routine maintenance, repairs, major component replacements, re-linearization of the monitor, etc.) shall be documented in the operation and maintenance records for the monitor. Data from the monitor shall remain invalid until a probationary calibration error test of the monitor is passed following completion of all corrective actions, at which point data from the monitor are conditionally valid. The owner or operator then either may complete the abbreviated flow-to-load test in section 2.2.5.3 of this appendix, or, if the corrective action taken has required relinearization of the flow monitor, shall perform a 3-level RATA.
Perform a single-load RATA (at a load designated as normal under section 6.5.2.1 of appendix A to this part) of each flow monitor for which E
(a) The following abbreviated flow-to-load test may be performed after any documented repair, component replacement, or other corrective maintenance to a flow monitor (except for changes affecting the linearity of the flow monitor, such as adjusting the flow monitor coefficients or K factor(s)) to demonstrate that the repair, replacement, or other maintenance has not significantly affected the monitor's ability to accurately measure the stack gas volumetric flow rate. Data from the monitoring system are considered invalid from the hour of commencement of the repair, replacement, or maintenance until the hour in which a probationary calibration error test is passed following completion of the repair, replacement, or maintenance and any associated adjustments to the monitor. The abbreviated flow-to-load test shall be completed within 168 unit operating hours of the probationary calibration error test (or, for peaking units, within 30 unit operating days, if that is less restrictive). Data from the monitor are considered to be conditionally valid (as defined in § 72.2 of this chapter), beginning with the hour of the probationary calibration error test.
(b) Operate the unit(s) in such a way as to reproduce, as closely as practicable, the
(c) The results of the abbreviated flow-to-load test shall be considered acceptable, and no further action is required if the value of E
For each primary and redundant backup monitoring system, perform relative accuracy assessments either semiannually or annually, as specified in section 2.3.1.1 or 2.3.1.2 of this appendix, for the type of test and the performance achieved. This requirement applies as of the calendar quarter following the calendar quarter in which the monitoring system is provisionally certified. A summary chart showing the frequency with which a relative accuracy test audit must be performed, depending on the accuracy achieved, is located at the end of this appendix in Figure 2.
(a) Except as otherwise specified in § 75.21(a)(6) or (a)(7) or in section 2.3.1.2 of this appendix, perform relative accuracy test audits semiannually, i.e., once every two successive QA operating quarters (as defined in § 72.2 of this chapter) for each primary and redundant backup SO
(b) The relative accuracy test audit frequency of a CEMS may be reduced, as specified in section 2.3.1.2 of this appendix, for primary or redundant backup monitoring systems which qualify for less frequent testing. Perform all required RATAs in accordance with the applicable procedures and provisions in sections 6.5 through 6.5.2.2 of appendix A to this part and sections 2.3.1.3 and 2.3.1.4 of this appendix.
Relative accuracy test audits of primary and redundant backup SO
(a) The relative accuracy during the audit of an SO
(b) Prior to January 1, 2000, the relative accuracy during the audit of a flow monitor is ≤ 10.0 percent at each operating level tested;
(c) On and after January 1, 2000, the relative accuracy during the audit of a flow monitor is ≤ 7.5 percent at each operating level tested;
(d) For low flow (≤ 10.0 fps) stacks/ducts, when the flow monitor fails to achieve a relative accuracy ≤ 7.5 percent (10.0 percent if prior to January 1, 2000) during the audit, but the monitor mean value, calculated using Equation A-7 in appendix A to this part and converted back to an equivalent velocity in standard feet per second (fps), is within
(e) For low SO
(f) For units with low NO
(g) For units with low SO
(h) For a CO
(i) When the relative accuracy of a continuous moisture monitoring system is ≤ 7.5 percent or when the mean difference between the reference method values from the RATA and the corresponding monitoring system values is within
(a) For SO
(b) For flow monitors installed on peaking units and bypass stacks, all required semiannual or annual relative accuracy test audits shall be single-load audits at the normal load, as defined in section 6.5.2.1 of appendix A to this part.
(c) For all other flow monitors, the RATAs shall be performed as follows:
(1) An annual 2-load flow RATA shall be done at the two most frequently used load levels, as determined under section 6.5.2.1 of appendix A to this part.
(2) If the flow monitor is on a semiannual RATA frequency, 2-load flow RATAs and single-load flow RATAs at normal load may be performed alternately.
(3) A single-load annual flow RATA, at the most frequently used load level, may be performed in lieu of the 2-load RATA if the results of an historical load data analysis show that in the time period extending from the ending date of the last annual flow RATA to a date that is no more than 7 days prior to the date of the current annual flow RATA, the unit has operated at a single load level (low, mid or high) for ≥ 85.0 percent of the time. * * *
(4) A 3-load RATA, at the low-, mid-, and high-load levels, determined under section 6.5.2.1 of appendix A to this part, shall be performed at least once in every period of five consecutive calendar years.
(5) A 3-load RATA is required whenever a flow monitor is re-linearized, i.e., when its polynomial coefficients or K factor(s) are changed.
(6) For all multi-level flow audits, the audit points at adjacent load levels (e.g., mid and high) shall be separated by no less than 25.0 percent of the “range of operation,” as defined in section 6.5.2.1 of appendix A to this part.
(d) A RATA of a moisture monitoring system shall be performed whenever the coefficient, K factor or mathematical algorithm determined under section 6.5.7 of appendix A to this part is changed.
The owner or operator may perform as many RATA attempts as are necessary to achieve the desired relative accuracy test audit frequencies and/or bias adjustment factors. However, the data validation procedures in section 2.3.2 of this appendix must be followed.
(a) A RATA shall not commence if the monitoring system is operating out-of-control with respect to any of the daily and quarterly quality assurance assessments required by sections 2.1 and 2.2 of this appendix or with respect to the additional calibration error test requirements in section 2.1.3 of this appendix.
(b) Each required RATA shall be done according to paragraphs (b)(1), (b)(2) or (b)(3) of this section:
(1) The RATA may be done “cold,” i.e., with no corrective maintenance, repair, calibration adjustments, re-linearization or reprogramming of the monitoring system prior to the test.
(2) The RATA may be done after performing only the routine or non-routine calibration adjustments described in section 2.1.3 of this appendix at the zero and/or upscale calibration gas levels, but no other corrective maintenance, repair, re-linearization or reprogramming of the monitoring system. Trial RATA runs may be performed after the calibration adjustments and additional adjustments within the allowable limits in section 2.1.3 of this appendix may be made prior to the RATA, as necessary, to optimize the performance of the CEMS. The trial RATA runs need not be reported, provided that they meet the specification for trial RATA runs in § 75.20(b)(3)(vii)(E)(
(3) The RATA may be done after repair, corrective maintenance, re-linearization or reprogramming of the monitoring system. In this case, the monitoring system shall be considered out-of-control from the hour in which the repair, corrective maintenance, re-linearization or reprogramming is commenced until the RATA has been passed. Alternatively, the data validation procedures and associated timelines in §§ 75.20(b)(3)(ii) through (ix) may be followed upon completion of the necessary repair, corrective maintenance, re-linearization or reprogramming. If the procedures in § 75.20(b)(3) are used, the words “quality assurance” apply instead of the word “recertification.”
(c) Once a RATA is commenced, the test must be done hands-off. No adjustment of the monitor's calibration is permitted during the RATA test period, other than the routine calibration adjustments following daily calibration error tests, as described in section 2.1.3 of this appendix. For 2-level and 3-level flow monitor audits, no linearization or reprogramming of the monitor is permitted in between load levels.
(d) For single-load RATAs, if a daily calibration error test is failed during a RATA test period, prior to completing the test, the RATA must be repeated. Data from the monitor are invalidated prospectively from the hour of the failed calibration error test until the hour of completion of a subsequent successful calibration error test. The subsequent RATA shall not be commenced until the monitor has successfully passed a calibration error test in accordance with section 2.1.3 of this appendix. For multiple-load flow RATAs, each load level is treated as a separate RATA (i.e., when a calibration error test is failed prior to completing the RATA at a particular load level, only the RATA at that load level must be repeated; the results of any previously-passed RATA(s) at the other load level(s) are unaffected, unless re-linearization of the monitor is required to correct the problem that caused the calibration failure, in which case a subsequent 3-load RATA is required).
(e) If a RATA is failed (that is, if the relative accuracy exceeds the applicable specification in section 3.3 of appendix A to this part) or if the RATA is aborted prior to completion due to a problem with the CEMS, then the CEMS is out-of-control and all emission data from the CEMS are invalidated prospectively from the hour in which the RATA is failed or aborted. Data from the CEMS remain invalid until the hour of completion of a subsequent RATA that meets the applicable specification in section 3.3 of appendix A to this part, unless the option in paragraph (b)(3) of this section to use the data validation procedures and associated timelines in §§ 75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in which case the beginning and end of the out-of-control period shall be determined in accordance with § 75.20(b)(3)(vii)(A) and (B). Note that a monitoring system shall not be considered out-of-control when a RATA is aborted for a reason other than monitoring system malfunction (see paragraph (h) of this section).
(f) For a 2-level or 3-level flow RATA, if, at any load level, a RATA is failed or aborted due to a problem with the flow monitor, the RATA at that load level must be repeated. The flow monitor is considered out-of-control and data from the monitor are invalidated from the hour in which the test is failed or aborted and remain invalid until the passing of a RATA at the failed load level, unless the option in paragraph (b)(3) of this section to use the data validation procedures and associated timelines in § 75.20(b)(3)(ii) through (b)(3)(ix) has been selected, in which case the beginning and end of the out-of-control period shall be determined in accordance with § 75.20(b)(3)(vii)(A) and (B). Flow RATA(s) that were previously passed at the other load level(s) do not have to be repeated unless the flow monitor must be re-linearized following the failed or aborted test. If the flow monitor is re-linearized, a subsequent 3-load RATA is required.
(g) For a CO
(h) For each monitoring system, report the results of all completed and partial RATAs that affect data validation (i.e., all completed, passed RATAs; all completed, failed RATAs; and all RATAs aborted due to a problem with the CEMS, including trial RATA runs counted as failed test attempts under paragraph (b)(2) of this section or under § 75.20(b)(3)(vii)(F)) in the quarterly report required under § 75.64. Note that RATA attempts that are aborted or invalidated due to problems with the reference method or due to operational problems with the affected unit(s) need not be reported. Such runs do not affect the validation status of emission data recorded by the CEMS. However, a record of all RATAs, trial RATA runs and RATA attempts (whether reported or not) must be kept on-site as part of the official test log for each monitoring system.
(i) Each time that a hands-off RATA of an SO
(j) Failure of the bias test does not result in the monitoring system being out-of-control.
(a) The owner or operator has a grace period of 720 consecutive unit operating hours, as defined in § 72.2 of this chapter (or, for CEMS installed on common stacks or bypass stacks, 720 consecutive stack operating hours, as defined in § 72.2 of this chapter), in which to complete the required RATA for a particular CEMS whenever: a required RATA has not been performed by the end of the QA operating quarter in which it is due; or five consecutive calendar years have elapsed without a required 3-load flow RATA having been conducted; or for a unit which is conditionally exempted under § 75.21(a)(7) from the SO
(b) Except for SO
(c) If, at the end of the 720 unit (or stack) operating hour grace period, the RATA has not been completed, data from the monitoring system shall be invalid, beginning with the first unit operating hour following the expiration of the grace period. Data from the CEMS remain invalid until the hour of completion of a subsequent hands-off RATA. Note that when a RATA (or RATAs, if more than one attempt is made) is done during a grace period in order to satisfy a RATA requirement from a previous quarter, the deadline for the next RATA shall be determined from the quarter in which the RATA was due, not from the quarter in which the RATA is actually completed. However, if a RATA deadline determined in this manner is less than two QA operating quarters from the quarter in which the missed RATA is completed , the RATA deadline shall be re-set at two QA operating quarters from the quarter in which the missed RATA is completed .
Except as otherwise specified in section 7.6.5 of appendix A to this part, if an SO
(a) When a significant change is made to a monitoring system such that recertification of the monitoring system is required in accordance with § 75.20(b), a recertification test (or tests) must be performed to ensure that the CEMS continues to generate valid data. In all recertifications, a RATA will be one of the required tests; for some recertifications, other tests will also be required. A recertification test may be used to satisfy the quality assurance test requirement of this appendix. For example, if, for a particular change made to a CEMS, one of the required recertification tests is a linearity check and the linearity check is successful, then, unless another such recertification event occurs in that same QA operating quarter, it would not be necessary to perform an additional linearity test of the CEMS in that quarter to meet the quality assurance requirement of section 2.2.1 of this appendix. For this reason, EPA recommends that owners or operators coordinate component replacements, system upgrades, and other events that may require recertification, to the extent practicable, with the periodic quality assurance testing required by this appendix. When a quality assurance test is done for the dual purpose of recertification and routine quality assurance, the applicable data validation procedures in § 75.20(b)(3) shall be followed.
(b) Except as provided in section 2.3.3 of this appendix, whenever a passing RATA of a gas monitor or a passing 2-load or 3-load RATA of a flow monitor is performed (irrespective of whether the RATA is done to satisfy a recertification requirement or to meet the quality assurance requirements of this appendix, or both), the RATA frequency (semi-annual or annual) shall be established based upon the date and time of completion of the RATA and the relative accuracy percentage obtained. For 2-load and 3-load flow RATAs, use the highest percentage relative accuracy at any of the loads to determine the RATA frequency. The results of a single-load flow RATA may be used to establish the RATA frequency when the single-load flow RATA is specifically required under section 2.3.1.3(b) of this appendix (for flow monitors installed on peaking units and bypass stacks) or when the single-load RATA is allowed under section 2.3.1.3(c) of this appendix for a unit that has operated at the most frequently used load level for ≥85.0 percent of the time since the last annual flow RATA. No other single-load flow RATA may be used to establish an annual RATA frequency; however, a 2-load or 3-load flow RATA may be performed at any time or in place of any required single-load RATA, in order to establish an annual RATA frequency.
Affected units may be subject to relative accuracy test audits at any time. If a monitor or continuous emission monitoring system fails the relative accuracy test during the audit, the monitor or continuous emission monitoring system shall be considered to be out-of-control beginning with the date and time of completion of the audit, and continuing until a successful audit test is completed following corrective action. If a monitor or monitoring system fails the bias test during an audit, use the bias adjustment factor given by equations A-11 and A-12 in appendix A to this part to adjust the monitored data. Apply this adjustment factor from the date and time of completion of the audit until the date and time of completion of a relative accuracy test audit that does not show bias.
The owner or operator of any affected unit equipped with post-combustion SO
Base the empirical and process simulation methods or models on the fundamental chemistry and engineering principles involved in the treatment of pollutant gas. On a case-by-case basis, the Administrator may pre-certify commercially available process simulation methods and models.
Continuously monitor, determine, and record hourly averages of the estimated SO
1.2.1Parameters for Wet Flue Gas Desulfurization System
1.2.1.1Number of scrubber modules in operation.
1.2.1.2Total slurry rate to each scrubber module (gal per min).
1.2.1.3In-line absorber pH of each scrubber module.
1.2.1.4Pressure differential across each scrubber module (inches of water column).
1.2.1.5Unit load (MWe).
1.2.1.6Inlet and outlet SO
1.2.1.7Percent solids in slurry for each scrubber module.
1.2.1.8Any other parameters necessary to verify scrubber removal efficiency, if the Administrator determines the parameters above are not sufficient.
1.2.2Parameters for Dry Flue Gas De-sul-fur-i-za-tion System
1.2.2.1Number of scrubber modules in operation.
1.2.2.2Atomizer slurry flow rate to each scrubber module (gal per min).
1.2.2.3Inlet and outlet temperature for each scrubber module ( °F).
1.2.2.4Pressure differential across each scrubber module (inches of water column).
1.2.2.5Unit load (MWe).
1.2.2.6Inlet and outlet SO
1.2.2.7Any other parameters necessary to verify scrubber removal efficiency, if the Administrator determines the parameters above are not sufficient.
If SO
1.2.4.1Inlet air flow rate to the unit (boiler) (mcf/hr).
1.2.4.2Excess oxygen concentration of flue gas at stack outlet (percent).
1.2.4.3Carbon monoxide concentration of flue gas at stack outlet (ppm).
1.2.4.4Temperature of flue gas at outlet of the unit ( °F).
1.2.4.5Inlet and outlet NO
1.2.4.6Any other parameters specific to the emission reduction process necessary to verify the NO
Establish a method for correlating hourly averages of the parameters identified above with the percent removal efficiency of the SO
Each parametric data substitution procedure should develop a data correlation procedure to verify the performance of the SO
For NO
1.4.1Use the following equation to calculate substitute data for filling in missing (outlet) SO
1.4.2Use the following equation to calculate substitute data for filling in missing (outlet) NO
1.5.1If both the inlet and the outlet SO
1.5.2If both the inlet and outlet NO
Apply to the Administrator for approval and certification of the parametric substitution procedure for filling in missing SO
This procedure is applicable for data from all affected units for use in accordance with the provisions of this part to provide substitute data for volumetric flow rate (scfh), NO
2.2.1For a single unit, establish ten operating load ranges defined in terms of percent of the maximum hourly average gross load of the unit, in gross megawatts (MWge), as shown in Table C-1. (Do not use integrated hourly gross load in MW-hr.) For units sharing a common stack monitored with a single flow monitor, the load ranges for flow (but not for NO
2.2.2Beginning with the first hour of unit operation after installation and certification of the flow monitor or the NO
2.2.3Beginning with the first hour of unit operation after installation and certification of the flow monitor or the NO
2.2.3.1Average of the hourly flow rates reported by a flow monitor, in scfh.
2.2.3.2The 90th percentile value of hourly flow rates, in scfh.
2.2.3.3The 95th percentile value of hourly flow rates, in scfh.
2.2.3.4The maximum value of hourly flow rates, in scfh.
2.2.3.5Average of the hourly NO
2.2.3.6The 90th percentile value of hourly NO
2.2.3.7The 95th percentile value of hourly NO
2.2.3.8The maximum value of hourly NO
2.2.3.9Average of the hourly NO
2.2.3.10The 90th percentile value of hourly NO
2.2.3.11The 95th percentile value of hourly NO
2.2.3.12The maximum value of hourly NO
2.2.4Calculate all monitor or continuous emission monitoring system data averages, maximum values, and percentile values determined by this procedure using bias adjusted values in the load ranges.
2.2.5When a bias adjustment is necessary for the flow monitor and/or the NO
2.2.6Use the calculated monitor or monitoring system data averages, maximum values, and percentile values to substitute for missing flow rate and NO
1.1This protocol may be used in lieu of continuous SO
1.2Pursuant to the procedures in § 75.20, complete all testing requirements to certify use of this protocol in lieu of a flow monitor and an SO
For each hour when the unit is combusting fuel, measure and record the flow rate of fuel combusted by the unit, except as provided in section 2.1.4 of this appendix. Measure the flow rate of fuel with an in-line fuel flowmeter, and automatically record the data with a data acquisition and handling system, except as provided in section 2.1.4 of this appendix.
2.1.1Measure the flow rate of each fuel entering and being combusted by the unit. If, on an annual basis, more than 5.0 percent of the fuel from the main pipe is diverted from the unit without being burned and that diversion occurs downstream of the fuel flowmeter, an additional in-line fuel flowmeter is required to account for the unburned fuel. In this case, record the flow rate of each fuel combusted by the unit as the difference between the flow measured in the pipe leading to the unit and the flow in the pipe diverting fuel away from the unit. However, the additional fuel flowmeter is not required if, on an annual basis, the total amount of fuel diverted away from the unit, expressed as a percentage of the total annual fuel usage by the unit is demonstrated to be less than or equal to 5.0 percent. The owner or operator may make this demonstration in the following manner:
2.1.1.1For existing units with fuel usage data from fuel flowmeters, if data are submitted from a previous year demonstrating that the total diverted yearly fuel does not exceed 5% of the total fuel used; or
2.1.1.2For new units which do not have historical data, if a letter is submitted signed by the designated representative certifying that, in the future, the diverted fuel will not exceed 5.0% of the total annual fuel usage; or
2.1.1.3By using a method approved by the Administrator under § 75.66(d).
2.1.2Install and use fuel flowmeters meeting the requirements of this appendix in a pipe going to each unit, or install and use a fuel flowmeter in a common pipe header (i.e., a pipe carrying fuel for multiple units). However, the use of a fuel flowmeter in a common pipe header and the provisions of sections 2.1.2.1 and 2.1.2.2 of this appendix are not applicable to any unit that is using the provisions of subpart H of this part to monitor, record, and report NO
2.1.2.1Measure the fuel flow rate in the common pipe, and combine SO
2.1.2.2Provide information satisfactory to the Administrator on methods for apportioning SO
2.1.3For a gas-fired unit or an oil-fired unit that continuously or frequently combusts a supplemental fuel for flame stabilization or safety purposes, measure the flow rate of the supplemental fuel with a fuel flowmeter meeting the requirements of this appendix.
For an oil-fired unit that uses gas solely for start-up or burner ignition or a gas-fired unit that uses oil solely for start-up or burner ignition, a flowmeter for the start-up fuel is not required. Estimate the volume of oil combusted for each start-up or ignition either by using a fuel flowmeter or by using the dimensions of the storage container and measuring the depth of the fuel in the storage container before and after each start-up or ignition. A fuel flowmeter used solely for start-up or ignition fuel is not subject to the calibration requirements of sections 2.1.5 and 2.1.6 of this appendix. Gas combusted solely for start-up or burner ignition does not need to be measured separately.
A gas or oil flowmeter used for commercial billing of natural gas or oil may be used to measure, record, and report hourly fuel flow rate. A gas or oil flowmeter used for commercial billing of natural gas or oil is not required to meet the certification requirements of section 2.1.5 of this appendix or the quality assurance requirements of section 2.1.6 of this appendix under the following circumstances:
(a) The gas or oil flowmeter is used for commercial billing under a contract, provided that the company providing the gas or oil under the contract and each unit combusting the gas or oil do not have any common owners and are not owned by subsidiaries or affiliates of the same company;
(b) The designated representative reports hourly records of gas or oil flow rate, heat input rate, and emissions due to combustion of natural gas or oil;
(c) The designated representative also reports hourly records of heat input rate for each unit, if the gas or oil flowmeter is on a common pipe header, consistent with section 2.1.2 of this appendix;
(d) The designated representative reports hourly records directly from the gas or oil flowmeter used for commercial billing if these records are the values used, without adjustment, for commercial billing, or reports hourly records using the missing data procedures of section 2.4 of this appendix if these records are not the values used, without adjustment, for commercial billing; and
(e) The designated representative identifies the gas or oil flowmeter in the unit's monitoring plan.
The designated representative of a unit that is restricted by its Federal, State or local permit to combusting a particular fuel only during emergencies where the primary fuel is not available is exempt from certifying a fuel flowmeter for use during combustion of the emergency fuel. During any hour in which the emergency fuel is combusted, report the hourly heat input to be the maximum rated heat input of the unit for the fuel. Additionally, begin sampling the emergency fuel for sulfur content only using the procedures under section 2.2 (for oil) or 2.3 (for gas) of this appendix. The designated representative shall also provide notice under § 75.61(a)(6)(ii) for each period when the emergency fuel is combusted.
For the purposes of initial certification, each fuel flowmeter used to meet the requirements of this protocol shall meet a flowmeter accuracy of 2.0 percent of the upper range value (i.e. maximum calibrated fuel flow rate) across the range of fuel flow rate to be measured at the unit. Flowmeter accuracy may be determined under section 2.1.5.1 of this appendix for initial certification in any of the following ways (as applicable): by design or by measurement under laboratory conditions; by the manufacturer; by an independent laboratory; or by the owner or operator. Flowmeter accuracy may also be determined under section 2.1.5.2 of
2.1.5.1Use the procedures in the following standards to verify flowmeter accuracy or design, as appropriate to the type of flowmeter: ASME MFC-3M-1989 with September 1990 Errata (“Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi”); ASME MFC-4M-1986 (Reaffirmed 1990), “Measurement of Gas Flow by Turbine Meters;” American Gas Association Report No. 3, “Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids Part 1: General Equations and Uncertainty Guidelines” (October 1990 Edition), Part 2: “Specification and Installation Requirements” (February 1991 Edition), and Part 3: “Natural Gas Applications” (August 1992 edition) (excluding the modified flow-calculation method in part 3); Section 8, Calibration from American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (Second Revision, April, 1996); ASME MFC-5M-1985 (“Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters”); ASME MFC-6M-1987 with June 1987 Errata (“Measurement of Fluid Flow in Pipes Using Vortex Flow Meters”); ASME MFC-7M-1987 (Reaffirmed 1992), “Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles;” ISO 8316: 1987(E) “Measurement of Liquid Flow in Closed Conduits—Method by Collection of the Liquid in a Volumetric Tank;” American Petroleum Institute (API) Section 2, “Conventional Pipe Provers”, Section 3, “Small Volume Provers”, and Section 5, “Master-Meter Provers”, from Chapter 4 of the Manual of Petroleum Measurement Standards, October 1988 (Reaffirmed 1993); or ASME MFC-9M-1988 with December 1989 Errata (“Measurement of Liquid Flow in Closed Conduits by Weighing Method”), for all other flowmeter types (incorporated by reference under § 75.6). The Administrator may also approve other procedures that use equipment traceable to National Institute of Standards and Technology standards. Document such procedures, the equipment used, and the accuracy of the procedures in the monitoring plan for the unit, and submit a petition signed by the designated representative under § 75.66(c). If the flowmeter accuracy exceeds 2.0 percent of the upper range value, the flowmeter does not qualify for use under this part.
2.1.5.2(a) Alternatively, determine the flowmeter accuracy of a fuel flowmeter used for the purposes of this part by comparing it to the measured flow from a reference flowmeter which has been either designed according to the specifications of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix, or tested for accuracy during the previous 365 days, using a standard listed in section 2.1.5.1 of this appendix or other procedure approved by the Administrator under § 75.66 (all standards incorporated by reference under § 75.6). Any secondary elements, such as pressure and temperature transmitters, must be calibrated immediately prior to the comparison. Perform the comparison over a period of no more than seven consecutive unit operating days. Compare the average of three fuel flow rate readings over 20 minutes or longer for each meter at each of three different flow rate levels. The three flow rate levels shall correspond to:
(1) Normal full unit operating load,
(2) Normal minimum unit operating load,
(3) A load point approximately equally spaced between the full and minimum unit operating loads, and
(4) Calculate the flowmeter accuracy at each of the three flow levels using the following equation:
(c) Notwithstanding the requirement for calibration of the reference flowmeter within 365 days prior to an accuracy test, when an in-place reference meter or prover is used for quality assurance under section 2.1.6 of this appendix, the reference meter calibration requirement may be waived if, during the previous in-place accuracy test with that reference meter, the reference flowmeter and the flowmeter being tested agreed to within
2.1.5.3If the flowmeter accuracy exceeds the specification in section 2.1.5 of this appendix, the flowmeter does not qualify for use for this appendix. Either recalibrate the flowmeter until the flowmeter accuracy is within the performance specification, or replace the flowmeter with another one that is demonstrated to meet the performance specification. Substitute for fuel flow rate using the missing data procedures in section 2.4.2 of this appendix until quality assured fuel flow data become available.
2.1.5.4For purposes of initial certification, when a flowmeter is tested against a reference fuel flow rate (i.e., fuel flow rate from another fuel flowmeter under section
(a) Test the accuracy of each fuel flowmeter prior to use under this part and at least once every four fuel flowmeter QA operating quarters, as defined in § 72.2 of this chapter, thereafter. Notwithstanding these requirements, no more than 20 successive calendar quarters shall elapse after the quarter in which a fuel flowmeter was last tested for accuracy without a subsequent flowmeter accuracy test having been conducted. Test the flowmeter accuracy more frequently if required by manufacturer specifications.
(b) Except for orifice-, nozzle-, and venturi-type flowmeters, perform the required flowmeter accuracy testing using the procedures in either section 2.1.5.1 or section 2.1.5.2 of this appendix. Each fuel flowmeter must meet the accuracy specification in section 2.1.5 of this appendix.
(c) For orifice-, nozzle-, and venturi-type flowmeters, either perform the required flowmeter accuracy testing using the procedures in section 2.1.5.1 or 2.1.5.2 of this appendix or perform a transmitter accuracy test once every four fuel flowmeter QA operating quarters and a primary element visual inspection once every 12 calendar quarters, according to the procedures in sections 2.1.6.1 through 2.1.6.4 of this appendix for periodic quality assurance.
(d) Notwithstanding the requirements of this section, if the procedures of section 2.1.7 (fuel flow-to-load test) of this appendix are performed during each fuel flowmeter QA operating quarter, subsequent to a required flowmeter accuracy test or transmitter accuracy test and primary element inspection, where applicable, those procedures may be used to meet the requirement for periodic quality assurance testing for a period of up to 20 calendar quarters from the previous accuracy test or transmitter accuracy test and primary element inspection, where applicable.
(a) Calibrate the differential pressure transmitter or transducer, static pressure transmitter or transducer, and temperature transmitter or transducer, as applicable, using equipment that has a current certificate of traceability to NIST standards. Check the calibration of each transmitter or transducer by comparing its readings to that of the NIST traceable equipment at least once at each of the following levels: the zero-level and at least two other levels (e.g., “mid” and “high”), such that the full range of transmitter or transducer readings corresponding to normal unit operation is represented.
(b) Calculate the accuracy of each transmitter or transducer at each level tested, using the following equation:
(c) If each transmitter or transducer meets an accuracy of
(a) Record the accuracy of the orifice, nozzle, or venturi meter or its individual transmitters or transducers and keep this information in a file at the site or other location suitable for inspection. When testing individual orifice, nozzle, or venturi meter transmitters or transducers for accuracy, include the information displayed in the following Table D-2. At a minimum, record results for each transmitter or transducer at the zero-level and at least two other levels across the range of the transmitter or transducer readings that correspond to normal unit operation.
(b) When accuracy testing of the orifice, nozzle, or venturi meter is performed according to section 2.1.5.2 of this appendix, record the information displayed in Table D-1 in this section. At a minimum, record the overall flowmeter accuracy results for the fuel flowmeter at the three flow rate levels specified in section 2.1.5.2 of this appendix.
(c) Report the results of all fuel flowmeter accuracy tests, transmitter or transducer accuracy tests, and primary element inspections, as applicable, in the emissions report for the quarter in which the quality assurance tests are performed, using the electronic format specified by the Administrator under § 75.64.
If, during a transmitter or transducer accuracy test conducted according to section 2.1.6.1 of this appendix, the flowmeter accuracy specification of 2.0 percent is not met at any of the levels tested, repair or replace transmitter(s) or transducer(s) as necessary until the flowmeter accuracy specification has been achieved at all levels. (Note that only transmitters or transducers which are repaired or replaced need to be re-tested; however, the re-testing is required at all three measurement levels, to ensure that the flowmeter accuracy specification is met at each level). The fuel flowmeter is “out-of-control” and data from the flowmeter are considered invalid, beginning with the date and hour of the failed accuracy test and continuing until the date and hour of completion of a successful transmitter or transducer accuracy test at all levels. In addition, if, during normal operation of the fuel flowmeter, one or more transmitters or transducers malfunction, data from the fuel flowmeter shall be considered invalid from the hour of the transmitter or transducer failure until the hour of completion of a successful 3-level transmitter or transducer accuracy test. During fuel flowmeter out-of-control periods, provide data from another fuel flowmeter that meets the requirements of § 75.20(d) and section 2.1.5 of this appendix, or substitute for fuel flow rate using the missing data procedures in section 2.4.2 of this appendix. Record and report test data and results, consistent with sections 2.1.6.1 and 2.1.6.2 of this appendix and § 75.56 or § 75.59, as applicable.
(a) Conduct a visual inspection of the orifice, nozzle, or venturi meter at least once every twelve calendar quarters. Notwithstanding this requirement, the procedures of section 2.1.7 of this appendix may be used to reduce the inspection frequency of the orifice, nozzle, or venturi meter to at least once every twenty calendar quarters. The inspection may be performed using a baroscope. If the visual inspection indicates that the orifice, nozzle, or venturi meter has become damaged or corroded, then:
(1) Replace the primary element with another primary element meeting the requirements of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6);
(2) Replace the primary element with another primary element, and demonstrate that the overall flowmeter accuracy meets the accuracy specification in section 2.1.5 of this appendix under the procedures of section 2.1.5.2 of this appendix; or
(3) Restore the damaged or corroded primary element to “as new” condition; determine the overall accuracy of the flowmeter, using either the specifications of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6); and retest the transmitters or transducers prior to providing quality assured data from the flowmeter.
(b) If the primary element size is changed, calibrate the transmitter or transducers consistent with the new primary element size. Data from the fuel flowmeter are considered invalid, beginning with the date and hour of a failed visual inspection and continuing until the date and hour when:
(1) The damaged or corroded primary element is replaced with another primary element meeting the requirements of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6);
(2) The damaged or corroded primary element is replaced, and the overall accuracy of the flowmeter is demonstrated to meet the accuracy specification in section 2.1.5 of this appendix under the procedures of section 2.1.5.2 of this appendix; or
(3) The restored primary element is installed to meet the requirements of American Gas Association Report No. 3 or ASME MFC-3M-1989, as cited in section 2.1.5.1 of this appendix (both standards incorporated by reference under § 75.6) and its transmitters or transducers are retested to meet the accuracy specification in section 2.1.6.1 of this appendix.
(c) During this period, provide data from another fuel flowmeter that meets the requirements of § 75.20(d) and section 2.1.5 of this appendix, or substitute for fuel flow rate using the missing data procedures in section 2.4.2 of this appendix.
2.1.7Fuel Flow-to-Load Quality Assurance Testing for Certified Fuel Flowmeters
The procedures of this section may be used as an optional supplement to the quality assurance procedures in section 2.1.5.1, 2.1.5.2,
(a) Determine R
(b) In Equation D-1b, for a common pipe header, L
(c) Alternatively, a baseline value of the gross heat rate (GHR) may be determined in lieu of R
(d) Report the current value of R
(a) Evaluate the fuel flow rate-to-load ratio (or GHR) for each fuel flowmeter QA operating quarter, as defined in § 72.2 of this chapter. At the end of each fuel flowmeter QA operating quarter, use Equation D-1d in this appendix to calculate R
(b) For a common pipe header, L
(c) Alternatively, calculate the hourly gross heat rates (GHR) in lieu of the hourly flow-to-load ratios. If this option is selected, calculate each hourly GHR value as follows:
(d) Evaluate the calculated flow rate-to-load ratios (or gross heat rates) as follows. Perform a separate data analysis for each fuel flowmeter following the procedures of this section. Base each analysis on a minimum of 168 hours of data. If, for a particular fuel flowmeter, fewer than 168 hourly flow-to-load ratios (or GHR values) are available, a flow-to-load (or GHR) evaluation is not required for that flowmeter for that calendar quarter.
(e) For each hourly flow-to-load ratio or GHR value, calculate the percentage difference (percent D
(f) Consistently use R
(g) Next, determine the arithmetic average of all of the hourly percent difference (percent D
(h) When the quarterly average load value used in the data analysis is greater than 50 MWe (or 500 klb steam per hour), the results of a quarterly fuel flow rate-to-load (or GHR) evaluation are acceptable and no further action is required if the quarterly average percentage difference (E
(a) If E
(b) After identifying and excluding all non-representative hourly fuel flow-to-load ratios or GHR values, analyze the quarterly fuel flow rate-to-load data a second time.
(a) If E
(b) Substitute for fuel flow rate, for any hour when that fuel is combusted, using the missing data procedures in section 2.4.2 of this appendix, beginning with the first hour of the calendar quarter following the quarter for which E
Report the results of each quarterly flow rate-to-load (or GHR) evaluation, as determined from Equation D-1g, in the electronic quarterly report required under § 75.64. Table D-3 is provided as a reference on the type of information to be recorded under § 75.59 and reported under § 75.64.
Perform sampling and analysis of oil to determine the following fuel properties for each type of oil combusted by a unit: percentage of sulfur by weight in the oil; gross calorific value (GCV) of the oil; and, if necessary, the density of the oil. Use the sulfur content, density, and gross calorific value, determined under the provisions of this section, to calculate SO
2.2.1When combusting oil, use one of the following methods to sample the oil (see Table D-4): sample from the storage tank for the unit after each addition of oil to the storage tank, in accordance with section 2.2.4.2 of this appendix; or sample from the fuel lot in the shipment tank or container upon receipt of each oil delivery or from the fuel lot in the oil supplier's storage container, in accordance with section 2.2.4.3 of this appendix; or use the flow proportional sampling methodology in section 2.2.3 of this appendix; or use the daily manual sampling methodology in section 2.2.4.1 of this appendix. For purposes of this appendix, a fuel lot of oil is the mass or volume of product oil from one source (supplier or pretreatment facility), intended as one shipment or delivery (e.g., ship load, barge load, group of trucks, discrete purchase of diesel fuel through pipeline, etc.). A storage tank is a container at a plant holding oil that is actually combusted by the unit, such that no blending of any other fuel with the fuel in the storage tank occurs from the time that the fuel lot is transferred to the storage tank to the time when the fuel is combusted in the unit.
2.2.2[Reserved]
Conduct flow proportional oil sampling or continuous drip oil sampling in accordance with ASTM D4177-82 (Reapproved 1990), “Standard Practice for Automatic Sampling of Petroleum and Petroleum Products” (incorporated by reference under § 75.6), every day the unit is combusting oil. Extract oil at least once every hour and blend into a composite sample. The sample compositing period may not exceed 7 calendar days (168 hrs). Use the actual sulfur content (and where density data are required, the actual density) from the composite sample to calculate the hourly SO
Representative oil samples may be taken from the storage tank or fuel flow line manually every day that the unit combusts oil according to ASTM D4057-88, “Standard Practice for Manual Sampling of Petroleum and Petroleum Products” (incorporated by reference under § 75.6). Use either the actual daily sulfur content or the highest fuel sulfur content recorded at that unit from the most recent 30 daily samples for the purpose of calculating SO
Take a manual sample after each addition of oil to the storage tank. Do not blend additional fuel with the sampled fuel prior to combustion. Sample according to the single tank composite sampling procedure or all-levels sampling procedure in ASTM D4057-88, “Standard Practice for Manual Sampling of Petroleum and Petroleum Products” (incorporated by reference under § 75.6). Use the
(a) The most recent oil sample taken or
(b) One of the conservative assumed values described in section 2.2.4.3 of this appendix.
(a) Alternatively, an oil sample may be taken from—
(1) The shipment tank or container upon receipt of each lot of fuel oil or
(2) The supplier's storage container which holds the lot of fuel oil. (Note: a supplier need only sample the storage container once for sulfur content, GCV and, where required, the density so long as the fuel sulfur content and GCV do not change and no fuel is added to the supplier's storage container.)
(b) For the purpose of this section, a lot is defined as a shipment or delivery (e.g., ship load, barge load, group of trucks, discrete purchase of diesel fuel through a pipeline, etc.) of a single fuel.
(c) Oil sampling may be performed either by the owner or operator of an affected unit, an outside laboratory, or a fuel supplier, provided that samples are representative and that sampling is performed according to either the single tank composite sampling procedure or the all-levels sampling procedure in ASTM D4057-88, “Standard Practice for Manual Sampling of Petroleum and Petroleum Products” (incorporated by reference under § 75.6). Except as otherwise provided in this section, calculate SO
(1) The highest value sampled during the previous calendar year (this option is allowed for any consistent fuel which comes from a single source whether or not the fuel is supplied under a contractual agreement) or
(2) The maximum value indicated in the contract with the fuel supplier. Continue to use this assumed contract value unless and until the actual sampled sulfur content, density, or gross calorific value of a delivery exceeds the assumed value.
(d) If the actual sampled sulfur content, gross calorific value, or density of an oil sample is greater than the assumed value for that parameter, then use the actual sampled value for sulfur content, gross calorific value, or density of fuel to calculate SO
2.2.5Split and label each oil sample. Maintain a portion (at least 200 cc) of each sample throughout the calendar year and in all cases for not less than 90 calendar days after the end of the calendar year allowance accounting period. Analyze oil samples for percent sulfur content by weight in accordance with ASTM D129-91, “Standard Test Method for Sulfur in Petroleum Products (General Bomb Method),” ASTM D1552-90, “Standard Test Method for Sulfur in Petroleum Products (High Temperature Method),” ASTM D2622-92, “Standard Test Method for Sulfur in Petroleum Products by X-Ray Spectrometry,” or ASTM D4294-90, “Standard Test Method for Sulfur in Petroleum Products by Energy-Dispersive X-Ray Fluorescence Spectroscopy” (incorporated by reference under § 75.6).
2.2.6Where the flowmeter records volumetric flow rate rather than mass flow rate, analyze oil samples to determine the density or specific gravity of the oil. Determine the density or specific gravity of the oil sample in accordance with ASTM D287-82 (Reapproved 1991), “Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method),” ASTM D941-88, “Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Lipkin Bicapillary Pycnometer,” ASTM D1217-91, “Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Bingham Pycnometer,” ASTM D1481-91, “Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Lipkin Bicapillary,” ASTM D1480-91, “Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer,” ASTM D1298-85 (Reapproved 1990), “Standard Practice for Density, Relative Density (Specific Gravity) or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method,” or ASTM D4052-91, “Standard Test Method for Density and Relative Density of Liquids by Digital Density Meter” (incorporated by reference under § 75.6).
2.2.7Analyze oil samples to determine the heat content of the fuel. Determine oil heat content in accordance with ASTM D240-87 (Reapproved 1991), “Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter,” ASTM D2382-88, “Standard Test Method for Heat or Combustion of Hydrocarbon Fuels by Bomb
2.2.8Results from the oil sample analysis must be available no later than thirty calendar days after the sample is composited or taken. However, during an audit, the Administrator may require that the results of the analysis be available as soon as practicable, and no later than 5 business days after receipt of a request from the Administrator.
(a) Account for the hourly SO
(b) The procedures in sections 2.3.1 and 2.3.2 of this appendix, respectively, may be used to determine SO
The owner or operator may determine the SO
For a fuel that meets the definition of pipeline natural gas under § 72.2 of this chapter, the owner or operator may determine the SO
Calculate hourly heat input rate, in mmBtu/hr, for a unit combusting pipeline natural gas, using the procedures of section 3.4.1 of this appendix. Use the measured fuel flow rate from section 2.1 of this appendix and the gross calorific value from section 2.3.4.1 of this appendix in the calculations.
For pipeline natural gas combustion, calculate the SO2 mass emission rate, in lb/hr, using Equation D-5 in section 3.3.2 of this appendix (when the default SO
(a) For pipeline natural gas, provide information in the monitoring plan required under § 75.53, demonstrating that the definition of pipeline natural gas in § 72.2 of this chapter has been met. The information must demonstrate that the fuel has a hydrogen sulfide content of less than 0.3 grain/100scf. The demonstration must be made using one of the following sources of information:
(1) The gas quality characteristics specified by a purchase contract or by a pipeline transportation contract;
(2) A certification of the gas vendor, based on routine vendor sampling and analysis (minimum of one year of data with samples taken monthly or more frequently);
(3) At least one year's worth of analytical data on the fuel hydrogen sulfide content from samples taken monthly or more frequently;
(4) For fuels delivered in shipments or lots, the sulfur content from all shipments or lots received in a one year period; or
(5) Data from a 720-hour demonstration conducted using the procedures of section 2.3.6 of this appendix.
(b) When a 720-hour test is used for initial qualification as pipeline natural gas, the owner or operator is required to continue sampling the fuel for hydrogen sulfide at least once per month for one year after the initial qualification period. The use of the default natural gas SO
The owner or operator may determine the SO
The owner or operator may account for SO
2.3.2.1.1In lieu of daily sampling of the sulfur content of the natural gas, an SO
2.3.2.1.2The hydrogen sulfide value used in Equation D-1h may be obtained from one of the following sources of information:
(a) The highest hydrogen sulfide content specified by a purchase contract or by a pipeline transportation contract;
(b) The highest hydrogen sulfide content from a certification of the gas vendor, based on routine vendor sampling and analysis (minimum of one year of data with samples taken monthly or more frequently);
(c) The highest hydrogen sulfide content from at least one year's worth of analytical data on the fuel hydrogen sulfide content
(d) For fuels delivered in shipments or lots, the highest hydrogen sulfide content from all shipments or lots received in a one year period; or (5) the highest hydrogen sulfide content measured during a 720-hour demonstration conducted using the procedures of section 2.3.6 of this appendix.
Calculate hourly heat input rate for natural gas combustion, in mmBtu/hr, using the procedures in section 3.4.1 of this appendix. Use the measured fuel flow rate from section 2.1 of this appendix and the gross calorific value from section 2.3.4.2 of this appendix in the calculations.
For natural gas combustion, calculate the SO
(a) For natural gas, provide information in the monitoring plan required under § 75.53, demonstrating that the definition of natural gas in § 72.2 of this chapter has been met. The information must demonstrate that the fuel has a hydrogen sulfide content of less than 1.0 grain/100 scf. This demonstration must be made using one of the following sources of information:
(1) The gas quality characteristics specified by a purchase contract or by a transportation contract;
(2) A certification of the gas vendor, based on routine vendor sampling and analysis (minimum of one year of data with samples taken monthly or more frequently);
(3) At least one year's worth of analytical data on the fuel hydrogen sulfide content from samples taken monthly or more frequently;
(4) For fuels delivered in shipments or lots, sulfur content from all shipments or lots received in a one year period; or
(5) Data from a 720-hour demonstration conducted using the procedures of section 2.3.6 of this appendix.
(b) When a 720-hour test is used for initial qualification as natural gas, the owner or operator shall continue sampling the fuel for hydrogen sulfide at least once per month for one year after the initial qualification period. The use of the default natural gas SO
The owner or operator of a unit may determine SO
2.3.3.1.1Analyze the total sulfur content of the gaseous fuel in grain/100 scf, at the frequency specified in Table D-5 of this appendix. That is: for fuel delivered in discrete shipments or lots, sample each shipment or lot; for fuel transmitted by pipeline, if a demonstration is provided under section 2.3.6 of this appendix showing that the gaseous fuel has a “low sulfur variability,” determine the sulfur content daily using either manual sampling or a gas chromatograph; and for all other gaseous fuels, determine the sulfur content on an hourly basis using a gas chromatograph.
2.3.3.1.2Use one of the following methods when using manual sampling (as applicable to the type of gas combusted) to determine the sulfur content of the fuel: ASTM D1072-90, “Standard Test Method for Total Sulfur in Fuel Gases”, ASTM D4468-85 (Reapproved 1989) “Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Radiometric Colorimetry,” ASTM D5504-94 “Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence,” or ASTM D3246-81 (Reapproved 1987) “Standard Test Method for Sulfur in Petroleum Gas By Oxidative Microcoulometry” (incorporated by reference under § 75.6).
2.3.3.1.3The sampling and analysis of daily manual samples may be performed by the owner or operator, an outside laboratory, or the gas supplier. If hourly sampling with a gas chromatograph is required, or a source chooses to use an online gas chromatograph to determine daily fuel sulfur content, the owner or operator shall develop and implement a program to quality assure the data from the gas chromatograph, in accordance with the manufacturer's recommended procedures. The quality assurance procedures shall be kept on-site, in a form suitable for inspection.
2.3.3.1.4Results of all sample analyses must be available no later than thirty calendar days after the sample is taken.
2.3.3.2SO
Calculate the SO
Calculate the hourly heat input rate for combustion of the gaseous fuel, using the provisions in section 3.4.1 of this appendix. Use the measured fuel flow rate from section 2.1 of this appendix and the gross calorific value from section 2.3.4.3 of this appendix in the calculations.
Determine the GCV of each gaseous fuel at the frequency specified in this section, using one of the following methods: ASTM D1826-88, ASTM D3588-91, ASTM D4891-89, GPA Standard 2172-86 “Calculation of Gross Heating Value, Relative Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis,” or GPA Standard 2261-90 “Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography” (incorporated by reference under § 75.6 of this part). Use the appropriate GCV value, as specified in section 2.3.4.1, 2.3.4.2 or 2.3.4.3 of this appendix, in the calculation of unit hourly heat input rates.
Determine the GCV of fuel that is pipeline natural gas, as defined in § 72.2 of this chapter, at least once per calendar month. For GCV used in calculations use the specifications in Table D-5: either the value from the most recent monthly sample, the highest value specified in a contract or tariff sheet, or the highest value from the previous year. The fuel GCV value from the most recent monthly sample shall be used for any month in which that value is higher than a contract limit. If a unit combusts pipeline natural gas for less than 48 hours during a calendar month, the sampling and analysis requirement for GCV is waived for that calendar month. The preceding waiver is limited by the condition that at least one analysis for GCV must be performed for each quarter the unit operates for any amount of time.
Determine the GCV of fuel that is natural gas, as defined in § 72.2 of this chapter, on a monthly basis, in the same manner as described for pipeline natural gas in section 2.3.4.1 of this appendix.
For gaseous fuels other than natural gas or pipeline natural gas, determine the GCV as specified in section 2.3.4.3.1, 2.3.4.3.2 or 2.3.4.3.3, as applicable.
2.3.4.3.1 For a gaseous fuel that is delivered in discrete shipments or lots, determine the GCV for each shipment or lot. The determination may be made by sampling each delivery or by sampling the supply tank after each delivery. For sampling of each delivery, use the highest GCV in the previous year's samples. For sampling from the tank after each delivery, use either the most recent GCV sample or the highest GCV in the previous year.
2.3.4.3.2 For any gaseous fuel that does not qualify as pipeline natural gas or natural gas and which is not delivered in shipments or lots which performs the required 720 hour test under section 2.3.5 of this appendix, and the results of the test demonstrate that the gaseous fuel has a low GCV variability, determine the GCV at least monthly. In calculations of hourly heat input for a unit, use either the most recent monthly sample or the highest fuel GCV from the previous year's samples.
2.3.4.3.3 For any other gaseous fuel, determine the GCV at least daily and use the actual fuel GCV in calculations of unit hourly heat input. If an online gas chromatograph or on-line calorimeter is used to determine fuel GCV each day, the owner or operator shall develop and implement a program to quality assure the data from the gas chromatograph or on-line calorimeter, in accordance with the manufacturer's recommended procedures. The quality assurance procedures shall be kept on-site, in a form suitable for inspection.
(a) This demonstration is required of any fuel which does not qualify as pipeline natural gas or natural gas, and is not delivered only in shipments or lots. The demonstration data shall be used to determine whether daily or monthly sampling of the GCV of the gaseous fuel or blend is required.
(b) To make this demonstration, proceed as follows. Provide a minimum of 720 hours of data, indicating the GCV of the gaseous fuel or blend (in Btu/100 scf). The demonstration data shall be obtained using either: hourly sampling and analysis using the methods in section 2.3.4 to determine GCV of the fuel; an on-line gas chromatograph capable of determining fuel GCV on an hourly basis; or an on-line calorimeter. For gaseous fuel produced by a variable process, the data shall be representative of and include all process operating conditions including seasonal and yearly variations in process which may affect fuel GCV.
(c) The data shall be reduced to hourly averages. The mean GCV value and the standard deviation from the mean shall be calculated from the hourly averages. Specifically, the gaseous fuel is considered to have a low GCV variability, and monthly gas sampling for GCV may be used, if the mean value of the GCV multiplied by 1.075 is greater than the sum of the mean value and one standard deviation. If the gaseous fuel or blend does not meet this requirement, then daily fuel sampling and analysis for GCV, using manual sampling, a gas chromatograph or an on-line calorimeter is required.
(a) This demonstration is required for any fuel which does not qualify as pipeline natural gas or natural gas and is not delivered in shipments or lots. The results of the demonstration will be used to determine whether daily or hourly sampling for sulfur in the fuel is required. To make this demonstration, proceed as follows. Provide a minimum of 720 hours of data, indicating the total sulfur content (and hydrogen sulfide content, if needed to define a fuel as either pipeline natural gas or natural gas) of the gaseous fuel or blend (in gr/100 scf). The demonstration data shall be obtained using either manual hourly sampling or an on-line gas chromatograph capable of determining fuel total sulfur content (and, if applicable, H
(b) Reduce the data to hourly averages of the total sulfur content (and hydrogen sulfide content, if applicable) of the fuel. Then, calculate the mean value of the total sulfur content and standard deviation in order to determine whether daily sampling of the sulfur content of the gaseous fuel or blend is sufficient or whether hourly sampling with a gas chromatograph is required. Specifically, daily gas sampling and analysis for total sulfur content, using either manual sampling or an online gas chromatograph, shall be sufficient, provided that the standard deviation of the hourly average values from the mean value does not exceed 5.0 grains per 100 scf. If the gaseous fuel or blend does not meet this requirement, then hourly sampling of the fuel with a gas chromatograph and hourly reporting of the average sulfur content of the fuel is required.
When data from the procedures of this part are not available, provide substitute data using the following procedures.
When fuel sulfur content, gross calorific value or, when necessary, density data are missing or invalid for an oil or gas sample taken according to the procedures in section 2.2.3, 2.2.4.1, 2.2.4.2, 2.2.4.3, 2.2.5, 2.2.6, 2.2.7, 2.3.3.1, 2.3.3.1.2, or 2.3.4 of this appendix, then substitute the maximum potential sulfur content, density, or gross calorific value of that fuel from Table D-6 of this appendix. Irrespective of which reporting option is selected (i.e., actual value, contract value or highest value from the previous year, the missing data values in Table D-6 shall be reported whenever the results of a required sample of sulfur content, GCV or density is missing or invalid in the current calendar year. The substitute data value(s) shall be used until the next valid sample for the missing parameter(s) is obtained. Note that only actual sample results shall be used to determine the “highest value from the previous year” when that reporting option is used; missing data values shall not be used in the determination.
2.4.2Whenever data are missing from any fuel flowmeter that is part of an excepted monitoring system under appendix D or E to this part, where the fuel flowmeter data are required to determine the amount of fuel combusted by the unit, use the procedures in sections 2.4.2.2 and 2.4.2.3 of this appendix to account for the flow rate of fuel combusted at the unit for each hour during the missing data period. In addition, a fuel flowmeter used for measuring fuel combusted by a peaking unit may use the simplified fuel flow missing data procedure in section 2.4.2.1 of this appendix.
If no fuel flow rate data are available for a fuel flowmeter system installed on a peaking unit (as defined in § 72.2 of this chapter), then substitute for each hour of missing data using the maximum potential fuel flow rate. The maximum potential fuel flow rate is the lesser of the following:
(a) The maximum fuel flow rate the unit is capable of combusting or (b) the maximum flow rate that the flowmeter can measure (i.e, upper range value of flowmeter leading to a unit).
2.4.2.2For hours where only one fuel is combusted, substitute for each hour in the missing data period the average of the hourly fuel flow rate(s) measured and recorded by the fuel flowmeter (or flowmeters, where fuel is recirculated) at the corresponding operating unit load range recorded for each missing hour during the previous 720 hours during which the unit combusted that same fuel only. Establish load ranges for the unit using the procedures of section 2 in appendix C of this part for missing volumetric flow rate data. If no fuel flow rate data are available at the corresponding load range, use data from the next higher load range where data are available. If no fuel flow rate data are available at either the corresponding load range or a higher load range during any hour of the missing data period for that fuel, substitute the maximum potential fuel flow rate. The maximum potential fuel flow rate is the lesser of the following: (1) the maximum fuel flow rate the unit is capable of combusting or (2) the maximum flow rate that the flowmeter can measure.
2.4.2.3For hours where two or more fuels are combusted, substitute the maximum hourly fuel flow rate measured and recorded by the flowmeter (or flowmeters, where fuel is recirculated) for the fuel for which data are missing at the corresponding load range recorded for each missing hour during the previous 720 hours when the unit combusted that fuel with any other fuel. For hours where no previous recorded fuel flow rate data are available for that fuel during the missing data period, calculate and substitute the maximum potential flow rate of that fuel for the unit as defined in section 2.4.2.2 of this appendix.
2.4.3.In any case where the missing data provisions of this section require substitution of data measured and recorded more than three years (26,280 clock hours) prior to the date and time of the missing data period, use three years (26,280 clock hours) in place of the prescribed lookback period.
Calculate hourly SO
3.1.1Use Equation D-2 to calculate SO
SO
OIL
%S
2.0 = Ratio of lb SO
3.1.2 Record the SO
3.2.1Where the oil flowmeter records volumetric flow rate rather than mass flow rate, calculate and record the oil mass flow rate for each hourly period using hourly oil flow rate measurements and the density or specific gravity of the oil sample.
3.2.2Convert density, specific gravity, or API gravity of the oil sample to density of the oil sample at the sampling location's temperature using ASTM D1250-80 (Re-ap-proved 1990), “Standard Guide for Petroleum Measurement Tables” (incorporated by reference under § 75.6 of this part).
3.2.3Where density of the oil is determined by the applicable ASTM procedures from section 2.2.6 of this appendix, use Equation D-3 to calculate the rate of the mass of oil consumed (in lb/hr):
3.3.1Use Equation D-4 to calculate the SO
3.3.2Use Equation D-5 to calculate the SO
3.3.3Record the SO
(a) Determine total hourly gas flow or average hourly gas flow rate with a fuel flowmeter in accordance with the requirements of section 2.1 of this appendix and the fuel GCV in accordance with the requirements of section 2.3.4 of this appendix. If necessary perform the 720-hour test under section 2.3.5 to determine the appropriate fuel GCV sampling frequency.
(b) Then, use Equation D-6 to calculate heat input rate from gaseous fuels for each hour.
(c) Note that when fuel flow is measured on an hourly totalized basis (e.g. a fuel flowmeter reports totalized fuel flow for each hour), before Equation D-6 can be used, the total hourly fuel usage must be converted from units of 100 scf to units of 100 scf/hr using Equation D-7:
(a) Determine total hourly oil flow or average hourly oil flow rate with a fuel flowmeter, in accordance with the requirements of section 2.1 of this appendix. Determine oil GCV according to the requirements of section 2.2 of this appendix.
Then, use Equation D-8 to calculate hourly heat input rate from oil for each hour:
(b) Note that when fuel flow is measured on an hourly totalized basis (e.g., a fuel flowmeter reports totalized fuel flow for each hour), before equation D-8 can be used, the total hourly fuel usage must be converted from units of lb to units of lb/hr, using equation D-9:
(a) Use the procedure in this section to apportion hourly heat input rate to two or more units using a single fuel flowmeter which supplies fuel to the units. (This procedure is not applicable to units calculating NO
(b) Determine total hourly fuel flow or flow rate through the fuel flowmeter supplying gas or oil fuel to the units. Convert fuel flow rates to units of 100 scf for gaseous fuels or to lb for oil, using the procedures of this appendix. Apportion the fuel to each unit separately based on hourly output of the unit in MW
(c) Use the total apportioned fuel flow calculated from Equation D-10 or D-11 to calculate the hourly unit heat input rate, using Equations D-6 and D-7 (for gas) or Equations D-8 and D-9 (for oil).
Determine the total mass emissions for each hour from the combustion of all fuels using Equation D-12:
Sum the hourly SO
Calculate and record SO
Determine the total heat input in mmBtu for each hour from the combustion of all fuels using Equation D-15:
Sum the hourly heat input values determined from equation D-15 for all hours in a quarter using Equation D-16:
Calculate and record the total heat input in the year to date using Equation D-17.
Calculate and record quarterly and cumulative SO
This NO
1.2.1Pursuant to the procedures in § 75.20, complete all testing requirements to certify use of this protocol in lieu of a NO
1.2.2If the owner or operator has already successfully completed certification testing of the unit using the protocol of appendix E of part 75 and submitted a certification application under § 75.20(g) prior to
Use the following procedures for: measuring NO
Establish at least four approximately equally spaced operating load points, ranging from the maximum operating load to the minimum operating load. Select the maximum and minimum operating load from the operating history of the unit during the most recent two years. (If projections indicate that the unit's maximum or minimum operating load during the next five years will be significantly different from the most recent two years, select the maximum and minimum operating load based on the projected dispatched load of the unit.) For new gas-fired peaking units or new oil-fired peaking units, select the maximum and minimum operating load from the expected maximum and minimum load to be dispatched to the unit in the first five calendar years of operation.
Use the following procedures to measure NO
2.1.2.1For boilers, select an excess O
2.1.2.2For stationary gas turbines, select sampling points and measure the NO
2.1.2.3Allow the unit to stabilize for a minimum of 15 minutes (or longer if needed for the NO
Measure the total heat input (mmBtu) and heat input rate during testing (mmBtu/hr) as follows:
2.1.3.1When the unit is combusting fuel, measure and record the flow of fuel consumed. Measure the flow of fuel with an in-line flowmeter(s) and automatically record the data. If a portion of the flow is diverted from the unit without being burned, and that diversion occurs downstream of the fuel flowmeter, an in-line flowmeter is required to account for the unburned fuel. Install and calibrate in-line flow meters using the procedures and specifications contained in sections 2.1.2, 2.1.3, 2.1.4, and 2.1.5 of appendix D of this part. Correct any gaseous fuel flow rate measured at actual temperature and pressure to standard conditions of 68 °F and 29.92 inches of mercury.
2.1.3.2For liquid fuels, analyze fuel samples taken according to the requirements of section 2.2 of appendix D of this part to determine the heat content of the fuel. Determine heat content of liquid or gaseous fuel in accordance with the procedures in appendix F of this part. Calculate the heat input rate during testing (mmBtu/hr) associated with each load condition in accordance with equations F-19 or F-20 in appendix F of this part and total heat input using equation E-1 of this appendix. Record the heat input rate at each heat input/load point.
The designated representative of a unit that is restricted by its Federal, State or local permit to combusting a particular fuel only during emergencies where the primary fuel is not available may petition the Administrator pursuant to the procedures in § 75.66 for an exemption from the requirements of this appendix for testing the NO
Tabulate the results of each baseline correlation test for each fuel or, as applicable, combination of fuels, listing: time of test, duration, operating loads, heat input rate (mmBtu/hr), F-factors, excess oxygen levels, and NO
Plot the tabulated results as an x-y graph for each fuel and (as applicable) combination of fuels combusted according to the following procedures.
2.1.6.1Plot the heat input rate (mmBtu/hr) as the independent (or x) variable and the NO
2.1.6.2Units that co-fire gas and oil may be tested while firing gas only and oil only instead of testing with each combination of fuels. In this case, construct a graph for each fuel.
Retest the NO
When the operating levels of certain parameters exceed the limits specified below, or where the Administrator issues a notice requesting retesting because the NO
2.3.1For a stationary gas turbine, obtain a list of at least four operating parameters indicative of the turbine's NO
2.3.2For a diesel or dual-fuel reciprocating engine, obtain a list of at least four operating parameters indicative of the engine's NO
2.3.3For boilers using the procedures in this appendix, the NO
2.4.1Record the time (hr. and min.), load (MWge or steam load in 1000 lb/hr), fuel flow rate and heat input rate (using the procedures in section 2.1.3 of this appendix) for each hour during which the unit combusts fuel. Calculate the total hourly heat input using equation E-1 of this appendix. Record the heat input rate for each fuel to the nearest 0.1 mmBtu/hr. During partial unit operating hours or during hours where more than one fuel is combusted, heat input must be represented as an hourly rate in mmBtu/hr, as if the fuel were combusted for the entire hour at that rate (and not as the actual, total heat input during that partial hour or hour) in order to ensure proper correlation with the NO
2.4.2 Use the graph of the baseline correlation results (appropriate for the fuel or fuel
2.4.3 To determine the NO
2.4.4 For each hour, record the critical quality assurance parameters, as identified in the monitoring plan, and as required by section 2.3 of this appendix from the date and hour of the completion of the most recent test for each type of fuel.
Provide substitute data for each unit electing to use this alternative procedure whenever a valid quality-assured hour of NO
2.5.1Use the procedures of this section whenever any of the quality assurance/quality control parameters exceeds the limits in section 2.3 of this appendix or whenever any of the quality assurance/quality control parameters are not available.
2.5.2Substitute missing NO
2.5.3Maintain a record indicating which data are substitute data and the reasons for the failure to provide a valid quality-assured hour of NO
2.5.4 Substitute missing data from a fuel flowmeter using the procedures in section 2.4.2 of appendix D to this part.
2.5.5 Substitute missing data for gross calorific value of fuel using the procedures in sections 2.4.1 of appendix D to this part.
Calculate the total heat input by summing the product of heat input rate and fuel usage time of each fuel, as in the following equation:
Calculate the total heat input by summing the product of heat input rate and fuel usage time of each fuel, as in the following equation:
Determine the F-factors for each fuel or combination of fuels to be combusted according to section 3.3 of appendix F of this part.
Convert the NO
Report the quarterly average emission rate (lb/mmBtu) as required in subpart G of this part. Calculate the quarterly average NO
Report the average emission rate (lb/mmBtu) for the calendar year as required in subpart G of this part. Calculate the average NO
For hours where a fuel is combusted for only part of the hour, use the fuel flow rate or mass flow rate during the fuel usage time, instead of the total fuel flow or mass flow during the hour, when calculating heat input rate using Equation F-19 or F-20.
Include a section on the NO
4.1Submit a copy of the unit manufacturer's recommended range of operating parameter values, and the range of operating parameter values recorded during the previous NO
4.2Keep records of these operating parameters for each hour of operation in order to demonstrate that a unit is remaining within the manufacturer's recommended operating range.
Use the procedures in this appendix to convert measured data from a monitor or continuous emission monitoring system into the appropriate units of the standard.
Use the following procedures to compute hourly SO
2.1 When measurements of SO
2.3 Use the following equations to calculate total SO
2.4 Round all SO
Use the following procedures to convert continuous emission monitoring system measurements of NO
3.1When the NO
3.2When the NO
3.3Use the definitions listed below to derive values for the parameters in equations F-5 and F-6 of this appendix.
3.3.1K=1.194x10−7 (lb/dscf)/ppm NO
3.3.2E = Pollutant emissions during unit operation, lb/mmBtu.
3.3.3C
3.3.4%O
3.3.5F, F
3.3.6Equations F-7a and F-7b may be used in lieu of the F or F
3.3.6.1H, C, S, N, and O are content by weight of hydrogen, carbon, sulfur, nitrogen, and oxygen (expressed as percent), respectively, as determined on the same basis as the gross calorific value (GCV) by ultimate analysis of the fuel combusted using ASTM D3176-89, “Standard Practice for Ultimate Analysis of Coal and Coke” (solid fuels), ASTM D5291-92, “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants” (liquid fuels) or computed from results using ASTM D1945-91, “Standard Test Method for Analysis of Natural Gas by Gas Chromatography” or ASTM D1946-90, “Standard Practice for Analysis of Reformed Gas by Gas Chromatography” (gaseous fuels) as applicable. (These methods are incorporated by reference under § 75.6 of this part.)
3.3.6.2GCV is the gross calorific value (Btu/lb) of the fuel combusted determined by ASTM D2015-91, “Standard Test Method for Gross Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter”, ASTM D1989-92 “Standard Test Method for Gross Calorific Value of Coal and Coke by Microprocessor Controlled Isoperibol Calorimeters,” or ASTM D3286-91a “Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter” for solid and liquid fuels, and ASTM D240-87 (Reapproved 1991) “Standard
3.3.6.3For affected units that combust a combination of fossil (coal, oil and gas) and nonfossil (e.g., bark, wood, residue, or refuse) fuels, the F or F
3.3.6.4For affected units that combust combinations of fossil fuels or fossil fuels and wood residue, prorate the F or F
3.4 Use the following equations to calculate the average NO
3.5 Round all NO
Use the following procedures to convert continuous emission monitoring system measurements of CO
4.1 When CO
4.2 When CO
4.3 Use the following equations to calculate total CO
4.4 For an affected unit, when the owner or operator is continuously monitoring O
4.4.1 Use appropriate F and F
4.4.2Determine CO
Use the following procedures to compute heat input rate to an affected unit (in mmBtu/hr or mmBtu/day):
5.1 Calculate and record heat input rate to an affected unit on an hourly basis, except as provided in sections 5.5 through 5.5.7. The owner or operator may choose to use the provisions specified in § 75.16(e) or in section 2.1.2 of appendix D to this part in conjunction with the procedures provided in sections 5.6 through 5.6.2 to apportion heat input among each unit using the common stack or common pipe header.
5.2 For an affected unit that has a flow monitor (or approved alternate monitoring system under subpart E of this part for measuring volumetric flow rate) and a diluent gas (O
5.2.1 When measurements of CO
F
5.2.2 When measurements of CO
5.2.3 When measurements of O
HI = Hourly heat input rate during unit operation, mmBtu/hr.
F = Dry basis F-factor, listed in section 3.3.5 of this appendix for each fuel, dscf/mmBtu.
5.2.4 When measurements of O
HI = Hourly heat input rate during unit operation, mmBtu/hr.
F = Dry basis F-factor, listed in section 3.3.5 of this appendix for each fuel, dscf/mmBtu.
5.3.1 Calculate total quarterly heat input for a unit or common stack using a flow monitor and diluent monitor to calculate heat input, using the following equation:
HI
5.3.2Calculate total cumulative heat input for a unit or common stack using a flow monitor and diluent monitor to calculate heat input, using the following equation:
5.5For a gas-fired or oil-fired unit that does not have a flow monitor and is using the procedures specified in appendix D to this part to monitor SO
5.5.1(a)When the unit is combusting oil, use the following equation to calculate hourly heat input rate:
(b) When performing oil sampling and analysis solely for the purpose of the missing data procedures in § 75.36, oil samples for measuring GCV may be taken weekly, and the procedures specified in appendix D to this part for determining the mass rate of oil consumed per hour are optional.
5.5.2When the unit is combusting gaseous fuels, use the following equation to calculate heat input rate from gaseous fuels for each hour:
5.5.3When the unit is combusting coal, use the procedures, methods, and equations in sections 5.5.3.1-5.5.3.3 of this appendix to determine the heat input from coal for each 24-hour period. (All ASTM methods are incorporated by reference under § 75.6 of this part.)
5.5.3.1Perform coal sampling daily according to section 5.3.2.2 in Method 19 in appendix A to part 60 of this chapter and use ASTM Method D2234-89, “Standard Test Methods for Collection of a Gross Sample of Coal,” (incorporated by reference under § 75.6) Type I, Conditions A, B, or C and systematic spacing for sampling. (When performing coal sampling solely for the purposes of the missing data procedures in § 75.36, use of ASTM D2234-89 is optional, and coal samples may be taken weekly.)
5.5.3.2Use ASTM D2013-86, “Standard Method of Preparing Coal Samples for Analysis,” for preparation of a daily coal sample and analyze each daily coal sample for gross calorific value using ASTM D2015-91, “Standard Test Method for Gross Calorific Value of Coal and Coke by the Adiabatic Bomb Calorimeter”, ASTM 1989-92 “Standard Test Method for Gross Calorific Value of Coal and Coke by Microprocessor Controlled Isoperibol Calorimeters,” or ASTM 3286-91a “Standard Test Method for Gross Calorific Value of Coal and Coke by the Isoperibol Bomb Calorimeter.” (All ASTM methods are incorporated by reference under § 75.6 of this part.)
On-line coal analysis may also be used if the on-line analytical instrument has been demonstrated to be equivalent to the applicable ASTM methods under §§ 75.23 and 75.66.
5.5.3.3Calculate the heat input from coal using the following equation:
5.5.4For units obtaining heat input values daily instead of hourly, apportion the daily heat input using the fraction of the daily steam load or daily unit operating load used each hour in order to obtain HI
5.5.5If a daily fuel sampling value for gross calorific value is not available, substitute the maximum gross calorific value measured from the previous 30 daily samples. If a monthly fuel sampling value for gross calorific value is not available, substitute the maximum gross calorific value measured from the previous 3 monthly samples.
5.5.6If a fuel flow value is not available, use the fuel flowmeter missing data procedures in section 2.4 of appendix D of this part. If a daily coal consumption value is not available, substitute the maximum fuel feed rate during the previous thirty days when the unit burned coal.
5.5.7Results for samples must be available no later than thirty calendar days after the sample is composited or taken. However, during an audit, the Administrator may require that the results be available in five business days, or sooner if practicable.
5.6.1Where applicable, the owner or operator of an affected unit that determines heat input rate at the unit level by apportioning the heat input monitored at a common stack or common pipe using megawatts should apportion the heat input rate using the following equation:
The owner or operator of an affected unit that determines the heat input rate at the unit level by summing the heat input rates monitored at multiple stacks or multiple pipes should sum the heat input rates using the following equation:
Use the following equation to convert volumetric flow at actual temperature and pressure to standard temperature and pressure.
The owner or operator shall use the following equation to calculate hourly SO
The owner or operator of a unit that is required to monitor, record, and report NO
8.1Use the following procedures to calculate hourly NO
8.1.1If both NO
8.1.2If NO
8.1.3If a unit has multiple ducts and NO
8.1.4If a unit has multiple ducts and NO
8.2If a unit calculates NO
8.3If a unit calculates NO
8.4Use the following procedures to calculate quarterly, cumulative ozone season, and cumulative yearly NO
8.5 Specific provisions for monitoring NO
8.5.1The owner or operator may determine both NO
8.5.2The owner or operator may determine the NO
The procedures in this appendix may be used to estimate CO
Use the following procedures to estimate daily CO
2.1Use the following equation to calculate daily CO
2.2For an affected coal-fired unit, the estimate of daily CO
2.2.1Determine the ash content of the weekly sample of coal using ASTM D3174-89 “Standard Test Method for Ash in the Analysis Sample of Coal and Coke From Coal” (incorporated by reference under § 75.6 of this part).
2.2.2Sample and analyze the carbon content of the fly-ash according to ASTM D3178-89, “Standard Test Methods for Carbon and Hydrogen in the Analysis Sample of Coal and Coke” (incorporated by reference under § 75.6 of this part).
2.2.3Discount the estimate of daily CO
2.2.4The daily CO
2.3In lieu of using the procedures, methods, and equations in section 2.1 of this appendix, the owner or operator of an affected gas-fired unit as defined under § 72.2 of this chapter may use the following equation and records of hourly heat input to estimate hourly CO
When the affected unit has a wet flue gas desulfurization system, is a fluidized bed boiler, or uses other emission controls with sorbent injection, use either a CO
3.1When limestone is the sorbent material, use the equations and procedures in either section 3.1.1 or 3.1.2 of this appendix.
3.1.1Use the following equation to estimate daily CO
3.1.2In lieu of using equation G-5, any owner or operator who operates and maintains a certified SO
3.2When a sorbent material other than limestone is used, modify the equations, methods, and procedures in section 3.1 of this appendix as follows to estimate daily CO
3.2.1Determine a site-specific value for F
3.2.2When using equation G-5, replace MW
When the affected unit has a wet flue gas desulfurization system, is a fluidized bed boiler, or uses other emission controls with sorbent injection, use the following equation to obtain total daily CO
Use the following procedures to substitute for missing fuel analytical data used to calculate CO
Prior to April 1, 2000, follow either the procedures of this section or the procedures of section 5.2 of this appendix to substitute for missing carbon content data. On and after April 1, 2000, use the procedures of section 5.2 of this appendix to substitute for missing carbon content data, not the procedures of this section.
Substitute the most recent, previous carbon content value available for that fuel type (gas, oil, or coal) of the same grade (for oil) or rank (for coal). To the extent practicable, use a carbon content value from the same fuel supply. Where no previous carbon content data are available for a particular fuel type or rank of coal, substitute the default carbon content from Table G-1 of this appendix.
Prior to April 1, 2000, follow either the procedures of this section or the procedures of section 5.1 of this appendix to substitute for missing carbon content data. On and after April 1, 2000, use the procedures of this section to substitute for missing carbon content data.
5.2.1In all cases (i.e., for weekly coal samples or composite oil samples from continuous sampling, for oil samples taken from the storage tank after transfer of a new delivery of fuel, for as-delivered samples of oil, diesel fuel, or gaseous fuel delivered in lots, and for gaseous fuel that is supplied by a pipeline and sampled monthly, daily or hourly for gross calorific value) when carbon content data is missing, report the appropriate default value from Table G-1.
5.2.2The missing data values in Table G-1 shall be reported whenever the results of a
For a gas-fired unit using the procedures of section 2.3 of this appendix to determine CO
42 U.S.C. 7601 and 7651
(a) Except as provided in paragraphs (b) through (d) of this section, the provisions apply to each coal-fired utility unit that is subject to an Acid Rain emissions limitation or reduction requirement for SO
(b) The emission limitations for NO
(c) The provisions of this part apply to each coal-fired substitution unit or compensating unit, designated and approved as a Phase I unit pursuant to
(1) A coal-fired substitution unit that is designated in a substitution plan that is approved and active as of January 1, 1995 shall be treated as a Phase I coal-fired utility unit for purposes of this part. In the event the designation of such unit as a substitution unit is terminated after December 31, 1995, pursuant to § 72.41 of this chapter and the unit is no longer required to meet Phase I SO
(2) A coal-fired substitution unit that is designated in a substitution plan that is not approved or not active as of January 1, 1995, or a coal-fired compensating unit, shall be treated as a Phase II coal-fired utility unit for purposes of this part.
(d) The provisions of this part for Phase I units apply to each coal-fired transfer unit governed by a Phase I extension plan, approved pursuant to § 72.42 of this chapter, on January 1, 1997. Notwithstanding the preceding sentence, a coal-fired transfer unit shall be subject to the Acid Rain emissions limitations for nitrogen oxides beginning on January 1, 1996 if, for that year, a transfer unit is allocated fewer Phase I extension reserve allowances than the maximum amount that the designated representative could have requested in accordance with § 72.42(c)(5) of this chapter (as adjusted under § 72.42(d) of this chapter) unless the transfer unit is the last unit allocated Phase I extension reserve allowances under the plan.
All terms used in this part shall have the meaning set forth in the Act, in § 72.2 of this chapter, and in this section as follows:
(1) Operates the installed NO
(2) records and reports quality-assured continuous emission monitoring (CEM) and unit operating data according to the methods and procedures in part 75 of this chapter.
The following provisions of part 72 of this chapter shall apply to this part:
(a) § 72.2(Definitions);
(b) § 72.3(Measurements, abbreviations, and acronyms);
(c) § 72.4(Federal authority);
(d) § 72.5(State authority);
(e) § 72.6(Applicability);
(f) § 72.7(New unit exemption);
(g) § 72.8(Retired units exemption);
(h) § 72.9(Standard requirements);
(i) § 72.10(Availability of information); and
(j) § 72.11(Computation of time).
In addition, the procedures for appeals of decisions of the Administrator under this part are contained in part 78 of this chapter.
(a) The materials listed in this section are incorporated by reference in the sections noted. These incorporations by reference (IBR's) were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they existed on the date of approval, and notice of any change in these materials will be published in the
(b) The following materials are available for purchase from at least one of the following addresses: American Society for Testing and Materials (ASTM), 1916 Race Street, Philadelphia, Pennsylvania 19103; or the University Microfilms International, 300 North Zeeb Road, Ann Arbor, Michigan 48106.
(1) ASTM D 3176-89, Standard Practice for Ultimate Analysis of Coal and Coke, IBR approved May 23, 1995 for § 76.15.
(2) ASTM D 3172-89, Standard Practice for Proximate Analysis of Coal and Coke, IBR approved May 23, 1995 for § 76.15.
(c) The following material is available for purchase from the American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 2350, Fairfield, NJ 07007-2350.
(1) ASME Performance Test Code 4.2 (1991), Test Code for Coal Pulverizers, IBR approved May 23, 1995 for § 76.15.
(2) [Reserved]
(d) The following material is available for purchase from the American National Standards Institute, 11 West 42nd Street, New York, NY 10036 or from the International Organization for Standardization (ISO), Case Postale 56, CH-1211 Geneve 20, Switzerland.
(1) ISO 9931 (December, 1991) “Coal—Sampling of Pulverized Coal Conveyed by Gases in Direct Fired Coal Systems,” IBR approved May 23, 1995 for § 76.15.
(2) [Reserved]
(a) Beginning January 1, 1996, or for a unit subject to section 404(d) of the Act, the date on which the unit is required to meet Acid Rain emission reduction requirements for SO
(1) 0.45 lb/mmBtu of heat input on an annual average basis for tangentially fired boilers.
(2) 0.50 lb/mmBtu of heat input on an annual average basis for dry bottom wall-fired boilers (other than units applying cell burner technology).
(b) The owner or operator shall determine the annual average NO
(c) Unless the unit meets the early election requirement of § 76.8, the owner or operator of a coal-fired substitution unit with a tangentially fired boiler or a dry bottom wall-fired boiler (other than units applying cell burner technology) that satisfies the requirements of § 76.1(c)(2), shall comply with the NO
(d) The owner or operator of a Phase I unit with a cell burner boiler that converts to a conventional wall-fired boiler on or before January 1, 1995 or, for a unit subject to section 404(d) of the Act, the date the unit is required to meet Acid Rain emissions reduction requirements for SO
(e) The owner or operator of a Phase I unit with a Group 1 boiler that converts to a fluidized bed or other type of utility boiler not included in Group 1 boilers on or before January 1, 1995 or, for a unit subject to section 404(d) of the Act, the date the unit is required to meet Acid Rain emissions reduction requirements for SO
(f) Except as provided in § 76.8 and in paragraph (c) of this section, each unit subject to the requirements of this section is not subject to the requirements of § 76.7.
(a) Beginning January 1, 2000 or, for a unit subject to section 409(b) of the Act, the date on which the unit is required to meet Acid Rain emission reduction requirements for SO
(1) 0.68 lb/mmBtu of heat input on an annual average basis for cell burner boilers. The NO
(2) 0.86 lb/mmBtu of heat input on an annual average basis for cyclone boilers with a Maximum Continuous Steam Flow at 100% of Load of greater than 1060, in thousands of lb/hr. The NO
(3) 0.84 lb/mmBtu of heat input on an annual average basis for wet bottom boilers, with a Maximum Continuous Steam Flow at 100% of Load of greater than 450, in thousands of lb/hr. The NO
(4) 0.80 lb/mmBtu of heat input on an annual average basis for vertically fired boilers. The NO
(b) The owner or operator shall determine the annual average NO
(a) Beginning January 1, 2000, the owner or operator of a Group 1, Phase II coal-fired utility unit with a tangentially fired boiler or a dry bottom wall-fired boiler shall not discharge, or allow to be discharged, emissions of NO
(1) 0.40 lb/mmBtu of heat input on an annual average basis for tangentially fired boilers.
(2) 0.46 lb/ mmBtu of heat input on an annual average basis for dry bottom wall-fired boilers (other than units applying cell burner technology).
(b) The owner or operator shall determine the annual average NO
(a)
(2) The owner or operator of a Phase II coal-fired utility unit with a Group 1 boiler that elects to become subject to the applicable emission limitation under § 76.5 shall not be subject to § 76.7 until January 1, 2008, provided the designated representative demonstrates that the unit is in compliance with the
(3) The owner or operator of any Phase II unit with a cell burner boiler that converts to conventional burner technology may elect to become subject to the applicable emissions limitation under § 76.5 for dry bottom wall-fired boilers, provided the owner or operator complies with the provisions in paragraph (a)(2) of this section.
(4) The owner or operator of a Phase II unit approved for early election shall not submit an application for an alternative emissions limitation demonstration period under § 76.10 until the earlier of:
(i) January 1, 2008; or
(ii) Early election is terminated pursuant to paragraph (e)(3) of this section.
(5) The owner or operator of a Phase II unit approved for early election may not incorporate the unit into an averaging plan prior to January 1, 2000. On or after January 1, 2000, for purposes of the averaging plan, the early election unit will be treated as subject to the applicable emissions limitation for NO
(b)
(c)
(1) A request for early election;
(2) The first year for which early election is to take effect, but not later than 1997; and
(3) The special provisions under paragraph (e) of this section.
(d)(1)
(i) If a Phase I Acid Rain permit governing the source at which the unit is located has been issued, will revise the permit in accordance with the permit modification procedures in § 72.81 of this chapter to include the early election plan; or
(ii) If a Phase I Acid Rain permit governing the source at which the unit is located has not been issued, will issue a Phase I Acid Rain permit effective from January 1, 1995 through December 31, 1999, that will include the early election plan and a complete compliance plan under § 72.40(a) of this chapter and paragraph (b) of this section. If the early election plan is not effective until after January 1, 1995, the permit will not contain any NO
(2) Beginning January 1, 2000, the permitting authority will approve any early election plan previously approved by the Administrator during Phase I, unless the plan is terminated pursuant to paragraph (e)(3) of this section.
(e)
(A) The permit requirements under §§ 72.9(a)(1) (i) and (ii) of this chapter;
(B) The sulfur dioxide requirements under § 72.9(c) of this chapter; and
(C) The excess emissions requirements under § 72.9(e)(1) of this chapter.
(ii)
(2)
(3)
(i) If the designated representative of the unit under an approved early election plan fails to demonstrate compliance with the applicable emissions limitation under § 76.5 for any year during the period beginning January 1 of the first year the early election takes effect and ending December 31, 2007, the permitting authority will terminate the plan. The termination will take effect beginning January 1 of the year after the year for which there is a failure to demonstrate compliance, and the designated representative may not submit a new early election plan.
(ii) The designated representative of the unit under an approved early election plan may terminate the plan any year prior to 2008 but may not submit a new early election plan. In order to terminate the plan, the designated representative must submit a notice under § 72.40(d) of this chapter by January 1 of the year for which the termination is to take effect.
(iii)(A) If an early election plan is terminated any year prior to 2000, the unit shall meet, beginning January 1, 2000, the applicable emissions limitation for NO
(B) If an early election plan is terminated in or after 2000, the unit shall meet, beginning on the effective date of the termination, the applicable emissions limitation for NO
(a)
(2) The original and three copies of the permit application and compliance plan for NO
(b)
(2) For a Phase I or Phase II unit with a Group 2 boiler or a Phase II unit with a Group 1 boiler, the designated representative shall submit a complete permit application and compliance plan for NO
(c)
(i) Identification of the source;
(ii) Identification of each affected unit that is at the source and is subject to this part;
(iii) Identification of the boiler type of each unit;
(iv) Identification of the compliance option proposed for each unit (i.e., meeting the applicable emissions limitation under § 76.5, 76.6, 76.7, 76.8 (early election), 76.10 (alternative emission limitation), 76.11 (NO
(v) Reference to the standard requirements in § 72.9 of this chapter (consistent with § 76.8(e)(1)(i)); and
(vi) The requirements of §§ 72.21 (a) and (b) of this chapter.
(2) [Reserved]
(d)
(a)
(2) In order for the unit to qualify for an alternative emission limitation, the designated representative shall demonstrate that the affected unit cannot meet the applicable emission limitation in § 76.5, 76.6, or 76.7 based on a showing, to the satisfaction of the Administrator, that:
(i)(A) For a tangentially fired boiler, the owner or operator has either properly installed low NO
(B) For a dry bottom wall-fired boiler (other than a unit applying cell burner technology), the owner or operator has properly installed low NO
(C) For a Group 1 boiler, the owner or operator has properly installed an alternative technology (including but not limited to reburning, selective noncatalytic reduction, or selective catalytic reduction) that achieves NO
(D) For a Group 2 boiler, the owner or operator has properly installed the appropriate NO
(ii) The installed NO
(iii) For a demonstration period of at least 15 months or other period of time, as provided in paragraph (f)(1) of this section:
(A) The NO
(B) Unit operating data as specified in this section show that the unit and NO
(C) Unit operating data as specified in this section, continuous emission monitoring data obtained pursuant to part 75 of this chapter, and the test data specific to the NO
(b)
(1) Operation during a period of at least 3 months, following the installation of the NO
(2) Submission of a petition for an alternative emission limitation demonstration period as specified in paragraph (d) of this section;
(3) Operation during a demonstration period of at least 15 months, or other period of time as provided in paragraph (f)(1) of this section, that demonstrates the inability of the specific unit to meet the applicable emissions limitation under § 76.5, 76.6, or 76.7 and the minimum NO
(4) Submission of a petition for a final alternative emission limitation as specified in paragraph (e) of this section.
(c)
(i) For units that seek to have an alternative emission limitation demonstration period apply during all or part of calendar year 1996, or any previous calendar year by the later of:
(A) 120 days after startup of the NO
(B) May 1, 1996.
(ii) For units that seek an alternative emission limitation demonstration period beginning in a calendar year after 1996, not later than:
(A) 120 days after January 1 of that calendar year, or
(B) 120 days after startup of the NO
(2)
(3)
(d)
(1) Identification of the unit;
(2) The type of NO
(3) If an alternative technology is installed, the time period (not less than 6 consecutive months) prior to installation of the technology to be used for the demonstration required in paragraph (e)(11) of this section.
(4) Documentation as set forth in § 76.14(a)(1) showing that the installed NO
(5) The date the unit commenced operation following the installation of the NO
(6) The dates of the operating period (which must be at least 3 months long);
(7) Certification by the designated representative that the owner(s) or operator operated the unit and the NO
(8) A brief statement describing the reason or reasons why the unit cannot achieve the applicable emission limitation in § 76.5, 76.6, or 76.7;
(9) A demonstration period plan, as set forth in § 76.14(a)(2);
(10) Unit operating data and quality-assured continuous emission monitoring data (including the specific data items listed in § 76.14(a)(3) collected in accordance with part 75 of this chapter during the operating period) and demonstrating the inability of the specific unit to meet the applicable emission limitation in § 76.5, 76.6, or 76.7 on an annual average basis while operating as certified under paragraph (d)(7) of this section;
(11) An interim alternative emission limitation, in lb/mmBtu, that the unit can achieve during a demonstration period of at least 15 months. The interim alternative emission limitation shall be derived from the data specified in paragraph (d)(10) of this section using methods and procedures satisfactory to the Administrator;
(12) The proposed dates of the demonstration period (which must be at least 15 months long);
(13) A report which outlines the testing and procedures to be taken during the demonstration period in order to determine the maximum NO
(14) The special provisions at paragraph (g)(1) of this section.
(e)
(1) Identification of the unit;
(2) Certification that the owner(s) or operator operated the affected unit and the NO
(3) Certification that the owner(s) or operator have installed in the affected unit all NO
(4) A clear description of each step or modification taken during the demonstration period to improve or optimize the performance of the installed NO
(5) Engineering design calculations and drawings that show the technical specifications for installation of any additional operational or emission control modifications installed during the demonstration period.
(6) Unit operating and quality-assured continuous emission monitoring
(7) A report (based on the parametric test requirements set forth in the approved demonstration period plan as identified in paragraph (d)(13) of this section), that demonstrates the unit was operated in accordance with the operating conditions upon which the design of the NO
(8) The minimum NO
(9) All supporting data and calculations documenting the determination of the requested alternative emission limitation and its conformance with the methods and procedures satisfactory to the Administrator;
(10) The special provisions in paragraph (g)(2) of this section.
(11) In addition to the other requirements of this section, the owner or operator of an affected unit with a Group 1 boiler that has installed an alternative technology in addition to or in lieu of low NO
(f)
(ii) If the demonstration period is approved, the permitting authority will include, as part of the demonstration period, the 4 month period prior to submission of the application in the demonstration period.
(iii) The alternative emission limitation demonstration period will authorize the unit to emit at a rate not greater than the interim alternative emission limitation during the demonstration period on or after January 1, 1996 for Phase I units and the applicable date established in § 76.6 or 76.7 for Phase II units, and until the date that the Administrator approves or denies a final alternative emission limitation.
(iv) After an alternative emission limitation demonstration period is approved, if the designated representative requests an extension of the demonstration period in accordance with paragraph (g)(1)(i)(B) of this section, the permitting authority may extend the demonstration period by administrative amendment (under § 72.83 of this chapter) to the Acid Rain permit.
(v) The permitting authority shall deny the demonstration period if the designated representative cannot demonstrate that the unit met the requirements of paragraph (a)(2) of this section. In such cases, the permitting authority shall require that the owner or
(2)
(ii) If a permitting authority disapproves an alternative emission limitation under paragraph (a)(2) of this section, the owner or operator shall operate the affected unit in compliance with the applicable emission limitation in § 76.5, 76.6, or 76.7 (unless the unit is participating in an approved averaging plan under § 76.11) beginning on the date the permitting authority revises an Acid Rain permit to disapprove an alternative emission limitation.
(3)
(ii) If the permitting authority determines that changes have been made to the control technology, its operation, the fuel quality, or the operating conditions on which the alternative emission limitation was based, the designated representative shall submit, in order to renew the alternative emission limitation or to obtain a new alternative emission limitation, a petition for an alternative emission limitation demonstration period that meets the requirements of paragraph (d) of this section using a new demonstration period.
(g)
(B) When the owner or operator identifies, during the demonstration period, boiler operating or NO
(C) If the approved interim alternative emission limitation applies to a unit for part, but not all, of a calendar year, the unit shall determine compliance for the calendar year in accordance with the procedures in § 76.13(a).
(ii)
(B) A unit with an approved alternative emission limitation demonstration period shall install all NO
(C) When the owner or operator identifies boiler or NO
(iii)
(2)
(B) If the approved interim or final alternative emission limitation applies to a unit for part, but not all, of a calendar year, the unit shall determine compliance for the calendar year in accordance with the procedures in § 76.13(a).
(a)
(1) Each affected unit included in an averaging plan for Phase I shall be a Phase I unit with a Group 1 boiler subject to an emission limitation in § 76.5 during all years for which the unit is included in the plan.
(i) If a unit with an approved NO
(ii) A Phase II unit approved for early election under § 76.8 shall not be included in an averaging plan for Phase I.
(2) Each affected unit included in an averaging plan for Phase II shall be a boiler subject to an emission limitation in § 76.5, 76.6, or 76.7 for all years for which the unit is included in the plan.
(3) Each unit included in an averaging plan shall have an alternative contemporaneous annual emission limitation (lb/mmBtu) and can only be included in one averaging plan.
(4) Each unit included in an averaging plan shall have a minimum allowable annual heat input value (mmBtu), if it has an alternative contemporaneous annual emission limitation more stringent than that unit's applicable emission limitation under § 76.5, 76.6, or 76.7, and a maximum allowable annual heat input value, if it has an alternative contemporaneous annual emission limitation less stringent than that unit's applicable emission limitation under § 76.5, 76.6, or 76.7.
(5) The Btu-weighted annual average emission rate for the units in an averaging plan shall be less than or equal to the Btu-weighted annual average emission rate for the same units had they each been operated, during the same period of time, in compliance with the applicable emission limitations in § 76.5, 76.6, or 76.7.
(6) In order to demonstrate that the proposed plan is consistent with paragraph (a)(5) of this section, the alternative contemporaneous annual emission limitations and annual heat input values assigned to the units in the proposed averaging plan shall meet the following requirement:
(7) For units with an alternative emission limitation, R
(8) No unit may be included in more than one averaging plan.
(b)(1)
(2) The designated representative shall submit a copy of the same averaging plan (or the same revision to an approved averaging plan) to each permitting authority with jurisdiction over a unit in the plan.
(3) When an averaging plan (or a revision to an approved averaging plan) is not approved, the owner or operator of each unit in the plan shall operate the unit in compliance with the emission limitation that would apply in the absence of the averaging plan (or revision to a plan).
(c)
(1) Identification of each unit in the plan;
(2) Each unit's applicable emission limitation in § 76.5, 76.6, or 76.7;
(3) The alternative contemporaneous annual emission limitation for each unit (in lb/mmBtu). If any of the units identified in the NO
(4) The annual heat input limit for each unit (in mmBtu);
(5) The calculation for Equation 1 in paragraph (a)(6) of this section;
(6) The calendar years for which the plan will be in effect; and
(7) The special provisions in paragraph (d)(1) of this section.
(d)
(i) For each unit, the unit's actual annual average emission rate for the calendar year, in lb/mmBtu, is less than or equal to its alternative contemporaneous annual emission limitation in the averaging plan; and
(A) For each unit with an alternative contemporaneous emission limitation
(B) For each unit with an alternative contemporaneous annual emission limitation more stringent than the applicable emission limitation in § 76.5, 76.6, or 76.7, the actual annual heat input for thecalendar year is not less than the annual heat input limit in the averaging plan; or
(ii) If one or more of the units does not meet the requirements under paragraph (d)(1)(i) of this section, the designated representative shall demonstrate, in accordance with paragraph (d)(1)(ii)(A) of this section (Equation 2) that the actual Btu-weighted annual average emission rate for the units in the plan is less than or equal to the Btu-weighted annual average rate for the same units had they each been operated, during the same period of time, in compliance with the applicable emission limitations in § 76.5, 76.6, or 76.7.
(A) A group showing of compliance shall be made based on the following equation:
(B) For units with an alternative emission limitation, R
(C) If there is a successful group showing of compliance under paragraph (d)(1)(ii)(A) of this section for a calendar year, then all units in the averaging plan shall be deemed to be in compliance for that year with their alternative contemporaneous emission limitations and annual heat input limits under paragraph (d)(1)(i) of this section.
(2)
(3)
(a)
(i) The low NO
(ii) The unit is participating in an approved clean coal technology demonstration project.
(2) In order to obtain a Phase I NO
(b)
(1) Identification of the unit.
(2) For units applying pursuant to paragraph (a)(1)(i) of this section:
(i) A list of the company names, addresses, and telephone numbers of vendors who are qualified to provide the services and low NO
(ii) A copy of those portions of a legally binding contract with a qualified vendor that demonstrate that services and low NO
(iii) Scheduling information, including justification and test schedules.
(iv) To demonstrate, if applicable, that the supply of the low NO
(A) Certification from the selected vendor(s) (by a certifying official) listed in paragraph (b)(2)(i) of this section stating that they cannot provide the necessary services and install the low NO
(B) The following information:
(i) Standard load forecasts, based on standard forecasting models available throughout the utility industry and applied to the period, January 1, 1993, through December 31, 1994.
(ii) Specific reasons why an outage cannot be scheduled to enable the unit to install and operate the low NO
(iii) Fuel and energy balance summaries and power and other consumption requirements (including those for air, steam, and cooling water).
(3) To demonstrate, if applicable, participation in an approved clean coal technology demonstration project, a description of the project, including all sources of Federal, State, and other outside funding, amount and date for approval of Federal funding, the duration of the project, and the anticipated completion date of the project.
(4) The special provisions in paragraph (d) of this section.
(c)(1)
(2) The Administrator will approve or disapprove a proposed NO
(d)
(2) If a unit with an approved NO
(e)
(i) The unit is located at a source with two or more other units, all of which are Phase I units that are subject to section 404(d) of the Act and have tangentially fired boilers;
(ii) The NO
(iii) Installation of the redesigned low NO
(2) A complete petition shall include the following elements and shall be submitted by April 28, 1995.
(i) Identification of the unit and the other units at the source;
(ii) A statement describing how the requirements of paragraphs (e)(1)(ii) and (e)(1)(iii) of this section are met;
(iii) The earliest date, not later than December 31, 1997, by which installation of the redesigned low NO
(iv) The provisions in paragraph (e)(4) of this section.
(3) To the extent the Administrator determines that a Phase I unit meets the requirements of paragraphs (e)(1) and (e)(2) of this section, the Administrator will approve the petition within 90 days from receipt of the complete petition. The Acid Rain permit governing the unit will be revised in order to incorporate the approved extension, which shall terminate no later than December 31, 1997, by administrative amendment under § 72.83 of this chapter except that the Administrator will have 90 days to take final action.
(4) The unit shall comply with the applicable emission limitation under § 76.5 beginning on the day immediately following the day on which the extension approved under paragraph (e)(3) of this section terminates. Compliance shall be determined as specified in part 75 of this chapter using measured values of NO
Excess emissions of nitrogen oxides under § 77.6 of this chapter shall be calculated as follows:
(a) For a unit that is not in an approved averaging plan:
(1) Calculate EE
(2) If EE
(3) Sum all EE
(b) For units participating in an approved averaging plan, when all the requirements under § 76.11(d)(1) are not met,
(a) A petition for an alternative emission limitation demonstration period under § 76.10(d) shall include the following information:
(1) In accordance with § 76.10(d)(4), the following information:
(i) Documentation that the owner or operator solicited bids for a NO
(ii) A copy of the performance guarantee submitted by the vendor of the installed NO
(iii) Documentation describing the operational and combustion conditions that are the basis of the performance guarantee.
(iv) Certification by the primary vendor of the NO
(v) Certification by the designated representative that the owner(s) or operator installed technology that meets the requirements of § 76.10(a)(2).
(2) In accordance with § 76.10(d)(9), the following information:
(i) The operating conditions of the NO
(ii) Certification by the designated representative that the owner(s) or operator have achieved and are following the operating conditions, boiler modifications, and upgrades that formed the basis for the system design and performance guarantee;
(iii) Any planned equipment modifications and upgrades for the purpose
(iv) A list of any modifications or replacements of equipment that are to be done prior to the completion of the demonstration period for the purpose of reducing emissions of NO
(v) The parametric testing that will be conducted to determine the reason or reasons for the failure of the unit to achieve the applicable emission limitation and to verify the proper operation of the installed NO
(A) The owner or operator of the unit may add tests to those listed in § 76.15, if such additions provide data relevant to the failure of the installed NO
(B) The owner or operator of the unit may remove tests listed in § 76.15 that are shown, to the satisfaction of the permitting authority, not to be relevant to NO
(C) In the event the performance guarantee or the NO
(3) In accordance with § 76.10(d)(10), the following information for the operating period:
(i) The average NO
(ii) The highest hourly NO
(iii) Hourly NO
(iv) Total heat input (in mmBtu) for the unit for each hour of operation, calculated in accordance with the requirements of part 75 of this chapter; and
(v) Total integrated hourly gross unit load (in MWge).
(b) A petition for an alternative emission limitation shall include the following information in accordance with § 76.10(e)(6).
(1) Total heat input (in mmBtu) for the unit for each hour of operation, calculated in accordance with the requirements of part 75 of this chapter;
(2) Hourly NO
(3) Total integrated hourly gross unit load (MWge).
(c)
(2) The report under paragraph (c)(1) of this section is not required with regard to the following types of Group 1, Phase I units:
(i) Units employing no new NO
(ii) Units employing modifications to boiler operating parameters (e.g., burners out of service or fuel switching) without low NO
(iii) Units with wall-fired boilers employing only overfire air and units with tangentially fired boilers employing only separated overfire air; or
(iv) Units beginning installation of a new NO
(3) The report under paragraph (c)(1) of this section shall be submitted to the Administrator by:
(i) 120 days after completion of the low NO
(ii) May 23, 1995, if the project was completed on or before January 23, 1995.
(a) The owner or operator may use the following tests as a basis for the report required by § 76.10(e)(7):
(1) Conduct an ultimate analysis of coal using ASTM D 3176-89 (incorporated by reference as specified in § 76.4);
(2) Conduct a proximate analysis of coal using ASTM D 3172-89 (incorporated by reference as specified in § 76.4); and
(3) Measure the coal mass flow rate to each individual burner using ASME Power Test Code 4.2 (1991), “Test Code for Coal Pulverizers” or ISO 9931 (1991), “Coal—Sampling of Pulverized Coal Conveyed by Gases in Direct Fired Coal Systems” (incorporated by reference as specified in § 76.4).
(b) The owner or operator may measure and record the actual NO
(1) Excess air levels;
(2) Settings of burners or coal and air nozzles, including tilt and yaw, or swirl;
(3) For tangentially fired boilers, distribution of combustion air within the NO
(4) Coal mass flow rates to each individual burner;
(5) Coal-to-primary air ratio (based on pound per hour) for each burner, the average coal-to-primary air ratio for all burners, and the deviations of individual burners’ coal-to-primary air ratios from the average value; and
(6) If the boiler uses varying types of coal, the type of coal. Provide the results of proximate and ultimate analyses of each type of as-fired coal.
(c) In performing the tests specified in paragraph (a) of this section, the owner or operator shall begin the tests using the equipment settings for which the NO
(d) After establishing the baseline controlled condition under paragraph (c) of this section, the owner or operator may:
(1) Change excess air levels
(2) For tangentially fired boilers, change the distribution of combustion air within the NO
(3) Show that the combustion process within the boiler is optimized (e.g., that the burners are balanced).
This technical appendix specifies the procedures, methods, and data that the Administrator will use in establishing “***the degree of reduction achievable through this retrofit application of the best system of continuous emission reduction, taking into account available technology, costs, and energy and environmental impacts; and which is comparable to the costs of nitrogen oxides controls set pursuant to subsection (b)(1) (of section 407 of the Act).” In developing the allowable NO
The Administrator will evaluate the capital cost (in dollars per kilowatt electrical ($/kW)), the operating and maintenance costs (in $/year), and the cost-effectiveness (in annualized $/ton NO
The Administrator will use the procedures, methods, and data specified in this section to estimate the average capital cost (in $/kW) of installed low NO
2.1Using cost data submitted pursuant to the reporting requirements in section 4 below, boiler-specific actual or estimated actual capital costs will be determined for each unit in the population specified in section 1 above for assessing the costs of installed low NO
2.2Using gross nameplate capacity (in MW) for each unit as reported in the National Allowance Data Base (NADB), boiler-specific capital costs will be converted to a $/kW basis.
2.3Capital cost curves ($/kW versus boiler size in MW) or equations for installed low NO
4.1The following information is to be submitted by each designated representative of a Phase I affected unit subject to the reporting requirements of § 76.14(c):
4.1.1Schedule and dates for baseline testing, installation, and performance testing of low NO
4.1.2Estimates of the annual average baseline NO
4.1.3Copies of pre-retrofit and post-retrofit performance test reports.
4.1.4Detailed estimates of the capital costs based on actual contract bids for each component of the installed low NO
4.1.5Detailed estimates of the capital costs of system replacements or upgrades such as coal pipe changes, fan replacements/upgrades, or mill replacements/upgrades undertaken as part of the low NO
4.1.6Detailed breakdown of the actual costs of the completed low NO
4.1.7Description of the probable causes for significant differences between actual and estimated low NO
4.1.8Detailed breakdown of the burner and, if applicable, combustion air staging system annual operating and maintenance costs for the items listed in section 3.3 before and after the installation, shakedown, and/or optimization of the installed low NO
4.2All capital cost estimates are to be broken down into materials costs, construction and installation labor costs, and engineering and overhead costs. All operating and maintenance costs are to be broken down into maintenance materials costs, maintenance labor costs, operating labor costs, and fan electricity costs. All capital and operating costs are to be reported in dollars with the year of expenditure or estimate specified for each component.
42 U.S.C. 7601 and 7651, et seq.
(a) This part sets forth the excess emissions offset planning and offset penalty requirements under section 411 of the Clean Air Act, 42 U.S.C. 7401,
(b) Nothing in this part shall limit or otherwise affect the application of sections 112(r)(9), 113, 114, 120, 303, 304, or 306 of the Act, as amended. Any allowance deduction, excess emission penalty, or interest required under this part shall not affect the liability of the affected unit's and affected source's owners and operators for any additional fine, penalty, or assessment, or their obligation to comply with any other remedy, for the same violation, as ordered under the Act.
Part 72 of this chapter, including §§ 72.2 (definitions), 72.3 (measurements, abbreviations, and acronyms), 72.4 (Federal authority), 72.5 (State authority), 72.6 (applicability), 72.7 (new units exemption), 72.8 (retired units exemption), 72.9 (standard requirements), 72.10 (availability of information), and 72.11 (computation of time), shall apply to this part. The procedures for appeals of decisions of the Administrator under this part are contained in part 78 of this chapter.
(a)
(b)
(c)
(d)
(1) Identification of the unit.
(2) If the unit had excess emissions for the calendar year prior to the year for which the plan is submitted, an explanation of how and why the excess emissions occurred for the year for which the plan is submitted and a description of any measures that were or will be taken to prevent excess emissions in the future.
(3) At the designated representative's option, the number of allowances to be deducted from the unit's Allowance Tracking System account to offset the excess emissions for the year for which the plan is submitted.
(4) At the designated representative's option, the serial numbers of the allowances that are to be deducted from the unit's Allowance Tracking System account.
(5) A statement either that allowances to offset the excess emissions are to be deducted immediately from the unit's compliance subaccount or that they are to be deducted on a specified date in a subsequent year.
(6) If the proposed offset plan does not propose an immediate deduction of allowances under paragraph (d)(5) of this section, a demonstration that such a deduction will interfere with electric reliability.
(a)
(b)
(2) Notwithstanding paragraph (b)(1) of this section, the Administrator may, in his or her discretion, require that the proposed offset plan under paragraph (b)(1) of this section be reviewed under paragraphs (c) through (k) of this section. The Administrator may exercise such discretion where he or she determines that review of the plan is necessary to ensure compliance with the emissions limitation and reduction goals or other purposes of title IV of the Act.
(3) If the designated representative submits a complete proposed offset plan that does not meet the requirements of paragraph (b)(1) of this section, the Administrator will review the plan under paragraphs (c) through (k) of this section.
(c)
(ii) Such supplemental information may include, but is not limited to:
(A) A description of the measures that are proposed to be taken to ensure that the unit will have sufficient allowances to offset the excess emissions and to prevent excess emissions in future years;
(B) A schedule of compliance with appropriate increments of progress for the proposed measures; and
(C) A schedule for the submission of progress reports, and supporting documentation, describing actions taken and actions remaining to be taken under the schedule of compliance and any proposed adjustments to the schedule of compliance.
(2)(i) The designated representative shall submit the information required under paragraph (c)(1) of this section within a reasonable period determined by the Administrator.
(ii) If the designated representative fails to submit the supplemental information within the required time period, the Administrator may disapprove the proposed offset plan.
(d)
(2) The draft offset plan will be based on the information submitted by the designated representative for the affected unit and other relevant information.
(3) The Administrator will serve a copy of the draft offset plan and the statement of basis on the designated representative of the affected unit.
(4) The Administrator will provide a 30-day period for public comment, and opportunity to request a public hearing, on the draft offset plan or disapproval of a draft offset plan in accordance with the public notice required under paragraph (g)(1)(i)(A) of this section.
(e)
(i) The proposed offset plan and any supporting or supplemental information submitted by the designated representative;
(ii) The draft offset plan;
(iii) The statement of basis;
(iv) Copies of all documents relied on by the Administrator in approving or disapproving the draft offset plan (including any records of discussions or conferences with owners, operators or the designated representative of the unit or interested persons regarding the draft offset plan) or, for any such documents that are readily available, a statement of their location;
(v) Copies of all written public comments submitted on the draft offset plan or disapproval of a draft offset plan;
(vi) The record of any public hearing on the draft offset plan or disapproval of a draft offset plan;
(vii) The offset plan approved by the Administrator; and
(viii) Any response to public comments submitted on the draft offset plan or disapproval of a draft offset plan, including any documents cited in the response and any other documents relied on by the Administrator or, for any such documents that are readily available, a statement of their location.
(2) The Administrator will approve or disapprove an offset plan within 6 months of receipt of a complete proposed offset plan.
(f)
(2) The statement of basis will include:
(i) The reasons, and supporting authority, for approval or disapproval of any proposed offset plan that does not require immediate deduction of allowances, including references to applicable statutory or regulatory provisions and to the administrative record; and
(ii) The name, address, and telephone and facsimile number of the EPA office processing the approval or disapproval of the offset plan.
(g)
(1)
(A) The draft offset plan or disapproval of a draft offset plan and the opportunity for public comment and to request a public hearing; and
(B) Date, time, location, and procedures for any scheduled hearing on the draft offset plan or the disapproval of a draft offset plan.
(ii) Any public notice given under this section may be for the approval or disapproval of one or more draft offset plans.
(2)
(i) Serving written notice on the following persons (except to the extent
(A) The designated representative;
(B) The air pollution control agencies of affected States; and
(C) Any interested person.
(ii) Giving notice by publication in the
(3)
(i) Identification of the EPA office processing the approval or disapproval of the draft offset plan for which the notice is being given.
(ii) Identification of the designated representative for the affected unit.
(iii) Identification of each affected unit covered by the proposed offset plan.
(iv) The amount of excess emissions that must be offset and the date on which the allowances are proposed to be deducted.
(v) The address and office hours of a public location where the administrative record is available for public inspection and a statement that all information submitted by the designated representative and not protected as confidential pursuant to section 114(c) of the Act is available for public inspections as part of the administrative record.
(vi) For public notice under paragraph (g)(1)(i)(A) of this section, a brief description of the public comment procedures, including:
(A) A 30-day public comment period beginning the date of publication of the notice or, in the case of an extension or reopening of the public comment period, such period as the Administrator deems appropriate;
(B) The address where public comments should be sent;
(C) Required formats and contents for public comment;
(D) An opportunity to request a public hearing to occur not earlier than 15 days after public notice is given and the location, date, time, and procedures of any scheduled public hearing; and
(E) Any other means by which the public may participate.
(4)
(h)
(2)
(ii) The submission shall clearly indicate the draft offset plan approval or disapproval to which the comments apply.
(iii) The submission shall clearly indicate the name of the commenter, his or her interest, and his or her affiliation, if any, to owners and operators of any unit covered by the proposed offset plan.
(3)
(i) The environmental effects of acid rain, acid deposition, sulfur dioxide, or nitrogen oxides generally; and
(ii) Offset plan approval procedures or actions on other proposed offset plans that are not relevant to approval or disapproval of the draft offset plan in question.
(4) Persons who do not wish to raise issues on the draft offset plan or denial of a draft offset plan, but who wish to be notified of any subsequent actions concerning such matter, may so indicate during the public comment period or at any other time. The Administrator will place their names on a list of interested persons.
(i)
(2) On the Administrator's own motion or on the request of any person, the Administrator may, at his or her discretion, hold a public hearing whenever the Administrator finds that such a hearing will contribute to the decision-making process by clarifying one or more significant issues affecting the draft offset plan or disapproval of a draft offset plan. Public hearings will not be held on issues under paragraphs (h)(3) (i) and (ii) of this section.
(3) During a public hearing under this section, any person may submit oral or written comments concerning the draft offset plan or disapproval of a draft offset plan. The Administrator may set reasonable limits on the time allowed for oral statements and will require the submission of written summaries of each oral statement.
(4) The Administrator will assure that a record is made of the hearing.
(j)
(2) In approving or disapproving an offset plan, the Administrator will:
(i) Identify any draft offset plan provision or portion of the statement of basis that has been changed and the reasons for the change; and
(ii) Briefly describe and respond to relevant comments under paragraph (j)(1) of this section.
(k)
(2) The Administrator will approve an offset plan requiring immediate deduction from the unit's compliance subaccount of all allowances necessary to offset the excess emissions except to the extent the designated representative of the unit demonstrates that such a deduction will interfere with electric reliability.
(3) Upon approval of the offset plan by the Administrator, the offset plan will be incorporated into the Acid Rain permit in accordance with § 72.84 (automatic permit amendment) and shall supersede any inconsistent provision of the permit.
(a) The Administrator will deduct allowances to offset excess emissions in accordance with the offset plan approved under § 77.4(b) (1) or (k) or in accordance with § 72.91(b) of this chapter.
(b) The designated representative shall hold enough allowances in the appropriate compliance subaccount to cover the deductions to be made in accordance with paragraph (a) or paragraph (c) of this section.
(c) If the designated representative does not submit a timely and complete proposed offset plan, or if the Administrator disapproves a proposed offset plan under § 77.4 (c) or (k), the Administrator will immediately deduct allowances, from the unit's compliance subaccount on a first-in, first-out basis in accordance with § 73.35(c)(2) of this chapter, equal to the amount of the unit's excess emissions of sulfur dioxide.
(d) If a compliance subaccount does not contain adequate allowances to offset the excess emissions, the Administrator will deduct the required allowances whenever allowances are recorded to that account.
(a)(1) If excess emissions of sulfur dioxide or nitrogen oxide occur at an affected unit during any year, the owners and operators of the affected unit shall pay, without demand, an excess emissions penalty, as calculated under paragraph (b) of this section.
(2) If one or more affected units governed by an approved NO
(3) Except as otherwise provided in this paragraph (a)(3), payment under paragraphs (a) (1) or (2) of this section shall be submitted to the Administrator by 30 days after the date on which the Administrator serves the designated representative a notice that the process of recordation set forth in § 73.34(a) of this chapter is completed or by July 1 of the year after the year in which the excess emissions occurred, whichever date is earlier. Payment under paragraph (a)(1) of this section for any increase in excess emissions of sulfur dioxide determined after adjustments made under § 72.91(b) of this chapter shall be submitted to the Administrator by 30 days after the date on which the Administrator serves the designated representative a notice that process set forth in § 72.91(b) of this chapter is completed.
(b)
(i) The annual adjustment factor will be calculated as follows:
(A) “CPI(year)” is the Consumer Price Index as defined in § 72.2 of this chapter and “year” is the year in which the unit had excess emissions.
(B) “CPI(1990)” is the Consumer Price Index for 1990, as defined in § 72.2 of this chapter.
(ii) The Administrator will publish the annual adjustment factor in the
(2) The penalty may be rounded to the nearest dollar after completing the calculation in paragraph (b)(1)(i) of this section.
(3) The penalty for excess emissions of sulfur dioxide shall be paid separately from the payment for excess emissions of nitrogen oxides. Each payment shall be accompanied by a document, in a format prescribed by the Administrator, indicating the unit for which the payment is made, whether the payment is for excess emissions of sulfur dioxide or nitrogen oxides, the number of tons of excess emissions, the penalty amount, and the check or money order number of the payment.
(c) If an excess emissions penalty due under this part is not paid on or before the applicable deadline under paragraph (a) of this section, the penalty shall be subject to interest charges in accordance with the Debt Collection Act (31 U.S.C. 3717). Interest shall begin to accrue on the date on which the Administrator mails, to the designated representative of the unit with excess emissions, a demand notice for the payment.
(d)(1) Except for wire transfers made in accordance with paragraph (d)(2) of this section, payments of penalties shall be made by money order, cashier's check, certified check, or U.S. Treasury check made payable to the “U.S. EPA.”
(2) Payments made under paragraph (c)(1) of this section shall be mailed to
(3) Payments of penalties of $25,000 or more may be made by wire transfer to the U.S. Treasury at the Federal Reserve Bank of New York.
(e) If the Administrator determines that overpayment has been made, he or she will refund the overpayment without interest, as promptly as administratively possible.
(f) Excess emissions in any year resulting directly from an order issued in that year under section 110(f) of the Act shall not be subject to the penalty payment requirements of this section;
42 U.S.C. 7601 and 7651, et. seq.
(a)(1) This part shall govern appeals of any final decision of the Administrator under parts 72, 73, 74, 75, 76, and 77 of this chapter;
(2) Filing an appeal, and exhausting administrative remedies, under this part shall be a prerequisite to seeking judicial review. For purposes of judicial review, final agency action occurs only when a decision appealable under this part is issued and the procedures under this part for appealing the decision are exhausted.
(b) The decisions of the Administrator that may be appealed include but are not limited to:
(1) Under part 72 of this chapter;
(i) The determination of incompleteness of an Acid Rain permit application;
(ii) The issuance or denial of an Acid Rain permit and approval or disapproval of a compliance option by the Administrator;
(iii) The approval or disapproval of an early ranking application for Phase I extension under § 72.42 of this chapter;
(iv) The final determination of whether a technology is a qualified repowering technology under § 72.44 of this chapter;
(v) The issuance or denial of an exemption under § 72.14 of this chapter;
(vi) The approval or disapproval of a permit revision;
(vii) The decision on the deduction or return of allowances under §§ 72.41, 72.42, 72.43, 72.44, 72.91(b), and 72.92 (a) and (c) of this chapter; and
(viii) The failure to issue an Acid Rain permit in accordance with the deadline under § 72.74(b) of this chapter.
(2) Under part 73 of this chapter,
(i) The decision on a claim of error in a transfer recordation;
(ii) The decision on the allocation of allowances from the Conservation and Renewal Energy Reserve;
(iii) The decision on the allocation of allowances under regulations implementing sections 404(e), 405(g)(4), 405(i)(2), and 410(h) of the Act;
(iv) The decision on the allocation of allowances under part 73, subpart F of this chapter;
(v) The decision on the sale or return of allowances and transfer of proceeds under part 73, subpart E; and
(vi) The decision on the deduction of allowances under § 73.35(b) of this chapter.
(3) Under part 74 of this chapter,
(i) The determination of incompleteness of an opt-in permit application;
(ii) The issuance or denial of an opt-in permit and approval or disapproval of the transfer of allowances for the replacement of thermal energy;
(iii) The approval or disapproval of a permit revision to an opt-in permit;
(iv) The decision on the deduction or return of allowances under subpart E of part 74 of this chapter;
(4) Under part 75 of this chapter,
(i) The decision on a petition for approval of an alternative monitoring system;
(ii) The approval or disapproval of a monitoring system certification or recertification;
(iii) The finalization of annual emissions data, including retroactive adjustment based on audit;
(iv) The determination of the percentage of emissions reduction achieved by qualifying Phase I technology; and
(v) The determination on the acceptability of parametric missing data procedures for a unit equipped with add-on controls for sulfur dioxide and nitrogen oxides in accordance with part 75 of this chapter.
(5) Under part 77 of this chapter, the determination of incompleteness of an offset plan and the approval or disapproval of an offset plan under § 77.4 of this chapter and the deduction of allowances under § 77.5(c) of this chapter.
(c) In order to appeal a decision under paragraph (a) of this section, a person shall file a petition for administrative review with the Environmental Appeals Board under § 78.3. The Environmental Appeals Board will, consistent with § 78.6, either:
(1) Issue an order deciding the appeal; or
(2) Where there is a disputed issue of fact material to the contested portions of the decision, refer the proceeding to the Chief Administrative Law Judge, who will designate an Administrative Law Judge to conduct an evidentiary hearing to decide the disputed issue of fact. If the proposed decision is contested or the Environmental Appeals Board decides to review the proposed decision, the Environmental Appeals Board will issue an order deciding the appeal.
(d) Questions arising at any stage of a proceeding that are not addressed in this part will be resolved at the discretion of the Environmental Appeals Board or the Presiding Officer.
Part 72 of this chapter, including §§ 72.2 (definitions), 72.3 (measurements, abbreviations, and acronyms), 72.4 (Federal authority), 72.5 (State authority), 72.6 (applicability), 72.7 (new units exemption), 72.8 (retired units exemption), 72.9 (standard requirements), 72.10 (availability of information), and 72.11 (computation of time), shall apply to this part.
(a)(1) The following persons may petition for administrative review of a decision of the Administrator that is made under parts 72, 74, 75, 76, and 77 of this chapter and that is appealable under § 78.1(a) of this part:
(i) The designated representative for the unit covered by the decision;
(ii) The authorized account representative for an account covered by the decision; and
(iii) Any interested person.
(2) The following persons may petition for administrative review of a decision of the Administrator that is made under part 73 of this chapter and that is appealable under § 78.1(a):
(i) The authorized account representative for any Allowance Tracking System account covered by the decision; and
(ii) With regard to the decision on the allocation of allowances from the Conservation and Renewable Energy Reserve, the certifying official whose application is covered by the decision.
(b)(1) Within 30 days following issuance of a decision under § 78.1 of this part by the Administrator, any person under paragraph (a) of this section may file a petition with the Environmental Appeals Board for administrative review of the decision. If no petition for administrative review of a decision under § 78.1 of this part is filed within such period, the decision shall become final agency action and shall not meet the prerequisite for judicial review under § 78.1(a)(2).
(2) The petition may include a request for an evidentiary hearing to resolve any disputed issue of material fact concerning the decision.
(3) At the same time that the petition for administrative review is filed, the petitioner shall:
(i) Serve a copy of the petition on the designated representative or authorized account representative under paragraph (a)(1) and (2) of this section (unless the designated representative or authorized account representative is the petitioner) and the Administrator; and
(ii) Mail a notice of the petition to the air pollution control agencies of affected States and any interested person.
(c) The petition for administrative review under this part shall state with specificity:
(1) Each material factual and legal issue alleged to be in dispute and any such factual issue for which an evidentiary hearing is sought;
(2) A clear and concise statement of the nature and scope of the interest of the petitioner;
(3) A clear and concise brief in support of the petition, explaining why the factual or legal issues are material and, if an evidentiary hearing is requested, why direct and cross-examination of witnesses is necessary to resolve such factual issues;
(4) If an evidentiary hearing is requested, the time estimated to be necessary for an evidentiary hearing;
(5) If an evidentiary hearing is requested, a certified statement that, in the event of an evidentiary hearing, and without cost or expense to any other party, any of the following persons shall be available to appear and testify:
(i) The petitioner; and
(ii) Any officer, director, employee, consultant, or agent of the petitioner.
(6) Specific references to the contested portions of the decision; and
(7) Any revised or alternative action of the Administrator sought by the petitioner as necessary to implement the requirements, purposes, or policies of title IV of the Act.
(d) In no event shall a petition for administrative review be filed, or review be available under this part, with regard to:
(1) Any provision or requirement of part 72, 73, 74, 75, 76, or 77 of this chapter, including any standard requirement under § 72.9 of this chapter and any emissions monitoring or reporting requirements under part 75 of this chapter;
(2) The reliance by the Administrator on a certificate of representation submitted by a designated representative or a certification statement submitted by an authorized account representative under the Acid Rain Program; and
(3) Actions of the Administrator under sections 112(r), 113, 114, 120, 301, and 303 of the Act.
(a) All original filings made under this part shall be signed by the person making the filing or by an attorney or authorized representative. Any filings on behalf of owners and operators of an affected unit or affected source shall be signed by the designated representative. Any filings on behalf of persons with an interest in allowances in a general account shall be signed by the authorized account representative. The name, address, telephone number, and facsimile number of the person making
(b)(1) All data and information referred to, or in any way relied upon, in any filings made under this part shall be included in full and may not be incorporated by reference, unless the data or information is contained in the administrative record for the decision being appealed.
(2) Notwithstanding paragraph (b)(1) of this section, State or Federal statutes, regulations, and judicial decisions published in a national reporter system, officially issued EPA documents of general applicability, and any other publicly and generally available reference material may be incorporated by reference. Any person incorporating such materials by reference shall provide copies of the materials as instructed by the Environmental Appeals Board or the Presiding Officer.
(3) If any part of any filing is in a foreign language, it shall be accompanied by an English translation verified by the person making the translation, under oath, to be complete and accurate, together with the name, address, and a brief statement of the qualifications of the person making the translation. Translations filed of material originally produced in a foreign language shall be accompanied by copies of the original material.
(4) Where relevant data or information is contained in a document also containing irrelevant matter, either the irrelevant matter shall be deleted or an index to the relevant portions of the document shall be included in the document.
(c)(1) Failure to comply with the requirements of this section or any other requirement in this part may result in the noncomplying portions of the filing being excluded from consideration. If the Environmental Appeals Board or the Presiding Officer determines on motion by any party or
(2) The making of a filing shall not mean or imply that the filing, in fact, meets all applicable requirements, that the filing contains reasonable grounds for the action requested, or that the action requested is in accordance with law.
(d) An original and two copies of any written filing under this part shall be filed with the Environmental Appeals Board unless a proceeding is pending before a Presiding Officer, in which case they shall be filed with the Hearing Clerk (except as provided under § 78.19(d)) of this part.
(e)(1) The party making any filing in a proceeding under this part shall also serve a copy of the filing on each party to the proceeding, or, with regard to a petition for administrative review, on the persons specified in § 78.3(b)(3) of this part.
(2) Every filing made under this part shall be accompanied by a certificate of service citing the date, place, time, and manner of service and the names of the persons served.
(f) The Hearing Clerk will maintain and furnish, to any person upon request, the official service list containing the name, service address, telephone, and facsimile numbers of each party to a proceeding under this part and his or her attorney or duly authorized representative.
(g) Affidavits filed under this part shall be made on personal knowledge and belief, set forth only those facts that are admissible into evidence under § 78.5 of this part, and show affirmatively that the affiant is competent to testify to the matters stated therein.
(a) Where there was an opportunity for public comment, or a claim of error notification was submitted, prior to the decision that is subject to appeal, no evidence shall be filed or presented, and no issues raised, in a proceeding
(b) If an evidentiary hearing is granted, no evidence shall be filed or presented on questions of law or policy or on matters not subject to challenge in the evidentiary hearing.
(a) If no evidentiary hearing concerning the petition for review is requested or is to be held, the Environmental Appeals Board will issue an order under § 78.20(c) of this part.
(b)(1) The Environmental Appeals Board may grant a request for an evidentiary hearing, or schedule an evidentiary hearing
(2) To the extent the Environmental Appeals Board grants a request for an evidentiary hearing, in whole or in part, it will:
(i) Identify the portions of the decision that have been contested, and the disputed factual issues that have been raised by the petitioner with regard to which the evidentiary hearing has been granted; and
(ii) Refer the disputed factual issues to the Chief Administrative Law Judge for decision and, in its discretion, may also refer all or a portion of the remaining legal, policy, or factual issues to the Chief Administrative Law Judge for decision.
(3)(i) After issues are referred to the Chief Administrative Law Judge, he or she will designate an Administrative Law Judge as Presiding Officer to conduct the evidentiary hearing.
(ii) Notwithstanding paragraph (b)(3)(i) of this section, if all parties waive in writing their right to have an Administrative Law Judge designated as the Presiding Officer, the Administrator may designate a lawyer permanently or temporarily employed by EPA and without any prior connection with the proceeding to serve as Presiding Officer.
(a) The Environmental Appeals Board or Presiding Officer has the discretion to consolidate, in whole or in part, two or more proceedings under this part whenever it appears that a joint proceeding on any or all of the matters at issue in the proceedings will be in the interest of justice, will expedite or simplify consideration of the issues, and will not prejudice any party. Consolidation of proceedings under this paragraph (a) will not affect the right of any party to raise issues that might have been raised had there been no consolidation.
(b) The Environmental Appeals Board or Presiding Officer has the discretion to sever issues or parties from a proceeding under this part whenever it appears that separate proceedings will be in the interest of justice, will expedite or simplify consideration of the issues, and will not prejudice any party.
The Administrator will publish in the
(a)(1) No party or interested person outside EPA, representative of a party or interested person, or member of the EPA trial staff shall make, or knowingly cause to be made, to any member of the decisional body an
(2) No member of the decisional body shall make, or knowingly cause to be made, to any party or interested person outside EPA, representative of a party or interested person, or member of the EPA trial staff, an
(3) A member of the decisional body who receives, makes, or knowingly causes to be made an
(b) Whenever any member of the decisional body receives an
(c) The prohibitions of paragraph (a) of this section shall begin to apply upon publication by the Administrator of the notice of the filing of a petition under § 78.9 of this part. This prohibition terminates on the date of final agency action.
(a) Within 30 days (or other shorter, reasonable period established by the Administrator when giving notice) after notice is given under § 78.9 of this part that the petition for administrative review has been filed, any person listed in § 78.3(a) of this part may file a motion for leave to intervene in the proceeding. A motion for leave to intervene under this section shall set forth the grounds for the proposed intervention and may respond to the petition for administrative review. Late motions to intervene may be granted only for good cause shown.
(b) The Environmental Appeals Board of Presiding Officer will grant a motion to intervene only upon an express finding that:
(1) The motion to intervene raises matters relevant to the factual or legal issues to be reviewed;
(2) The intervenor consented to be bound by all stipulations previously entered into by the existing parties, and all orders previously issued, in the proceeding; and
(3) The intervention will promote the interests of justice and will not cause undue delay or prejudice to the rights of the existing parties.
(a) On appeal of a decision of the Administrator prior to which there was an opportunity for public comment, or to submit a claim of error notification:
(1) Except as provided under paragraph (a)(2) of this section, the petitioner shall have the burden of going forward and of persuasion to show that a finding of fact or conclusion of law underlying the decision is clearly erroneous or that an exercise of discretion or policy determination underlying the decision is arbitrary and capricious or otherwise warrants review.
(2) The owners and operators of the source or unit involved shall have the burden of persuasion that an Acid Rain permit or an exemption under § 72.14 of this chapter was properly issued or should be issued.
(b) On appeal of a decision of the Administrator not covered by paragraph (a) of this section, the Administrator shall have the burden of going forward to show the rational basis for the decision. The petitioner shall have the burden of persuasion to show that a finding of fact or conclusion of law underlying the decision is clearly erroneous
(a) If a request for an evidentiary hearing is granted, the Presiding Officer will issue an order scheduling the following:
(1) The filing by each party of a narrative statement of position on each factual issue in controversy.
(2) The identification of any witness that a party expects to call and of any written testimony, documents, papers, exhibits, or other materials that a party expects to introduce into evidence. At the request of the Presiding Officer, the party shall include a brief narrative summary of any witness’ expected testimony and of any such materials.
(3) The filing of written testimony, in accordance with § 78.14(b) of this part, and other evidence in support of a narrative statement.
(4) The filing of any motions by any party, including motions for the production of documentation, data, or other information material to the disputed facts to be addressed at the hearing.
(b) The Presiding Officer may also, on motion or
(1) Simplification, clarification, amplification, or limitation of the issues.
(2) Admissions and stipulations of facts and determinations of the genuineness of documents.
(3) Objections to the introduction into evidence at the hearing of any written testimony or other submissions proposed by a party;
(4) Taking official notice of any matters.
(5) Grouping of parties with substantially similar interests to eliminate redundant evidence, motions, objections, and briefs.
(6) Such other matters that may expedite the hearing or aid in the disposition of matters in dispute.
(c) The Presiding Officer will issue an order (which may be in the form of a transcript) reciting the actions taken at any pre-hearing conferences, setting the schedule for any hearing, and stating any areas of factual and legal agreement and disagreement and the methods and procedures to be used in developing any evidence.
(a) If a request for an evidentiary hearing is granted, the Presiding Officer will conduct a fair and impartial hearing on the record, take action to avoid unnecessary delay in the disposition of the proceedings, and maintain order. For these purposes, the Presiding Officer may:
(1) Administer oaths and affirmations.
(2) Regulate the course of the hearings and prehearing conferences and govern the conduct of participants.
(3) Examine witnesses.
(4) Identify and refer issues for interlocutory decision under § 78.19 of this part.
(5) Rule on, admit, exclude, or limit evidence.
(6) Establish the time for filing motions, testimony and other written evidence, and briefs and making other filings.
(7) Rule on motions and other pending procedural matters, including but not limited to motions for summary disposition in accordance with § 78.15 of this part.
(8) Order that the hearing be conducted in stages whenever the number of parties is large or the issues are numerous and complex.
(9) Allow direct and cross-examination of witnesses only to the extent the Presiding Officer determines that such direct and cross-examination may be necessary to resolve disputed issues of material fact;
(10) Limit public access to the hearing where necessary to protect confidential business information. The Presiding Officer will provide written notice of the hearing to the parties, and where the hearing will be open to the public, notice in the
(11) Take any other action not inconsistent with the provisions of this part for the maintenance of order at the hearing and for the expeditious, fair and impartial conduct of the proceeding.
(b) All direct and rebuttal testimony at an evidentiary hearing shall be filed in written form, unless, upon motion and good cause shown, the Presiding Officer, in his or her discretion, determines that oral presentation of such evidence on any particular factual issue will materially assist in the efficient resolution of the issue.
(c)(1) The Presiding Officer will admit all evidence that is not irrelevant, immaterial, unduly repetitious, or otherwise unreliable or of little probative value. Evidence relating to settlement that would be excluded in the Federal courts under the Federal Rules of Evidence shall not be admissible.
(2) Whenever any evidence or testimony is excluded by the Presiding Officer as inadmissible, all such evidence will remain a part of the record as an offer of proof. The party seeking the admission of oral testimony may make an offer of proof by means of a brief statement on the record describing the testimony excluded.
(3) When two or more parties have substantially similar interests and positions, the Presiding Officer may limit the number of attorneys or authorized representatives who will be permitted to examine witnesses and to make and argue motions and objections on behalf of those parties.
(4) Rulings of the Presiding Officer on the admissibility of evidence or testimony, the propriety of direct and cross-examination, and other procedural matters will appear in the record of the hearing and control further proceedings unless reversed by the Presiding Officer or as a result of an interlocutory appeal taken under § 78.19 of this part.
(5) All objections shall be made promptly or be deemed waived;
(a) Any party may make a motion to the Presiding Officer on any matter relating to the evidentiary hearing in accordance with the scheduling orders issued under § 78.13 of this part. All motions shall be in writing and served as provided in § 78.4 of this part, except those made on the record during an oral hearing before the Presiding Officer.
(b) Any party may make a motion for a summary disposition in its favor on any factual issue on the basis that there is no genuine issue of material fact. When a motion for summary disposition is made and supported, any party opposing the motion may not rest upon mere allegations or denials, but must show, by affidavit or by other materials subject to consideration by the Presiding Officer, that there is a genuine issue of material fact.
(c) Within 10 days (or other shorter, reasonable period established by the Presiding Officer) after a motion made on the record or service of any written motion, any party may file a response to the motion.
(d) The Presiding Officer may schedule an oral argument and call for the filing of briefs on any motion. The Presiding Officer will rule on the motion within a reasonable time after the date that responses to the motion may be filed under paragraph (c) of this section and that any oral argument or filing of briefs is completed.
(e) If all factual issues are decided by summary disposition prior to the hearing, no hearing will be held and the Presiding Officer will issue a proposed decision under § 78.18 of this part. If a
(a) The proposed decision issued by the Presiding Officer, transcripts of oral hearings or oral arguments, written direct and rebuttal testimony, and any other written materials of any kind filed in the proceeding will be part of the record and will be available to the public in the office of the Hearing Clerk, subject to the requirements of part 2 of this chapter.
(b) Hearings and oral arguments shall be recorded as specified by the Presiding Officer, and thereupon transcribed. After the hearing or oral argument, the reporter will certify and file with the Hearing Clerk.
(1) The original transcript; and
(2) Any exhibits received or offered into evidence at the hearing.
(c) The Hearing Clerk will promptly give written notice to the parties when any transcript is available. Any party that desires a copy of the transcript may obtain a copy upon payment of costs.
(d) The Presiding Officer will allow witnesses, parties, and their counsel or representatives:
(1) Up to 7 days (or other shorter, reasonable period established by the Presiding Officer) from issuance of the notice under paragraph (c) of this section in order to file written proposed corrections of the transcript necessary to correct errors made in the transcribing; and
(2) Up to 7 days (or other shorter, reasonable period established by the Presiding Officer) from the submission of the corrections in order to file objections to the proposed corrections.
(e) The Presiding Officer will determine which, if any, corrections should be made to the transcript and incorporate them into the record.
Within 45 days (or other shorter, reasonable period established by the Presiding Officer) after issuance of a notice under § 78.16(c) of this part that the complete transcript of the evidentiary hearing is available, any party may file with the Hearing Clerk proposed findings and conclusions on the issues referred to the Presiding Officer and a brief in support thereof. Briefs shall contain appropriate references to the record. The Presiding Officer may allow reply briefs.
(a) The Presiding Officer will review and evaluate the record, including the proposed findings and conclusions and any briefs filed by the parties, and issue a proposed decision on the factual, policy, and legal issues referred by the Environmental Appeals Board for decision under § 78.6(b)(2)(ii) of this part, accompanied by findings of fact and proposed conclusions of law, as appropriate, within a reasonable time after the evidentiary hearing is completed. The Hearing Clerk will promptly serve copies of the proposed decision on all parties and on the Environmental Appeals Board.
(b) The proposed decision of the Presiding Officer shall become the final agency action under section 307 of the Act unless:
(1) A party files objections with the Environmental Appeals Board pursuant to § 78.20(a) of this part, or
(2) The Environmental Appeals Board
(a) Interlocutory appeal from orders or rulings of the Presiding Officer made during the course of a proceeding may be taken if the Presiding Officer certifies those orders or rulings to the Environmental Appeals Board for interlocutory appeal on the record. Any
(b)(1) Within 15 days of the filing of any request for interlocutory appeal, the Presiding Officer may certify an order or ruling for interlocutory appeal to the Environmental Appeals Board if:
(i) The order or ruling involves an important question on which there is substantial ground for difference of opinion, and
(ii) Either:
(A) An immediate appeal of the order or ruling will materially advance the ultimate completion of the proceeding, or
(B) A review after the proceeding is completed will be inadequate or ineffective.
(2) If the Presiding Officer takes no action within 15 days of the filing of a request for interlocutory appeal, the request shall be automatically dismissed without prejudice.
(c) If the Presiding Officer grants certification, the Environmental Appeals Board may accept or decline the interlocutory appeal within 30 days of certification. If the Environmental Appeals Board decides that certification was improperly granted, it will decline to hear the interlocutory appeal. If the Environmental Appeals Board takes no action within 30 days of certification, the interlocutory appeal shall be automatically dismissed without prejudice.
(d) If the Presiding Officer declines to certify an order or ruling for an interlocutory appeal, the order or ruling may be reviewed by the Environmental Appeals Board only upon an appeal of the proposed decision following completion of the proceedings before the Presiding Officer, except when the Environmental Appeals Board determines, upon motion of a party and in exceptional circumstances, that to delay review would not be in the public interest. Such motion shall be filed with Environmental Appeals Board within 5 days after the earlier of automatic dismissal of the request for interlocutory appeal or receipt by the party of notification that the Presiding Officer declines to certify an order or ruling for interlocutory appeal.
(e) The failure of a party to request an interlocutory appeal shall not prevent an appeal of an order or ruling as part of an appeal of a proposed decision under § 78.20 of this part.
(a) Within 30 days after the issuance of a proposed decision by a Presiding Officer under this part, any party may appeal any matter set forth in the proposed decision, or any other order or ruling made during the proceeding to which the party objected during the proceeding before the Presiding Officer, by filing an objection with the Environmental Appeals Board. On appeal of an order, ruling, or proposed decision of a Presiding Officer:
(1) The party filing the objection shall have the burden of going forward to show that the order, ruling, or proposed decision is based on a finding of fact or conclusion of law that is clearly erroneous; or a policy determination or exercise of discretion that is arbitrary and capricious or otherwise warrants review; and
(2) The petitioner or the owners and operators shall have the burden of persuasion, as set forth in § 78.12(a) (1) and (2) of this part.
(b) Within 45 days (or other shorter, reasonable period established by the Environmental Appeals Board) after issuance of a proposed decision of a Presiding Officer, the Environmental Appeals Board may issue
(c) Within a reasonable time following the filing of a petition for administrative review of a decision of the Administrator under § 78.3 of this part, or, if any issues raised by such petition are referred to the Presiding Officer, the filing of objections under paragraph (a) of this section or the issuance of a notice of intent to review under paragraph (b) of this section, the Environmental Appeals Board will issue an order affirming, reversing, modifying, or remanding the decision or proposed decision, as appropriate. Prior to
(d) If the Environmental Appeals Board issues an order affirming, reversing, or modifying the decision of the Administrator, then the decision as supplemented or changed by the order, shall be final agency action.
(e) If the Environmental Appeals Board issues an order affirming, reversing, or modifying the proposed decision, the proposed decision, as supplemented or changed by the order, shall be final agency action.
(f) If the Environmental Appeals Board issues an order remanding the proceeding, then final agency action occurs upon completion of the remanded proceeding, including any appeals to the Environmental Appeals Board in the remanded proceeding.
42 U.S.C. 7414, 7524, 7545 and 7601.
The regulations of this part apply to the registration of fuels and fuel additives designated by the Administrator, pursuant to section 211 of the Clean Air Act (42 U.S.C. 1857f-6c, as amended by section 9, Pub. L. 91-604).
As used in this part, all terms not defined herein shall have the meaning given them in the Act:
(a)
(b)
(c)
(d)
(1) A party (other than a fuel refiner or importer) who adds a quantity of additive(s) amounting to less than 1.0 percent by volume of the resultant additive(s)/fuel mixture is not thereby considered a fuel manufacturer.
(2) A party (other than a fuel refiner or importer) who adds an oxygenate compound to fuel in any otherwise allowable amount is not thereby considered a fuel manufacturer.
(e)
(f)
(g)
(h)
(i)
(j)
(k)
The availability to the public of information provided to, or otherwise obtained by, the Administrator under this part shall be governed by part 2 of this chapter except as expressly noted in subpart F of this part.
(a)
(2) No manufacturer of a registered fuel shall add or direct the addition to it of an additive which he has not previously reported unless he has notified the Administrator of such intended use, including the expected or estimated range of concentration. If necessary to meet an unforeseen production problem, however, a fuel manufacturer may use an additive that he has not previously reported provided that (i) the additive is on the current list of registered additives and (ii) the fuel manufacturer notifies the Administrator within 30 days regarding such unforeseen use and his plans regarding continued use, including the expected or estimated range of concentration.
(3) Any designated fuel that is (i) in a research, development, or test status; (ii) sold to automobile, engine, or component manufacturers for research, development, or test purposes; or (iii) sold to automobile manufacturers for factory fill, and is not in any case offered for commercial sale to the public, shall be exempt from registration.
(4) A domestic fuel manufacturer may purchase and offer for commercial sale foreign-produced fuel containing unidentified additives provided that within 30 days of his offer for sale he
(b)
(2) Any designated additive that is either (i) in a research, development, or test status or (ii) sold to petroleum, automobile, engine, or component manufacturers for research, development, or test purposes, and in either case is not offered for commercial sale to the public, shall be exempt from registration.
(3) Process chemicals used by refineries during the refinery process are exempted from the requirement for registration.
(4) If an additive manufacturer prepares for sale only to fuel manufacturers (i) a blend or mixture of two or more registered additives or (ii) a blend or mixture of one or more registered additives with one or more substances containing only carbon and/or hydrogen, he will not be required to register such blend or mixture provided he will, upon request, furnish the Administrator with the names and percentages by weight of all components of such blend or mixture.
(a)
(2) Fuel manufacturers shall submit to the Administrator a report annually for each registered fuel providing additional data and information as specified in § 79.31(c) and (d) in the designation of the fuel in subpart D. Reports shall be submitted on or before March 31 for the preceding year or part thereof on forms supplied by the Administrator upon request. If the date prescribed for a particular fuel in subpart D or the later registration of a fuel is between October 1 and December 31, no report will be required for the period to the end of that year.
(b)
(1) An additive registered under another name,
(2) A blend or mixture of two or more registered additives, or
(3) A blend or mixture of one or more registered additives with one or more substances containing only carbon and/or hydrogen.
Provisions regarding testing that is required for registration of a designated fuel or fuel additive are contained in subpart F of this part.
When the Administrator requires for test purposes a fuel or additive which is not readily available in the open market, he may request the manufacturer of such fuel or additive to furnish a sample in a reasonable quantity. The fuel or additive manufacturer shall comply with such request within 30 days.
Any person who violates section 211(a) of the Act or who fails to furnish any information or conduct any tests required under this part shall be liable to the United States for a civil penalty of not more than the sum of $25,000 for every day of such violation and the amount of economic benefit or savings resulting from the violation. Civil penalties shall be assessed in accordance with paragraphs (b) and (c) of section 205 of the Act.
Any manufacturer of a designated fuel who wishes to register that fuel shall submit an application for registration including all of the information set forth in § 79.11. If the manufacturer produces more than one grade or brand of a designated fuel, a manufacturer may include more than one grade or brand in a single application, provided that the application includes all information required for registration of each such grade or brand by this part. Each application shall be signed by the fuel manufacturer and shall be submitted on such forms as the Administrator will supply on request.
Each application for registration submitted by the manufacturer of a designated fuel shall include the following:
(a) The commercial identifying name of each additive that will or may be used in a designated fuel subsequent to the date prescribed for such fuel in subpart D;
(b) The name of the additive manufacturer of each additive named;
(c) The range of concentration of each additive named, as follows:
(1) In the case of an additive which has been or is being used in the designated fuel, the range during any 3-month or longer period prior to the date of submission;
(2) In the case of an additive which has not been used in the designated fuel, the expected or estimated range;
(d) The purpose-in-use of each additive named;
(e) The description (or identification, in the case of a generally accepted method) of a suitable analytical technique (if one is known) that can be used to detect the presence of each named additive in the designated fuel and/or to measure its concentration therein;
(f) Such other data and information as are specified in the designation of the fuel in subpart D;
(g) Assurances that the fuel manufacturer will notify the Administrator in writing and within a reasonable time of any change in:
(1) The name of any additive previously reported;
(2) The name of the manufacturer of any additive being used;
(3) The purpose-in-use of any additive;
(4) Information submitted pursuant to paragraph (e) of this section;
(h) Assurances that the fuel manufacturer will not represent, directly or indirectly, in any notice, circular, letter, or other written communication, or any written, oral, or pictorial notice or other announcement in any publication or by radio or television, that registration of the fuel constitutes endorsement, certification, or approval by any agency of the United States;
(i) The manufacturer of any fuel which will be sold, offered for sale, or introduced into commerce for use in motor vehicles manufactured after model year 1974 shall demonstrate that the fuel is substantially similar to any fuel utilized in the certification of any 1975 or subsequent model year vehicle or engine, or that the manufacturer
(j) The manufacturer shall submit, or shall reference prior submissions, including all of the test data and other information required prior to registration of the fuel by the provisions of subpart F of this part.
If the Administrator determines that an applicant for registration of a designated fuel has failed to submit all of the information required by § 79.11, or determines within the applicable period provided for Agency review that the applicant has not satisfactorily completed any testing which is required prior to registration of the fuel by any provision of subpart F of this part, he shall return the application to the manufacturer, along with an explanation of all deficiencies in the required information.
(a) If the Administrator determines that a manufacturer has submitted an application for registration of a designated fuel which includes all of the information and assurances required by § 79.11 and has satisfactorily completed all of the testing required by subpart F of this part, the Administrator shall promptly register the fuel and notify the fuel manufacturer of such registration.
(b) The Administrator shall maintain a list of registered fuels, which shall be available to the public upon request.
Registration may be terminated by the Administrator if the fuel manufacturer requests such termination in writing.
Any manufacturer of a designated fuel additive who wishes to register that additive shall submit an application for registration including all of the information set forth in § 79.21. Each application shall be signed by the fuel additive manufacturer and shall be submitted on such forms as the Administrator will supply on request.
Each application for registration submitted by the manufacturer of a designated fuel additive shall include the following:
(a) The chemical composition of the additive with the methods of analysis identified, except that
(1) If the chemical composition is not known, full disclosure of the chemical process of manufacture will be accepted in lieu thereof;
(2) In the case of an additive for engine oil, only the name, percentage by weight, and method of analysis of each element in the additive are required provided, however, that a percentage figure combining the percentages of carbon, hydrogen, and/or oxygen may be provided unless the breakdown into percentages for these individual elements is already known to the registrant.
(3) In the case of a purchased component, only the name, manufacturer, and percent by weight of such purchased component are required if the manufacturer of the component will, upon request, furnish the Administrator with the chemical composition thereof.
(b) The chemical structure of each compound in the additive if such structure is known and is not adequately specified by the name given under “chemical composition.” Nominal identification is adequate if mixed isomers are present.
(c) The description (or identification, in the case of a generally accepted method) of a suitable analytical technique (if one is known) that can be used to detect the presence of the additive in any fuel named in the designation and/or to measure its concentration therein.
(d) The specific types of fuels designated under § 79.32 for which the fuel additive will be sold, offered for sale, or introduced into commerce, and the fuel additive manufacturer's recommended range of concentration and purpose-in-use for each such type of fuel.
(e) Such other data and information as are specified in the designation of the additive in subpart D.
(f) Assurances that any change in information submitted pursuant to (1) paragraphs (a), (b), (c), and (d) of this section will be provided to the Administrator in writing within 30 days of such change; and (2) paragraph (e) of this section as provided in § 79.5(b).
(g) Assurances that the additive manufacturer will not represent, directly or indirectly, in any notice, circular, letter, or other written communication or any written, oral, or pictorial notice or other announcement in any publication or by radio or television, that registration of the additive constitutes endorsement, certification, or approval by any agency of the United States.
(h) The manufacturer of any fuel additive which will be sold, offered for sale, or introduced into commerce for use in any type of fuel intended for use in motor vehicles manufactured after model year 1974 shall demonstrate that the fuel additive, when used at the recommended range of concentration, is substantially similar to any fuel additive included in a fuel utilized in the certification of any 1975 or subsequent model year vehicle or engine, or that the manufacturer has obtained a waiver under 42 U.S.C. 7545(f)(4).
(i) The manufacturer shall submit, or shall reference prior submissions, including all of the test data and other information required prior to registration of the fuel additive by the provisions of subpart F of this part.
If the Administrator determines that an applicant for registration of a designated fuel additive has failed to submit all of the information required by § 79.21, or determines within the applicable period provided for Agency review that the applicant has not satisfactorily completed any testing which is required prior to registration of the fuel additive by any provision of subpart F of this part, he shall return the application to the manufacturer, along with an explanation of all deficiencies in the required information.
(a) If the Administrator determines that a manufacturer has submitted an application for registration of a designated fuel additive which includes all of the information and assurances required by § 79.21 and has satisfactorily completed all of the testing required by subpart F of this part, the Administrator shall promptly register the fuel additive and notify the fuel manufacturer of such registration.
(b) The Administrator shall maintain a list of registered additives, which shall be available to the public upon request.
Registration may be terminated by the Administrator if the additive manufacturer requests such termination in writing.
Fuels and additives designated and dates prescribed by the Administrator for the registration of such fuels and additives, pursuant to section 211 of the Act, are listed in this subpart. In addition, specific informational requirements under §§ 79.11(f) and 79.21(e) are set forth for each designated fuel or
(a) All additives produced or sold for use in motor vehicle gasoline and/or motor vehicle diesel fuel are hereby designated. The Act defines the term
(b) All designated additives must be registered by July 7, 1976.
(c) In accordance with §§ 79.5(b) and 79.21(e), and to the extent such information is known to the additive manufacturer as a result of testing conducted for reasons other than additive registration or reporting purposes, the additive manufacturer shall furnish the highest, lowest, and average values of the impurities in each designated additive, if greater than 0.1 percent by weight. The methods of analysis in making the determinations shall also be given.
(d) In accordance with §§ 79.5(b) and 79.21(e), and to the extent such information is known to the additive manufacturer, he shall furnish summaries of any information developed by or specifically for him concerning the following items:
(1) Mechanisms of action of the additive;
(2) Reactions between the additive and the fuels listed in paragraph (a) of this section;
(3) Identification and measurement of the emission products of the additive when used in the fuels listed in paragraph (a) of this section;
(4) Effects of the additive on all emissions;
(5) Toxicity and any other public health or welfare effects of the emission products of the additive;
(6) Effects of the emission products of the additive on the performance of emission control devices/systems. Such submissions shall be accompanied by a description of the test procedures used in obtaining the information. Information will be considered to be known to the additive manufacturer if a report thereon has been prepared and circulated or distributed outside the research department or division.
(a) The following fuels commonly or commercially known or sold as motor vehicle gasoline are hereby individually designated:
(1) Motor vehicle gasoline, unleaded—motor vehicle gasoline that contains no more than 0.05 gram of lead per gallon;
(2) Motor vehicle gasoline, leaded, premium—motor vehicle gasoline that contains more than 0.05 gram of lead per gallon and is sold as “premium;”
(3) Motor vehicle gasoline, leaded, non-premium—motor vehicle gasoline that contains more than 0.05 gram of lead per gallon but is not sold as “premium.”
(b) All designated motor vehicle gasolines must be registered by September 7, 1976.
(c) In accordance with §§ 79.5(a)(2) and 79.11(f), and to the extent such information is known to the fuel manufacturer as a result of testing conducted for reasons other than fuel registration or reporting purposes, the fuel manufacturer shall furnish the data listed below. The highest, lowest, and average values of the listed characteristics/properties are to be reported. For initial registration, data shall be given for any 3-month or longer period prior to the date of submission. For annual reports thereafter, data shall be for the calendar year, except that if the first required annual report covers a period of less than a year, the data may be for such shorter period.
(1) Hydrocarbon composition (aromatic content, olefin content, saturate content), with the methods of analysis identified;
(2) Polynuclear organic material content, sulfur content, and trace element content, with the methods of analysis identified;
(3) Reid vapor pressure;
(4) Distillation temperatures (10 percent point, end point);
(5) Research octane number and motor octane number.
(d) In accordance with §§ 79.5(a)(2) and 79.11(f), and to the extent such information is known to the fuel manufacturer, he shall furnish summaries of any information developed by or specifically for him concerning the following items:
(1) Mechanisms of action of each additive he reports;
(2) Reactions between such additives and motor vehicle gasoline;
(3) Identification and measurement of the emission products of such additives when used in motor vehicle gasoline;
(4) Effects of such additives on all emissions;
(5) Toxicity and any other public health or welfare effects of the emission products of such additives;
(6) Effects of the emission products of such additives on the performance of emission control devices/systems. Such submissions shall be accompanied by a description of the test procedures used in obtaining the information. Information will be considered to be known to the fuel manufacturer if a report thereon has been prepared and circulated or distributed outside the research department or division.
(a) The following fuels commonly or commercially known or sold as motor vehicle diesel fuel are hereby individually designated:
(1) Motor vehicle diesel fuel, grade 1-D;
(2) Motor vehicle diesel fuel, grade 2-D.
(b) All designated motor vehicle diesel fuels must be registered within 12 months after promulgation of this part.
(c) In accordance with §§ 79.5(a)(2) and 79.11(f), and to the extent such information is known to the fuel manufacturer as a result of testing conducted for reasons other than fuel registration or reporting purposes, the fuel manufacturer shall furnish the data listed below. The highest, lowest, and average values of the listed characteristics/properties are to be reported. For initial registration, data shall be given for any 3-month or longer period prior to the date of submission. For annual reports thereafter, data shall be for the calendar year, except that if the first required annual report covers a period of less than a year, the data may be for such shorter period.
(1) Hydrocarbon composition (aromatic content, olefin content, saturate content), with the methods of analysis identified;
(2) Polynuclear organic material content, sulfur content, and trace element content, with the methods of analysis identified;
(3) Distillation temperatures (90 percent point, end point);
(4) Cetane number or cetane index;
(d) In accordance with §§ 79.5(a)(2) and 79.11(f), and to the extent such information is known to the fuel manufacturer, he shall furnish summaries of any information developed by or specifically for him concerning the following items:
(1) Mechanisms of action of each additive he reports;
(2) Reactions between such additives and motor vehicle diesel fuel;
(3) Identification and measurement of the emission products of such additives when used in motor vehicle diesel fuel;
(4) Effects of such additives on all emissions;
(5) Toxicity and any other public health or welfare effects of the emission products of such additives.
The definitions listed in this section apply only to subpart F of this part.
(a)
(2) Laboratory facilities shall perform testing in compliance with Good Laboratory Practice (GLP) requirements as those requirements apply to inhalation toxicology studies. All studies shall be monitored by the facilities’ Quality Assurance units (as specified in § 79.60).
(b)
(c)
(1)
(ii) Except as provided in paragraphs (c)(1)(vi) and (vii) of this section, the manufacturer of such products must also satisfy the requirements and time schedules in either of the following paragraphs (c)(1)(ii) (A) or (B) of this section:
(A) No later than May 27, 1997, all applicable Tier 1 and Tier 2 requirements must be submitted to EPA, pursuant to §§ 79.52, 79.53, and 79.59; or
(B) No later than May 27, 1997, all applicable Tier 1 requirements (pursuant to §§ 79.52 and 79.59), plus evidence of a contract with a qualified laboratory (or other suitable arrangement) for completion of all applicable Tier 2 requirements, must be submitted to EPA. For this purpose, a qualified laboratory is one which can demonstrate the capabilities and credentials specified in § 79.53(c)(1). In addition, by May 26, 2000, all applicable Tier 2 requirements (pursuant to §§ 79.53 and 79.59) must be submitted to EPA.
(iii) In the case of such fuels and fuel additives which, pursuant to applicable special provisions in § 79.58, are not subject to Tier 2 requirements, all other requirements (except Tier 3) must be submitted to EPA before May 27, 1997.
(iv) In the event that Tier 3 testing is also required (under § 79.54), EPA shall determine an appropriate timeline for completion of the additional requirements and shall communicate this schedule to the manufacturer according to the provisions of § 79.54(b).
(v) The manufacturer may at any time modify an existing fuel registration by submitting a request to EPA to add or delete a bulk additive to the existing registration information for such fuel product, provided that any additional additive must be registered by EPA for use in the specific fuel family to which the fuel product belongs. However, the addition or deletion of a bulk additive to a fuel registration may effect the grouping of such registered fuel under the criteria of § 79.56, and thus may effect the testing responsibilities of the fuel manufacturer under this subpart.
(vi) In regard to atypical fuels or additives in the gasoline and diesel fuel families (pursuant to the specifications in § 79.56(e)(4)(iii)(A) (
(A) All applicable Tier 1 requirements, pursuant to §§ 79.52 and 79.59, must be submitted to EPA by May 27, 1997.
(B) Tier 2 requirements, pursuant to §§ 79.53 and 79.59, must be satisfied according to the deadlines in either of the following paragraphs (c)(1)(vi)(B) (
(
(
(vii) In regard to nonbaseline diesel products formulated with mixed alkyl esters of plant and/or animal origin (i.e., “biodiesel” fuels, pursuant to § 79.56(e)(4)(ii)(B)(
(A) All applicable Tier 1 requirements, pursuant to §§ 79.52 and 79.59, must be submitted to EPA by March 17, 1998.
(B) Tier 2 requirements, pursuant to §§ 79.53 and 79.59, must be satisfied according to the deadlines in either of the following paragraphs (c)(1)(vii)(B) (
(
(
(2)
(ii) A manufacturer seeking to register under subpart B of this part a fuel product which is deemed registrable under this section, or to register under subpart C of this part a fuel additive product for a specific type of fuel for which it is deemed registrable under this section, shall submit the basic registration data (pursuant to § 79.59(b)) for that product as part of the application for registration. If the Administrator determines that the product is registrable under this section, then the Administrator shall promptly register the product, provided that the applicant has satisfied all of the other requirements for registration under subpart B or subpart C of this part, and contingent upon satisfactory submission of required information under paragraph (c)(2)(iii) of this section.
(iii) Registration of a registrable fuel or additive shall be subject to the same requirements and compliance schedule as specified in paragraph (c)(1) of this section for existing fuels and fuel additives. Accordingly, manufacturers of registrable fuels or additives may be granted and may retain registration for such products only if any applicable and due Tier 1, 2, and 3 requirements have also been satisfied by either the manufacturer of the product or the fuel/additive group to which the product belongs.
(3)
(d)
(1)
(ii) If the manufacturer of a registered fuel or fuel additive product is notified that testing or retesting is necessary to bring the Tier 1 and/or Tier 2 submittal into compliance, the continued sale or importation of the product shall be conditional upon satisfactorily completing the requirements within the time frame specified in paragraph (c)(1) of this section.
(iii) EPA intends to notify the manufacturer of the adequacy of the submitted data within two years of EPA's receipt of such data. However, EPA retains the right to require that adequate data be submitted to EPA if, upon subsequent review, EPA finds that the original Tier 1 and/or Tier 2 submittal is not consistent with the requirements of this subpart. If EPA does not notify the manufacturer of the adequacy of the Tier 1 and/or Tier 2 data within two years, EPA will not hold the manufacturer liable for penalties for violating this rule for the period beginning when the data was due until the time EPA notifies the manufacturer of the violation.
(iv) If the manufacturer of a registered fuel or fuel additive product is notified (pursuant to § 79.54(b)) that Tier 3 testing is required for its product, then the manufacturer may continue to sell, offer for sale, introduce into commerce the registered product as permitted by the existing registration for the product under § 79.4. However, if the manufacturer fails to complete the specified Tier 3 requirements within the specified time, the registration of the product will be subject to cancellation under § 79.51(f)(6).
(v) EPA retains the right to require additional Tier 3 testing pursuant to the procedures in § 79.54.
(2)
(A) If EPA notifies the manufacturer that testing, retesting, or additional information is necessary to bring the Tier 1 and Tier 2 submittal into compliance, the manufacturer shall remedy all inadequacies and provide Tier 3 data, if required, before EPA shall consider the requirements for registration to have been met for the product in question.
(B) If EPA does not notify the manufacturer of the adequacy of the Tier 1 and Tier 2 submittal within six months following the submittal, the manufacturer shall be deemed to have satisfactorily completed Tiers 1 and 2.
(ii) Within six months of the date on which EPA notifies the manufacturer of satisfactory completion of Tiers 1 and 2 for a new product, or within one year of the submittal of the Tier 1 and Tier 2 data (whichever is earlier), EPA shall determine whether additional testing is currently needed under the provisions of Tier 3 and, pursuant to § 79.54(b), shall notify the manufacturer of its determination.
(A) If the manufacturer of a new fuel or fuel additive product is notified that Tier 3 testing is required for such product, then EPA shall have the authority to withhold registration until the specified Tier 3 requirements have been satisfactorily completed. EPA shall determine whether the Tier 3 requirements have been met, and shall notify the manufacturer of this determination, within one year of receiving the manufacturer's Tier 3 submittal.
(B) If EPA does not notify the manufacturer of potential Tier 3 requirements within the prescribed timeframe, then additional testing at the Tier 3 level is deemed currently unnecessary and the manufacturer shall be considered to have complied with all current registration requirements for the new fuel or additive product.
(iii) Upon completion of all current Tier 1, Tier 2, and Tier 3 requirements, and submission of an application for registration which includes all of the information and assurances required by § 79.11 or § 79.21, the registration of the new fuel or additive shall be granted, and the registrant may then sell, offer for sale, or introduce into commerce the registered product as permitted by § 79.4.
(iv) Once the new product becomes registered, EPA reserves the right to require additional Tier 3 testing pursuant to the procedures specified in § 79.54.
(e)
(2) EPA will not consider reliable for purposes of showing that a test substance does or does not present a risk of injury to health or the environment any data developed by a testing facility or sponsor that refuses to permit inspection in accordance with this section. The determination that a study will not be considered reliable does not, however, relieve the sponsor of a required test of any obligation under any applicable statute or regulation to submit the results of the study to EPA.
(3) Effects of non-compliance. Pursuant to sections 114, 208, and 211(d) of the CAA, it shall be a violation of this section and a violation of 40 CFR part 79, subpart F to deny entry to an authorized employee or duly designated representative of EPA for the purpose of auditing a testing facility or test data.
(f)
(2) Under section 205(b) of the CAA, the Administrator may commence a civil action for violation of this subpart in the district court of the United States for the district in which the violation is alleged to have occurred or in which the defendant resides or has a principal place of business.
(3) Under section 205(c) of the CAA, the Administrator may assess a civil penalty of $25,000 for each and every day of the continuance of the violation and the economic benefit or savings resulting from the violation, except that the maximum penalty assessment shall not exceed $200,000, unless the Administrator and the Attorney General jointly determine that a matter involving a larger penalty amount is appropriate for administrative penalty assessment. Any such determination by the Administrator and the Attorney General shall not be subject to judicial review.
(4) The Administrator may, upon application by the person against whom any such penalty has been assessed,
(5) The district courts of the United States shall have jurisdiction to compel the furnishing of information and the conduct of tests required by the Administrator under these regulations and to award other appropriate relief. Actions to compel such actions shall be brought by and in the name of the United States. In any such action, subpoenas for witnesses who are required to attend a district court in any district may run into any other district.
(6)
(ii) Upon issuance of a notice of intent to cancel, EPA will forward a copy of the notice to the registrant by certified mail, return receipt requested, at the address of record given in the registration, along with an explanation of the reasons for the proposed cancellation.
(iii) The registrant will be afforded 60 days from the date of receipt of the notice of intent to cancel to submit written comments concerning the notice, and to demonstrate or achieve compliance with the specific data requirements which provide the basis for the proposed cancellation. If the registrant does not respond in writing within 60 days from the date of receipt of the notice of intent to cancel, the cancellation of the registration shall become final by operation of law and the Administrator shall notify the registrant of such cancellation. If the registrant responds in writing within 60 days from the date of receipt of the notice of intent to cancel, the Administrator shall review and consider all comments submitted by the registrant before taking final action concerning the proposed cancellation. The registrants’ communications should be sent to the following address: Director, Field Operations and Support Division, 6406J—Fuel/Additives Registration, U.S. Environmental Protection Agency, 401 M Street SW., Washington, DC 20460.
(iv) As part of a written response to a notice of intent to cancel, a registrant may request an informal hearing concerning the notice. Any such request shall state with specificity the information the registrant wishes to present at such a hearing. If an informal hearing is requested, EPA shall schedule such a hearing within 60 days from the date of receipt of the request. If an informal hearing is held, the subject matter of the hearing shall be confined solely to whether or not the registrant has complied with the specific data requirements which provide the basis for the proposed cancellation. If an informal hearing is held, the designated presiding officer may be any EPA employee, the hearing procedures shall be informal, and the hearing shall not be subject to or governed by 40 CFR part 22 or by 5 U.S.C. 554, 556, or 557. A verbatim transcript of each informal hearing shall be kept and the Administrator shall consider all relevant evidence and arguments presented at the hearing in making a final decision concerning a proposed cancellation.
(v) If a registrant who has received a notice of intent to cancel submits a timely written response, and the Administrator decides after reviewing the response and the transcript of any informal hearing to cancel the registration, the Administrator shall issue a final cancellation order, forward a copy of the cancellation order to the registrant by certified mail, and promptly publish the cancellation order in the
(g)
(i) Such request shall be made as soon as the test sponsor is aware that
(ii) Upon such request, the Administrator may, in circumstances which are outside the control of the manufacturer(s) or his/their agent and which could not have been reasonably foreseen or avoided, modify the mandatory testing requirements in the rule if such requirements are infeasible.
(iii) If the Administrator determines that such modifications would not significantly alter the scope of the test, EPA will not ask for public comment before approving the modification. The Administrator will notify the test sponsor by certified mail of the response to the request. EPA will place copies of each application and EPA response in the public docket. EPA will publish a notice in the
(iv) Where, in EPA's judgment, the requested modification of a test standard would significantly change the scope of the test, EPA will publish a notice in the
(2) [Reserved]
(h)
(1) All required emission characterization and health effects testing procedures shall be performed on the mixture which results when the additive is combined with the base fuel for the appropriate fuel family (as specified in § 79.55) at the maximum concentration recommended by the additive manufacturer pursuant to § 79.21(d). This combination shall be known as the additive/base fuel mixture.
(i) The appropriate fuel family to be utilized for the additive/base fuel mixture is the fuel family which contains the specific type(s) of fuel for which the additive is presently registered or for which the manufacturer of the additive is seeking registration.
(ii) Additives belonging to more than one fuel family.
(A) If an additive product is registered in two or more fuel families as of May 27, 1994, then the manufacturer of that additive is responsible for testing (or participating in group testing of) the respective additive/base fuel mixtures in compliance with the requirements of this subpart for each fuel family in which the manufacturer wishes to maintain a registration for its additive.
(B) If a manufacturer is seeking to register such additive in two or more fuel families then, for testing and registration purposes, the additive shall be considered to be a member of each fuel family in which the manufacturer is seeking registration. The manufacturer is responsible for testing (or participating in group testing of) the respective additive/base fuel mixture in compliance with the requirements of this subpart for each fuel family in which the manufacturer wishes to obtain a product registration for its additive.
(iii) In the case of the methanol fuel family, which contains two base fuels (M100 and M85 base fuels, pursuant to § 79.55(d)), the applicable base fuel is the one which represents the fuel/additive group (specified in § 79.56(e)(4)(i)(C)) containing fuels of which the most gallons are sold annually.
(iv) Aftermarket additives which are intended by the manufacturer to be added to the fuel tank only at infrequent intervals shall be applied according to the manufacturer's specifications during mileage accumulation, pursuant to § 79.57(c). However, during emission generation and testing, each tankful of fuel used must contain the fuel additive at its maximum recommended level. If the additive manufacturer believes that this maximum treatment rate will cause adverse effects to the test engine and/or that the engine's emissions may be subject to
(v) Additives produced exclusively for use in
(vi) Bulk additives which are used intermittently for the direct purpose of conditioning or treating a fuel during storage or transport, or for treating or maintaining the storage, pipeline, and/or other components of the fuel distribution system itself and not the vehicle/engine for which the fuel is ultimately intended, shall, for purposes of this program, be added to the base fuel at the maximum concentration recommended by the additive manufacturer for treatment of the fuel or distribution system component. However, if the additive manufacturer believes that this treatment rate will cause adverse effects to the test engine and/or that the engine's emissions may be subject to artifacts due to overuse of the additive, then the manufacturer may submit a request to EPA for modification of this requirement and related test procedures. Such request must include objective evidence that the modification(s) are needed, along with data demonstrating the maximum concentration of the additive which may actually reach the fuel tanks of vehicles in use.
(2) EPA shall use emissions speciation and health effects data generated in the analysis of the applicable base fuel as control data for comparison with data generated for the additive/base fuel mixture.
(i) The base fuel control data may be:
(A) Generated internally as an experimental control in conjunction with testing done in compliance with registration requirements for a specific additive; or
(B) Generated externally in the course of testing different additive(s) belonging to the same fuel family, or in the testing of a base fuel serving as representative of the baseline group for the respective fuel family pursuant to § 79.56(e)(4)(i).
(ii) Control data generated using test equipment (including vehicle model and/or engine, or Evaporative Emissions Generator specifications, as appropriate) and protocols identical or nearly identical to those used in emissions and health effects testing of the subject additive/base fuel mixture would be most relevant for comparison purposes.
(iii) If an additive manufacturer chooses the same vehicle/engine to independently test the base fuel as an experimental control prior to testing the additive/base fuel mixture, then the test vehicle/engine shall undergo two mileage accumulation periods, pursuant to § 79.57(c). The initial mileage accumulation period shall be performed using the base fuel alone. After base fuel testing, and prior to testing of the additive/base fuel mixture, a second mileage accumulation period shall be performed using the additive/base fuel mixture. The procedures outlined in this paragraph shall not preclude a manufacturer from testing a base fuel and the manufacturer's additive/base fuel mixture separately in identical, or nearly identical, vehicles/engines.
(i)
(2) When the composition information reported in the registration application or basic registration data for a non- baseline gasoline product contains a range of total oxygenate concentration-in-use which encompasses gasoline formulations with less than 1.5 weight percent oxygen as well as gasoline formulations with 1.5 weight percent oxygen or more, then the manufacturer is required to test (or participate in applicable group testing of) a baseline gasoline formulation as well as one or more non-baseline gasoline formulations as described in paragraph (h)(1) of this section.
(3) When the composition information reported in the registration application or basic registration data for a non- baseline diesel product contains a range of total oxygenate concentration-in-use which encompasses diesel formulations with less than 1.0 weight percent oxygen as well as diesel formulations with 1.0 weight percent oxygen or more, then the manufacturer is required to test (or participate in applicable group testing) of a baseline diesel formulation as well as one or more non-baseline diesel formulations as described in paragraph (h)(1) of this section.
(4) The presence in a particular oxygenating additive of small amounts of other unintended oxygenate compounds as byproducts of the manufacturing process of the given oxygenating additive does not affect the grouping of that additive and does not create multiple testing responsibilities for manufacturers who blend that additive into fuel.
(j)
(1) When such disparate additive products are for the same purpose-in-use and are not ordinarily used in the fuel simultaneously, the fuel manufacturer shall be responsible for testing (or participating in the group testing of) a separate formulation for each such additive product. Testing related to each additive product shall be performed on a mixture of the additive in the applicable base fuel, as described in paragraph (g)(1) of this section, or by participation in the costs of testing the designated representative of the fuel/additive group to which each separate atypical additive product belongs.
(2) When the disparate additive products are not for the same purpose-in-use, the fuel manufacturer shall nevertheless be responsible for testing a separate formulation for each such additive product, as described in paragraph (g)(1) of this section, if these additives are not ordinarily blended together in the same commercial formulation of the fuel.
(3) When the disparate additive products are ordinarily blended together in the same commercial formulation of the fuel, then the fuel manufacturer shall be responsible for the testing of a single test formulation containing all such simultaneously used atypical additive products. Alternatively, this responsibility can be satisfied by enrolling such fuel product in a group which includes other fuel or additive products with the same total combination of atypical elements as that occurring in the fuel product in question. If the basic registration data for the subject fuel includes any alternative additives which contain atypical elements not represented in the test formulation, then the fuel manufacturer is also responsible for testing a separate formulation for each such additional disparate additive product.
(k)
(a)
(b)
(1)
(ii) As provided in § 79.57(d), if the emission generation vehicle/engine is ordinarily equipped with an emission aftertreatment device, then all requirements in this section for the characterization of combustion emissions must be completed both with and without the aftertreatment device in a functional state. The emissions shall be generated three times (on three different days) without a functional aftertreatment device and, if applicable, three times (on three different days) with a functional aftertreatment device, and each such time shall be analyzed according to the remaining provisions in this paragraph (b) of this section.
(iii) Measurement of background emissions: It is required that ambient/dilution air be analyzed for levels of background chemical species present at the time of emissions sampling (for both combustion and evaporative emissions) and that sample values be corrected by substracting the concentrations contributed by the ambient/dilution air. Background chemical species measurement/analysis during the FTP is specified in §§ 86.109-94(c)(5) and 86.135-94 of this chapter.
(iv) Concentrations of emission products shall be reported either in units of grams per mile (g/mi) or grams per brake-horsepower/hour (g/bhp-hr) (for chassis dynamometer and engine dynamometer test configurations, respectively), as well as in units of weight
(v) Laboratory practice must be of high quality and must be consistent with state-of-the-art methods as presented in current environmental and analytical chemistry literature. Examples of analytical procedures which may be used in conducting the emission characterization/speciation requirements of this section can be found among the references in paragraph (b)(5) of this section.
(2) Characterization of the combustion emissions shall include, for products in all fuel families (except when expressly noted in this section):
(i) Determination of the concentration of the basic emissions as follows: total hydrocarbons, carbon monoxide, oxides of nitrogen, and particulates. Manufacturers are referred to the vehicle certification procedures in 40 CFR part 86, subparts B and D (§§ 86.101 through 86.145 and §§ 86.301 through 86.348) for guidance on the measurement of the basic emissions of interest to this subpart.
(ii) Characterization of the vapor phase of combustion emissions, as follows:
(A) Determination of the identity and concentration of individual species of hydrocarbon compounds containing 12 or fewer carbon atoms. Such characterization shall begin within 30 minutes after emission collection is completed.
(B) Determination of the identity and concentration of individual species of aldehyde and ketone compounds containing eight or fewer carbon atoms. Characterization of these emissions captured in cartridges shall be performed within two weeks if the cartridge is stored at room temperature, and one month if the cartridge is stored at 0 °C or less. If the emissions are sampled using the impinger method, the sample must be stored in a capped sample vial at 0 °C or less and characterized within one week.
(C) Determination of the identity and concentration of individual species of alcohol and ether compounds containing six or fewer carbon atoms, for those fuels and additive/base fuel mixtures which contain alcohol and/or ether compounds containing from one to six carbon atoms in the uncombusted state. For fuel and additive formulations containing alcohols or ethers with more than six carbon atoms in the uncombusted state, alcohol and ether species with that higher number of carbon atoms or less must be identified and measured in the emissions. Such characterization shall begin within four hours after emission collection is completed.
(iii) Characterization of the semi-volatile and particulate phases of combustion emissions to identify and measure polycyclic aromatic compounds, as follows:
(A) Analysis for polycyclic aromatic compounds shall not be conducted at or soon after the start of a recommended engine lubricant change interval.
(B) Analysis for polycyclic aromatic hydrocarbons (PAHs) and nitrated polycyclic aromatic hydrocarbons (NPAHs), specified in paragraph (b)(2)(iii)(D) of this section, need not be done for any fuels and additives in the methane or propane fuel families, nor for fuels and additives in the atypical categories of any other fuel families, pursuant to the definitions of such families and categories in § 79.56.
(C) Analysis for poly-chlorinated dibenzodioxins and dibenzofurans (PCDD/PCDFs), specified in paragraph (b)(2)(iii)(E) of this section, is required only for fuels and additives which contain chlorine as an atypical element, pursuant to paragraph (b)(2)(iv) of this section, which requires all individual emission products containing atypical elements to be determined for atypical fuels and additives. However, manufacturers of baseline and nonbaseline fuels and fuel additives in all fuel families, except those in the methane and propane fuel families, are strongly encouraged to conduct these analyses on a voluntary basis.
(D) The analytical method used to measure species of PAHs and NPAHs should be capable of detecting at least 1 ppm (equivalent to 0.001 microgram (μg) of compound per milligram of organic extract) of these compounds in the extractable organic matter. The concentration of each individual PAH or NPAH compound identified shall be reported in units of microgram per
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(E) The analytical method used to measure species and classes of PCDD/PCDFs should be capable of detecting at least 1 part per trillion (ppt) (equivalent to 0.001 picogram (pg) of compound per milligram of organic extract) of these compounds in the extractable organic matter. The concentration of each individual PCDD/PCDF compound identified shall be reported in units of picograms (pg) per mile or picograms per brake-horsepower/hour (for chassis dynamometer and engine dynamometer test configurations, respectively). Each compound which is present at 0.5 pg/mile (0.3 pg/bhp-hr) or more must be identified, measured, and reported.
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(iv) With respect to all phases (vapor, semi-volatile, and particulate) of combustion emissions generated from those fuels and additive/base fuel mixtures classified in the atypical categories (pursuant to § 79.56), the identity and concentration of individual emission products containing such atypical elements shall also be determined.
(3) For evaporative fuels and evaporative fuel additives, characterization of the evaporative emissions shall include:
(i) Determination of the concentration of total hydrocarbons for the applicable vehicle type and class in 40 CFR part 86, subpart B (§§ 86.101 through 86.145).
(ii) Determination of the identity and concentration of individual species of hydrocarbon compounds containing 12 or fewer carbon atoms. Such characterization shall begin within 30 minutes after emission collection is completed.
(iii) In the case of those fuels and additive/base fuel mixtures which contain alcohol and/or ether compounds in the uncombusted state, determination of the identity and concentration of individual species of alcohol and ether compounds containing six or fewer carbon atoms. For fuel and additive formulations containing alcohols or ethers with more than six carbon atoms in the uncombusted state, alcohol and ether species with that higher number of carbon atoms or less must be identified and measured in the emissions. Such characterization shall begin within four hours after emission collection is completed.
(iv) In the case of those fuels and additive/base fuel mixtures which contain atypical elements, determination of the identity and concentration of individual emission products containing such atypical elements.
(4)
(ii) Laboratories performing the procedures specified in this section shall agree to permit quality control inspections by EPA, and for this purpose shall admit any EPA Enforcement Officer, upon proper presentation of credentials, to any facility where vehicles are conditioned or where emissions are generated, collected, stored, sampled, or characterized in meeting the requirements of this section. Such laboratory audits may include EPA distribution of “blind” samples for analysis by participating laboratories.
(5)
(i) “Advanced Emission Speciation Methodologies for the Auto/Oil Air Quality Improvement Program—I. Hydrocarbons and Ethers,” Auto Oil Air Quality Improvement Research Program, SP-920, 920320, SAE, February 1992.
(ii) “Advanced Speciation Methodologies for the Auto/Oil Air Quality Improvement Research Program—II. Aldehydes, Ketones, and Alcohols,” Auto Oil Air Quality Improvement Research Program, SP-920, 920321, SAE, February 1992.
(iii) ASTM D 5197-91, “Standard Test Method for Determination of Formaldehyde and Other Carbonyl Compounds in Air (Active Sampler Methodology).”
(iv) Johnson J. H., Bagley, S. T., Gratz, L. D., and Leddy, D. G., “A Review of Diesel Particulate Control Technology and Emissions Effects—1992 Horning Memorial Award Lecture,” SAE Technical Paper Series, SAE 940233, 1994.
(v) Keith
(vi) Perez, J.M., Jabs, R.E., Leddy, D.G., eds. “Chemical Methods for the Measurement of Unregulated Diesel Emissions (CRC-APRAC Project No. CAPI-1-64), Coordinating Research Council, CRC Report No. 551, August, 1987.
(vii) Schuetzle, D., “Analysis of Nitrated Polycyclic Aromatic Hydrocarbons in Diesel Particulates,” Analytical Chemistry, Volume 54, pp. 265-271, 1982.
(viii) Siegl, W.O.,
(ix) Tejada, S. B.
(x) Tejada, S. B.
(xi) “Test Method for Determination of C1-C4 Alcohols and MTBE in Gasoline by Gas Chromatography,” 40 CFR part 80, appendix F.
(c) [Reserved]
(d)
(2) The literature search shall address the potential adverse effects of whole combustion emissions, evaporative emissions, relevant emission fractions, and individual emission products of the subject fuel or fuel additive except as specified in the following paragraph. The individual emission products to be included are those
(3) In the case of the individual emission products of non-baseline or atypical fuels and additives (pursuant to § 79.56(e)(2)), the literature data need not be submitted for those emission products which are the same as the combustion emission products of the respective base fuel for the product's fuel family (pursuant to § 79.55). For this purpose, data on the base fuel emission products for the product's fuel family:
(i) May be found in the literature of previously-conducted, adequate emission speciation studies for the base fuel, or for a fuel or additive/fuel mixture capable of grouping with the base fuel (see, for example, the references in paragraph (b)(5) of this section).
(ii) May be compiled while gathering internal control data during emissions characterization studies on the manufacturer's non-baseline or atypical product; or
(iii) May be obtained from various manufacturers in the course of their testing different additive(s) belonging to the same fuel family, or in the testing of a base fuel serving as representative of the baseline group for the respective fuel family.
(e)
(f)
(g)
(1) Auto/Oil Air Quality Improvement Research Program, Technical Bulletin
(2) Keith
(3) “The Composition of Gasoline Engine Hydrocarbon Emissions—An Evaluation of Catalyst and Fuel Effects”—SAE 902074 and “Speciated Hydrocarbon Emissions from Aromatic, Olefin, and Paraffinic Model Fuels”—SAE 930373.
(a)
(b)
(c)
(2) Carcinogenic or mutagenic effects in animals from emissions exposures shall be determined pursuant to § 79.64
(d)
(2) EPA shall give appropriate weight when making this determination to the following factors:
(i) The age of the data;
(ii) The adequacy of documentation of procedures, findings, and conclusions;
(iii) The extent to which the testing conforms to generally accepted scientific principles and practices;
(iv) The type and number of test subjects;
(v) The number and adequacy of exposure concentrations,
(vi) The degree to which the tested emissions were generated by procedures and under conditions reasonably comparable to those set forth in § 79.57; and
(vii) The degree to which the test procedures conform to the testing guidelines set forth in §§ 79.60 through 79.68 and/or furnish information comparable to that provided by such testing.
(3) The test animals shall be rodents, preferably a strain of rat, and testing shall include all of the endpoints covered in §§ 79.62 through 79.68. All studies shall be properly executed, with appropriate documentation, and in accord with the individual health testing guidelines (§§ 79.60 through 79.68) of this part, e.g., 90-day, 6-hour per day exposure, minimum.
(4) In general, the data in a manufacturer's registration submittal shall be adequate if the duration of a test's exposure period is at least as long, in days and hours, as the inhalation exposure specified in the related health test guideline(s). Data from tests with
(5) Data in support of a manufacturer's registration submittal shall directly address the effects of inhalation exposure to the whole evaporative and exhaust emissions of the respective fuel or additive or to the whole evaporative and exhaust emissions of other fuels or additives which satisfy the criteria in § 79.56 for classification into the same group as the subject fuel or fuel additive. Data obtained in the testing of a raw liquid fuel or additive/base fuel mixture or a raw, aerosolized fuel or additive/base fuel mixture shall not be adequate to support a manufacturer's registration submittal. Data from testing of evaporative emissions cannot substitute for test data on combustion emissions. Data from testing of combustion emissions cannot substitute for test data on evaporative emissions.
(a)
(2) In addition to the criteria specific to particular tests as summarized and detailed in the testing guidelines (§§ 79.62 through 79.68), EPA may consider a number of factors (including, but not limited to):
(i) The number of positive and negative outcomes related to each endpoint;
(ii) The identification of concentration-effect relationships;
(iii) The statistical sensitivity and significance of such studies;
(iv) The severity of the observed effects (e.g., whether the effects would be likely to lead to incapacitating or irreversible conditions);
(v) The type and number of species included in the reported tests;
(vi) The consistency and clarity of apparent mechanisms, target organs, and outcomes;
(vii) The presence or absence of effective health test control data for base-fuel-only versus additive/base fuel mixture comparisons;
(viii) The nature and amount of known toxic agents in the emissions stream; and
(ix) The observation of lesions which specifically implicate inhalation as an important exposure route.
(3)
(i) Types and emission rates of speciated emission components;
(ii) Types and emission rates of combinations of compounds or elements of concern;
(iii) Historical and/or projected production volumes and market distributions; and
(iv) Estimated population and/or environmental exposures obtained through extrapolation, modeling, or literature search findings on ambient, occupational, or epidemiological exposures.
(b)
(2) EPA will issue a notice in the
(3) EPA will include in the public record a copy of any timely comments concerning the proposed Tier 3 testing requirements received from the affected manufacturer or group or from the public, and the responses of EPA to such comments. After reviewing all such comments received, EPA will adopt final Tier 3 requirements by sending a certified letter describing such final requirements to the manufacturer or group. EPA will also issue a notice in the
(4) Prior to beginning any required Tier 3 testing, the manufacturer shall submit detailed test protocols to EPA for approval. Once EPA has determined the Tier 3 testing requirements and approves the test protocols, any modification to the requirements shall be governed by § 79.51(f).
(c)
(2) The testing for carcinogenicity required under this paragraph may, at EPA's discretion, be conducted in accordance with 40 CFR 798.3300 or 798.3320, or their equivalents (see suggested references following each health effects testing guideline). The testing for mutagenicity required under this paragraph may likewise be conducted in accordance with 40 CFR 798.5195, 798.5500, 798.5955, 798.7100, and/or other suitable equivalent testing (see suggested references following each health effects testing guideline). EPA may supplement or modify guidelines as required to ensure that the prescribed testing addresses the identified areas of concern.
(d)
(2) The testing for reproductive and teratological effects required under this paragraph may, at EPA's discretion, be conducted in accordance with 40 CFR 798.4700 and/or by performance of a reproductive assay by continuous breeding. These guidelines may be modified or supplemented by EPA as required to ensure that the prescribed testing addresses the identified areas of concern.
(e)
(2) The testing for neurotoxicity required under this paragraph may, at EPA's discretion, be conducted in accordance with 40 CFR 798.3260 and 40 CFR part 798 subpart G. These guidelines may be modified or supplemented by EPA as required to ensure that the prescribed testing addresses the identified areas of concern.
(f)
(2) A potential need for Tier 3 testing with respect to other organ systems or endpoints not addressed by specific Tier 2 tests, e.g., hepatic, renal, or endocrine toxicity, may be demonstrated by findings in the Tier 2 Subchronic Toxicity Study (pursuant to § 79.62) or by findings in the Tier 1 literature search of adverse functional, physiologic, metabolic, or histopathologic effects of fuel or additive emissions to such other organ systems or any other information available to EPA. In addition, findings in the Tier 1 emission characterization of significant levels of a known toxicant to such other organ systems and endpoints may also indicate a need for relevant health effects testing. The testing required under this paragraph may include tests conducted in accordance with 40 CFR 798.3260 or 798.3320. These guidelines may be modified or supplemented by EPA as necessary to ensure that the prescribed testing addresses the identified areas of concern.
(3) The testing for general/pulmonary toxicity required under this paragraph may, at EPA's discretion, be conducted in accordance with 40 CFR 798.2450 or 798.3260. These guidelines may be modified or supplemented by EPA as necessary to ensure that the prescribed testing addresses the identified areas of concern. Pulmonary function measurements, host defense assays, immunotoxicity tests, cell morphology/morphometry, and/or enzyme assays of lung lavage cells and fluids may be specifically required.
(g)
(i) Estimates of exposures to the emission products of a fuel or fuel additive or group of products;
(ii) The expected atmospheric transformation products of such emissions; and
(iii) The environmental partitioning of such emissions to the air, soil, water, and biota.
(2) Additional emission characterization may be required if uncertainty over the identity of chemical species or rate of their emission interferes with reasonable judgments as to the presence and/or concentration of potentially toxic substances in the emissions of a fuel or fuel additive. The required tests may include characterization of additional classes of emissions, the characterization of emissions generated by additional vehicles/engines of various technology mixes (e.g., catalyzed versus non-catalyzed emissions), and/or other more precise analytic procedures for identification or quantification of emissions compounds. Additional emissions testing may also be required to evaluate concerns which may arise regarding the potential effects of a fuel or fuel additive on the performance of emission control equipment.
(3) A manufacturer or group may be required to conduct biological and/or
(4) With regard to group submittals, Tier 3 studies on a fuel or additive product(s) other than the originally specified group representative may be required if specific differences in the product's composition indicate that its emissions may have different toxicologic properties from those of the original group representative.
(5) Additional emission characterization and/or toxicologic tests may be required to evaluate the impact of different vehicle, engine, or emission control technologies on the observed composition or health or welfare effects of the emissions of a fuel or additive.
(6) Toxicological tests on individual emission products may be required.
(7) Upon review of information submitted for an aerosol product under § 79.58(e), emissions characterization, exposure, and/or toxicologic testing at a Tier 3 level may be required.
(8) A manufacturer which qualifies for and has elected to use the special provisions for the products of small businesses (pursuant to § 79.58(d)) may be required to conduct emission characterization, exposure, and/or toxicologic studies at the Tier 3 level for such products, as specified in § 79.58(d)(4).
(9) The examples of potential Tier 3 tests described in this section do not in any way limit EPA's broad discretion and authority under Tier 3.
(a)
(2) Base fuels shall contain a limited complement of the additives which are essential for the fuel's production or distribution and/or for the successful operation of the test vehicle/engine throughout the mileage accumulation and emission generation periods. Such additives shall be used at the minimum effective concentration-in-use for the base fuel in question.
(3) Unless otherwise restricted, the presence of trace contaminants does not preclude the use of a fuel or fuel additive as a component of a base fuel formulation.
(4) When an additive is the test subject, any additive normally contained in the base fuel which serves the same function as the subject additive shall be removed from the base fuel formulation. For example, if a corrosion inhibitor were the subject of testing and if this additive were to be tested in a base fuel which normally contained a corrosion inhibitor, this test additive would replace the corrosion inhibitor normally included as a component of the base fuel.
(5) Additive components of the methanol, ethanol, methane, and propane base fuels in addition to any such additives included below shall be limited to those recommended by the manufacturers of the vehicles and/or engines used in testing such fuels. For this purpose, EPA will review requests from manufacturers (or their agents) to modify the additive specifications for the alternative fuels and, if necessary, EPA shall change these specifications based on consistency of those changes with the associated vehicle manufacturer's recommendations for the operation of the vehicle. EPA shall publish notice of any such changes to a base fuel and/or its base additive package specifications in the
(b)
(2) The additive components of the gasoline base fuel shall contain compounds comprised of no elements other than carbon, hydrogen, oxygen, nitrogen, and sulfur. Additives shall be used at the minimum concentration needed to perform effectively in the gasoline base fuel. In no case shall their concentration in the base fuel exceed the maximum concentration recommended by the additive manufacturer. The increment of sulfur contributed to the formulation by any additive shall not exceed 15 parts per million sulfur by weight and shall not cause the gasoline base fuel to exceed the sulfur specifications in table F94-1 of this section.
(c)
(2) The additive components of the diesel base fuel shall contain compounds comprised of no elements other than carbon, hydrogen, oxygen, nitrogen, and sulfur. Additives shall be used at the minimum concentration needed to perform effectively in the diesel base fuel. In no case shall their concentration in the base fuel exceed the maximum concentration recommended by the additive manufacturer. The increment of sulfur contributed to the base fuel by additives shall not cause the diesel base fuel to exceed the sulfur specifications in table F94-2 of this section.
(d)
(2) The M100 base fuel shall consist of 100 percent by volume chemical grade methanol.
(3) The M85 base fuel is to contain 85 percent by volume chemical grade methanol, blended with 15 percent by volume gasoline base fuel meeting the gasoline base fuel specifications outlined in paragraph (b)(1) of this section. Manufacturers shall ensure the methanol compatibility of lubricating oils as well as fuel additives used in the gasoline portion of the M85 base fuel.
(4) The methanol base fuels shall meet the specifications listed in table F94-3.
(e)
(2) The ethanol base fuel shall contain 85 percent by volume chemical grade ethanol, blended with 15 percent by volume gasoline base fuel that meets the specifications listed in paragraph (b)(1) of this section. Additives used in the gasoline component of E85 shall be ethanol-compatible.
(3) The ethanol base fuel shall meet the specifications listed in table F94-4.
(f)
(2) The methane base fuel shall contain no elements other than carbon, hydrogen, oxygen, nitrogen, and sulfur. The fuel shall contain an odorant additive for leak detection purposes. The added odorant shall be used at a level such that, at ambient conditions, the fuel must have a distinctive odor potent enough for its presence to be detected down to a concentration in air of not over
(3) The methane base fuel shall meet the specifications listed in table F94-5.
(g)
(2) The propane base fuel may contain no elements other than carbon, hydrogen, oxygen, nitrogen, and sulfur. The fuel shall contain an odorant additive for leak detection purposes. The added odorant shall be used at a level such that at ambient conditions the fuel must have a distinctive odor potent enough for its presence to be detected down to a concentration in air of not over
(3) The propane base fuel shall meet the specifications listed in table F94-6.
(a) Manufacturers of fuels and fuel additives are allowed to satisfy the testing requirements in §§ 79.52, 79.53, and 79.54 and the associated reporting requirements in § 79.59 on an individual or group basis, provided that such products meet the criteria in this section for enrollment in the same fuel/additive group. However, each manufacturer of a fuel or fuel additive must individually comply with the notification requirements of § 79.59(b). Further, if a manufacturer elects to comply by participation in a group, each manufacturer continues to be individually subject to the information requirements of this subpart.
(1) The use of the grouping provision to comply with Tier 1 and Tier 2 testing requirements is voluntary. No manufacturer is prohibited from testing and submitting its own data for its own product registration, despite its qualification for membership in a particular group.
(2) The only groups permitted are those established in this section.
(b) Each manufacturer who chooses to enroll a fuel or fuel additive in a
(1) The health effects information submitted by a group shall be considered applicable to all fuels and fuel additives in the group. A fuel or fuel additive manufacturer who has chosen to participate in a group may subsequently choose to perform testing of such fuel or fuel additive on an individual basis; however, until such independent registration information has been received and reviewed by EPA, the information initially submitted by the group on behalf of the manufacturer's fuel or fuel additive shall be considered applicable and valid for that fuel or fuel additive. It could therefore be used to support requirements for further testing under the provisions of Tier 3 or to support regulatory decisions affecting that fuel or fuel additive.
(2) Manufacturers are responsible for determining the appropriate groups for their products according to the criteria in this section and for enrolling their products into those groups under industry-sponsored or other independent brokering arrangements.
(3) Manufacturers who enroll a fuel or fuel additive into a group shall share the applicable costs according to appropriate arrangements established by the group. The organization and administration of group functions and the development of cost-sharing arrangements are the responsibility of the participating manufacturers. If manufacturers are unable to agree on fair and equitable cost sharing arrangements and if such dispute is referred by one or more manufacturers to EPA for resolution, then the provisions in § 79.56(c) (1) and (2) shall apply.
(c) In complying with the registration requirements for a given fuel or fuel additive, notwithstanding the enrollment of such fuel or additive in a group, a manufacturer may make use of available information for any product which conforms to the same grouping criteria as the given product. If, for this purpose, a manufacturer wishes to rely upon the information previously submitted by another manufacturer (or group of manufacturers) for registration of a similar product (or group of products), then the previous submitter is entitled to reimbursement by the manufacturer for an appropriate portion of the applicable costs incurred to obtain and report such information. Such entitlement shall remain in effect for a period of fifteen years following the date on which the original information was submitted. Pursuant to § 79.59(b)(4)(ii), the manufacturer who relies on previously-submitted registration data shall certify to EPA that the original submitter has been notified and that appropriate reimbursement arrangements have been made.
(1) When private efforts have failed to resolve a dispute about a fair amount or method of cost-sharing or reimbursement for testing costs incurred under this subpart, then any party involved in that dispute may initiate a hearing by filing two signed copies of a request for a hearing with a regional office of the American Arbitration Association and mailing a copy of the request to EPA. A copy must also be sent to each person from whom the filing party seeks reimbursement or who seeks reimbursement from that party. The information and fees to be included in the request for hearing are specified in 40 CFR 791.20(b) and (c).
(2) Additional procedures and requirements governing the hearing process are those specified in 40 CFR 791.22 through 791.50, 791.60, 791.85, and 791.105, excluding 40 CFR 791.39(a)(3) and 791.48(d).
(d)
(2) Fuels shall be classified pursuant to § 79.56(e) into categories and groups of similar fuels and fuel additives according to the components and characteristics of such fuels in their uncombusted state. The classification
(3) Fuel additives shall be classified pursuant to § 79.56(e) into categories and groups of similar fuels and fuel additives according to the components and characteristics of the respective uncombusted additive/base fuel mixture pursuant to § 79.51(h)(1).
(4) In determining the category and group to which a fuel or fuel additive belongs, impurities present in trace amounts shall be ignored unless otherwise noted. Impurities are those substances which are present through contamination or which remain in the fuel or additive naturally after processing is completed.
(5)
(ii) This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Society for Testing and Materials (ASTM), 1916 Race Street, Philadelphia, PA 19103. Copies may be inspected at U.S. EPA, OAR, 401 M Street SW., Washington, DC, 20460 or at the Office of the Federal Register, 800 North Capitol Street NW., suite 700, Washington, DC.
(e)
(1)
(i) The Gasoline Family includes fuels composed of more than 50 percent gasoline by volume and their associated fuel additives. The base fuel for this family is specified in § 79.55(b).
(ii) The Diesel Family includes fuels composed of more than 50 percent diesel fuel by volume and their associated fuel additives. The Diesel fuel family includes both Diesel
(iii) The Methanol Family includes fuels composed of at least 50 percent methanol by volume and their associated fuel additives. The M100 and M85 base fuels are specified in § 79.55(d).
(iv) The Ethanol Family includes fuels composed of at least 50 percent ethanol by volume and their associated fuel additives. The base fuel for this family is E85 as specified in § 79.55(e).
(v) The Methane Family includes compressed natural gas (CNG) and liquefied natural gas (LNG) fuels containing at least 50 mole percent methane and their associated fuel additives. The base fuel for the family is a CNG formulation specified in § 79.55(f).
(vi) The Propane Family includes propane fuels containing at least 50 percent propane by volume and their associated fuel additives. The base fuel for this family is a liquefied petroleum gas (LPG) as specified in § 79.55(g).
(vii) A manufacturer seeking registration for formulation(s) which do not fit the criteria for inclusion in any of the fuel families described in this section shall contact EPA at the address in § 79.59(a)(1) for further guidance in classifying and testing such formulation(s).
(2)
(i) Baseline categories consist of fuels and fuel additives which contain
(ii) Non-Baseline Categories consist of fuels and fuel additives which contain no elements other than those permitted in the base fuel for the respective fuel family, but which exceed one or more of the limitations for certain specified components or characteristics applicable to baseline formulations in that fuel family.
(iii) Atypical Categories consist of fuels and fuel additives which contain elements or classes of compounds other than those permitted in the base fuel for the respective fuel family or which otherwise do not meet the criteria for either baseline or non-baseline formulations in that fuel family. A fuel or fuel additive product having both non-baseline and atypical characteristics pursuant to § 79.56(e)(3), shall be considered to be an atypical product.
(3) This section defines the specific categories applicable to each fuel family. When applied to fuel additives, the criteria in these descriptions refer to the associated additive/base fuel mixture, pursuant to § 79.51(h)(1).
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(B) The Non-Baseline Gasoline category is comprised of gasoline fuels and associated additives which conform to the specifications in paragraph (e)(3)(i)(A) of this section for the Baseline Gasoline category except that they contain 1.5 percent or more oxygen by weight and/or may be derived from sources other than those listed in paragraph (e)(3)(i)(A)(
(C) The Atypical Gasoline category is comprised of gasoline fuels and associated additives which contain one or more elements other than carbon, hydrogen, oxygen, nitrogen, and sulfur.
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(B) The Non-Baseline Diesel category is comprised of diesel fuels and associated additives which conform to the specifications in paragraph (e)(3)(ii)(A) of this section for the Baseline Diesel category except that they contain 1.0 percent or more oxygen by weight and/or may be derived from sources other than those listed in paragraph (e)(3)(ii)(A)(
(C) The Atypical Diesel category is comprised of diesel fuels and associated additives which contain one or more elements other than carbon, hydrogen, oxygen, nitrogen, and sulfur.
(iii)
(B) The Non-Baseline Methanol category is comprised of fuel blends which contain at least 50 percent methanol by volume, more than 4.0 percent by volume of a substance(s) other than methanol and gasoline, and meet the baseline limitations on elemental composition in paragraph (e)(3)(iii)(A) of this section.
(C) The Atypical Methanol category consists of methanol fuels and associated additives which do not meet the criteria for either the Baseline or the Non-Baseline Methanol category.
(iv)
(B) The Non-Baseline Ethanol category is comprised of fuel blends which contain at least 50 percent ethanol by volume, more than five (5) percent by volume of a substance(s) other than ethanol and gasoline, and meet the baseline limitations on elemental composition in paragraph (e)(3)(iv)(A) of this section.
(C) The Atypical Ethanol category consists of ethanol fuels and associated additives which do not meet the criteria for either the Baseline or the Non-Baseline Ethanol categories.
(v)
(B) The Non-Baseline Methane category consists of methane fuels and associated additives which conform to the specifications in paragraph (e)(3)(v)(A) of this section for the Baseline Methane category except that they exceed 20 mole percent non-methane hydrocarbons.
(C) The Atypical Methane category consists of methane fuels and associated additives which contain one or more elements other than carbon, hydrogen, oxygen, nitrogen, and/or sulfur, or exceed 16 ppm by volume of sulfur.
(vi)
(B) The Non-Baseline Propane category consists of propane fuels and associated additives which conform to the specifications in paragraph (e)(3)(vi)(A) of this section for the Baseline Propane category, except that they exceed the 20 percent by volume limit for butane and higher hydrocarbons.
(C) The Atypical Propane category consists of propane fuels and associated additives which contain elements other than carbon, hydrogen, oxygen, nitrogen, and/or sulfur, or exceed 123 ppm by weight of sulfur.
(4)
(i)
(B) The Baseline Diesel category comprises a single group. The diesel base fuel specified in § 79.55(c) shall serve as the representative of this group.
(C) The Baseline Methanol category includes two groups: M100 and M85. The M100 group consists of methanol-gasoline formulations containing at least 96 percent methanol by volume. These formulations must contain odorants and bitterants (limited in elemental composition to carbon, hydrogen, oxygen, nitrogen, sulfur, and chlorine) for prevention of purposeful or inadvertent consumption. The M100 base fuel specified in § 79.55(d) shall serve as the representative for this group. The M85 group consists of methanol-gasoline formulations containing at least 50 percent by volume but less than 96 percent by volume methanol. The M85 base fuel specified in § 79.55(d) shall serve as the representative of this group.
(D) The Baseline Ethanol category comprises a single group. The E85 base fuel specified in § 79.55(e) shall serve as the representative of this group.
(E) The Baseline Methane category comprises a single group. The CNG base fuel specified in § 79.55(f) shall serve as the representative of this group.
(F) The Baseline Propane category comprises a single group. The LPG base fuel specified in § 79.55(g) shall serve as the representative of this group.
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(B) General rules for sorting these atypical fuels and additives into separate groups are as follows:
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(C) Specific rules for sorting each family's atypical fuels and additives into separate groups, and for choosing each such group's representative for testing, are as follows:
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This section specifies the equipment and procedures that must be used in generating the emissions which are to be subjected to the characterization procedures and/or the biological tests specified in §§ 79.52(b) and 79.53 of these regulations. When applicable, they may also be required in conjunction with testing under §§ 79.54 and 79.58(c). Additional requirements concerning emission generation, delivery, dilution, quality control, and safety practices are outlined in § 79.61.
(a)
(2) The vehicle/engine type, vehicle/engine class, and vehicle/engine subclass designated to generate emissions for a given fuel or additive shall be the same type, class, and subclass which, over the previous three years, has consumed the most gallons of fuel in the fuel family applicable to the given fuel or additive. No distinction shall be made between light-duty vehicles and light-duty trucks for purposes of this classification.
(3) Within this vehicle/engine type, class, and subclass, the specific vehicles and engines acceptable for emission generation are those that represent the most common fuel metering system and the most common of the most important emission control system devices or characteristics with respect to emission reduction performance for the model year in which testing begins. These vehicles will be determined through a survey of the previous model year's vehicle/engine sales within the given subclass. These characteristics shall include, but need not be limited to, aftertreatment device(s), fuel aspiration, air injection, exhaust gas recirculation, and feedback type.
(4) Within the applicable subclass, the five highest selling vehicle/engine models that contain the most common such equipment and characteristics shall be determined. Any of these five models of the current model year (at the time testing begins) may be selected for emission generation.
(i) If one or more of the five models is not available for the current model year, the choice of model for emission generation shall be limited to those remaining among the five.
(ii) If fewer than five models of the given vehicle/engine type are available for the current model year, all such models shall be eligible.
(5) When the fuel or fuel additive undergoing testing is not commonly used or intended to be used in the vehicle/engine types prescribed by this selection procedure, or when rebuilding or alteration is required to obtain a suitable vehicle/engine for emission generation, the manufacturer may submit a request to EPA for a modification in test procedure requirements. Any such request must include objective test results which support the claim that a more appropriate vehicle/engine type is needed as well as a suggested substitute vehicle/engine type. The vehicle/engine selection in this case shall be approved by EPA prior to the start of testing.
(6) Once a particular model has been chosen on which to test a fuel or additive product, all mileage accumulation and generation of emissions for characterization and biological testing of such product shall be conducted on that same model.
(i) If the initial test vehicle/engine fails or must be replaced for any reason, emission generation shall continue with a second vehicle/engine which is identical to, or resembles to the greatest extent possible, the initial test vehicle/engine. If more than one replacement vehicle/engine is necessary, all such vehicles/engines shall be identical, or resemble to the greatest extent possible, the initial test vehicle/engine.
(ii) Manufacturers are encouraged to obtain, at the start of a test program, more than one emission generation vehicle/engine of the identical model, to ensure the availability of back-up emission generator(s). All backup vehicles/engines must be conditioned and must have their emissions fully characterized, as done for the initial test vehicle/engine, prior to their use as emission generators for biological testing. Alternating between such vehicles/engines regularly during the course of testing is permissible and advisable, particularly to allow regular maintenance on such vehicles/engines during prolonged health effects testing.
(b)
(2) Except as provided in § 79.51(h)(2)(iii), the fuel or additive/base fuel mixture being tested shall be used at all times during operation of the test vehicle or engine. No other fuels or additives shall be used in the test vehicle or engine once mileage accumulation has begun until emission generation for emission characterization and biological testing purposes is completed.
(i) A vehicle or engine may be used to generate emissions for the testing of more than one fuel or additive, provided that all such fuels and additives belong to the same fuel family pursuant to § 79.56(e)(i), and that, once a vehicle or engine has been used to generate emissions for an atypical fuel or additive (pursuant to § 79.56(e)(2)(iii)), it shall not be used in the testing of any other fuel or additive. Paragraphs (a) (2) and (3) of this section shall apply only to the first fuel or additive tested.
(ii) Prior to being used to generate emissions for testing an additional fuel or additive, a vehicle or engine which has previously been used for testing a different fuel or additive shall undergo an effective intermediate preconditioning cycle to remove the previously used fuel and its emissions from the vehicle's fuel and exhaust systems and from the combustion emission and evaporative emission control systems, if any.
(iii) Such preconditioning shall include, at a minimum, the following steps:
(A) The canister (if any) shall be removed from the vehicle and purged with 300 °F nitrogen at 20 liters per minute until the incremental weight loss of the canister is less than 1 gram in 30 minutes. This typically takes 3-4 hours and removes 100 to 120 grams of adsorbed gasoline vapors.
(B) The fuel tank shall be drained and filled to capacity with the new test fuel or additive/fuel mixture.
(C) The vehicle or engine shall be operated until at least 95% of the fuel tank capacity is consumed.
(D) The purged canister shall be returned to the vehicle.
(E) The fuel tank shall be drained and filled to 40% capacity with test fuel.
(F) Two-hour fuel tank heat builds from 72-120 °F shall be performed repeatedly as necessary to achieve canister breakthrough. The fuel tank must be drained and filled prior to each heat build.
(3) Scheduled and unscheduled vehicle/engine maintenance. (i) During emission generation, vehicles and engines must be maintained in good condition by following the recommendations of the original equipment manufacturer (OEM) for scheduled service and parts replacement, with repairs performed only as necessary. Modifications, adjustments, and maintenance procedures contrary to procedures found in 40 CFR part 86 for the maintenance of test vehicles/engines or performed solely for the purpose of emissions improvement are not allowed.
(ii) If unscheduled maintenance becomes necessary, the vehicle or engine must be repaired to OEM specifications, using OEM or OEM-approved parts. In addition, the tester is required to measure the basic emissions pursuant to § 79.52(b)(2)(i) after the unscheduled maintenance and before resuming testing to ensure that the post-maintenance emissions shall be within 20 percent of pre-maintenance emissions levels. If the basic emissions cannot be brought within 20 percent of their previous levels, then the manufacturer shall restart the emissions characterization and health testing of its products combustion emissions using a new vehicle/engine.
(c)
(2) Vehicles to be used in the evaluation of baseline and non-baseline fuels and fuel additives shall accumulate 4,000 miles prior to emission testing. Engines to be used in the evaluation of baseline and non-baseline fuels and fuel additives shall accumulate 125 hours of operation on an engine dynamometer prior to emission testing.
(3) When the test formulation is classified as an atypical fuel or fuel additive formulation (pursuant to definitions in § 79.56(e)(4)(iii)), the following additional mileage accumulation requirements apply:
(i) The test vehicle/engine must be operated for a minimum of 4,000 vehicle miles or 125 hours of engine operation.
(ii) Thereafter, at intervals determined by the tester, all emission fractions (
(iii) Mileage accumulation shall continue until either 50 percent or more of the mass of each atypical element (or other atypical constituent) entering the engine can be measured in the exhaust emissions (all fractions combined), or the vehicle/engine has accumulated mileage (or hours) equivalent to 40 percent of the average useful life of the applicable vehicle/engine class (pursuant to regulations in 40 CFR part 86). For example, the maximum mileage required for light-duty vehicles is 40 percent of 100,000 miles (
(iv) When either condition in paragraph (c)(3)(iii) of this section has been reached, additional emission characterization and biological testing of the emissions may begin.
(d)
(2) Except as provided in paragraph (d)(3) of this section for certain specialized additives, the following provisions apply when the test vehicle/engine, as certified by EPA, comes equipped with an emissions aftertreatment device.
(i) For mileage accumulation:
(A) When the test formulation does not contain any atypical elements (pursuant to definitions in § 79.56(e)(4)(iii)), an intact aftertreatment device must be used during mileage accumulation.
(B) When the test formulation does contain atypical elements, then the manufacturer may choose to accumulate the required mileage using a vehicle/engine equipped with either an intact aftertreatment device or with a non-functional aftertreatment device (e.g., a blank catalyst without its catalytic wash coat). In either case, sampling and analysis of emissions for measurement of the mass of the atypical element(s) (as described in § 79.57(c)(3)) must be done on emissions generated with a non-functional (blank) aftertreatment device.
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(ii) For Tier 1 (§ 79.52), the total set of requirements for the characterization of combustion emissions (§ 79.52(b)) must be completed two times, once using emissions generated with the aftertreatment device intact and a second time with the aftertreatment device rendered nonfunctional or replaced with a non-functional aftertreatment device as described in paragraph (d)(2)(i)(B) of this section.
(iii) For Tier 2 (§ 79.53), the standard requirements for biological testing of combustion emissions shall be conducted using emissions generated with
(iv) For alternative Tier 2 requirements (§ 79.58(c)) or Tier 3 requirements (§ 79.54) which may be prescribed by EPA, the use of functional or nonfunctional aftertreatment devices shall be specified by EPA as part of the test guidelines.
(v) In the case where an intact aftertreatment device is not in place, all other manufacturer-specified combustion characteristics (e.g., back pressure, residence time, and mixing characteristics) of the altered vehicle/engine shall be retained to the greatest extent possible.
(3) Notwithstanding paragraphs (d)(1) and (d)(2) of this section, when the subject of testing is a fuel additive specifically intended to enhance the effectiveness of exhaust aftertreatment devices, the related aftertreatment device may be used on the emission generation vehicle/engine during all mileage accumulation and testing.
(e)
(A) For light-duty engines operated on an engine dynamometer, the tester shall determine the speed-torque equivalencies (“trace”) for its test engine from valid FTP testing performed on a chassis dynamometer, using a test vehicle with an engine identical to that being tested. The test engine must then be operated under these speed and torque specifications to simulate the FTP cycle.
(B) Special procedures not included in the FTP may be necessary in order to characterize emissions from fuels and fuel additives containing atypical elements or to collect some types of emissions (e.g., particulate emissions from light-duty vehicles/engines, semi-volatile emissions from both light-duty and heavy-duty vehicles/engines). Such alterations to the FTP are acceptable.
(C) For Tier 2 testing, the engines shall operate on repeated bags 2 and 3 of the UDDS or back to back repeats of the heavy-duty transient cycle of the EDS.
(ii) Pursuant to § 79.52(b)(1)(i) and § 79.57(d)(2)(ii), emission generation and characterization must be repeated three times when the selected vehicle/engine is normally operated without an emissions aftertreatment device and six times when the selected vehicle/engine is normally operated with an emissions aftertreatment device. In the latter case, the emission generation and characterization process shall be repeated three times with the intact aftertreatment device in place and three times with a non-functioning (blank) aftertreatment device in place.
(iii) From both light-duty and heavy-duty vehicles/engines, samples of vapor phase, semi-volatile phase, and particulate phase emissions shall be collected, except that semi-volatile phase, and particulate emissions need not be sampled for fuels and additives in the methane and propane families (pursuant to § 79.56(e)(1)(v) and (vi)). The number and type of samples to be collected and separately analyzed during one emission generation/characterization process are as follows:
(A) In the case of combustion emissions generated from light-duty vehicles/engines, the samples consist of three bags of vapor emissions (one from each segment of the light-duty exhaust emission cycle) plus one sample of particulate-phase emissions and one sample of semi-volatile-phase emissions (collected over all segments of the exhaust emission cycle). If the mass of particulate emissions or semi-volatile emissions obtained during one driving cycle is not sufficient for characterization, up to three driving cycles may be
(B) In the case of combustion emissions generated from heavy-duty engines, the samples consist of one sample of each emission phase (vapor, particulate, and semi-volatile) collected over the entire cold-start cycle and a second sample of each such phase collected over the entire hot-start cycle (see 40 CFR 86.334 through 86.342).
(iv)
(B) Particulate phase emissions shall be collected on a particulate filter (or more than one, if required) using methods described in 40 CFR 86.1301 through 86.1344. These methods, ordinarily applied only to heavy-duty emissions, are to be adapted and used for collection of particulates from light-duty vehicles/engines, as well. The particulate matter may be stored on the filter in a sealed container, or the soluble organic fraction may be extracted and stored in a separate sealed container. Both the particulate and the extract shall be shielded from ultraviolet light and stored at −20 °C or less. Particulate emissions shall be tested no later than six months from the date they were generated.
(C) Semi-volatile emissions shall be collected immediately downstream from the particulate collection filters using porous polymer resin beds, or their equivalent, designed for their capture. The soluble organic fraction of semi-volatile emissions shall be extracted immediately and tested within six months of being generated. The extract shall be stored in a sealed container which is shielded from ultraviolet light and stored at −20 °C or less.
(D) Particulate and semi-volatile phase emission collection, handling and extraction methods shall not alter the composition of the collected material, to the extent possible.
(v) Additional requirements for combustion emission sampling, storage, and characterization are specified in § 79.52(b).
(2)
(ii) Light-duty test vehicles/engines shall be repeatedly operated over the Urban Dynamometer Driving Schedule (UDDS) (or equivalent engine dynamometer trace, per paragraph (e)(1)(i)(A) of this section) and heavy-duty test engines shall be repeatedly operated over the Engine Dynamometer Schedule (EDS) (see 40 CFR part 86, appendix I).
(A) The tolerances of the driving cycle shall be two times those of the Federal Test Procedure and must be met 95 percent of the time.
(B) The UDDS or EDS shall be repeated as many times as required for the biological test session.
(C) Light-duty dynamometers shall be calibrated prior to the start of a biological test (40 CFR 86.118-78), verified weekly (40 CFR 86.118-78), and recalibrated as required. Heavy-duty dynamometers shall be calibrated and checked prior to the start of a biological test (40 CFR 86.1318-84), recalibrated every two weeks (40 CFR 86.1318-84(a)) and checked as stated in 40 CFR 86.1318-84(b) and (c).
(D) The fuel reservoir for the test vehicle/engine shall be large enough to operate the test vehicle/engine throughout the daily biological exposure period, avoiding the need for refueling during testing.
(iii) An apparatus to integrate the large concentration swings typical of transient-cycle exhaust is to be used between the source of emissions and the exposure chamber containing the animal test cages(s). The purpose of such apparatus is to decrease the variability of the biological exposure atmosphere and achieve the necessary concentration of CO or NO
(A) A large mixing chamber is suggested for this purpose. The mixing chamber would be charged from the
(B) A potential alternative apparatus is a mini-diluter (see, for example, AIGER/CRADA, February, 1994 in § 79.57(g)).
(C) [Reserved]
(iv)
(B) These procedures include requirements that the mean exposure concentration in the inhalation test chamber on 90 percent or more of the exposure days shall be controlled as follows:
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(C) After the initial exhaust dilution to preserve the character of the exhaust, the exhaust stream can be further diluted in the mixing chamber (and/or after leaving the chamber) to achieve the desired biological exposure concentrations.
(v)
(B) [Reserved]
(vi)
(B) These procedures include requirements that the mean exposure concentration in the inhalation test chamber on 90 percent or more of the exposure days shall be controlled as follows:
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(C) The testing facility shall allow an audit of its premises, the qualifications, e.g., curriculum vitae, of its staff assigned to testing, and the specimens and records of the testing for registration purposes (as specified in § 79.60).
(vii) To allow for customary laboratory scheduling and unforeseen problems affecting the combustion emission generation or dilution equipment, biological exposures may be interrupted on limited occasions, as specified in § 79.61(d)(5). Interruptions exceeding these limitations shall cause the affected test(s) to be void. Testers shall be aware of concerns for backup vehicles/engines cited in paragraph (a)(7)(ii) of this section.
(3)
(A) Particulate emissions shall be collected on particulate filters and extracted from the collection equipment for use in biological tests. The number of repetitions of the applicable driving schedule required to collect sufficient quantities of the particulate emissions will vary, depending on the characteristics of the engine, the test fuel, and the requirements of the biological test protocol. The particulate sample may be collected on one or more filters, as necessary.
(B) Semi-volatile emissions shall be collected immediately downstream from the particulate collection filters using porous polymer resin beds, or their equivalent, designed for their capture. Semi-volatile phase emissions shall be collected on one apparatus. The time spent collecting sufficient quantities of the test substances in emissions samples will vary, depending on the emission characteristics of the engine and fuel or additive/base fuel mixture and on the requirements of the biological test protocol.
(ii) The extraction method shall be determined by the specifications of the biological test for which the emissions are used.
(iii) Particulate and semi-volatile emission storage requirements are as specified in § 79.57(e)(1)(iv).
(iv) Particulate and semi-volatile phase emission collection, handling and extraction methods shall not alter the composition of the collected material, to the extent possible.
(v) Particulate emissions shall not be combined with semi-volatile phase emissions.
(f)
(2)
(i) The evaporation chamber shall be made from materials compatible with the fuels and additives being tested and shall be equipped with a drain.
(ii) The chamber shall be filled to 40
(iii) The concentration of the evaporated fuel or additive/base fuel mixture in the vapor space of the evaporation chamber during the time emissions are being withdrawn for testing shall not vary by more than 10 percent from the equilibrium concentration in the vapor space of emissions generated from the fresh fuel or additive/base fuel mixture in the chamber.
(A) During the course of a day's emission generation period, the level of fuel in the EEG shall be maintained to within 7 percent of its height at the start of the daily exposure period.
(B) The fuel used in the EEG shall be drained at the end of each daily exposure. The EEG shall be refilled with a fresh supply of the test formulation before the start of each daily exposure.
(C) The vapor space of the evaporation chamber shall be well mixed throughout the time emissions are being withdrawn for testing.
(iv) The size of the evaporation chamber shall be determined by the rate at which evaporative emissions shall be needed in the test animal exposure chambers and the rate at which the fuel or the additive/base fuel mixture evaporates. The rate of evaporative emissions may be adjusted by altering the size of the EEG or by using one or more additional EEG(s). Emission rate modifications shall not be adjusted by temperature control or pressure control.
(v) The temperature of the fuel or additive/base fuel mixture in the evaporation chamber shall be 130 °F
(vi) The pressure in the vapor space of the evaporation chamber and the dilution and sampling apparatus shall stay within 10 percent of ambient atmospheric pressure.
(vii) There shall be no controls or equipment on the evaporation chamber system that change the concentration or composition of the vapors generated for testing.
(viii) Manufacturers shall perform verification testing of evaporative emissions in a manner analogous to the verification testing performed for combustion emissions.
(3) For biological testing, vapor shall be withdrawn from the EEG at a constant rate, diluted with air as required for the particular study, and conducted immediately to the biological testing chamber(s) in a manner similar to the method used in § 79.57(e), excluding the mixing chamber therein. The rate of emission generation shall be high enough to supply the biological exposure chamber with sufficient emissions to allow for a minimum of fifteen air changes per exposure chamber per hour. To allow for customary laboratory scheduling and for unforeseen problems with the evaporative emission generation or dilution equipment, biological exposures may be interrupted on limited occasions, as specified in § 79.61(d)(5). Interruptions exceeding these limitations shall cause the affected test(s) to be void.
(4) For characterization of evaporative emissions, samples of equilibrated emissions to the vapor space of the EEG shall be withdrawn into Tedlar bags, then stored and analyzed as specified in § 79.52(b).
(5) A manufacturer (or group of manufacturers) may submit to EPA a request for approval of an alternative method of generating evaporative emissions for use in emission characterization and biological tests required under this subpart.
(i) To be approved by EPA, the request must fully explain the rationale for the proposed method as well as the technical procedures, quality control, and safety precautions to be used, and must demonstrate that the proposed method will meet the following criteria:
(A) The emission mixture generated by the proposed procedures must be reasonably similar to the equilibrium composition of the vapor which occurs in the vehicle fuel tank head space when the subject fuel or additive/base fuel mixture is in use and near-maximum in-use temperatures are encountered.
(B) The emissions mixture generated by the proposed method must be sufficiently concentrated to provide adequate exposure levels in the context of the required toxicologic tests.
(C) The proposed method must include procedures to ensure that the emissions delivered to the biologic exposure chambers will provide a reasonably constant exposure atmosphere over time.
(ii) If EPA approves the request, EPA will place in the public record a copy of the request, together with all supporting procedural descriptions and justifications, and will notify the public of its availability by publishing a notice in the
(g)
(1) AIGER/CRADA (American Industry/Government Emissions Research Cooperative Research and Development Agreement, “Specifications for Advanced Emissions Test Instrumentation” AIGER PD-94-1, Revision 5.0, February, 1994
(2) Black, F. and R. Snow, “Constant Volume Sampling System Water Condensation” SAE
(3) Perez, J.M., Jass, R.E., Leddy, D.G., eds. “Chemical Methods for the Measurement of Unregulated Diesel Emissions (CRC-APRAC Project No. CAPI-1-64), Coordinating Research Council, CRC Report No. 551, August, 1987.
(4) Phalen, R.F., “Inhalation Studies: Foundations and Techniques”, CRC Press, Inc., Boca Raton, Florida, 1984.
(a)
(b)
(c)
(1) When EPA intends to require testing in lieu of or in addition to standard Tier 2 health testing, EPA will notify the responsible manufacturer (or group) by certified letter of the specific tests which EPA is proposing to require in lieu of or in addition to Tier 2, and the proposed schedule for completion and submission of such tests. A copy of the letter will be placed in the public record. EPA intends to send the notification prior to November 27, 1995, or in the case of new fuels and additives (as defined in § 79.51(c)(3)), within 18 months of EPA's receipt of an intent to register such product. However, EPA's notification to the manufacturer (or group) may occur at any time up to EPA's receipt of Tier 2 data for the product(s) in question. EPA will provide the manufacturer with 60 days from the date of receipt of the notice to comment on the tests which EPA is proposing to require and on the proposed schedule. If the manufacturer believes that undue costs or hardships will occur as a result of EPA's delay in providing notification of alternative Tier 2 requirements, then the manufacturer's comments should describe and include evidence of such hardship. In particular, if the standard Tier 2 toxicology testing for the fuel or additive in question has already begun at the time the manufacturer receives EPA's notification of proposed alternative Tier 2 requirements, then EPA shall refrain from requiring alternative Tier 2 tests provided that EPA receives the standard Tier 2 data and report (pursuant to § 79.59(c)) within one year of the date on which the toxicology testing began.
(2) EPA will issue a notice in the
(3) EPA will include in the public record a copy of any timely comments concerning the proposed alternative
(4) After EPA's receipt of a manufacturer's (or group's) submittals, EPA will notify the responsible manufacturer (or group) regarding the adequacy of the submittal and potential Tier 3 testing requirements according to the same relative time intervals and by the same procedures as specified in § 79.51 (c) and (d) for routine Tier 1 and Tier 2 submittals.
(d)
(2)
(3)
(4) Any registration granted by EPA under the provisions of this section are conditional upon satisfactory completion of any Tier 3 requirements which EPA may subsequently impose pursuant to § 79.54. In such circumstances, the Tier 3 requirements might include (but would not necessarily be limited to) information which would otherwise have been required under the provisions of Tier 1 and/or Tier 2.
(5) The provisions in paragraphs (d)(2) and (d)(3) of this section are voluntary on the part of qualifying small manufacturers. Such manufacturers may choose to fulfill the standard requirements for their fuels and additives, individually or as a part of a group, rather than satisfying only the requirements specified in paragraphs (d)(2) and/or (d)(3) of this section. If a qualifying small manufacturer elects these special provisions rather than the standard requirements for a product, then EPA will generally assume that any additional information submitted by other manufacturers, for fuels and additives meeting the same grouping criteria (under § 79.56) as that of the small manufacturer's product, is pertinent to further testing and/or regulatory decisions that may affect the small manufacturer's product.
(6) In the case of an additive for which the manufacturer is not required
(i) A fuel manufacturer which blends such an additive into fuel shall not be required to meet the requirements of Tier 2 with respect to such additive/fuel mixture.
(ii) An additive manufacturer which blends such an additive with one or more other registered additive products and/or with substances containing only carbon and/or hydrogen shall not be required to meet the requirements of Tier 2 with respect to such additive or additive blend.
(e)
(2) The literature search shall include existing data on potential health and welfare effects due to exposure to the aerosol product itself and its raw (uncombusted) components. The analysis for potential exposures shall be based on the actual or anticipated production volume and market distribution of the particular aerosol product, and its estimated frequency of use. Other Tier 1 and Tier 2 requirements are not routinely required for aerosol products. EPA will review the submitted information and, at EPA's discretion, may require from the manufacturer further information and/or testing under Tier 3 on a case-by-case basis.
(a)
(i) For existing products (pursuant to § 79.51(c)(1)), manufacturers shall submit the basic registration data as specified in § 79.59(b) to EPA by November 28, 1994.
(ii) For registrable products (pursuant to § 79.51(c)(2)), manufacturers shall submit the basic registration data as specified in § 79.59(b) to apply for registration for such product.
(iii) For new products (pursuant to § 79.51(c)(3)), manufacturers are strongly encouraged to notify EPA of an intent to obtain product registration by submitting the basic registration data as specified in § 79.59(b) prior to starting Tiers 1 and 2.
(2) The information specified in paragraph (c) of this section shall be submitted to the address in paragraph (a)(1) of this section at the conclusion of activities performed in compliance with Tiers 1 and 2 under the provisions of §§ 79.52 and 79.53, according to the time constraints specified in § 79.51 (c) through (d).
(3) The information specified in paragraph (d) of this section shall be submitted to EPA at the address in paragraph (a)(1) of this section at the conclusion of activities performed in compliance with Tier 3 under the provisions of § 79.54.
(b)
(1) The information specified in § 79.11 or § 79.21. If such information has already been submitted to EPA in compliance with subpart B or C of this part, and if such previous information is accurate and up-to-date, the manufacturer need not resubmit this information.
(2) Annual production volume of the fuel or fuel additive product, in units of gallons per year if most commonly sold in liquid form or kilograms per year if most commonly sold in solid form. For fuels and fuel additives already in production, the most recent annual production volume and the volume projected to be produced in the third subsequent year shall be provided. For products not yet in production, the best estimate of expected annual volume during the third year of production shall be provided.
(3)
(i) The following States and jurisdictions are included in PADD I:
(ii) The following States are included in PADD II:
(iii) The following States are included in PADD III:
(iv) The following States are included in PADD IV:
(v) The following States are included in PADD V:
(4) Any applicable information pursuant to the grouping provisions in § 79.56, as follows:
(i) If the manufacturer has enrolled or intends to enroll the product in a fuel/additive group, the relevant group and the person(s) or entity expected to submit information on behalf of the group must be identified.
(ii) If the manufacturer intends to rely on registration information previously submitted by another manufacturer (or group) for registration of other product(s) in the same fuel/additive group, then the original submitter and its product (or product group) shall be identified. In such cases, the manufacturer shall provide evidence that the original submitter has been notified of the use of its registration data and that the manufacturer has complied or intends to comply with the proportional reimbursement required under § 79.56(c) of this rule.
(5) Any applicable information pursuant to the special provisions in § 79.58, as follows:
(i) If the manufacturer claims applicability of the special provisions for relabeled additives, pursuant to § 79.58(a), then the manufacturer and brand name of the original product shall be given.
(ii) If the manufacturer claims applicability of any small business provisions pursuant to § 79.58(d), the average of the manufacturer's total annual sales revenue for the previous three years shall be given.
(iii) If the manufacturer claims applicability of the special provisions for aerosol products, pursuant to § 79.58(e), then the purpose and recommended frequency of use shall be given.
(c)
(1)
(ii) Name and address of the manufacturer of the test substance,
(iii) Name and phone number of a designated contact person,
(iv) Group information, if applicable, including:
(A) Group name or grouping criteria,
(B) Name and address of responsible organization or entity reporting for the group,
(C) Product trade name and manufacturer of each member fuel and additive to which the report pertains.
(2)
(3)
(i) Base fuel parameter values (including types and concentrations of base fuel additives) or test fuel composition (if a fuel other than the base fuel is used in testing). These values must be provided for each of the fuel parameters specified in § 79.55 for the applicable fuel family.
(ii) Test additive composition and concentration
(4)
(A) Identification of person(s) performing the literature search,
(B) Description of data sources accessed, search strategy used, search period, and terms included in literature search,
(C) Documentation of all unpublished in-house and other privately-conducted studies,
(D) Tables summarizing the protocols and results of all cited studies,
(E) Summary of significant results and conclusions with respect to the effects of the emissions of the subject fuel or fuel additive on the public health and welfare, including references if used to support such results and conclusions.
(F) Statement of the extent to which the literature search has produced adequate information comparable to that which would otherwise be obtained through the performance of applicable emission characterization requirements under § 79.52(b) and/or health effects testing requirements under § 79.53, including justifications and specific references.
(ii)
(A) Name, address, and telephone number of the laboratory performing the characterization,
(B) Name and description of analytic methods used for characterization.
(5)
(i) Name, address, and telephone number of the testing facility,
(ii) Summary of procedures (including quality assurance, quality control and compliance with Good Laboratory Practice Standards as specified in § 79.60), findings, and conclusions, including references if used to support such results and conclusions,
(iii) Description of any problems and their resolution.
(6)
(7)
(i) Literature search appendices shall contain:
(A) Copies of literature source outputs, including reference lists and associated abstracts from database searches, printed or on 3
(B) Summary tables organized by health or welfare endpoint and type of emission (e.g., combustion, evaporation, individual emission product), presenting in tabular form the following information at a minimum: number and species of test subjects, exposure concentrations/duration, positive (
(C) Complete documentation and/or reprints of articles for any previous study relied upon for satisfying emission characterization and/or Tier 2 test requirements; and
(D) Full reports for unpublished/in-house studies.
(ii) Emissions characterization appendices shall contain:
(A) Complete laboratory reports, including documentation of calibration and verification procedures;
(B) Documentation of the emissions generation procedures used; and
(C) Lists of speciated emission products and their emission rates reported in units of grams/mile.
(iii) [Reserved]
(iv) Tier 2 appendices shall contain, for each test performed:
(A) Complete protocol used;
(B) Documentation of emission generation procedures; and
(C) Complete laboratory report in compliance with the reporting standards in § 79.60, including detailed test results and conclusions, and descriptions of any problems encountered and their resolution.
(v) Laboratory certification/accreditation information, personnel credentials, and statements of compliance with the Good Laboratory Practices Standards specified in § 79.60 and the requirements in § 79.53(c)(1).
(d)
(1) The test objectives, including a summary of the reason(s) why such additional testing, beyond Tiers 1 and 2, was required;
(2) Name, address, and telephone number of each testing facility;
(3) Summary of test procedures, results and conclusions;
(4) Complete documentation of test protocols and emission generation procedures, complete laboratory reports in compliance with the reporting standards of § 79.60, detailed test results and conclusions, including references if used to support such results and conclusions, and descriptions of any problems encountered and their resolution; and
(5) Laboratory certification information, personnel credentials, and statements of compliance with the Good Laboratory Practices Standards specified in § 79.60.
(e)
(2) To assert a business confidentiality claim concerning any information submitted under this subpart, the submitter must:
(i) Clearly mark the information as confidential at each location it appears in the submission; and
(ii) Submit with the information claimed as confidential a separate document setting forth the claim and listing each location at which the information appears in the submission.
(3) If any person subsequently requests access to information submitted under this subpart (other than health
(a)
(ii) This section applies to any study described by paragraph (a)(1)(i) of this section which any person conducts, initiates, or supports on or after May 27, 1994.
(iii) It is EPA's policy that all health effects data developed under sections 211(b) and (e) of CAA be in accordance with provisions of this section. If data are not developed in accordance with the provisions of this section, EPA may consider such data insufficient to evaluate the health effects of a motor vehicle's fuel or fuel additive emissions, unless the submitter provides additional information demonstrating that the data are reliable and adequate and EPA determines that the data are sufficient.
(2)
(3)
(4)
(i) A statement that the study was conducted in accordance with this section; or
(ii) A statement describing in detail all differences between the practices used in the study and those required by this section; or
(iii) A statement that the person was not a sponsor of the study, did not conduct the study, and does not know whether the study was conducted in accordance with this section.
(5)
(ii) EPA will not consider reliable for purposes of showing that a test substance does or does not present a risk of injury to health or the environment any data developed by a testing facility or sponsor that refuses to permit inspection in accordance with this section. The determination that a study will not be considered reliable does not, however, relieve the sponsor of a required test of any obligation under any applicable statute or regulation to submit the results of the study to EPA.
(6)
(A) The test is not being or was not conducted in accordance with any requirement of this part; or
(B) Data or information submitted to EPA under part 79, including the statement required by § 79.60(a)(4), include information or data that are false or misleading, contain significant omissions, or otherwise do not fulfill the requirements of this part; or
(C) Entry in accordance with § 79.60(a)(5) for the purpose of auditing test data is denied.
(ii) EPA, at its discretion, may not consider reliable for purposes of showing that a chemical substance or mixture does not present a risk of injury to health any study which was not conducted in accordance with this part. EPA, at its discretion, may rely upon such studies for purposes of showing adverse effects. The determination that a study will not be considered reliable does not, however, relieve the sponsor of a required test of the obligation under any applicable statute or regulation to submit the results of the study to EPA.
(iii) If data submitted in compliance with registration regulations issued under CAA section 211(b) or section 211(e) are not developed in accordance with this section, EPA may determine that the sponsor has not fulfilled its obligations under 40 CFR part 79 and may require the sponsor to develop data in accordance with the requirements of this section in order to satisfy such obligations.
(b)
(ii) Each testing facility shall maintain a current summary of training and experience and job description for each individual engaged in or supervising the conduct of a study.
(iii) There shall be a sufficient number of personnel for the timely and proper conduct of the study according to the protocol.
(iv) Personnel shall take necessary personal sanitation and health precautions designed to avoid contamination of test fuel and additive/base fuel mixtures, test and reference substances, and test systems.
(v) Personnel engaged in a study shall wear clothing appropriate for the duties they perform. Such clothing shall be changed as often as necessary to prevent microbiological, radiological, or chemical contamination of test systems and test, control, and reference substances.
(vi) Any individual found at any time to have an illness that may adversely affect the quality and integrity of the study shall be excluded from direct contact with test systems, fuel and fuel/additive mixtures, test and reference substances and any other operation or function that may adversely affect the study until the condition is corrected. All personnel shall be instructed to report to their immediate supervisors any health or medical conditions that may reasonably be considered to have an adverse effect on a study.
(2)
(i) Designate a study director as described in § 79.60(b)(3) before the study is initiated.
(ii) Replace the study director promptly if it becomes necessary to do so during the conduct of a study.
(iii) Assure that there is a quality assurance unit as described in § 79.60(b)(4).
(iv) Assure that test fuels and fuel/additive mixtures and test and reference substances have been identified as to content, strength, purity, stability, and uniformity, as applicable.
(v) Assure that personnel, resources, facilities, equipment, materials and methodologies are available as scheduled.
(vi) Assure that personnel clearly understand the functions they are to perform.
(vii) Assure that any deviations from these regulations reported by the quality assurance unit are communicated to the study director and corrective actions are taken and documented.
(3)
(i) The protocol, including any changes, is approved as provided by § 79.60(g)(1)(i) and is followed;
(ii) All experimental data, including observations of unanticipated responses of the test system are accurately recorded and verified;
(iii) Unforeseen circumstances that may affect the quality and integrity of the study are noted when they occur, and corrective action is taken and documented;
(iv) Test systems are as specified in the protocol;
(v) All applicable good laboratory practice regulations are followed; and
(vi) All raw data, documentation, protocols, specimens, and final reports are archived properly during or at the close of the study.
(4)
(i)
(B) Maintain copies of all protocols pertaining to all studies for which the unit is responsible.
(C) Inspect each study at intervals adequate to ensure the integrity of the study and maintain written and properly signed records of each periodic inspection showing the date of the inspection, the study inspected, the phase or segment of the study inspected, the person performing the inspection, findings and problems, action recommended and taken to resolve existing problems, and any scheduled date for re-inspection. Any problems which are likely to affect study integrity found during the course of an inspection shall be brought to the attention of the study director and management immediately.
(D) Periodically submit to management and the study director written status reports on each study, noting any problems and the corrective actions taken.
(E) Determine that no deviations from approved protocols or standard operating procedures were made without proper authorization and documentation.
(F) Review the final study report to assure that such report accurately describes the methods and standard operating procedures, and that the reported results accurately reflect the raw data of the study.
(G) Prepare and sign a statement to be included with the final study report which shall specify the dates inspections were made and findings reported to management and to the study director.
(ii) The responsibilities and procedures applicable to the quality assurance unit, the records maintained by the quality assurance unit, and the method of indexing such records shall be in writing and shall be maintained. These items including inspection dates, the study inspected, the phase or segment of the study inspected, and the name of the individual performing the inspection shall be made available for inspection to authorized employees or duly designated representatives of EPA.
(iii) An authorized employee or a duly designated representative of EPA shall have access to the written procedures established for the inspection and may request test facility management to certify that inspections are
(c)
(2)
(ii) A testing facility shall have a number of animal rooms or other test system areas separate from those described in paragraph (a) of this section to ensure isolation of studies being done with test systems or test, control, and reference substances known to be biohazardous, including volatile atmospheres and aerosols, radioactive materials, and infectious agents. The animal handling facility must operate under the supervision of a veterinarian.
(iii) Separate areas shall be provided, as appropriate, for the diagnosis, treatment, and control of laboratory test system diseases. These areas shall provide effective isolation for the housing of test systems either known or suspected of being diseased, or of being carriers of disease, from other test systems.
(iv) Facilities shall have proper provisions for collection and disposal of contaminated air, water, or other spent materials. When animals are housed, facilities shall exist for the collection and disposal of all animal waste and refuse or for safe sanitary storage of waste before removal from the testing facility. Disposal facilities shall be so provided and operated as to minimize vermin infestation, odors, disease hazards, and environmental contamination.
(v) Facilities shall have provisions to regulate environmental conditions (e.g., temperature, humidity, day length, etc.) as specified in the protocol.
(3)
(ii) Separate laboratory space and other space shall be provided, as needed, for the performance of the routine and specialized procedures required by studies.
(4)
(A) Receipt and storage of the test fuels and fuel/additive mixtures and reference substances;
(B) Mixing of the test fuels, fuel/additive mixtures, and reference substances with a carrier,
(C) Storage of the test fuels, fuel/additive mixtures, and reference substance/carrier mixtures.
(ii) Storage areas for test fuels and fuel/additive mixtures and reference substances and for reference mixtures shall be separate from areas housing the test systems and shall be adequate to preserve the identity, strength, purity, and stability of the substances and mixtures.
(5)
(d)
(2)
(ii) The written standard operating procedures required under § 79.60(e)(1)(ii)(K) shall set forth in sufficient detail the methods, materials, and schedules to be used in the routine inspection, cleaning, maintenance, testing, calibration, and/or standardization of equipment, and shall specify, when appropriate, remedial action to be taken in the event of failure or malfunction of equipment. The written standard operating procedures shall designate the person responsible for the performance of each operation.
(iii) Written records shall be maintained of all inspection, maintenance, testing, calibrating, and/or standardizing operations. These records, containing the date of the operation, shall describe whether the maintenance operations were routine and followed the written standard operating procedures. Written records shall be kept of non-routine repairs performed on equipment as a result of failure and malfunction. Such records shall document the nature of the defect, how and when the defect was discovered, and any remedial action taken in response to the defect.
(e)
(ii) Standard operating procedures shall be established for, but not limited to, the following:
(A) Test system room preparation;
(B) Test system care;
(C) Receipt, identification, storage, handling, mixing, and method of sampling of test fuels and fuel/additive mixtures and reference substances;
(D) Test system observations;
(E) Laboratory or other tests;
(F) Handling of test animals found moribund or dead during study;
(G) Necropsy or postmortem examination of test animals;
(H) Collection and identification of specimens;
(I) Histopathology
(J) Data handling, storage and retrieval.
(K) Maintenance and calibration of equipment.
(L) Transfer, proper placement, and identification of test systems.
(iii) Each laboratory or other study area shall have immediately available manuals and standard operating procedures relative to the laboratory procedures being performed. Published literature may be used as a supplement to standard operating procedures.
(iv) A historical file of standard operating procedures, and all revisions thereof, including the dates of such revisions, shall be maintained.
(2)
(3)
(ii) All newly received test systems from outside sources shall be isolated and their health status or appropriateness for the study shall be evaluated. This evaluation shall be in accordance with acceptable veterinary medical practice or scientific methods.
(iii) At the initiation of a study, test systems shall be free of any disease or condition that might interfere with the purpose or conduct of the study. If during the course of the study, the test systems contract such a disease or condition, the diseased test systems shall be isolated, if necessary. These test systems may be treated for disease or signs of disease provided that such treatment does not interfere with the study. The diagnosis, authorization of
(iv) When laboratory procedures require test animals to be manipulated and observed over an extended period of time or when studies require test animals to be removed from and returned to their housing units for any reason (e.g., cage cleaning, treatment, etc.), these test systems shall receive appropriate identification (e.g., tattoo, color code, etc.). Test system identification shall conform with current laboratory animal handling practice. All information needed to specifically identify each test system within the test system-housing unit shall appear on the outside of that unit. Suckling animals are excluded from the requirement of individual identification unless otherwise specified in the protocol.
(v) Except as specified in paragraph (e)(3)(v)(A) of this section, test animals of different species shall be housed in separate rooms when necessary. Test animals of the same species, but used in different studies, shall not ordinarily be housed in the same room when inadvertent exposure to the test or reference substances or test system mixup could affect the outcome of either study. If such mixed housing is necessary, adequate differentiation by space and identification shall be made.
(A) Test systems that may be used in multispecies tests need not be housed in separate rooms, provided that they are adequately segregated to avoid mixup and cross-contamination.
(B) [Reserved]
(vi) Cages, racks, pens, enclosures, and other holding, rearing, and breeding areas, and accessory equipment, shall be cleaned and sanitized at appropriate intervals.
(vii) Feed and water used for the test animals shall be analyzed periodically to ensure that contaminants known to be capable of interfering with the study and reasonably expected to be present in such feed or water are not present at greater than trace levels. Documentation of such analyses shall be maintained as raw data.
(viii) Bedding used in animal cages or pens shall not interfere with the purpose or conduct of the study and shall be changed as often as necessary to keep the animals dry and clean.
(ix) If any pest control materials are used, the use shall be documented. Cleaning and pest control materials that interfere with the study shall not be used.
(x) All test systems shall be acclimatized to the environmental conditions of the test, prior to their use in a study.
(f) T
(ii) The stability of test fuel, fuel/additive mixture, and reference substances under storage conditions at the test site shall be known for all studies.
(2)
(i) There is proper storage.
(ii) Distribution is made in a manner designed to preclude the possibility of contamination, deterioration, or damage.
(iii) Proper identification is maintained throughout the distribution process.
(iv) The receipt and distribution of each batch is documented. Such documentation shall include the date and quantity of each batch distributed or returned.
(3) Mixtures of test emissions or reference solutions with carriers.
(i) For test emissions or each reference substance mixed with a carrier, tests by appropriate analytical methods shall be conducted:
(A) To determine the uniformity of the test substance and to determine,
(B) When relevant to the conduct of the experiment, to determine the solubility of each reference substance in the carrier mixture before the experimental start date; and
(C) To determine the stability of test emissions or a reference solution in the test substance before the experimental start date or concomitantly according to written standard operating procedures, which provide for periodic analysis of each batch.
(ii) Where any of the components of the reference substance/carrier mixture has an expiration date, that date shall be clearly shown on the container. If more than one component has an expiration date, the earliest date shall be shown.
(iii) If a chemical or physical agent is used to facilitate the mixing of a test substance with a carrier, assurance shall be provided that the agent does not interfere with the integrity of the test.
(g)
(A) A descriptive title and statement of the purpose of the study.
(B) Identification of the test fuel, fuel/additive mixture, and reference substance by name, chemical abstracts service (CAS) number or code number, as applicable.
(C) The name and address of the sponsor and the name and address of the testing facility at which the study is being conducted.
(D) The proposed experimental start and termination dates.
(E) Justification for selection of the test system, as necessary.
(F) Where applicable, the number, body weight, sex, source of supply, species, strain, substrain, and age of the test system.
(G) The procedure for identification of the test system.
(H) A description of the experimental design, including methods for the control of bias.
(I) Where applicable, a description and/or identification of the diet used in the study. The description shall include specifications for acceptable levels of contaminants that are reasonably expected to be present in the dietary materials and are known to be capable of interfering with the purpose or conduct of the study if present at levels greater than established by the specifications.
(J) Each concentration level, expressed in milligrams per cubic meter of air or other appropriate units, of the test or reference substance to be administered and the frequency of administration.
(K) The type and frequency of tests, analyses, and measurements to be made.
(L) The records to be maintained.
(M) The date of approval of the protocol by the sponsor and the dated signature of the study director.
(N) A statement of the proposed statistical method.
(ii) All changes in or revisions of an approved protocol and the reasons therefor shall be documented, signed by the study director, dated, and maintained with the protocol.
(2)
(ii) The test systems shall be monitored in conformity with the protocol.
(iii) Specimens shall be identified by test system, study, nature, and date of collection. This information shall be located on the specimen container or shall accompany the specimen in a manner that precludes error in the recording and storage of data.
(iv) In animal studies where histopathology is required, records of gross findings for a specimen from postmortem observations shall be available to a pathologist when examining that specimen histopathologically.
(v) All data generated during the conduct of a study, except those that are generated by automated data collection systems, shall be recorded directly, promptly, and legibly in ink. All data entries shall be dated on the day of entry and signed or initialed by the person entering the data. Any change in entries shall be made so as
(h)
(A) Name and address of the facility performing the study and the dates on which the study was initiated and was completed, terminated, or discontinued.
(B) Objectives and procedures stated in the approved protocol, including any changes in the original protocol.
(C) Statistical methods employed for analyzing the data.
(D) The test fuel, additive/base fuel mixture, and test and reference substances identified by name, chemical abstracts service (CAS) number or code number, strength, purity, content, or other appropriate characteristics.
(E) Stability, and when relevant to the conduct of the study, the solubility of the test emissions and reference substances under the conditions of administration.
(F) A description of the methods used.
(G) A description of the test system used. Where applicable, the final report shall include the number of animals or other test organisms used, sex, body weight range, source of supply, species, strain and substrain, age, and procedure used for identification.
(H) A description of the concentration regimen as daily exposure period,
(I) A description of all circumstances that may have affected the quality or integrity of the data.
(J) The name of the study director, the names of other scientists or professionals and the names of all supervisory personnel, involved in the study.
(K) A description of the transformations, calculations, or operations performed on the data, a summary and analysis of the data, and a statement of the conclusions drawn from the analysis.
(L) The signed and dated reports of each of the individual scientists or other professionals involved in the study, including each person who, at the request or direction of the testing facility or sponsor, conducted an analysis or evaluation of data or specimens from the study after data generation was completed.
(M) The locations where all specimens, raw data, and the final report are to be kept or stored.
(N) The statement, prepared and signed by the quality assurance unit, as described in § 79.60(b)(4)(i)(G).
(ii) The final report shall be signed and dated by the study director.
(iii) Corrections or additions to a final report shall be in the form of an amendment by the study director. The amendment shall clearly identify that part of the final report that is being added to or corrected and the reasons for the correction or addition, and shall be signed and dated by the person responsible. Modification of a final report to comply with the submission requirements of EPA does not constitute a correction, addition, or amendment to a final report.
(iv) A copy of the final report and of any amendment to it shall be maintained by the sponsor and the test facility.
(2)
(ii) All raw data, documentation, protocols, specimens, and interim and final reports shall be archived for orderly storage and expedient retrieval. Conditions of storage shall minimize
(iii) An individual shall be identified as responsible for the archiving of records.
(iv) Access to archived material shall require authorization and documentation.
(v) Archived material shall be indexed to permit expedient retrieval.
(3)
(ii) Except as provided in paragraph (h)(3)(iii) of this section, documentation records, raw data, and specimens pertaining to a study and required to be retained by this part shall be archived for a period of at least ten years following the completion of the study.
(iii) Wet specimens, samples of test fuel, additive/base fuel mixtures, or reference substances, and specially prepared material which are relatively fragile and differ markedly in stability and quality during storage, shall be retained only as long as the quality of the preparation affords evaluation. Specimens obtained from mutagenicity tests, wet specimens of blood, urine, feces, biological fluids, do not need to be retained after quality assurance verification. In no case shall retention be required for a longer period than that set forth in paragraph (h)(3)(ii) of this section.
(iv) The master schedule sheet, copies of protocols, and records of quality assurance inspections, as required by § 79.60(b)(4)(iii) shall be maintained by the quality assurance unit as an easily accessible system of records for the period of time specified in paragraph (h)(3)(ii) of this section.
(v) Summaries of training and experience and job descriptions required to be maintained by § 79.60(b)(1)(ii) may be retained along with all other testing facility employment records for the length of time specified in paragraph (h)(3)(ii) of this section.
(vi) Records and reports of the maintenance and calibration and inspection of equipment, as required by § 79.60(d)(2) (ii) and (iii), shall be retained for the length of time specified in paragraph (h)(3)(ii) of this section.
(vii) If a facility conducting testing or an archive contracting facility goes out of business, all raw data, documentation, and other material specified in this section shall be transferred to the sponsor of the study for archival.
(viii) Records required by this section may be retained either as original records or as true copies such as photocopies, microfilm, microfiche, or other accurate reproductions of the original records.
(a)
(b)
(c)
(1)
(2)
(ii) Dilution provides control of the emissions concentration delivered to the exposure system, serving the function of diluting the associated combustion gases, such as carbon monoxide, carbon dioxide, nitrogen oxides, sulfur dioxide and other noxious gases and vapors, to levels that will ensure that there are no significant or measurable responses in the test animals as a result of exposure to the combustion gases. The formation of particle species is strongly dependent on the dilution rate, as well.
(iii) The engine exhaust system shall connect to the first-stage-dilution section at 90° to the axis of the dilution section. This is then connected to a right angle elbow on the center line of the dilution section. Engine emissions are injected through the elbow so that exhaust flow is concurrent to dilution flow.
(iv)
(v)
(B) Dimensions of the dilute raw exhaust conduit shall be such that, at a minimum, the flow Reynolds number is 70,000 or greater (see Mokler,
(C)
(D) Whole-body exposure vs. nose-only exposure delivery systems. Flow rates through whole-body chamber systems are of the order of 100 liters per minute to 500 liters per minute. Nose-only systems are on the order of less than 50 liters per minute. To maintain laminar flow conditions, the principles described in paragraph (c)(2)(v)(C) of this section apply to both systems.
(vi)
(B) A maximum concentration (minimum dilution) of the raw exhaust going into the test animal cages is anticipated to lie in the range between 1:5 and 1:50 exhaust emissions to clean, filtered air. The minimum concentration (maximum dilution) of raw exhaust for health effects testing is anticipated to be in range between 1:100 and 1:150. Individual manufacturers will treat these ranges as approximations only and will determine the optimum range of emission concentrations to elicit effects in Tier 2 health testing for their particular fuel/fuel additive mixture.
(3)
(B) This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be purchased from the Superintendent of Documents, U.S. Government Printing Office, Washington, DC 20402. Copies may be inspected at U.S. EPA, OAR, 401 M Street SW., Washington, DC, 20460 or at the Office of the Federal Register, 800 North Capitol Street NW., suite 700, Washington, DC.
(ii)
(A)
(
(
(
(B)
(
(iii) Since whole-body exposure appears to be the least stressful mode of exposure, it is the preferred method. In general, head/nose only exposure, which is sometimes used to avoid concurrent exposure by the dermal or oral routes,
(d)
(ii) Young adult animals, approximately ten weeks of age for the rat, shall be used. At the commencement of the study, the weight variation of animals used shall not exceed
(iii) An equal number of male and female rodents shall be used at each concentration level. Situations may arise where use of a single sex may be appropriate. Females, in general, shall be nulliparous and nonpregnant.
(iv) The number of animals used at each concentration level and in the control group(s) depends on the type of study, number of biological end points used in the toxicity evaluation, the pre-determined sensitivity of detection and power of significance of the study, and the animal species. For an acute study, at least five animals of each sex shall be used in each test group. For both the subacute and subchronic studies, at least 10 rodents of each sex shall be used in each test group. For a chronic study, at least 20 male and 20 female rodents shall be used in each test group.
(A) If interim sacrifices are planned, the number of animals shall be increased by the number of animals scheduled to be sacrificed during the course of the study.
(B) For a chronic study, the number of animals at the termination of the study must be adequate for a meaningful and valid statistical evaluation of chronic effects.
(v) A concurrent control group is required. This group shall be exposed to clean, filtered air under conditions identical to those used for the group exposed to the test atmosphere.
(vi) The same species/strain shall be used to make comparisons between fuel-only and fuel/additive mixture studies. If another species/strain is used, the tester shall provide justification for its selection.
(2)
(ii) In whole-body exposure chambers, animals shall be housed in individual caging. The minimum cage size per animal will be in accordance with instructions set forth in the
(iii) Chambers shall be cleaned and maintained in accordance with recommendations and schedules set forth in the
(A) Observations shall be made daily with appropriate actions taken to minimize loss of animals to the study (e.g., necropsy or refrigeration of animals found dead and isolation or sacrifice of weak or moribund animals). Exposure systems using head/nose-only exposure chambers require no special daily chamber maintenance. Chambers shall be inspected to ensure that they are clean, and that there are no obstructions in the chamber which would restrict air flow to the animals. Whole-body exposure chambers will be inspected on a minimum of twice daily, once before exposures and once after exposures.
(B) Signs of toxicity shall be recorded as they are observed, including the time of onset, degree, and duration.
(C) Cage-side observations shall include, but are not limited to: changes in skin, fur, eye and mucous membranes, respiratory, autonomic, and central nervous systems, somatomotor activity, and behavioral patterns. Particular attention shall be directed to observation of tremors, convulsions, salivation, diarrhea, lethargy, sleep, and coma.
(iv) Food and water will be withheld from animals for head/nose-only exposure systems. For whole-body-exposure systems, water only may be provided. When the exposure generation system is not operating, food will be available
(v) At the end of the study period, all survivors in the main study population shall be sacrificed. Moribund animals shall be removed and sacrificed when observed.
(3)
(ii) In subchronic and chronic toxicity tests, testers shall use at least three different concentration levels, with a control exposure group, to determine a concentration-response relationship. Concentrations shall be spaced appropriately to produce test groups with a range of toxic effects. The concentration-response data may also be sufficient to determine a NOAEL, unless the result of a limit test precludes such findings. The criteria for selecting concentration levels has been published (40 CFR 798.2450 and 798.3260).
(A) The highest concentration shall result in toxic effects but not produce an incidence of fatalities which would prevent a meaningful evaluation of the study.
(B) The lowest concentration shall not produce toxic effects which are directly attributable to the test exposure. Where there is a useful estimation of human exposure, the lowest concentration shall exceed this.
(C) The intermediate concentration level(s) shall produce minimal observable toxic effects. If more than one intermediate concentration level is used, the concentrations shall be spaced to produce a gradation of toxic effects.
(D) In the low, intermediate, and control exposure groups, the incidence of fatalities shall be low to absent, so as not to preclude a meaningful evaluation of the results.
(4) Exposure chamber environmental conditions. The following environmental conditions in the exposure chamber are critical to the maintenance of the test animals: flow; temperature; relative humidity; lighting; and noise.
(i) Filtered and conditioned air shall be used during exposure, to dilute the
(ii) Recommended ranges of temperature for various species are given in the
(iii)
(iv)
(5)
(i) Each daily exposure must be at least 6 hours plus the time necessary to build the chamber atmosphere to 90 percent of the target exposure atmosphere. Interruptions of daily exposures caused by technical difficulties, if infrequent in occurrence and limited in duration, may be made up the same day by adding equivalent exposure time after the technical problem has been corrected and the exposure atmosphere restored to the required level.
(ii) Normally, no more than two non-exposure days may occur consecutively during the test period. However, if a third consecutive non-exposure day should occur due to circumstances beyond the tester's control, it may be remedied by adding a supplementary exposure day. Federal and other holidays do not constitute such circumstances. Whenever possible, a make-up day should be taken at the first opportunity, i.e., on the next day which would otherwise have been an intentional non-exposure day. If a compensatory day must be scheduled at the end of the standard test period, then it may occur either:
(A) Immediately following the last standard exposure day, with no intervening non-exposure days; or
(B) With up to two intervening non-exposure days, provided that no fewer than two consecutive compensatory exposure days are completed before the test is terminated and the animals sacrificed.
(iii) Except as allowed in paragraph (d)(5)(ii)(B) of this section, in no case shall there be fewer than four exposure days per week at any time during the test period.
(iv) A nominal 90-day (13-week) subchronic test period shall include no fewer than 63 total exposure days.
(6)
(A) Integrated samples of test atmosphere aerosol shall be taken daily during the exposure period from a single representative sample port in the
(B) To ensure that animals in different locations of the chamber receive a similar exposure atmosphere, distribution of an aerosol or vapor concentration in exposure chambers can be determined without animals during the developmental phase of the study, or it can be determined with animals early in the study. For head/nose-only exposure chambers, it may not be possible to monitor the chamber distribution during the exposure, because the exposure port contains the animal.
(C) During the development of the emissions generation system, particle size analysis shall be performed to establish the stability of an aerosol concentration with respect to particle size. Over the course of the exposure, analysis shall be conducted as often as is necessary to determine the consistency of particle size distribution.
(D)
(ii) Instrumentation used for a given study will be determined based on the type of generation system and the type of exposure chamber system specified for the exposure study.
(A) For exhaust studies, combustion gases shall be sampled by collecting exposure air in bags and then analyzing the collected air sample to determine major components of the combustion gas using gas analyzers. Exposure chambers can also be connected to gas analyzers directly by using sampling lines and switching valves. Samples can be taken more frequently using the latter method. Aerosol instruments, such as photometers, or time-integrated gravimetric determination may be used to determine the stability of any aerosol concentration in the chamber.
(B) For evaporative emission studies, concentration of fuel vapors can usually be determined by using a gas chromatograph (GC) and/or infrared (IR) spectrometry. Grab samples for intermittent sampling can be taken from the chamber by using bubble samplers with the appropriate solvent to collect the vapors, or by collecting a small volume of air in a syringe. Intermediate or continuous monitoring of the chamber concentration is also possible by connecting the chamber with a GC or IR detector.
(7) Monitoring chamber environmental conditions may be performed by a computer system or by exposure system operating personnel.
(i) The flow-metering device used for the exposure chambers must be a continuous monitoring device, and actual flow measurements must be recorded at least every 30 minutes. Accuracy must be
(ii)
(iii)
(iv)
(v) Lighting shall be measured quarterly, or once at the beginning, middle, and end of the study for shorter studies.
(vi) Noise level in the exposure chamber(s) shall be measured quarterly, or once at the beginning, middle, and end of the study for shorter studies.
(vii) Oxygen content is critical, especially in nose-only chamber systems, and shall be greater than or equal to 19 percent in the test cages. An oxygen sensor shall be located at a single position in the test chamber and a lower alarm limit of 18 percent shall be used to activate an alarm system.
(8)
(i) It is mandatory that the upper explosive limit (UEL) and lower explosive limit (LEL) for the fuel and/or fuel additive(s) that are being tested be determined. These limits can be found in the material safety data sheets (MSDS) for each substance and in various reference texts. The air concentration of the fuel or additive-base fuel mixture in the generation system, dilution/delivery system, and the exposure chamber system shall be calculated to ensure that explosive limits are not present.
(ii) Storage, handling, and use of fuels or fuel/additive mixtures shall follow guidelines given in 29 CFR 1910.106.
(iii) Monitoring for carbon monoxide (CO) levels is mandatory for combustion systems. CO shall be continuously monitored in the immediate area of the engine/vehicle system and in the exposure chamber(s).
(iv) Air samples shall be taken quarterly in the immediate area of the vapor generation system and the exposure chamber system, or once at the beginning, middle, and end of the study for shorter studies. These samples shall be analyzed by methods described in paragraph (d)(6)(ii)(B) of this section.
(v) With the presence of fuels and/or fuel additives, all electrical and electronic equipment must be grounded. Also, the dilution/delivery system and chamber exposure system must be grounded. Guidelines for grounding are given in 29 CFR 1910.304.
(9)
(ii) Technicians/operators shall be trained in exposure operation, maintenance, and documentation, as appropriate, and their training shall be documented.
(iii) Flow meters, sampling instruments, and balances used in the inhalation experiments shall be calibrated with standards during the developmental phase to determine their sensitivity, detection limits, and linearity. During the exposure period, instruments shall be checked for calibration and documented to ensure that each instrument still functions properly.
(iv) The mean exposure concentration shall be within 10 percent of the target concentration on 90 percent or more of exposure days. The coefficient of variation shall be within 25 percent of target on 90 percent or more of exposure days. For example, a manufacturer might determine a mean exposure concentration of its product's exposure emissions by identifying “marker” compound(s) typical of the emissions of the fuel or fuel/additive mixture under study as a surrogate for the total of individual compounds in those exposure emissions. The manufacturer would note any concentration changes
(v) The spatial variation of the chamber concentration shall be 10 percent, or less. If a higher spatial variation is observed during the developmental phase, then air mixing in the chamber shall be increased. In any case, animals shall be rotated among the various cages in the exposure chamber(s) to insure each animal's uniform exposure during the study.
(e)
(1)
(2)
(3)
(A) The vehicle/engine design and type, the dynamometer, the cooling system, if any, the computer control system, and the dilution system for exhaust emission generation;
(B) The evaporative emissions generator model, type, or design and its dilution system; and
(C) Other test conditions, such as the source and quality of mixing air, fuel or fuel/additive mixture used, treatment of exhaust air, design of exposure chamber and the method of housing animals in a test chamber shall be described.
(ii) The equipment for measuring temperature, humidity, particulate aerosol concentrations and size distribution, gas analyzers, fuel vapor concentrations, chamber distribution, and rise and fall time shall be described.
(iii)
(4) Exposure data shall be tabulated and presented with mean values and a measure of variability (
(i) Airflow rates through the inhalation equipment;
(ii) Temperature and humidity of air;
(iii) Chamber concentrations in the chamber breathing zone;
(iv) Concentration of combustion exhaust gases in the chamber breathing zone;
(v) Particle size distribution (e.g., mass median aerodynamic diameter and geometric standard deviation from the mean);
(vi) Rise and fall time;
(vii) Chamber concentrations during the non-exposure period; and
(viii) Distribution of test substance in the chamber.
(5)
(i) Number of animals exposed;
(ii) Number of animals showing signs of toxicity; and
(iii) Number of animals dying.
(f)
(1) Barr, E.B. (1988) Operational Limits for Temperature and Percent Oxygen During HM Nose-Only Exposures—Emergency Procedures [interoffice memorandum]. Albuquerque, NM: Lovelace Inhalation Toxicology Research Institute; May 13.
(2) Barr, E.B.; Cheng, Y.S.; Mauderly, J.L. (1990) Determination of Oxygen
(3) Barrow, C.S. (1989) Generation and Characterization of Gases and Vapors. In: McClellan, R.O., Henderson, R.F. ed. Concepts in Inhalation Toxicology. New York, NY: Hemisphere Publishing Corp., 63-84.
(4) Benedict, R.P. (1984) Fundamentals of Temperature, Pressure, and Flow Measurements. 3rd ed. New York, NY: John Wiley and Sons.
(5) Cannon, W.C.; Blanton, E.F.; McDonald, K.E. The Flow-Past Chamber. (1983) An Improved Nose-Only Exposure System for Rodents. Am. Ind. Hyg. Assoc. J. 44: 923-928.
(6) Chaddock, J.B. ed. (1985) Moisture and humidity. Measurement and Control in Science and Industry: Proceedings of the 1985 International Symposium on Moisture and Humidity; April 1985; Washington, D.C. Research Triangle Park, NC: Instrument Society of America.
(7) Cheng, Y.S.; Barr, E.B.; Carpenter, R.L.; Benson, J.M.; Hobbs, C.H. (1989) Improvement of Aerosol Distribution in Whole-Body Inhalation Exposure Chambers. Inhal. Toxicol. 1: 153-166.
(8) Cheng,Y.S.; Moss, O.R. (1989) Inhalation Exposure Systems. In: McClellan, R.O.; Henderson, R.F. ed. Concepts in Inhalation Toxicology. New York, NY: Hemisphere Publishing Corp., 19-62.
(9) Cheng, Y.S.; Yeh, H.C.; Mauderly, J.L.; Mokler, B.V. (1984) Characterization of Diesel Exhaust in a Chronic Inhalation Study. Am. Ind. Hyg. Assoc. J. 45: 547-555.
(10) Gillum, D.R. (1982) Industrial Pressure Measurement. Research Triangle Park, NC: Instrument Society of America.
(11) Hinners, R.G.; Burkart, J.K.; Malanchuk, M. (1979) Animal Exposure Facility for Diesel Exhaust Studies.
(12) Kittelson, D.B.; Dolan, D.F. (1979) Diesel exhaust aerosols. In Willeke, K. ed. Generation of Aerosols and Facilities for Exposure Experiments. Ann Arbor, MI: Ann Arbor Science Publishers Inc., 337-360.
(13) Mokler, B.V.; Archibeque, F.A.; Beethe, R.L.; Kelly, C.P.J.; Lopez, J.A.; Mauderly, J.L.; Stafford, D.L. (1984) Diesel Exhaust Exposure System for Animal Studies. Fundamental and Applied Toxicology 4: 270-277.
(14) Moore, W.;
(15) Raabe, O.G., Bennick, J.E., Light, M.E., Hobbs, C.H., Thomas, R.L., Tillery, M.I. (1973) An Improved Apparatus for Acute Inhalation Exposure of Rodents to Radioactive Aerosols. Toxicol & Applied Pharmaco.; 1973; 26: 264-273.
(16) Rao, G.N. (1986) Significance of Environmental Factors on the Test System. In: Hoover, B.K.; Baldwin, J.K.; Uelner, A.F.; Whitmire, C.E.; Davies, C.L.; Bristol, D.W. ed. Managing conduct and data quality of toxicology studies. Raleigh, NC: Princeton Scientific Publishing Co., Inc.: 173-185.
(17) Spitzer, D.W. (1984) Industrial Flow Measurement. Research Triangle Park, NC: Instrument Society of America.
(18) 40 CFR part 798, Health effects testing guidelines.
(19) 29 CFR part 1910, Occupational safety and health standards for general industry.
(20)
(a)
(2)
(i)
(ii)
(iii)
(iv)
(b)
(c)
(1)
(ii) All test groups are exposed over a period of 90 days to various concentrations of the test atmosphere for a minimum of six hours per day. After seven weeks of exposures, analysis of vaginal cell smears shall resume on a daily basis for the 25 for-breeding females and shall continue for a period of four weeks or until each female in the group is confirmed pregnant. Following the ninth week of exposures, each for-breeding female is housed overnight with a single study male. Matings shall continue for as long as two weeks, or until pregnancy is confirmed (pregnancy day 0). Pregnant females are only exposed through day 15 of their pregnancy while daily exposures continue throughout the course of the study for non-pregnant females and study males.
(iii) On pregnancy day 20, pregnant females are sacrificed and their uteri are examined. Pregnancy status and fetal effects are recorded as described in § 79.63. At the end of the exposure period, all males and non-pregnant females are sacrificed and necropsied. Testes and epididymal tissue samples are taken from five perfusion-fixed test subjects and histopathological examinations are carried out on the remainder of the non-pregnant females and study males.
(2)
(3)
(ii)
(iii) The start of the exposure period for the NTX measures study population may be staggered from that of the main study group to more evenly distribute the analytical work required in both study populations. The exposures would remain the same in all other respects.
(d)
(ii)
(A) Thirty rodents per concentration level/group, fifteen of each sex, shall be used to satisfy the reporting requirements of the 90-day toxicity study. Ten animals per concentration level/group shall be designated for whole body perfusion with fixative (by gravity) for lung studies, and neurohistology and testes studies, as appropriate.
(B) Thirty-five rodents, 25 females and ten males, shall be added for each test concentration or control group when combining a 90-day toxicity study with a fertility assessment.
(C) The tester shall provide a group of 10 animals (five animals per sex per experimental/control groups) in addition to the main test population when performing the GFAP neurotoxicity HEA.
(2)
(3)
(ii) The general conduct of this study shall be in accordance with the vehicle emissions inhalation exposure guideline in § 79.61.
(4)
(ii) The following is a minimal list of measures that shall be noted:
(A) Body weight;
(B) Subject's reactivity to general stimuli such as removal from the cage or handling;
(C) Description, incidence, and severity of any convulsions, tremors, or abnormal motor movements in the home cage;
(D) Descriptions and incidence of posture and gait abnormalities observed in the home cage;
(E) Description and incidence of any unusual or abnormal behaviors, excessive or repetitive actions (stereotypies), emaciation, dehydration, hypotonia or hypertonia, altered fur appearance, red or crusty deposits around the eyes, nose, or mouth, and any other observations that may facilitate interpretation of the data.
(iii) Any animal which dies during the test is necropsied as soon as possible after discovery.
(5)
(A) The following hematology determinations shall be carried out at least two times during the test period (after 30 days of exposure and just prior to terminal sacrifice at the end of the exposure period): hematocrit, hemoglobin concentration, erythrocyte count, total and differential leukocyte count, and a measure of clotting potential such as prothrombin time, thromboplastin time, or platelet count.
(B) Clinical biochemistry determinations on blood shall be carried out at least two times during the test period, after 30 days of exposure and just prior to terminal sacrifice at the end of the exposure period, on all groups of animals including concurrent controls. Clinical biochemical testing shall include assessment of electrolyte balance, carbohydrate metabolism, and liver and kidney function. The selection of specific tests will be influenced by observations on the mode of action of the substance. In the absence of more specific tests, the following determinations may be made: calcium, phosphorus, chloride, sodium, potassium, fasting glucose (with period of
(ii) The following examinations shall initially be performed on the high concentration and control groups only:
(A) Ophthalmological examination, using an ophthalmoscope or equivalent suitable equipment, shall be made prior to exposure to the test substance and at the termination of the study. If changes in the eyes are detected, all animals shall be examined.
(B) Urinalysis is not required on a routine basis, but shall be done when there is an indication based on expected and/or observed toxicity.
(iii) Preservation by whole-body perfusion of fixative into the anaesthetized animal for lung histology of ten animals from the 90-day study population for each experimental and control group.
(6)
(i) The liver, kidneys, lungs, adrenals, brain, and gonads, including uterus, ovaries, testes, epididymides, seminal vesicles (with coagulating glands), and prostate, constitute the group of target organs for histology and shall be weighed as soon as possible after dissection to avoid drying. In addition, for other than rodent test species, the thyroid with parathyroids, when present, shall also be weighed as soon as possible after dissection to avoid drying.
(ii) The following organs and tissues, or representative samples thereof, shall be preserved in a suitable medium for possible future histopathological examination: All gross lesions; lungs—which shall be removed intact, weighed, and treated with a suitable fixative to ensure that lung structure is maintained (perfusion with the fixative is considered to be an effective procedure); nasopharyngeal tissues; brain—including sections of medulla/pons, cerebellar cortex, and cerebral cortex; pituitary; thyroid/parathyroid; thymus; trachea; heart; sternum with bone marrow; salivary glands; liver; spleen; kidneys; adrenals; pancreas; reproductive organs: uterus; cervix; ovaries; vagina; testes; epididymides; prostate; and, if present, seminal vesicles; aorta; (skin); gall bladder (if present); esophagus; stomach; duodenum; jejunum; ileum; cecum; colon; rectum; urinary bladder; representative lymph node; (mammary gland); (thigh musculature); peripheral nerve/tissue; (eyes); (femur—including articular surface); (spinal cord at three levels—cervical, midthoracic, and lumbar); and (zymbal and exorbital lachrymal glands).
(7)
(i) All gross lesions.
(ii) Respiratory tract and other organs and tissues, listed in paragraph (d)(6)(ii) of this section (except organs/tissues in parentheses), of all animals in the control and high dose groups.
(iii) The tissues mentioned in parentheses, listed in paragraph (d)(6)(ii) of this section, if indicated by signs of toxicity or target organ involvement.
(iv) Lungs of animals in the low and intermediate dose groups shall also be subjected to histopathological examination, primarily for evidence of infection since this provides a convenient assessment of the state of health of the animals.
(v) Lungs and trachea of the whole-body perfusion-fixed test animals cited in paragraph (d)(1)(ii)(A) of this section are examined for inhaled particle distribution.
(e) Interpretation of results. All observed results, quantitative and incidental, shall be evaluated by an appropriate statistical method. The specific
(f)
(1) Date of death during the study or whether animals survived to termination.
(2) Date of observation of each abnormal sign and its subsequent course.
(3) Individual body weight data, and group average body weight data vs. time.
(4) Feed consumption data, when collected.
(5) Hematological tests employed and all results.
(6) Clinical biochemistry tests employed and all results.
(7) Necropsy findings.
(8) Type of stain/fixative and procedures used in preparing tissue samples.
(9) Detailed description of all histopathological findings.
(10) Statistical treatment of the study results, where appropriate.
(g)
(1) 40 CFR 798.2450, Inhalation toxicity.
(2) 40 CFR 798.2675, Oral Toxicity with Satellite Reproduction and Fertility Study.
(3) General Statement of Work for the Conduct of Toxicity and Carcinogenicity Studies in Laboratory Animals (revised April, 1987/modifications through January, 1990) appendix G, National Toxicology Program—U.S. Dept. of Health and Human Services (Public Health Service), P.O. Box 12233, Research Triangle Park, NC 27709.
(a)
(b)
(c)
(2) Beginning two weeks before the start of the mating period, daily vaginal smears resume for all to-be-bred females to characterize their estrous cycles. This will continue for four weeks or until a rat's pregnancy is confirmed,
(3) This assay may be done separately or in combination with the subchronic toxicity study, pursuant to the provisions in § 79.62.
(d)
(e)
(ii) Animals shall be a minimum of 10 weeks old at the start of the exposure period.
(iii)
(2)
(3)
(ii) The highest concentration level shall induce some overt maternal toxicity such as reduced body weight or body weight gain, but not more than 10 percent maternal deaths.
(iii) The lowest concentration level shall not produce any grossly observable evidence of either maternal or developmental toxicity.
(4)
(ii) The general conduct of this study shall be in accordance with the vehicle emissions inhalation exposure guideline in § 79.61.
(iii) Pregnant females shall be exposed to the test atmosphere on each and every day between (and including) the first and fifteenth day of gestation.
(f)
(i) The duration of exposure shall be at least six hours daily, allowing appropriate additional time for chamber equilibrium.
(ii) Where an exposure chamber is used, its design shall minimize crowding of the test animals. This is best accomplished by individual caging.
(iii) Pregnant animals shall not be subjected to beyond the minimum amount of stress. Since whole-body exposure appears to be the least stressful mode of exposure, it is the preferred method. In general oronasal or head-only exposure, which is sometimes used to avoid concurrent exposure by the dermal or oral routes, is not recommended because of the associated stress accompanying the restraining of the animals. However, there may be specific instances where it may be more appropriate than whole-body exposure. The tester shall provide justification/reasoning for its selection.
(iv) Measurements shall be made at least every other day of food consumption for all animals in the study. Males and females shall be weighed on the first day of exposure and 2-3 times per week thereafter, except for pregnant dams.
(v) The test animal housing, mating, and exposure chambers shall be operated on a twenty-four hour lighting schedule, with twelve hours of light and twelve hours of darkness. Test animal exposure shall only occur during the light portion of the cycle.
(vi) Signs of toxicity shall be recorded as they are observed including the time of onset, degree, and duration.
(vii) Females showing signs of abortion or premature delivery shall be sacrificed and subjected to a thorough macroscopic examination.
(viii) Animals that die or are euthanized because of morbidity will be necropsied promptly.
(2)
(ii) This will continue for four weeks or until day 0 of a rat's pregnancy is confirmed by the presence of sperm in the cell smear.
(3)
(ii) Each morning, including weekends, cages shall be examined for the presence of a sperm plug. When found, this shall mark gestation day 0 and pregnancy shall be confirmed by the presence of sperm in the day's wet vaginal cell smears.
(iii) Two weeks after mating is begun, or as females are determined to be pregnant, bred animals are returned to pre-mating housing. Daily exposures continues through gestation day 15 for all pregnant females or through the balance of the exposure period for non-pregnant females and all males.
(iv) Those pairs which fail to mate shall be evaluated in the course of the study to determine the cause of the apparent infertility. This may involve such procedures as additional opportunities to mate with a proven fertile partner, histological examination of the reproductive organs, and, in males, examination of the spermatogenic cycles. The stage of estrus for each non-pregnant female in the breeding group will be determined at the end of the exposure period.
(4) All animals in the histology group shall be subject to histopathologic examination at the end of the study's exposure period.
(g)
(2) Data and reporting. In addition to the reporting requirements specified
(i)
(B) The liver, kidneys, adrenals, pituitary, uterus, vagina, ovaries, testes, epididymides and seminal vesicles (with coagulating glands), and prostate shall be weighed wet, as soon as possible after dissection, to avoid drying.
(
(
(
(
(
(
(ii)
Testes, seminal vesicles, epididymides, and ovaries, at a minimum, shall be examined in perfusion-fixed (pressure or gravity method) test subjects, when available.
(B) All gross lesions in all study animals shall be examined.
(C) As noted under mating procedures, reproductive organs of animals suspected of infertility shall be subject to microscopic examination.
(D) The following organs and tissues, or representative samples thereof, shall be preserved in a suitable medium for future histopathological examination: all gross lesions; vagina; uterus; ovaries; testes; epididymides; seminal vesicles; prostate; liver; and kidneys/adrenals.
(3)
(ii) There are several criteria for determining a positive result for reproductive/teratologic effects; a statistically significant dose-related decrease in the weight of the testes for treated subjects over control subjects, a decrease in neonatal viability, a significant change in the presence of soft tissue or skeletal abnormalities, or an increased rate of embryonic or fetal resorption or death. Other criteria, e.g., lengthening of the estrous cycle or the time spent in any one stage of estrus, changes in the proportion of viable male vs female fetuses or offspring, the number and type of cells in vaginal smears, or pathologic changes found during gross or microscopic examination of male or female reproductive organs may be based upon detection of a reproducible and statistically significant positive response for that evaluation parameter. A positive result indicates that, under the test conditions, the test substance does induce reproductive organ or fetal toxicity in the test species.
(iii) A test substance which does not produce either a statistically significant dose-related change in the reproductive organs or cycle or a statistically significant and reproducible
(h)
(1)
(ii) Date of onset and duration of each abnormal sign and its subsequent course.
(iii) Feed and body weight data.
(iv) Necropsy findings.
(v) Male test subjects.
(A) Testicle weight, and body weight: testicle weight ratio.
(B) Detailed description of all histopathological findings, especially for the testes and the epididymides.
(vi) Female test subjects.
(A) Uterine weight data.
(B) Beginning and ending collection dates for vaginal cell smears.
(C) Estrous cycle length compared within and between groups including mean cycle length for groups.
(D) Percentage of time spent in each stage of cycle.
(E) Stage of estrus at time of mating/sacrifice and proportion of females in estrus between concentration groups.
(F) Detailed description of all histopathological findings, especially for uterine/ovary samples.
(vii) Pregnancy and litter data. Toxic response data by exposure level, including but not limited to, indices of fertility and time-to-mating, including the number of days until mating and the number of full or partial estrous cycles until mating.
(A) Number of pregnant animals,
(B) Number and percentage of live fetuses, resorptions.
(viii)
(B) Number of fetuses with any soft tissue or skeletal abnormalities.
(2) Type of stain/fixative and procedures used in preparing tissue samples.
(3) Statistical treatment of the study results.
(i)
(1) 40 CFR 798.2675, Oral Toxicity with Satellite Reproduction and Fertility Study.
(2) 40 CFR 798.4350, Inhalation Developmental Toxicity Study.
(3) Chapin, R.E. and J.J. Heindel (1993) Methods in Toxicology, Vol. 3, Parts A and B: Reproductive Toxicology, Academic Press, Orlando, FL.
(4) Gray, L.E., et al. (1989) “A Dose-Response Analysis of Methoxychlor-Induced Alterations of Reproductive Development and Function in the Rat” Fund. App. Tox. 12, 92-108.
(5) Leblond, C.P. and Y. Clermont (1952) “Definition of the Stages of the Cycle of the Seminiferous Epithelium of the Rat.” Ann. N. Y. Acad. Sci. 55:548-73.
(6) Morrissey, R.E., et al. (1988) “Evaluation of Rodent Sperm, Vaginal Cytology, and Reproductive Organ Weight Data from National Toxicology Program 13-week Studies.” Fundam. Appl. Toxicol. 11:343-358.
(7) Russell, L.D., Ettlin, R.A., Sinhattikim, A.P., and Clegg, E.D (1990) Histological and Histo-patho-logical Evaluation of the Testes, Cache River Press, Clearwater, FL.
(a)
(b)
(c)
(ii) This assay may be done separately or in combination with the subchronic toxicity study, pursuant to the provisions in § 79.62.
(2)
(ii) If a strain of mouse is used in this assay, the tester shall sample peripheral blood from an appropriate site on the test animal, e.g., the tail vein, as a source of normochromatic erythrocytes. Results shall be reported as outlined later in this guideline with “normochromatic” interchanged for “polychromatic”, where specified.
(3)
(4)
(d)
(ii) The general conduct of this study shall be in accordance with the vehicle emissions inhalation exposure guideline in § 79.61.
(2)
(3)
(e)
(2)
(ii) A test substance which does not produce either a statistically significant dose-related increase in the number of micronucleated polychromatic erythrocytes or a statistically significant and reproducible positive response at any one of the test points is considered nonmutagenic in this system.
(3)
(ii) Negative results indicate that under the test conditions the test substance does not produce micronuclei in the bone marrow of the test species.
(f)
(1) Test atmosphere concentration(s) used and rationale for concentration selection.
(2) Rationale for and description of treatment and sampling schedules, toxicity data, negative and positive controls.
(3) Historical control data (negative and positive), if available.
(4) Details of the protocol used for slide preparation.
(5) Criteria for identifying micronucleated erythrocytes.
(6) Micronucleus analysis by animal and by group for each concentration (sexes analyzed separately).
(i) Ratio of polychromatic to normochromatic erythrocytes.
(ii) Number of polychromatic erythrocytes with micronuclei.
(iii) Number of polychromatic erythrocytes scored.
(7) Statistical methodology chosen for test analysis.
(g)
(1) 40 CFR 798.5395,
(2) Cihak, R. “Evaluation of Benzidine by the Micronucleus Test.” Mutation Research, 67: 383-384 (1979).
(3) Evans, H.J. “Cytological Methods for Detecting Chemical Mutagens.” Chemical Mutagens: Principles and Methods for Their Detection, Vol. 4. Ed. A. Hollaender (New York and London: Plenum Press, 1976) pp. 1-29.
(4) Heddle, J.A.,
(5) Preston, J.R.
(6) Schmid, W. “The micronucleus test for cytogenetic analysis”, Chemical Mutagens, Principles and Methods for their Detection. Vol. 4 Hollaender A, (Ed. A ed. (New York and London: Plenum Press, (1976) pp. 31-53.
(7) Tice, R.E., and Al Pellom “User's guide: Micronucleus assay data management and analysis system”, NTIS Order no. PB-90-212-598AS.
(a)
(b)
(c)
(ii) This assay may be done separately or in combination with the subchronic toxicity study, pursuant to the provisions in § 79.62.
(2)
(ii) Within twenty-four hours of the last exposure, test animal lymphocytes are obtained by heart puncture and duplicate cell cultures are started for each animal. Cultures are grown in bromo-deoxyuridine (BrdU), and then a spindle inhibitor (e.g., colchicine) is added to arrest cell growth. Cells are harvested, fixed, and stained and their chromosomes are scored for SCEs.
(3)
(4)
(5)
(6)
(ii) The general conduct of this study shall be in accordance with the vehicle emissions inhalation exposure guideline in § 79.61.
(d)
(2)
(3)
(ii) At least 100 consecutive metaphase cells shall be scored for the number of first, second, and third division metaphases for each animal for each cell type.
(iii) At least 1000 consecutive PBL's shall be scored for the number of metaphase cells present.
(iv) The number of cells to be analyzed per animal shall be based upon the number of animals used, the negative control frequency, the pre-determined sensitivity and the power chosen for the test. Slides shall be coded before microscopic analysis.
(e)
(2)
(3)
(ii) A test substance which does not produce either a statistically significant dose-related increase in the number of SCE or a statistically significant and reproducible positive response at any one of the test concentrations is considered not to induce rearrangements of DNA segments in this system.
(iii) Both biological and statistical significance shall be considered together in the evaluation.
(4)
(ii) Negative results indicate that under the test conditions the test substance does not induce reciprocal interchanges in lung or lymphocyte cells of the test species.
(5)
(i) Test concentrations used, rationale for concentration selection, negative and positive controls;
(ii) Toxic response data by concentration;
(iii) Schedule of administration of test atmosphere, BrdU, and spindle inhibitor;
(iv) Time of harvest after administration of BrdU;
(v) Identity of spindle inhibitor, its concentration and timing of treatment;
(vi) Details of the protocol used for cell culture and slide preparation;
(vii) Criteria for scoring SCE;
(viii) Replicative index,
(ix) Mitotic activity,
(f)
(1) 40 CFR 798.5915,
(2) Kato, H. “Spontaneous Sister Chromatid Exchanges Detected by a BudR-Labeling Method.” Nature, 251:70-72 (1974).
(4) Kligerman, A. D.,
(5) Kligerman, A.D.,
(6) Kligerman, A.,
(7) Wolff, S., and P. Perry. “Differential Giemsa Staining of Sister Chromatids and the Study of Sister Chromatid Exchanges Without Autoradiography.” Chromosoma 48: 341-53 (1974).
(a)
(2) [Reserved]
(b)
(c)
(2) The tests described herein may be combined with any other toxicity study, as long as none of the requirements of either are violated by the combination. Specifically, this assay may be combined with a subchronic toxicity study, pursuant to provisions in § 79.62.
(d)
(e)
(ii)
(iii)
(2)
(3)
(ii) The laboratory performing the testing shall provide positive control data, e.g., results from repeated acrylamide exposure, as evidence of the ability of their histology procedures to detect neurotoxic endpoints. Positive control data shall be collected at the time of the test study unless the laboratory can demonstrate the adequacy of historical data for the planned study.
(iii) A satellite group of 10 female and 10 male test subjects shall be treated with the highest concentration level for the duration of the exposure and observed thereafter for reversibility, persistence, or delayed occurrence of toxic effects during a post-treatment period of not less than 28 days.
(4)
(ii) The general conduct of this study shall be in accordance with the vehicle emissions inhalation exposure guideline in § 79.61.
(5)
(ii) The following is a minimal list of measures that shall be noted:
(A) Body weight;
(B) Subject's reactivity to general stimuli such as removal from the cage or handling;
(C) Description, incidence, and severity of any convulsions, tremors, or abnormal motor movements in the home cage;
(D) Descriptions and incidence of posture and gait abnormalities observed in the home cage; and
(E) Description and incidence of any unusual or abnormal behaviors, excessive or repetitive actions (stereotypies), emaciation, dehydration, hypotonia or hypertonia, altered fur appearance, red or crusty deposits around the eyes, nose, or mouth, and any other observations that may facilitate interpretation of the data.
(iii)
(B)
(C)
(D)
(iv)
(v)
(B)
(C)
(D)
(E)
(
(
(F)
(f) Data collection, reporting, and evaluation. In addition to information meeting the requirements stated under 40 CFR 79.60 and 79.61, the following specific information shall be reported:
(1)
(ii) Positive control data from the laboratory performing the test that demonstrate the sensitivity of the procedures being used. Historical data may be used if all essential aspects of the experimental protocol are the same.
(2)
(i)
(ii)
(A) The number of animals used in each group, the number of animals displaying specific neurologic signs, and the number of animals in which any lesion was found; and
(B) The number of animals affected by each different type of lesion, the average grade of each type of lesion, and the frequency of each different type and/or location of lesion.
(iii)
(B) The evaluation of dose-response, if existent, for various groups shall be given, and a description of statistical method must be presented. The evaluation of neuropathology data shall include, where applicable, an assessment in conjunction with any other neurotoxicity studies, electrophysiological, behavioral, or neurochemical, which may be relevant to this study.
(g)
(1) 40 CFR 798.6400, Neuropathology.
(2) AFIP Manual of Histologic Staining Methods. (New York: McGraw-Hill (1968).
(3) Chang, L.W. A Color Atlas and Manual for Applied Histochemistry. (Springfield, IL: Charles C. Thomas, 1979).
(4) Dunnick, J.K., et.al. Thirteen-week Toxicity Study of N-Hexane in B6C3F1 Mice After Inhalation Exposure (1989) Toxicology, 57, 163-172.
(5) Hayat, M.A. “Vol. 1. Biological applications,” Principles and techniques of electron microscopy. (New York: Van Nostrand Reinhold, 1970).
(6) Palay S.L., Chan-Palay, V. Cerebellar Cortex: Cytology and Organization. (New York: Springer-Verlag, 1974).
(7) Ralis, H.M., Beesley, R.A., Ralis, Z.A. Techniques in Neurohistology. (London: Butterworths, 1973).
(8) Sette, W. “Pesticide Assessment Guidelines, Subdivision F, Neurotoxicity Test Guidelines.” Report No. 540/09-91-123 U.S. Environmental Protection Agency 1991 (NTIS
(9) Spencer, P.S., Schaumburg, H.H. (eds). Experimental and Clinical Neurotoxicology. (Baltimore: Williams and Wilkins, 1980).
(10) Zeman, W., Innes, J.R.M. Craigie's Neuroanatomy of the Rat. (New York: Academic, 1963).
(a)
(b)
(2) This assay may be done separately or in combination with the subchronic toxicity study, pursuant to the provisions of § 79.62.
(c)
(ii)
(iii)
(iv)
(2)
(3)
(ii)
(iii)
(iv)
(v)
(vi)
(vii)
(viii)
(A) Incubate 20 minutes in fixer (25 percent (v/v) isopropanol, 10 percent (v/v) acetic acid).
(B) Discard fixer, wash several times in deionized water to eliminate the fixer, and then incubate for 5 minutes in Tris-buffered saline (TBS): 200 mM NaCL, 60 mM Tris-HCl to pH 7.4.
(C) Discard TBS and incubate 1 hour in blocking solution (0.5 percent gelatin (w/v)) in TBS.
(D) Discard blocking solution and incubate for 2 hours in antibody solution (anti-GFAP antiserum diluted to the desired dilution in blocking solution containing 0.1 percent Triton X-100). Serum anti-bovine GFAP, which cross reacts with GFAP from rodents and humans, can be obtained commercially (e.g., Dako Corp.) and used at a dilution of 1:500.
(E) Discard antibody solution, and wash in 4 changes of TBS for 5 minutes each time. Then wash in TBS for 10 minutes.
(F) Discard TBS and incubate in blocking solution for 30 minutes.
(G) Discard blocking solution and incubate for 1 hour in Protein A solution ([I
(H) Remove Protein A solution (it may be reused once). Wash in 0.1 percent Triton X-100 in TBS (TBSTX) for 5 minutes, 4 times. Then wash in TBSTX for 2-3 hours for 4 additional times. An overnight wash in a larger volume can be used to replace the last 4 washes.
(I) Hang sheets to air-dry. Cut out squares or spots and count radioactivity in a gamma counter.
(ix)
(d)
(i) Body weight and brain region weights at time of sacrifice for each subject tested;
(ii) Indication of whether each subject survived to sacrifice or time of death;
(iii) Data from control animals and blank samples; and
(iv) Statistical evaluation of results;
(2)
(ii) The results of this assay shall be compared to and evaluated with any relevant behavioral and histopathological data.
(e)
(1) Brock, T.O and O'Callaghan, J.P. 1987. Quantitative changes in the synaptic vesicle proteins, synapsin I and p38 and the astrocyte specific protein, glial fibrillary acidic protein, are associated with chemical-induced injury to the rat central nervous system, J. Neurosci. 7:931-942.
(2) Jahn, R., Schiebler, W. Greengard, P. 1984. A quantitative dot-immunobinding assay for protein using nitrocellulose membrane filters. Proc. Natl. Acad. Sci. U.S.A. 81:1684-1687.
(3) O'Callaghan, J.P. 1988. Neurotypic and gliotypic protein as biochemical markers of neurotoxicity. Neurotoxicol. Teratol. 10:445-452.
(4) O'Callaghan, J.P. 1991. Quantification of glial fibrillary acidic protein: comparison of slot-immunobinding assays with a novel sandwich ELISA. Neurotoxicol. Teratol. 13:275-281.
(5) O'Callaghan, J.P. and Miller, D.B. 1985. Cerebellar hypoplasia in the Gunn rat is associated with quantitative changes in neurotypic and gliotypic proteins. J. Pharmacol. Exp. Ther. 234:522-532.
(6) Sette, W.F. “Pesticide Assessment Guidelines, Subdivision ‘F’, Hazard Evaluation: Human and Domestic Animals, Addendum 10, Neurotoxicity, Series 81, 82, and 83” US-EPA, Office of Pesticide Programs, EPA-540/09-91-123, March 1991.
(7) Smith, P.K., Krohn, R.I., Hermanson, G.T., Mallia, A.K., Gartner, F.H., Provenzano, M.D., Fujimoto, E.K., Goeke, N.M., Olson, B.J., Klenk, D.C. 1985. Measurement of protein using bicinchoninic acid. Annal. Biochem. 150:76-85.
(a)
(b)
(c)
(d)
(2)
(i) Direct plate incorporation method;
(ii) Preincubation method;
(iii) Azo-reduction method;
(iv) Microsuspension method; and
(v) Spiral assay.
(3)
(ii)
(iii)
(4)
(5)
(ii) Strain specific positive controls shall be included in the assay. Examples of strain specific positive controls are as follows:
(A) Strain TA1535, TA100: sodium azide;
(B) TA98: 2-nitrofluorene (without activation), 2-anthramine (with activation);
(C) TA1537: 9-aminoacridine; and
(D) TA98/1,8-DNP
The papers by Claxton
(iii)
(iv)
(6)
(ii) Gaseous hydrocarbons passing through the filter are trapped by a porous, polymer resin, like XAD-2/styrene-divinylbenzene, or an equivalent product. Methylene chloride is used to extract the resin and the sample is evaporated to dryness before storage or use.
(iii) Samples taken from this material are then used to expose the cells in this assay. Final concentration of extracts in solvent/vehicle, or after solvent exchange, shall not interfere with cell viability or growth rate. The paper by Stump (1982) in paragraph (g) of this section is useful for preparing extracts of particulate and semi-volatile organic compounds from diesel and gasoline exhaust stream.
(iv) Exposure concentrations. (A) The test should initially be performed over a broad range of concentrations. Among the criteria to be taken into consideration for determining the upper limits of test substance concentration are cytotoxicity and solubility. Cytotoxicity of the test chemical may be altered in the presence of metabolic activation systems. Toxicity may be evidenced by a reduction in the number of spontaneous revertants, a clearing of the background lawn or by
(B) Generally, a maximum of 5 mg/plate for pure substances is considered acceptable. At least 5 different concentrations of test substance shall be used with adequate intervals between test points.
(C) When appropriate, a single positive response shall be confirmed by testing over a narrow range of concentrations.
(e)
(1) Direct plate incorporation method. When testing with metabolic activation, test solution, bacteria, and 0.5 ml of activation mixture containing an adequate amount of postmitochondrial fraction shall be added to the liquid overlay agar and mixed. This mixture is poured over the surface of a selective agar plate. Overlay agar shall be allowed to solidify before incubation. At the end of the incubation period, revertant colonies per plate shall be counted. When testing without metabolic activation, the test sample and 0.1 ml of a fresh bacterial culture shall be added to 2.0 ml of overlay agar.
(2) Azo-reduction method. When testing with metabolic activation, 0.5 ml of activation mixture containing 150 μl of postmitochondrial fraction and 0.1 ml of bacterial culture shall be added to a test tube kept on ice. 0.1 ml of test solution shall be added, and the tubes shall be incubated with shaking at 30 °C for 30 minutes. At the end of the incubation period, 2.0 ml of agar shall be added to each tube, the contents mixed and poured over the surface of a selective agar plate. Overlay agar shall be allowed to solidify before incubation. At the end of the incubation period, revertant colonies per plate shall be counted. For tests without metabolic activation, 0.5 ml of buffer shall be used in place of the 0.5 ml of activation mixture. All other procedures shall be the same as those used for the test with metabolic activation.
(3) Other methods/modifications may also be appropriate.
(4) Media. An appropriate selective medium with an adequate overlay agar shall be used.
(5) Incubation conditions. All plates within a given experiment shall be incubated for the same time period. This incubation period shall be for 48-72 hours at 37 °C.
(6) Number of cultures. All plating shall be done at least in triplicate.
(f)
(2)
(3)
(ii) A test substance which does not produce either a statistically significant dose-related increase in the number of revertants or a statistically significant and reproducible positive response at any one of the test points is considered nonmutagenic in this system.
(iii) Both biological and statistical significance shall be considered together in the evaluation.
(4)
(ii) Negative results indicate that under the test conditions the test substance is not mutagenic in Salmonella typhimurium.
(5)
(i) Sampling method(s) used and manner in which cells are exposed to sample solution;
(ii) Bacterial strains used;
(iii) Metabolic activation system used (source, amount and cofactor); details of preparation of postmitochondrial fraction;
(iv) Concentration levels and rationale for selection of concentration range;
(v) Description of positive and negative controls, and concentrations used, if appropriate;
(vi) Individual plate counts, mean number of revertant colonies per plate, number of revertants per kilometer (or mile, or brake-horsepower/hour), and standard deviation; and
(g)
(1) 40 CFR 798.5265, The
(2) Ames, B.N., McCann, J., Yamasaki, E. “Methods for detecting carcinogens and mutagens with the Salmonella/mammalian microsome mutagenicity test,” Mutation Research 31:347-364 (1975).
(3) Huisingh, J.L., et al.,“Mutagenic and Carcinogenic Potency of Extracts of Diesel and Related Environmental Emissions: Study Design, Sample Generation, Collection, and Preparation”. In: Health Effects of Diesel Engine Emissions, Vol. II, W.E. Pepelko, R., M., Danner and N. A. Clarke (Eds.), US EPA, Cincinnati, EPA-600/9-80-057b, pp. 788-800 (1980).
(4) [Reserved]
(5) Claxton, L.D., Allen, J., Auletta, A., Mortelmans, K., Nestmann, E., Zeiger, E. “Guide for the
(6) Claxton, L., Houk, V.S., Allison, J.C., Creason, J., “Evaluating the relationship of metabolic activation system concentrations and chemical dose concentrations for the Salmonella Spiral and Plate Assays” Mutation Research 253:127-136 (1991).
(7) Claxton, L., Houk, V.S., Monteith, L.G., Myers, L.E., Hughes, T.J., “Assessing the use of known mutagens to calibrate the
(8) Claxton, L., Houk, V.S., Warner, J.R., Myers, L.E., Hughes, T.J., “Assessing the use of known mutagens to calibrate the
(9) Claxton, L., Creason, J., Lares, B., Augurell, E., Bagley, S., Bryant, D.W., Courtois, Y.A., Douglas, G., Clare, C.B., Goto, S., Quillardet, P., Jagannath, D.R., Mohn, G., Neilsen, P.A., Ohnishi, Y., Ong, T., Pederson, T.C., Shimizu, H., Nylund, L., Tokiwa, H., Vink, I.G.R., Wang, Y., Warshawsky, D., “Results of the IPCS Collaborative Study on Complex Mixtures” Mutation Research 276:23-32 (1992).
(10) Claxton, L., Douglas, G., Krewski, D., Lewtas, J., Matsushita, H., Rosenkranz, H., “Overview, conclusions, and recommendations of the IPCS Collaborative Study on Complex Mixtures” Mutation Research 276:61-80 (1992).
(11) Houk, V.S., Schalkowsky, S., and Claxton, L.D., “Development and Validation of the Spiral Salmonella Assay: An Automated Approach to Bacterial Mutagenicity Testing” Mutation Research 223:49-64 (1989).
(12) Jones, E., Richold, M., May, J.H., and Saje, A. “The Assessment of the Mutagenic Potential of Vehicle Engine Exhaust in the Ames Salmonella Assay Using a Direct Exposure Method” Mutation Research 97:35-40 (1985).
(13) Maron, D., and Ames, B. N., Revised methods for the Salmonella mutagenicity test, Mutation Research, 113:173-212 (1983).
(14) Prival, M.J., and Mitchell, V.D. “Analysis of a method for testing azo
(15) Rosenkranz, H.S., et.al. “Nitropyrenes: Isolation, identification, and reduction of mutagenic impurities in carbon black and toners” Science 209:1039-43 (1980).
(16) Stump, F., Snow, R., et.al., “Trapping gaseous hydrocarbons for mutagenic testing” SAE Technical Paper Series, No. 820776 (1982).
(17) Vogel, H.J., Bonner, D.M. “Acetylornithinase of E. coli: partial purification and some properties,” Journal of Biological Chemistry. 218:97-106 (1956).
Secs. 114, 211, and 301(a) of the Clean Air Act, as amended (42 U.S.C. 7414, 7545 and 7601(a)).
At 59 FR 7716, Feb. 16, 1994, EPA published amendments to part 80 containing information collection requirements. These amendments will not become effective until approval has been given by the Office of Management and Budget (OMB).
(a) This part prescribes regulations for the control and/or prohibition of fuels and additives for use in motor vehicles and motor vehicle engines. These regulations are based upon a determination by the Administrator that the emission product of a fuel or additive will endanger the public health, or will impair to a significant degree the performance of a motor vehicle emission control device in general use or which the Administrator finds has been developed to a point where in a reasonable time it would be in general use were such regulations promulgated; and certain other findings specified by the Act.
(b) Nothing in this part is intended to preempt the ability of State or local governments to control or prohibit any fuel or additive for use in motor vehicles and motor vehicle engines which is not explicitly regulated by this part.
As used in this part:
(a)
(b)
(c)
(d) [Reserved]
(e)
(f) [Reserved]
(g)
(h)
(i)
(j)
(k)
(l)
(m)
(n)
(o)
(p)-(q) [Reserved]
(r)
(s)
(t)
(u)
(v)
(w)
(x)
(y)
(z)
(aa)
(1) Which has a crude oil or bonafide feedstock capacity of 50,000 barrels per day or less, and
(2) Which is not owned or controlled by any refiner with a total combined crude oil or bonafide feedstock capacity greater than 137,500 barrels per day.
(bb) [Reserved]
(cc)
(dd)
(ee)
(ff)
(gg)
(hh)
(ii)
(jj)
(kk)
(ll)
(mm)
(nn) [Reserved]
(oo)
(pp)
(qq)
(rr)
(ss)
(tt)
(uu)
(vv)
For
The lead and phosphorus content of gasoline shall be determined in accordance with test methods set forth in the appendices to this part.
The Administrator or his authorized representative, upon presentation of appropriate credentials, shall have a right to enter upon or through any refinery, retail outlet, wholesale purchaser-consumer facility, or detergent manufacturer facility; or the premises or property of any gasoline or detergent distributor, carrier, or importer; or any place where gasoline or detergent is stored; and shall have the right to make inspections, take samples, obtain information and records, and conduct tests to determine compliance with the requirements of this part.
Any person who violates these regulations shall be liable to the United
(a) When the Administrator, the Regional Administrator, or their delegates have reason to believe that a violation of section 211(c) or section 211(n) of the Act and the regulations thereunder has occurred, they may require any refiner, distributor, wholesale purchaser-consumer, or retailer to report the following information regarding receipt, transfer, delivery, or sale of gasoline represented to be unleaded gasoline and to allow the reproduction of such information at all reasonable times.
(1) For any bulk shipment of gasoline represented to be unleaded gasoline which is transferred, sold, or delivered within the previous 6 months by a refiner or a distributor to a distributor, wholesale purchaser-consumer or a retail outlet, the refiner or distributor shall maintain and provide the following information as applicable:
(i) Business or corporate name and address of distributors, wholesale purchaser-consumers or retail outlets to which the gasoline has been transferred, sold, or delivered.
(ii) Quantity of gasoline involved.
(iii) Date of delivery.
(iv) Storage location of gasoline prior to transit via delivery vessel (e.g., location of a bulk terminal).
(v) Business or corporate name and address of the person who delivered the gasoline.
(vi) Identification of delivery vessel (e.g., truck number). This information shall be supplied by the person in paragraph (a)(1)(v) of this section who performed the delivery, e.g., common or contract carrier.
(2) For any bulk shipment of gasoline represented to be unleaded gasoline received by a retail outlet or a wholesale-purchaser-consumer facility within the previous 6 months, whether by purchase or otherwise, the retailer or wholesale purchaser-consumer shall maintain accessibility to and provide the following information:
(i) Business or corporate name and address of the distributor.
(ii) Quantity of gasoline received.
(iii) Date of receipt.
(b) Upon request by the Administrator, the Regional Administrator, or their delegates, any retailer shall provide documentation of his annual total sales volume in gallons of gasoline for each retail outlet for each calendar year beginning with 1971.
(c) Any refiner, distributor, wholesale purchaser-consumer, retailer, or importer shall provide such other information as the Administrator or his authorized representative may reasonably require to enable him to determine whether such refiner, distributor, wholesale purchaser-consumer, retailer, or importer has acted or is acting in compliance with sections 211(c) and 211(n) of the Act and the regulations thereunder and shall, upon request of the Administrator or his authorized representative, produce and allow reproduction of any relevant records at all reasonable times. Such information may include but is not limited to records of unleaded gasoline inventory at a wholesale purchaser-consumer facility or a retail outlet, unleaded pump meter readings at a wholesale purchaser-consumer facility or a retail outlet, and receipts providing the date of acquisition of signs, labels, and nozzles required by § 80.22. No person shall be required to furnish information requested under this paragraph if he can establish that such information is not maintained in the normal course of his business.
(a) After December 31, 1995, no person shall sell, offer for sale, supply, offer for supply, dispense, transport, or introduce into commerce gasoline represented to be unleaded gasoline unless such gasoline meets the defined requirements for unleaded gasoline in § 80.2(g); nor shall he dispense, or cause or allow the gasoline other than unleaded gasoline to be dispensed into any motor vehicle which is equipped with a gasoline tank filler inlet which is designed for the introduction of unleaded gasoline.
(b) After December 31, 1995, no person shall sell, offer for sale, supply, offer for supply, dispense, transport, or introduce into commerce for use as fuel in any motor vehicle (as defined in Section 216(2) of the Clean Air Act, 42 U.S.C. 7550(2)), any gasoline which is produced with the use of lead additives or which contains more than 0.05 gram of lead per gallon.
(c)-(e) [Reserved]
(f) Beginning January 1, 1996, every retailer and wholesale purchaser-consumer shall equip all gasoline pumps as follows:
(1) [Reserved]
(2) Each pump from which unleaded gasoline is dispensed into motor vehicles shall be equipped with a nozzle spout which meets the following specifications:
(i) The outside diameter of the terminal end shall not be greater than 0.840 inch (2.134 centimeters);
(ii) The terminal end shall have a straight section of at least 2.5 inches (6.34 centimeters) in length; and
(iii) The retaining spring shall terminate 3.0 inches (7.6 centimeters) from the terminal end.
(g)-(i) [Reserved]
(j) After July 1, 1996 every retailer and wholesale purchaser-consumer handling over 10,000 gallons (37,854 liters) of fuel per month shall limit each nozzle from which gasoline or methanol is introduced into motor vehicles to a maximum fuel flow rate not to exceed 10 gallons per minute (37.9 liters per minute). The flow rate may be controlled through any means in the pump/dispenser system, provided the nozzle flow rate does not exceed 10 gallons per minute (37.9 liters per minute). After January 1, 1998 this requirement applies to every retailer and wholesale purchaser-consumer. Any dispensing pump that is dedicated exclusively to heavy-duty vehicles, boats, or airplanes is exempt from this requirement.
Liability for violations of paragraphs (a) and (b) of § 80.22 shall be determined as follows:
(a)(1) Where the corporate, trade, or brand name of a gasoline refiner or any of its marketing subsidiaries appears on the pump stand or is displayed at the retail outlet or wholesale purchaser-consumer facility from which the gasoline was sold, dispensed, or offered for sale, the retailer or wholesale purchaser-consumer, the reseller (if any), and such gasoline refiner shall be deemed in violation. Except as provided in paragraph (b)(2) of this section, the refiner shall be deemed in violation irrespective of whether any other refiner, distributor, retailer, or wholesale purchaser-consumer or the employee or agent of any refiner, distributor, retailer, or wholesale purchaser-consumer may have caused or permitted the violation.
(2) Where the corporate, trade, or brand name of a gasoline refiner or any of its marketing subsidiaries does not appear on the pump stand and is not displayed at the retail outlet or wholesale purchaser-consumer facility from which the gasoline was sold, dispensed, or offered for sale, the retailer or wholesale purchaser-consumer and any distributor who sold that person gasoline contained in the storage tank which supplied that pump at the time of the violation shall be deemed in violation.
(b)(1) In any case in which a retailer or wholesale purchaser-consumer and any gasoline refiner or distributor
(2) In any case in which a retailer or wholesale purchaser-consumer, a re-sell-er (if any), and any gas-o-line re-fin-er would be in vio-la-tion under paragraph (a)(1) of this section, the refiner shall not be deemed in violation if he can demonstrate:
(i) That the violation was not caused by him or his employee or agent, and
(ii) That the violation was caused by an act in violation of law (other than the Act or this part), or an act of sabotage, vandalism, or deliberate commingling of gasoline which is produced with the use of lead additives or phosphorus additives with unleaded gasoline, whether or not such acts are violations of law in the jurisdiction where the violation of the requirements of this part occurred, or
(iii) That the violation was caused by the action of a reseller or a retailer supplied by such reseller, in violation of a contractual undertaking imposed by the refiner on such reseller designed to prevent such action, and despite reasonable efforts by the refiner (such as periodic sampling) to insure compliance with such contractual obligation, or
(iv) That the violation was caused by the action of a retailer who is supplied directly by the refiner (and not by a reseller), in violation of a contractual undertaking imposed by the refiner on such retailer designed to prevent such action, and despite reasonable efforts by the refiner (such as periodic sampling) to insure compliance with such contractual obligation, or
(v) That the violation was caused by the action of a distributor subject to a contract with the refiner for transportation of gasoline from a terminal to a distributor, retailer or wholesale purchaser-consumer, in violation of a contractual undertaking imposed by the refiner on such distributor designed to prevent such action, and despite reasonable efforts by the refiner (such as periodic sampling) to insure compliance with such contractual obligation, or
(vi) That the violation was caused by a distributor (such as a common carrier) not subject to a contract with the refiner but engaged by him for transportation of gasoline from a terminal to a distributor, retailer or wholesale purchaser-consumer, despite reasonable efforts by the refiner (such as specification or inspection of equipment) to prevent such action, or
(vii) That the violation occurred at a wholesale purchaser-consumer facility:
(viii) In paragraphs (b)(2)(ii) through (vi) hereof, the term “was caused” means that the refiner must demonstrate by reasonably specific showings by direct or circumstantial evidence that the violation was caused or must have been caused by another.
(c) In any case in which a retailer or wholesale purchaser-consumer, a re-sell-er, and any gasoline refiner would be in violation under paragraph (a)(1) of this section, the reseller shall not be deemed in violation if he can demonstrate that the violation was not caused by him or his employee or agent.
(d) In any case in which a retailer or wholesale purchaser-consumer and any gasoline distributor would be in violation under paragraph (a)(2) of this section, the distributor will not be deemed in violation if he can demonstrate that the violation was not caused by him or his employee or agent.
(e)(1) In any case in which a retailer or his employee or agent or a wholesale purchase-consumer or his employee or agent introduced gasoline other than unleaded gasoline into a motor vehicle which is equipped with a gasoline tank filler inlet designed for the introduction of unleaded gasoline, only the retailer or wholesale purchaser-consumer shall be deemed in violation.
(2) [Reserved]
(a) [Reserved]
(b) The manufacturer of any motor vehicle equipped with an emission control device which the Administrator has determined will be significantly impaired by the use of gasoline other than unleaded gasoline shall manufacture such vehicle with each gasoline tank filler inlet having a restriction which prevents the insertion of a nozzle with a spout having a terminal end with an outside diameter of 0.930 inch (2.363 centimeters) or more and allows the insertion of a nozzle with a spout meeting the specifications of § 80.22(f)(2).
Information obtained by the Administrator or his representatives pursuant to this part shall be treated, in so far as its confidentiality is concerned, in accordance with the provisions of 40 CFR part 2.
(a)(1)
(2)
(i) 9.0 psi for all designated volatility attainment areas; and
(ii) The standard listed in this paragraph for the state and time period in which the gasoline is intended to be dispensed to motor vehicles for any designated volatility nonattainment area within such State or, if such area
(b)
(c)
(d)
(2) In order to qualify for the special regulatory treatment specified in paragraph (d)(1) of this section, gasoline must contain denatured, anhydrous ethanol. The concentration of the ethanol, excluding the required denaturing agent, must be at least 9% and no more than 10% (by volume) of the gasoline. The ethanol content of the gasoline shall be determined by use of one of the testing methodologies specified in appendix F to this part. The maximum ethanol content of gasoline shall not exceed any applicable waiver conditions under section 211(f)(4) of the Clean Air Act.
(3) Each invoice, loading ticket, bill of lading, delivery ticket and other document which accompanies a shipment of gasoline containing ethanol shall contain a legible and conspicuous statement that the gasoline being shipped contains ethanol and the percentage concentration of ethanol.
(e)
(ii) For purposes of this section, “testing exemption” means an exemption from the requirements of § 80.27(a) that is granted by the Administrator for the purpose of research or emissions certification.
(2)(i) In order for a testing exemption to be granted, the applicant must demonstrate the following:
(A) The proposed test program has a purpose that constitutes an appropriate basis for exemption;
(B) The proposed test program necessitates the granting of an exemption;
(C) The proposed test program exhibits reasonableness in scope; and
(D) The proposed test program exhibits a degree of control consistent with the purpose of the program and the Environmental Protection Agency's (EPA's) monitoring requirements.
(ii) Paragraphs (e)(3), (4), (5) and (6) of this section describe what constitutes a sufficient demonstration for each of the four elements in paragraphs (e)(2)(i) (A) through (D) of this section.
(3) An appropriate purpose is limited to research or emissions certification. The testing exemption application must include a concise statement of the purpose(s) of the testing program.
(4) With respect to the necessity that an exemption be granted, the applicant must demonstrate an inability to achieve the stated purpose in a practicable manner, during a period of the year in which the volatility regulations do not apply, or without performing or causing to be performed one or more of the prohibited activities under § 80.27(a). If any site of the proposed test program is located in an area that has been classified by the Administrator as a nonattainment area for purposes of the ozone national ambient air quality standard, the application must also demonstrate an inability to perform the test program in an area that is not so classified.
(5) With respect to reasonableness, a test program must exhibit a duration of reasonable length, effect a reasonable number of vehicles or engines, and utilize a reasonable amount of high volatility fuel. In this regard, the testing exemption application must include:
(i) An estimate of the program's duration;
(ii) An estimate of the maximum number of vehicles or engines involved in the test program;
(iii) The time or mileage duration of the test program;
(iv) The range of volatility of the fuel (expressed in Reid Vapor Pressure (RVP)) expected to be used in the test program; and
(v) The quantity of fuel which exceeds the applicable standard that is expected to be used in the test program.
(6) With respect to control, a test program must be capable of affording EPA a monitoring capability. At a minimum, the testing exemption application must also include:
(i) The technical nature of the test program;
(ii) The site(s) of the test program (including the street address, city, county, State, and zip code);
(iii) The manner in which information on vehicles and engines used in the test program will be recorded and made available to the Administrator;
(iv) The manner in which results of the test program will be recorded and made available to the Administrator;
(v) The manner in which information on the fuel used in the test program (including RVP level(s), name, address, telephone number, and contact person of supplier, quantity, date received from the supplier) will be recorded and made available to the Administrator;
(vi) The manner in which the distribution pumps will be labeled to insure proper use of the test fuel;
(vii) The name, address, telephone number and title of the person(s) in the organization requesting a testing exemption from whom further information on the request may be obtained; and
(viii) The name, address, telephone number and title of the person(s) in the organization requesting a testing exemption who will be responsible for recording and making available to the Administrator the information specified in paragraphs (e)(6)(iii), (iv), and (v) of this section, and the location in which such information will be maintained.
(7) A testing exemption will be granted by the Administrator upon a demonstration that the requirements of paragraphs (e)(2), (3), (4), (5) and (6) of this section have been met. The testing exemption will be granted in the form of a memorandum of exemption signed by the applicant and the Administrator (or his delegate), which shall include such terms and conditions as the Administrator determines necessary to monitor the exemption and to carry out the purposes of this section. Any violation of such a term or condition shall cause the exemption to be void.
(a)
(b)
(1) The carrier, except as provided in paragraph (g)(1) of this section;
(2) The refiner (if he is not an ethanol blender) at whose refinery the gasoline was produced or the importer at whose import facility the gasoline was imported, except as provided in paragraph (g)(2) of this section;
(3) The ethanol blender (if any) at whose ethanol blending plant the gasoline was produced, except as provided in paragraph (g)(6) of this section; and
(4) The distributor and/or reseller, except as provided in paragraph (g)(3) of this section.
(c)
(1) The distributor or reseller, except as provided in paragraph (g)(3) or (g)(8) of this section;
(2) The carrier (if any), if the carrier caused the gasoline to violate the applicable standard;
(3) The refiner under whose corporate, trade, or brand name (or that of any of its marketing subsidiaries) the distributor, reseller, or ethanol blender is operating, except as provided in paragraph (g)(4) of this section; and
(4) The ethanol blender (if any) at whose ethanol blending plant the gasoline was produced, except as provided in paragraph (g)(6) or (g)(8) of this section.
(d)
(1) The distributor, except as provided in paragraph (g)(3) or (g)(8) of this section;
(2) The carrier (if any), if the carrier caused the gasoline to violate the applicable standard;
(3) The refiner (if he is not an ethanol blender) at whose refinery the gasoline was produced or the importer at whose import facility the gasoline was imported, except as provided in paragraph (g)(2) of this section; and
(4) The ethanol blender (if any) at whose ethanol blending plant the gasoline was produced, except as provided in paragraph (g)(6) or (g)(8) of this section.
(e)
(1) The retailer or wholesale purchaser-consumer, except as provided in paragraph (g)(5) or (g)(8) of this section;
(2) The distributor and/or reseller (if any), except as provided in paragraph (g)(3) or (g)(8) of this section;
(3) The carrier (if any), if the carrier caused the gasoline to violate the applicable standard;
(4) The refiner whose corporate, trade, or brand name (or that of any of its marketing subsidiaries) is displayed at the retail outlet or wholesale purchaser-consumer facility, except as provided in paragraph (g)(4) of this section; and
(5) The ethanol blender (if any) at whose ethanol blending plant the gasoline was produced, except as provided in paragraph (g)(6) or (g)(8) of this section.
(f)
(1) The retailer or wholesale purchaser-consumer, except as provided in paragraph (g)(5) or (g)(8) of this section;
(2) The distributor (if any), except as provided in paragraph (g)(3) or (g)(8) of this section;
(3) The carrier (if any), if the carrier caused the gasoline to violate the applicable standard;
(4) The ethanol blender (if any) at whose ethanol blending plant the gasoline was produced, except as provided in paragraph (g)(6) of this section; and
(5) The refiner (if he is not an ethanol blender) at whose refinery the gasoline was produced and/or the importer at whose import facility the gasoline was imported, except as provided in paragraph (g)(2) of this section.
(g)
(i) That the violation was not caused by him or his employee or agent; and
(ii) Evidence of an oversight program conducted by the carrier, such as periodic sampling and testing of incoming gasoline, for monitoring the volatility of gasoline stored or transported by that carrier.
(iii) An oversight program under paragraph (g)(1)(ii) of this section need not include periodic sampling and testing of gasoline in a tank truck operated by a common carrier, but in lieu of such tank truck sampling and testing, the common carrier shall demonstrate evidence of an oversight program for monitoring compliance with the volatility requirements of § 80.27 relating to the transport or storage of gasoline by tank truck, such as appropriate guidance to drivers on compliance with applicable requirements and the periodic review of records normally received in the ordinary course of business concerning gasoline quality and delivery.
(2) In any case in which a refiner or importer would be in violation under paragraphs (b)(2), (d)(3), or (f)(5) of this section, the refiner or importer shall not be deemed in violation if he can demonstrate:
(i) That the violation was not caused by him or his employee or agent; and
(ii) Test results using the sampling and testing methodologies set forth in appendices D and E of this part, or any other test method where adequate correlation to Method 3 of appendix E of this part is demonstrated, which show evidence that the gasoline determined to be in violation was in compliance with the applicable standard when it was delivered to the next party in the distribution system.
(3) In any case in which a distributor or reseller would be in violation under paragraph (b)(4), (c)(1), (d)(1), (e)(2), or (f)(2) of this section, the distributor or reseller shall not be deemed in violation if he can demonstrate:
(i) That the violation was not caused by him or his employee or agent; and
(ii) Evidence of an oversight program conducted by the distributor or reseller, such as periodic sampling and testing of gasoline, for monitoring the volatility of gasoline that the distributor or reseller sells, supplies, offers for sale or supply, or transports.
(4) In any case in which a refiner would be in violation under paragraphs (c)(3) or (e)(4) of this section, the refiner shall not be deemed in violation if he can demonstrate all of the following:
(i) Test results using the sampling and testing methodologies set forth in appendices D and E of this part, or any other test method where adequate correlation to Method 3 of appendix E of this part is demonstrated, which show evidence that the gasoline determined to be in violation was in compliance with the applicable standard when transported from the refinery.
(ii) That the violation was not caused by him or his employee or agent; and
(iii) That the violation:
(A) Was caused by an act in violation of law (other than the Act or this part), or an act of sabotage or vandalism, whether or not such acts are violations of law in the jurisdiction where the violation of the requirements of this part occurred, or
(B) Was caused by the action of a reseller, an ethanol blender, or a retailer supplied by such reseller or ethanol blender, in violation of a contractual undertaking imposed by the refiner on such reseller or ethanol blender designed to prevent such action, and despite reasonable efforts by the refiner (such as periodic sampling and testing) to insure compliance with such contractual obligation, or
(C) Was caused by the action of a retailer who is supplied directly by the refiner (and not by a reseller), in violation of a contractual undertaking imposed by the refiner on such retailer designed to prevent such action, and despite reasonable efforts by the refiner (such as periodic sampling and testing) to insure compliance with such contractual obligation, or
(D) Was caused by the action of a distributor or an ethanol blender subject to a contract with the refiner for transportation of gasoline from a terminal to a distributor, ethanol blender, retailer or wholesale purchaser-con-sum-er, in violation of a con-trac-tu-al un-der-tak-ing imposed by the refiner on such distributor or ethanol blender designed
(E) Was caused by a carrier or other distributor not subject to a contract with the refiner but engaged by him for transportation of gasoline from a terminal to a distributor, ethanol blender, retailer or wholesale purchaser-consumer, despite reasonable efforts by the refiner (such as specification or inspection of equipment) to prevent such action, or
(F) Occurred at a wholesale purchaser-consumer facility:
(iv) In paragraphs (g)(4)(iii)(A) through (E) of this section, the term “was caused” means that the refiner must demonstrate by reasonably specific showings, by direct or circumstantial evidence, that the violation was caused or must have been caused by another.
(5) In any case in which a retailer or wholesale purchaser-consumer would be in violation under paragraphs (e)(1) or (f)(1) of this section, the retailer or wholesale purchaser-consumer shall not be deemed in violation if he can demonstrate that the violation was not caused by him or his employee or agent.
(6) In any case in which an ethanol blender would be in violation under paragraphs (b)(3), (c)(4), (d)(4), (e)(5) or (f)(4) of this section, the ethanol blender shall not be deemed in violation if he can demonstrate:
(i) That the violation was not caused by him or his employee or agent; and
(ii) Evidence of an oversight program conducted by the ethanol blender, such as periodic sampling and testing of gasoline, for monitoring the volatility of gasoline that the ethanol blender sells, supplies, offers for sale or supply or transports; and
(iii) That the gasoline determined to be in violation contained no more than 10% ethanol (by volume) when it was delivered to the next party in the distribution system.
(7) In paragraphs (g)(1)(i), (g)(2)(i), (g)(3)(i), (g)(4)(ii), (g)(5), and (g)(6)(i) of this section, the respective party must demonstrate by reasonably specific showings, by direct or circumstantial evidence, that it or its employee or agent did not cause the violation.
(8) In addition to the defenses provided in paragraphs (g)(1) through (g)(6) of this section, in any case in which an ethanol blender, distributor, reseller, carrier, retailer, or wholesale purchaser-consumer would be in violation under paragraphs (b), (c), (d), (e) or (f), of this section, as a result of gasoline which contains between 9 and 10 percent ethanol (by volume) but exceeds the applicable standard by more than one pound per square inch (1.0 psi), the ethanol blender, distributor, reseller, carrier, retailer or wholesale purchaser-consumer shall not be deemed in violation if such person can demonstrate, by showing receipt of a certification from the facility from which the gasoline was received or other evidence acceptable to the Administrator, that:
(i) The gasoline portion of the blend complies with the Reid vapor pressure limitations of § 80.27(a); and
(ii) The ethanol portion of the blend does not exceed 10 percent (by volume); and
(iii) No additional alcohol or other additive has been added to increase the Reid vapor pressure of the ethanol portion of the blend.
(a)
(i) Has a sulfur percentage, by weight, no greater than 0.05 percent;
(ii)(A) Has a cetane index of at least 40; or
(B) Has a maximum aromatic content of 35 volume percent; and
(iii) Is free of visible evidence of:
(A) The dye 1,4-dialkylamino-anthraquinone; and
(B) Beginning October 1, 1994;
(
(
(2) In the case of any diesel fuel not intended for use in motor vehicles, no refiner or importer shall add or introduce any amount of the dye 1,4-dialkylamino-anthraquinone into such fuel beginning October 1, 1994.
(b)
(c)
(2) Any person that is the transferor or the transferee of diesel fuel for use in motor vehicles which contains visible evidence of the dye solvent red 164, shall retain the documents required under paragraph (c)(1) of this section for a period of five years from the date of transfer of such fuel and shall provide such documents to the Administrator or the Administrator's representative upon request.
(d)
(e)
(a)
(b)
(1) The carrier, except as provided in paragraph (g)(1) of this section; and
(2) The refiner or importer at whose refinery or import facility the diesel fuel was produced or imported, except as provided in paragraph (g)(2) of this section.
(c)
(1) The distributor or reseller, except as provided in paragraph (g)(3) of this section;
(2) The carrier (if any), if the carrier caused the diesel fuel to violate the standard by fuel switching, blending, mislabeling, or any other means; and
(3) The refiner under whose corporate, trade, or brand name (or that of any of its marketing subsidiaries) the distributor or reseller is operating, except as provided in paragraph (g)(4) of this section.
(d)
(1) The distributor, except as provided in paragraph (g)(3) of this section;
(2) The carrier (if any), if the carrier caused the diesel fuel to violate the standard by fuel switching, blending, mislabeling, or any other means; and
(3) The refiner or importer at whose refinery or import facility the diesel fuel was produced or imported, except as provided in paragraph (g)(2) of this section.
(e)
(1) The retailer or wholesale purchaser-consumer, except as provided in paragraph (g)(5) of this section;
(2) The distributor and/or reseller (if any), except as provided in paragraph (g)(3) of this section;
(3) The carrier (if any), if the carrier caused the diesel fuel to violate the standard by fuel switching, blending, mislabeling, or any other means; and
(4) The refiner whose corporate, trade, or brand name, or that of any of its marketing subsidiaries, is displayed at the retail outlet or wholesale purchaser-consumer facility, except as provided in paragraph (g)(4) of this section.
(f)
(1) The retailer or wholesale purchaser-consumer, except as provided in paragraph (g)(5) of this section;
(2) The distributor (if any), except as provided in paragraph (g)(3) of this section;
(3) The carrier (if any), if the carrier caused the diesel fuel to violate the standard by fuel switching, blending, mislabeling, or any other means; and
(4) The refiner or importer at whose refinery or import facility the diesel fuel was produced or imported, except as provided in paragraph (g)(2) of this section.
(g)
(i) Evidence of an oversight program conducted by the carrier, for monitoring the diesel fuel stored or transported by that carrier, such as periodic sampling and testing of the cetane index and sulfur percentage of incoming diesel fuel. Such an oversight program need not include periodic sampling and testing of diesel fuel in a tank truck operated by a common carrier, but in lieu of such tank truck sampling and testing the common carrier shall demonstrate evidence of an oversight program for monitoring compliance with the diesel fuel requirements of § 80.29 relating to the transport or storage of diesel fuel by tank truck, such as appropriate guidance to drivers on compliance with applicable requirements and the periodic review of records normally received in the ordinary course of business concerning diesel fuel quality and delivery; and
(ii) That the violation was not caused by the carrier or his employee or agent.
(2) In any case in which a refiner or importer would be in violation under paragraphs (b)(2), (d)(3), or (f)(4) of this section, the refiner or importer shall not be deemed in violation if he can demonstrate:
(i) That the violation was not caused by him or his employee or agent; and
(ii) Test results, performed in accordance with the sampling and testing methodologies set forth in appendix G to this part, ASTM standard test method D 2622-87 or ASTM standard test method D 4294-83 for sulfur percentage (Entitled “Standard Test Method for Sulfur in Petroleum Products by Non-Dispersive X-Ray Fluorescence Spectrometry”. ASTM standard test method D 4294-83 is incorporated by reference. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. A copy may be obtained from the American Society for Testing and Materials, 1916 Race Street, Philadelphia, PA 19103. A copy may be inspected at the Air Docket Section (A-130), room M-1500, U.S. Environmental Protection Agency, Docket No. A-86-03, 401 M Street, SW., Washington, DC 20460 or at the Office of the Federal Register, 800 North Capitol Street, NW., suite 700, Washington, DC. Parties using this method must be able to support their data with a quality control plan and demonstrate the ability to accurately perform this test method. They must also have evidence from the manufacturer or others that it reliably produces results substantially equivalent to those produced by ASTM standard test method D 2622-87.), and ASTM standard test method D 1319-88 for aromatic content or ASTM standard method D 976-80 for cetane index, which evidence that the diesel fuel determined to be in violation was in compliance with the diesel fuel standards when it was delivered to the next party in the distribution scheme.
(3) In any case in which a distributor or reseller would be in violation under paragraphs (c)(1), (d)(1), (e)(2) or (f)(2) of this section, the distributor or reseller shall not be deemed in violation if he can demonstrate:
(i) That the violation was not caused by him or his employee or agent; and
(ii) Evidence of an oversight program conducted by the distributor or reseller, such as periodic sampling and testing of diesel fuel, for monitoring the sulfur percentage and cetane index of the diesel fuel that the distributor or reseller sells, supplies, offers for sale or supply, or transports.
(4) In any case in which a refiner would be in violation under paragraphs (c)(3) or (e)(4) of this section, the refiner shall not be deemed in violation if he can demonstrate all of the following:
(i) Test results, performed in accordance with the sampling and testing methodologies set forth in appendix G to this part, ASTM standard test method D 2622-87 or ASTM standard test method D 4294-83 for sulfur percentage (Parties using ASTM standard test method D 4294-83 must be able to support their data with a quality control plan and demonstrate the ability to accurately perform this test method. They must also have evidence from the manufacturer or others that it reliably
(ii) That the violation was not caused by him or his employee or agent; and
(iii) That the violation:
(A) Was caused by an act in violation of law (other than the Act or this part), or an act of sabotage or vandalism, whether or not such acts are violations of law in the jurisdiction where the violation of the requirements of this part occurred, or
(B) Was caused by the action of a reseller or a retailer supplied by such reseller, in violation of a contractual undertaking imposed by the refiner on such reseller designed to prevent such action, and despite reasonable efforts by the refiner (such as periodic sampling and testing) to insure compliance with such contractual obligation, or
(C) Was caused by the action of a retailer who is supplied directly by the refiner (and not by a reseller), in violation of a contractual undertaking imposed by the refiner on such retailer designed to prevent such action, and despite reasonable efforts by the refiner (such as periodic sampling and testing) to insure compliance with such contractual obligation, or
(D) Was caused by the action of a distributor subject to a contract with the refiner for transportation of diesel fuel from a terminal to a distributor, retailer or wholesale purchaser-consumer, in violation of a contractual undertaking imposed by the refiner on such distributor designed to prevent such action, and despite reasonable efforts by the refiner (such as periodic sampling and testing) to ensure compliance with such contractual obligation, or
(E) Was caused by a carrier or other distributor not subject to a contract with the refiner but engaged by him for transportation of diesel fuel from a terminal to a distributor, retailer or wholesale purchaser-consumer, despite reasonable efforts by the refiner (such as specification or inspection of equipment) to prevent such action, or
(F) Occurred at a wholesale purchaser-consumer facility:
(iv) In paragraphs (g)(4)(iii) (A) through (E) of this section, the term
(5) In any case in which a retailer or wholesale purchaser-consumer would be in violation under paragraphs (e)(1) or (f)(1) of this section, the retailer or wholesale purchaser-consumer shall not be deemed in violation if he can demonstrate that the violation was not caused by him or his employee or agent.
(6) In paragraphs (g)(1)(iii), (g)(2)(i), (g)(3)(i), (g)(4)(ii) and (g)(5) of this section, the respective party must demonstrate by reasonably specific showings, by direct or circumstantial evidence, that it or its employee or agent did not cause the violation.
(7) In the case of any distributor or reseller that would be in violation under paragraph (e)(2) or (f)(2) of this section or any wholesale purchaser-consumer or retailer that would be in violation under paragraph (e)(1) or (f)(1) of this section for diesel fuel for use in motor vehicles which contains visible evidence of the dye solvent red 164, the distributor or reseller or wholesale purchaser-consumer or retailer shall not be deemed in violation if he can:
(i) Demonstrate that the violation was not caused by him or his employee or agent,
(ii) Demonstrate that the fuel has been supplied, offered for supply, transported or available for tax-exempt use as defined under section 4082 of the Internal Revenue Code, and
(iii) Provide evidence from the supplier in the form of documentation that the fuel met the applicable standards under paragraph (a)(1) of this section for sulfur and cetane index or aromatics content for use in motor vehicles.
After January 1, 1998 every retailer and wholesale purchaser- consumer handling over 13,660 gallons of liquefied petroleum gas per month shall equip each pump from which liquefied petroleum gas is introduced into motor vehicles with a nozzle that has no greater than 2.0 cm
(a) After January 1, 1998 every retailer and wholesale purchaser-consumer handling over 1,215,000 standard cubic feet of natural gas per month shall equip each pump from which natural gas is introduced into natural gas motor vehicles with a nozzle and hose configuration which vents no more than 1.2 grams of natural gas to the atmosphere per refueling of a vehicle complying with § 86.098-8(d)(1)(iv) of this chapter, as determined by calculation of the geometric shape of the nozzle and hose. After January 1, 2000 this requirement applies to every natural gas retailer and wholesale purchaser-consumer. Any dispensing pump shown to be dedicated to heavy-duty vehicles is exempt from this requirement.
(b) The provisions of paragraph (a) of this section can be waived for refueling stations which were in operation on or before January 1, 1998 provided the station operator can demonstrate, to the satisfaction of the Administrator, that compliance with paragraph (a) of this section would require additional compression equipment or other modifications with costs similar to or greater than the cost of additional compression equipment.
(a) For oxygenated gasoline programs with a minimum oxygen content per gallon or minimum oxygen content requirement in conjunction with a credit program, the following shall apply:
(1) Each gasoline pump stand from which oxygenated gasoline is dispensed at a retail outlet in the control area shall be affixed during the control period with a legible and conspicuous label which contains the following statement:
(2) The posting of the above statement shall be in block letters of no less than 20-point bold type; in a color contrasting with the intended background. The label shall be placed on the vertical surface of the pump on each side with gallonage and price meters and shall be on the upper two-thirds of the pump, clearly readable to the public.
(3) The retailer shall be responsible for compliance with the labeling requirements of this section.
(b) For oxygenated gasoline programs with a credit program and no minimum oxygen content requirement, the following shall apply:
(1) Each gasoline pump stand from which oxygenated gasoline is dispensed at a retail outlet in the control area shall be affixed during the control period with a legible and conspicuous label which contains the following statement:
(2) The posting of the above statement shall be in block letters of no less than 20-point bold type; in a color contrasting with the intended background. The label shall be placed on the vertical surface of the pump on each side with gallonage and price meters and shall be on the upper two-thirds of the pump, clearly readable to the public.
(3) The retailer shall be responsible for compliance with the labeling requirements of this section.
(a) Gasoline that complies with one of the standards specified in § 80.41 (a) through (f) that is relevant for the gasoline, and that meets all other relevant requirements prescribed under § 80.41, shall be deemed certified.
(b) Any refiner or importer may, with regard to a specific fuel formulation, request from the Administrator a certification that the formulation meets one of the standards specified in § 80.41 (a) through (f).
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(i) Oxygen content shall not exceed 3.2 percent by weight from ethanol within the boundaries of any State if the State notifies the Administrator that the use of an oxygenate will interfere with attainment or maintenance of an ambient air quality standard or will contribute to an air quality problem.
(ii) A State may request the standard specified in paragraph (g)(1)(i) of this section separately for reformulated gasoline designated as VOC-controlled and reformulated gasoline not designated as VOC-controlled.
(2) The standard in paragraph (g)(1)(i) of this section shall apply 60 days after the Administrator publishes a notice in the
(h)
(1) The standard for heavy metals, including lead or manganese, on a per-gallon basis, is that reformulated gasoline may contain no heavy metals. The Administrator may waive this prohibition for a heavy metal (other than lead) if the Administrator determines that addition of the heavy metal to the gasoline will not increase, on an aggregate mass or cancer-risk basis, toxic air pollutant emissions from motor vehicles.
(2) In the case of any refinery or importer subject to the simple model standards:
(i) The annual average levels for sulfur, T-90, and olefins cannot exceed that refinery's or importer's 1990 baseline levels for each of these parameters; and
(ii) The 1990 baseline levels and the annual averages for these parameters shall be established using the methodology set forth in §§ 80.91 through 80.92; and
(iii) In the case of a refiner that operates more than one refinery, the standards specified under this paragraph (h)(2) shall be met using the refinery grouping selected by the refiner under § 80.101(h).
(i)
(i) No refinery or importer may be subject to a combination of simple and complex standards during any calendar year; and
(ii) Any refiner or importer that elects to achieve compliance with the anti-dumping requirements using the:
(A) Simple model shall meet the requirements of this subpart D using the simple model standards; or
(B) Complex model or optional complex model shall meet the requirements of this subpart D using the complex model standards.
(2) During the period January 1, 1998 through December 31, 1999, any refiner or importer shall be subject to the
(3) Beginning on January 1, 2000, any refiner or importer shall be subject to the Phase II complex model standards specified in paragraphs (e) and (f) of this section.
(j)
(1) The simple model values for benzene, RVP, and oxygen specified in § 80.41 (a) or (b), as applicable;
(2) The aromatics value which, together with the values for benzene, RVP, and oxygen determined under paragraph (j)(1) of this section, meets the Simple Model toxics requirement specified in paragraph (a) or (b) of this section, as applicable;
(3) The refinery's or importer's individual baseline values for sulfur, E-300, and olefins, as established under § 80.91; and
(4) The appropriate seasonal value of E-200 specified in § 80.45(b)(2).
(k)
(i) The required average RVP level shall be decreased by an additional 0.1 psi; and
(ii) The maximum RVP level for each gallon of averaged gasoline shall be decreased by an additional 0.1 psi.
(2) On each occasion that a covered area fails a complex model VOC emissions reduction survey conducted pursuant to § 80.68, or fails a simple model VOC emissions reduction survey conducted pursuant to § 80.68 during 1997, the VOC emissions performance standard for that covered area beginning in the year following the failure shall be adjusted to be more stringent as follows:
(i) The required average VOC emissions reduction shall be increased by an additional 1.0%; and
(ii) The minimum VOC emissions reduction, for each gallon of averaged gasoline, shall be increased by an additional 1.0%.
(3) In the event that a covered area for which required VOC emissions reductions have been made more stringent passes all VOC emissions reduction surveys in two consecutive years, the averaging standards VOC emissions reduction for that covered area beginning in the year following the second year of passed survey series shall be made less stringent as follows:
(i) The required average VOC emissions reduction shall be decreased by 1.0%; and
(ii) The minimum VOC emissions reduction shall be decreased by 1.0%.
(4) In the event that a covered area for which the required VOC emissions reductions have been made less stringent fails a subsequent VOC emissions reduction survey:
(i) The required average VOC emission reductions for that covered area beginning in the year following this subsequent failure shall be made more stringent by increasing the required average and the minimum VOC emissions reduction by 1.0%; and
(ii) The required VOC emission reductions for that covered area thereafter shall not be made less stringent regardless of the results of subsequent VOC emissions reduction surveys.
(l)
(2) On each occasion that a covered area fails a complex model toxics emissions reduction survey series, conducted pursuant to § 80.68, or fails a simple model toxics emissions reduction survey series conducted pursuant to § 80.68 during 1997, the complex
(3) In the event that a covered area for which the toxics emissions standard has been made more stringent passes all toxics emissions survey series in two consecutive years, the averaging standard for toxics emissions reductions for that covered area beginning in the year following the second year of passed survey series shall be made less stringent by decreasing the average toxics emissions reduction by 1.0%.
(4) In the event that a covered area for which the toxics emissions reduction standard has been made less stringent fails a subsequent toxics emissions reduction survey series:
(i) The standard for toxics emissions reduction for that covered area beginning in the year following this subsequent failure shall be made more stringent by increasing the average toxics emissions reduction by 1.0%; and
(ii) The standard for toxics emissions reduction for that covered area thereafter shall not be made less stringent regardless of the results of subsequent toxics emissions reduction surveys.
(m)
(1) On each occasion that a covered area fails a NO
(2) In the event that a covered area for which required NO
(3) In the event that a covered area for which the required NO
(i) The required average NO
(ii) The required NO
(n)
(i) The average benzene content shall be decreased by 0.05% by volume; and
(ii) The maximum benzene content for each gallon of averaged gasoline shall be decreased by 0.10% by volume.
(2) In the event that a covered area for which the benzene standards have been made more stringent passes all benzene content survey series conducted in two consecutive years, the benzene standards for that covered area beginning in the year following the second year of passed survey series shall be made less stringent as follows:
(i) The average benzene content shall be increased by 0.05% by volume; and
(ii) The maximum benzene content for each gallon of averaged gasoline shall be increased by 0.10% by volume.
(3) In the event that a covered area for which the benzene standards have been made less stringent fails a subsequent benzene content survey series:
(i) The standards for benzene content for that covered area beginning in the year following this subsequent failure shall be the more stringent standards which were in effect prior to the operation of paragraph (n)(2) of this section; and
(ii) The standards for benzene content for that covered area thereafter shall not be made less stringent regardless of the results of subsequent benzene content surveys.
(o)
(2) In the event that a covered area for which the minimum oxygen content standard has been made more stringent passes all oxygen content survey series in two consecutive years, the minimum oxygen content standard for that covered area beginning in the year following the second year of passed survey series shall be made less stringent by decreasing the minimum oxygen content standard by 0.1%.
(3) In the event that a covered area for which the minimum oxygen content standard has been made less stringent fails a subsequent oxygen content survey series:
(i) The standard for minimum oxygen content for that covered area beginning in the year following this subsequent failure shall be made more stringent by increasing the minimum oxygen content standard by 0.1%; and
(ii) The minimum oxygen content standard for that covered area thereafter shall not be made less stringent regardless of the results of subsequent oxygen content surveys.
(p)
(q)
(1) Adjusted standards for a covered area apply to averaged reformulated gasoline that is produced at a refinery or oxygenate blending facility if:
(i) Any averaged reformulated gasoline from that refinery or oxygenate blending facility supplied the covered area during any year a survey was conducted which gave rise to a standards adjustment; or
(ii) Any averaged reformulated gasoline from that refinery or oxygenate blending facility supplies the covered area during any year that the standards are more stringent than the initial standards; unless
(iii) The refiner or oxygenate blender is able to show that the volume of averaged reformulated gasoline from a refinery or oxygenate blending facility that supplied the covered area during any year under paragraphs (q)(1) (i) or (ii) of this section was less than one percent of the reformulated gasoline produced at the refinery or oxygenate blending facility during that year, or 100,000 barrels, whichever is less.
(2) Adjusted standards for a covered area apply to averaged reformulated gasoline that is imported by an importer if:
(i) The covered area with the adjusted standard is located in Petroleum Administration for Defense District (PADD) I, and the gasoline is imported at a facility located in PADDs I, II or III;
(ii) The covered area with the adjusted standard is located in PADD II, and the gasoline is imported at a facility located in PADDs I, II, III, or IV;
(iii) The covered area with the adjusted standard is located in PADD III, and the gasoline is imported at a facility located in PADDs II, III, or IV;
(iv) The covered area with the adjusted standard is located in PADD IV, and the gasoline is imported at a facility located in PADDs II, or IV; or
(v) The covered area with the adjusted standard is located in PADD V, and the gasoline is imported at a facility located in PADDs III, IV, or V; unless
(vi) Any gasoline which is imported by an importer at any facility located in any PADD supplies the covered area, in which case the adjusted standard also applies to averaged gasoline imported at that facility by that importer.
(3) Any gasoline that is transported in a fungible manner by a pipeline,
(4) Adjusted standards apply to all averaged reformulated gasoline produced by a refinery or imported by an importer identified in this paragraph (q), except:
(i) In the case of adjusted VOC standards for a covered area located in VOC Control Region 1, the adjusted VOC standards apply only to averaged reformulated gasoline designated as VOC-controlled intended for use in VOC Control Region 1; and
(ii) In the case of adjusted VOC standards for a covered area located in VOC Control Region 2, the adjusted VOC standards apply only to averaged reformulated gasoline designated as VOC-controlled intended for use in VOC Control Region 2.
(r)
(1) The following States are included in PADD I:
(2) The following States are included in PADD II:
(3) The following States are included in PADD III:
(4) The following States are included in PADD IV:
(5) The following States are included in PADD V:
(a)
(1) The following equations shall comprise the simple model for VOC emissions in VOC Control Region 1 during the summer period:
(2) The following equations shall comprise the simple model for VOC emissions in VOC Control Region 2 during the summer period:
(3) The following equation shall comprise the simple model for VOC emissions during the winter period:
(b)
(1) The following equations shall comprise the simple model for toxics emissions in VOC control region 1 during the summer period:
(i) For any oxygenate or mixtures of oxygenates, the formaldehyde and acetaldehyde shall be calculated with the following equations:
(ii) When calculating formaldehyde and acetaldehyde emissions using the equations in paragraph (b)(1)(i) of this section, oxygen in the form of alcohols which are more complex or have higher molecular weights than ethanol shall be evaluated as if it were in the form of ethanol. Oxygen in the form of methyl ethers other than TAME and MTBE shall be evaluated as if it were in the form of MTBE. Oxygen in the form of ethyl ethers other than ETBE shall be
(2) The following equations shall comprise the simple model for toxics emissions in VOC control region 2 during the summer period:
(i) For any oxygenate or mixtures of oxygenates, the formaldehyde and acetaldehyde shall be calculated with the following equations:
(ii) When calculating formaldehyde and acetaldehyde emissions using the equations in paragraph (b)(2)(i) of this section, oxygen in the form of alcohols which are more complex or have higher molecular weights than ethanol shall be evaluated as if it were in the form of ethanol. Oxygen in the form of methyl ethers other than TAME and MTBE shall be evaluated as if it were in the form of MTBE. Oxygen in the form of ethyl ethers other than ETBE shall be evaluated as if it were in the form of ETBE. Oxygen in the form of non-methyl, non-ethyl ethers shall be evaluated as if it were in the form of ETBE. Oxygen in the form of methanol or non-alcohol, non-ether oxygenates shall not be evaluated with the Simple Model, but instead must be evaluated through vehicle testing under the Complex Model per § 80.48.
(3) The following equations shall comprise the simple model for toxics emissions during the winter period:
(i) For any oxygenate or mixtures of oxygenates, the formaldehyde and acetaldehyde shall be calculated with the following equations:
(ii) When calculating formaldehyde and acetaldehyde emissions using the equations in paragraph (b)(3)(i) of this section, oxygen in the form of alcohols which are more complex or have higher molecular weights than ethanol shall be evaluated as if it were in the form of ethanol. Oxygen in the form of methyl ethers other than TAME and MTBE shall be evaluated as if it were in the form of MTBE. Oxygen in the form of ethyl ethers other than ETBE shall be evaluated as if it were in the form of ETBE. Oxygen in the form of non-methyl, non-ethyl ethers shall be evaluated as if it were in the form of ETBE. Oxygen in the form of methanol or non-alcohol, non-ether oxygenates shall not be evaluated with the Simple Model, but instead must be evaluated through vehicle testing under the Complex Model per § 80.48.
(4) If the fuel aromatics content of the fuel in question is less than 10 volume percent, then an FAROM value of 10 volume percent shall be used when evaluating the toxics emissions equations given in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(c)
(2) The model given in paragraphs (a) and (b) of this section shall be effective from January 1, 1995 through December 31, 1997, unless extended by action of the Administrator.
(a)
(b)
(2) The following properties of the baseline fuels shall be used when determining baseline mass emissions of the various pollutants:
(3) The baseline mass emissions for VOC, NO
(c)
(i)
(ii)
(iii)
(B) During Phase II, fuels with E200 values greater than 65.52 percent shall be evaluated with the E200 fuel parameter set equal to 65.52 percent when calculating VOCE using the equations described in paragraphs (c)(1) (i) and (ii)
(iv)
(B) For fuels with E200, E300 and/or ARO levels outside the ranges defined in table 6, Y
(
(
(C) During Phase I, the “edge target” fuel shall be identical to the target fuel for all fuel parameters, with the following exceptions:
(
(
(
(
(
(
(
(
(
(
(
(
(
(
(D) During Phase II, the “edge target” fuel is identical to the target fuel for all fuel parameters, with the following exceptions:
(
(
(
(
(
(
(
(
(
(
(
(
(
(2) The winter exhaust VOC emissions performance of gasolines shall be given by the equations presented in paragraph (c)(1) of this section with the RVP value set to 8.7 psi for both the baseline and target fuels.
(3) The nonexhaust VOC emissions performance of gasolines in VOC Control Region 1 shall be given by the following equations, where:
(i) During Phase I:
(ii) During Phase II:
(4) The nonexhaust VOC emissions performance of gasolines in VOC Control Region 2 shall be given by the following equations, where:
(i) During Phase I:
(ii) During Phase II:
(5) Winter VOC emissions shall be given by VOCE, as defined in paragraph (c)(2) of this section, using the appropriate baseline emissions given in paragraph (b)(3) of this section. Total nonexhaust VOC emissions shall be set equal to zero under winter conditions.
(6)
(ii) Total winter VOC emissions shall be given by the following equations:
(7)
(ii) The total winter VOC emissions performance of the target fuel in percentage terms from baseline levels shall be given by the following equations during Phase I:
(8)
(ii) The total winter VOC emissions performance of the target fuel in percentage terms from baseline levels shall be given by the following equation during Phase II:
(d)
(i)
(ii)
(iii)
(B) During Phase II, fuels with olefin levels less than 3.77 volume percent shall be evaluated with the OLE fuel parameter set equal to 3.77 volume percent when calculating NO
(iv)
(B) For fuels with SUL, OLE, and/or ARO levels outside the ranges defined in table 7 of paragraph (d)(1)(iv)(A) of this section, Y
(
(
(C) For both Phase I and Phase II, the “edge target” fuel is identical to the target fuel for all fuel parameters, with the following exceptions:
(
(
(
(
(
(
(
(
(
(
(
(
(2) The winter NO
(3) The NO
(e)
(ii) The percentage change in summer toxics performance in VOC Control Regions 1 and 2 shall be given by the following equations:
(2)
(ii) The percentage change in winter toxics performance in VOC Control Regions 1 and 2 shall be given by the following equation:
(3) The year-round toxics performance in VOC Control Regions 1 and 2 shall be derived from volume-weighted performances of individual batches of fuel as described in § 80.67(g).
(4) Exhaust benzene emissions shall be given by the following equation, subject to paragragh (e)(4)(iii) of this section:
(i)
(ii)
(iii) If the aromatics value of the target fuel is less than 10 volume percent, then an aromatics value of 10 volume percent shall be used when evaluating the equations given in paragraphs (e)(4) (i) and (ii) of this section. If the E300 value of the target fuel is greater than 95 volume percent, then an E300 value of 95 volume percent shall be used when evaluating the equations in paragraphs (e)(4)(i) and (ii) of this section.
(5) Formaldehyde mass emissions shall be given by the following equation, subject to paragraphs (e)(5) (iii) and (iv) of this section:
(i)
(ii)
(iii) If the aromatics value of the target fuel is less than 10 volume percent, then an aromatics value of 10 volume percent shall be used when evaluating the equations given in paragraphs (e)(5) (i) and (ii) of this section. If the E300 value of the target fuel is greater than 95 volume percent, then an E300 value of 95 volume percent shall be used when evaluating the equations given in paragraphs (e)(5) (i) and (ii) of this section.
(iv) When calculating formaldehyde emissions and emissions performance, oxygen in the form of alcohols which are more complex or have higher molecular weights than ethanol shall be evaluated as if it were in the form of ethanol. Oxygen in the form of methyl ethers other than TAME and MTBE shall be evaluated as if it were in the form of MTBE. Oxygen in the form of ethyl ethers other than ETBE shall be evaluated as if it were in the form of ETBE. Oxygen in the form of non-methyl, non-ethyl ethers shall be evaluated as if it were in the form of ETBE. Oxygen in the form of methanol or non-alcohol, non-ether oxygenates shall not be evaluated with the Complex Model, but instead must be evaluated through vehicle testing per § 80.48.
(6) Acetaldehyde mass emissions shall be given by the following equation, subject to paragraphs (e)(6) (iii) and (iv) of this section:
(i)
(ii)
(iii) If the aromatics value of the target fuel is less than 10 volume percent, then an aromatics value of 10 volume percent shall be used when evaluating the equations given in paragraphs (e)(6) (i) and (ii) of this section. If the E300 value of the target fuel is greater than 95 volume percent, then an E300 value of 95 volume percent shall be used when evaluating the equations given in paragraphs (e)(6) (i) and (ii) of this section.
(iv) When calculating acetaldehyde emissions and emissions performance, oxygen in the form of alcohols which are more complex or have higher molecular weights than ethanol shall be evaluated as if it were in the form of ethanol. Oxygen in the form of methyl ethers other than TAME and MTBE shall be evaluated as if it were in the form of MTBE. Oxygen in the form of ethyl ethers other than ETBE shall be evaluated as if it were in the form of ETBE. Oxygen in the form of non-methyl, non-ethyl ethers shall be evaluated as if it were in the form of ETBE. Oxygen in the form of methanol or non-alcohol, non-ether oxygenates shall not be evaluated with the Complex Model, but instead must be evaluated through vehicle testing per § 80.48.
(7) 1,3-butadiene mass emissions shall be given by the following equations, subject to paragraph (e)(7)(iii) of this section:
(i)
(ii)
(iii) If the aromatics value of the target fuel is less than 10 volume percent, then an aromatics value of 10 volume percent shall be used when evaluating the equations given in paragraphs (e)(7) (i) and (ii) of this section. If the E300 value of the target fuel is greater than 95 volume percent, then an E300 value of 95 volume percent shall be used when evaluating the equations given in paragraphs (e)(7) (i) and (ii) of this section.
(8) Polycyclic organic matter mass emissions shall be given by the following equation:
(9) Nonexhaust benzene emissions in VOC Control Region 1 shall be given by the following equations for both Phase I and Phase II:
(10) Nonexhaust benzene emissions in VOC Control Region 2 shall be given by the following equations for both Phase I and Phase II:
(f)
(i) For reformulated gasolines:
(ii) For conventional gasoline:
(2) Fuels with one or more properties that do not fall within the ranges described in above shall not be certified or evaluated for their emissions performance using the complex emissions model described in paragraphs (c), (d), and (e) of this section.
(a)
(b)
(c)
(d)
(2) The figures for repeatability and reproducibility given in degrees Fahrenheit in table 9 in the ASTM method are incorrect, and shall not be used.
(e)
(2) Instrument parameters must be adjusted to ensure complete resolution of the benzene, ethanol and methanol peaks because ethanol and methanol may cause interference with ASTM standard method D-3606-92 when present.
(f)
(1)(i)
(ii)
(B) The calibration points are constructed by calculating an amount ratio and response ratio for each level of a particular peak in the instrument's calibration table.
(C) The amount ratio is the amount of the compound divided by the amount of the internal standard for a given level.
(D) The response ratio is the response of the compound divided by the response of the internal standard at this level.
(E) The equation for the curve through the calibration points is calculated using the type fit and origin handling specified in the instrument's calibration table. In the initial study the fit was a second degree polynomial including a forced zero for the origin.
(F) The response of the compound in a sample is divided by the response of the internal standard to provide a response ratio for that compound in the sample.
(G) A corrected amount ratio for the unknown is calculated using the curve fit equation determined in paragragh (f)(1)(ii)(E) of this section.
(H) The amount of the aromatic compound is equal to the corrected amount ratio times the Amount of Internal Standard.
(I) The total aromatics in the sample is the sum of the amounts of the individual aromatic compounds in the sample.
(J) An internal standard solution can be made with the following compounds at the listed concentrations in volume percent. Also listed is the Chemical Abstracts Service Registry Number (CAS), atomic mass unit (amu) on which the detector must be set at the corresponding retention time if used in the selective ion mode, retention times in minutes, and boiling point in °C. (Other, similar, boiling point materials can be used which are not found in gasoline.) Retention times are approximate and apply only to a 60 meter capillary column used in the initial study. Other columns and retention times can be used.
(
(
(
(K) At least two calibration mixtures which bracket the measured total aromatics concentration must be made with a representative mixture of aromatic compounds. The materials and concentrations used in the highest concentration calibration level in the initial study for this method are listed in this paragraph (f)(1)(ii)(K). Also listed is the Chemical Abstracts Service Registry Number (CAS), atomic mass unit (amu) on which the detector must be set for the corresponding retention time if used in the selective ion mode, retention times in minutes, and in some cases boiling point in °C. The standards are made in 2,2,4-trimethylpentane (iso-octane), [540-84-1]. Other aromatic compounds, and retention times may be acceptable as long as the aromatic values produced meet the criteria found in the quality assurance section for the aromatic methods.
(iii)
(B) The calculation of the aromatic compounds is done by developing calibration curves for each compound using the type fit and origin handling specified in the instrument's calibration table.
(C) The amount of compound in a sample (the corrected amount) is calculated using the equation determined in paragraph (f)(1)(ii) of this section for that compound.
(D) The percent normalized amount of a compound is calculated using the following equation:
(E) The total aromatics is the sum of all the percent normalized aromatic amounts in the sample.
(F) This method allows quantification of non-aromatic compounds in the sample. However, correct quantification can only be achieved if the instrument's calibration table can identify the compounds that are responsible for at least 95 volume percent of the sample and meets the following quality control criteria.
(2) Quality assurance. (i) The performance standards will be from repeated measurement of the calibration mixture, standard reference material, or process control gasoline. The uncertainty in the measured aromatics percentages in the standards must be less than 2.0 volume percent in the fuel at a 95% confidence level.
(ii) If the bias of the standard mean is greater than 2% of the theoretical value, then the standard measurement and measurements of all samples measured subsequent to the previous standard measurement that met the performance criteria must be repeated after re-calibrating the instrument.
(iii) Replicate samples must be within 3.0 volume percent of the previous sample or within 2.0 volume percent of the mean at the 95% confidence level.
(3)
(ii) The refiner or importer test result is correlated with the method specified in paragraph (f)(1) of this section.
(g)
(1)
(ii) This method covers the quantitative determination of the oxygenate content of gasoline through the use of an oxygenate flame ionization detector (OFID). It is applicable to individual organic oxygenated compounds (up to 20 mass percent each) in gasoline having a final boiling point not greater
(iii) The total concentration of oxygen in the gasoline, due to oxygenated components, may also be determined with this method by summation of all peak areas except for dissolved oxygen, water, and the internal standard. Sensitivities to each component oxygenate must be incorporated in the calculation.
(iv) All oxygenated gasoline components (alcohols, ethers, etc.) may be assessed by this method.
(v) The total mass percent of oxygen in the gasoline due to oxygenated components also may be determined with this method by summing all peak areas except for dissolved oxygen, water, and the internal standard.
(vi) Where trade names or specific products are noted in the method, equivalent apparatus and chemical reagents may be used. Mention of trade names or specific products is for the assistance of the user and does not constitute endorsement by the U.S. Environmental Protection Agency.
(2)
(3)
(ii) If samples have been refrigerated they shall be brought to room temperature prior to analysis.
(iii) Gasoline is extremely flammable and should be handled cautiously and with adequate ventilation. The vapors are harmful if inhaled and prolonged breathing of vapors should be avoided. Skin contact should be minimized.
(4)
(ii) An autosampler for the GC is highly recommended.
(iii) A 60-m length, 0.25-mm ID, 1.0-μm film thickness, nonpolar capillary GC column (J&W DB-1 or equivalent) is recommended.
(iv) An integrator or other acceptable system to collect and process the GC signal.
(v) A positive displacement pipet (200 μL) for adding the internal standard.
(5)
(i) Reagent grade oxygenates for internal standards and for preparation of standard solutions.
(ii) Supply of oxygenate-free gasoline for blank assessments and for preparation of standard solutions.
(iii) Calibration standard solutions containing known quantities of suspected oxygenates in gasoline.
(iv) Calibration check standard solutions prepared in the same manner as the calibration standards.
(v) Reference standard solutions containing known quantities of suspected oxygenates in gasoline.
(vi) Glass standard and test sample containers (between 5 and 100 Ml capacity) fitted with a self-sealing polytetrafluoroethlene (PTFE) faced rubber septum crimp-on or screw-down sealing cap for preparation of standards and samples.
(6)
(B) Required calibration standards (percent by volume in gasoline):
(ii) Take a glass sample container and its PTFE faced rubber septum sealing cap. Transfer a quantity of an oxygenate to the sample container and record the mass of the oxygenate to the nearest 0.1 mg. Repeat this process for any additional oxygenates of interest except the internal standard. Add oxygenate-free gasoline to dilute the oxygenates to the desired concentration. Record the mass of gasoline added to the nearest 0.1 mg, and determine and label the standard according to the mass percent quantities of each oxygenate added. These standards are not to exceed 20 mass percent for any individual pure component due to potential hydrocarbon breakthrough and/or loss of calibration linearity.
(iii) Inject a quantity of an internal standard (such as 2-butanol) and weigh the contents again. Record the difference in masses as the mass of internal standard to the nearest 0.1 mg. The mass of the internal standard shall amount to between 2 and 6 percent of the mass of the test sample (standard). The addition of an internal standard reduces errors caused by variations in injection volumes.
(iv) Ensure that the prepared standard is thoroughly mixed and transfer approximately 2 Ml of the solution to a vial compatible with the autosampler if such equipment is used.
(v) At least five concentrations of each of the expected oxygenates should be prepared. The standards should be as equally spaced as possible within the range and may contain more than one oxygenate. A blank for zero concentration assessments is also to be included. Additional standards should be prepared for other oxygenates of concern.
(vi) Based on the recommended chromatographic operating conditions specified in paragraph (g)(7)(i) of this section, determine the retention time of each oxygenate component by analyzing dilute aliquots either separately or in known mixtures. Reference should be made to the Chemical Abstracts Service (CAS) registry number of each of the analytes for proper identification. Approximate retention times for selected oxygenates under these conditions are as follows:
(vii) By GC/OFID analysis, determine the peak area of each oxygenate and of the internal standard.
(viii) Obtain a calibration curve by performing a least-squares fit of the relative area response factors of the oxygenate standards to their relative mass response factors as follows:
(7)
(A) Oxygenate-free helium carrier gas: 1.1 Ml/min (2 bar), 22.7 cm/sec at 115 °C;
(B) Carrier gas split ratio: 1:100;
(C) Zero air FID fuel: 370 Ml/min (2 bar);
(D) Oxygenate free hydrogen FID fuel: 15 Ml/min (2 bar);
(E) Injector temperature: 250 °C;
(F) Injection volume: 0.5 μL;
(G) Cracker reactor temperature: sufficiently high enough temperature to ensure reduction of all hydrocarbons to the elemental states (i.e., C
(H) FID temperature: 400 °C; and
(I) Oven temperature program: 40 °C for 6 min, followed by a temperature increase of 5 °C/min to 50 °C, hold at 50 °C for 5 min, followed by a temperature increase of 25 °C/min to 175 °C, and hold at 175 °C for 2 min.
(ii) Prior to analysis of any samples, inject a sample of oxygenate-free gasoline into the GC to test for hydrocarbon breakthrough overloading the cracker reactor. If breakthrough occurs, the OFID is not operating effectively and must be corrected before samples can be analyzed.
(iii) Prepare gasoline test samples for analysis as follows:
(A) Tare a glass sample container and its PTFE faced rubber septum sealing cap. Transfer a quantity of the gasoline sample to the sample container and record the mass of the transferred sample to the nearest 0.1 mg.
(B) Inject a quantity of the same internal standard (such as 2-butanol) used in generating the standards and weigh the contents again. Record the difference in masses as the mass of internal standard to the nearest 0.1 mg. The mass of the internal standard shall amount to between 2 and 6 percent of the mass of the test sample (standard). The addition of an internal standard reduces errors caused by variations in injection volumes.
(C) Ensure that this test sample (gasoline plus internal standard) is thoroughly mixed and transfer approximately 2 mL of the solution to a vial compatible with the autosampler if such equipment is used.
(iv) After GC/OFID analysis, identify the oxygenates in the sample based on retention times, determine the peak area of each oxygenate and of the internal standard, and calculate the relative area response factor for each oxygenate.
(v) Monitor the peak area of the internal standard. A larger than expected peak area for the internal standard when analyzing a test sample may indicate that this oxygenate is present in the original sample. Prepare a new aliquot of the sample without addition of the oxygenate internal standard. If the presence of the oxygenate previously used as the internal standard can be detected, then either:
(A) The concentration of this oxygenate must be assessed by the method of standard additions; or
(B) An alternative internal standard, based on an oxygenate that is not present in the original sample, must be utilized with new calibration curves.
(vi) Calculate the relative mass response factor (R
(vii) Calculate the mass percent of the oxygenate in the test sample according to the following equation:
(viii) If the mass percent exceeds the calibrated range, gravimetrically dilute a portion of the original sample to a concentration within the calibration range and analyze this sample starting with paragraph (g)(7)(iii) of this section.
(ix) Report the total weight percent oxygen as follows:
(A) Subtract the peak areas due to dissolved oxygen, water, and the internal standard from the total summed peak areas of the chromatogram.
(B) Assume the total summed peak area solely due to one of the oxygenates that the instrument is calibrated for and determine the total mass percent as that oxygenate based on paragraph (g)(7)(vii) of this section. For simplicity, chose an oxygenate having one oxygen atom per molecule.
(C) Multiply this concentration by the molar mass of oxygen and divide by
(x) Sufficient sample should be retained to permit reanalysis.
(8)
(A) The preparation and analysis of laboratory duplicates at a rate of one per analysis batch or at least one per ten samples, whichever is more frequent.
(B) Laboratory duplicates shall be carried through all sample preparation steps independently.
(C) The range (R) for duplicate samples should be less than the following limits:
(D) If the limits in paragraph (g)(8)(i)(C) of this section are exceeded, the sources of error in the analysis should be determined, corrected, and all analyses subsequent to and including the last duplicate analysis confirmed to be within the compliance specifications must be repeated. The specification limits for the range and relative range of duplicate analyses are minimum performance requirements. The performance of individual laboratories may indeed be better than these minimum requirements. For this reason it is recommended that control charts be utilized to monitor the variability of measurements in order to optimally detect abnormal situations and ensure a stable measurement process.
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(ii) The laboratory shall routinely monitor the accuracy of its analyses. The recommendations are:
(A) Calibration check standards and calibration standards may be prepared from the same oxygenate stocks and by the same analyst. However, calibration check standards and calibration standards must be prepared from separate batches of the final diluted standards. For the specification limits listed in paragraph (g)(8)(ii)(C) of this section, the concentration of the check standards should be in the range given in paragraph (g)(8)(i)(C) of this section.
(B) Calibration check standards shall be analyzed at a rate of at least one per analysis batch and at least one per 10 samples, whichever is more frequent.
(C) If the measured concentration of a calibration check standard is outside the range of 100.0%
(D) Independent reference standards should be purchased or prepared from materials that are independent of the calibration standards and calibration check standards, and must not be prepared by the same analyst. For the specification limits listed in paragraph (g)(8)(ii)(F) of this section, the concentration of the reference standards should be in the range given in paragraph (g)(8)(i)(C) of this section.
(E) Independent reference standards shall be analyzed at a rate of at least one per analysis batch and at least one per 100 samples, whichever is more frequent.
(F) If the measured concentration of an independent reference standard is outside the range of 100.0%
(G) The preparation and analysis of spiked samples at a rate of one per analysis batch and at least one per ten samples.
(H) Spiked samples shall be prepared by adding a volume of a standard to a known volume of sample. To ensure adequate method detection limits, the volume of the standard added to the sample shall be limited to 5% or less than the volume of the sample. The spiked sample shall be carried through the same sample preparation steps as the background sample.
(I) The percent recovery of the spiked sample shall be calculated as follows:
(J) If the percent recovery of any individual spiked sample is outside the range 100%
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(iii) The laboratory shall routinely monitor the accuracy of its analyses. At a minimum this shall include:
(A) Calibration check standards and calibration standards may be prepared from the same oxygenate stocks and by the same analyst. However, calibration check standards and calibration standards must be prepared from separate batches of the final diluted standards. For the specification limits listed in paragraph (g)(8)(iii)(C) of this section, the concentration of the check standards should be in the range given in paragraph (g)(8)(iii)(C) of this section.
(B) Calibration check standards shall be analyzed at a rate of one per analysis batch or at least one per ten samples, whichever is more frequent.
(C) If the measured concentration of a calibration check standard is outside the range of 100%
(D) Independent reference standards shall be purchased or prepared from materials that are independent of the calibration standards and calibration check standards, and must not be prepared by the same analyst. For the specification limits listed in paragraph (g)(8)(iii)(F) of this section, the concentration of the reference standards should be in the range given in paragraph (g)(8)(iii)(C) of this section.
(E) Independent reference standards shall be analyzed at a rate of one per analysis batch or at least one per 100 samples, whichever is more frequent.
(F) If the measured concentration of an independent reference standard is outside the range of 100%
(G) If matrix effects are suspected, then spiked samples shall be prepared and analyzed as follows:
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(9)(i) Prior to September 1, 2000, and when the oxygenates present are limited to MTBE, ETBE, TAME, DIPE, tertiary-amyl alcohol, and C1 to C4 alcohols, any refiner, importer, or oxygenate blender may determine oxygen and oxygenate content using ASTM standard method D-4815-93, entitled “Standard Test Method for Determination of MTBE, ETBE, TAME, DIPE,
(ii) The refiner or importer test result is correlated with the method set forth in paragraphs (g)(1) through (g)(8) of this section.
(h)
(a) The provisions of this section apply only if a fuel claims emission reduction benefits from fuel parameters that are not included in the complex emission model or complex emission model database, or if the values of fuel parameters included in the complex emission model set forth in § 80.45 fall outside the range of values for which the complex emission model is deemed valid.
(b) To augment the complex emission model described at § 80.45, the following requirements apply:
(1) The petitioner must obtain prior approval from the Administrator for the design of the test program before beginning the vehicle testing process. To obtain approval, the petitioner must at minimum provide the following information: the fuel parameter to be evaluated for emission effects; the number and description of vehicles to be used in the test fleet, including model year, model name, vehicle identification number (VIN), mileage, emission performance (exhaust THC emission level), technology type, and manufacturer; a description of the methods used to procure and prepare the vehicles; the properties of the fuels to be used in the testing program (as specified at § 80.49); the pollutants and emission categories intended to be evaluated; the precautions used to ensure that the effects of the parameter in question are independent of the effects of other parameters already included in the model; a description of the quality assurance procedures to be used during the test program; the statistical analysis techniques to be used in analyzing the test data, and the identity and location of the organization performing the testing.
(2) Exhaust emissions shall be measured per the requirements of this section and § 80.49 through § 80.62.
(3) The nonexhaust emission model (including evaporative, running loss, and refueling VOC and toxics emissions) shall not be augmented by vehicle testing.
(4) The Agency reserves the right to observe and monitor any testing that is performed pursuant to the requirements of this section.
(5) The Agency reserves the right to evaluate the quality and suitability of data submitted pursuant to the requirements of this section and to reject, re-analyze, or otherwise evaluate such data as is technically warranted.
(6) Upon a showing satisfactory to the Administrator, the Administrator may approve a petition to waive the requirements of this section and § 80.49, § 80.50(a), § 80.60(d)(3), and § 80.60(d)(4) in order to better optimize the test program to the needs of the particular fuel parameter. Any such waiver petition should provide information justifying the requested waiver, including an acceptable rationale and supporting data. Petitioners must obtain approval from the Administrator prior to conducting testing for which the requirements in question are waived. The Administrator may waive the noted requirements in whole or in part, and may impose appropriate conditions on any such waiver.
(c) In the case of petitions to augment the complex model defined at § 80.45 with a new parameter, the effect of the parameter being tested shall be determined separately, for each pollutant and for each emitter class category. If the parameter is not included in the complex model but is represented in whole or in part by one or more parameters included in the model, the petitioner shall be required to demonstrate the emission effects of the parameter in question independent of the effects of the already-included parameters. The petitioner shall also have to demonstrate the effects of the already-included parameters independent of the effects of the parameter in question. The emission performance of each vehicle on the fuels specified at § 80.49, as measured through vehicle testing in accordance with § 80.50 through § 80.62, shall be analyzed to determine the effects of the fuel parameter being tested on emissions according to the following procedure:
(1) The analysis shall fit a regression model to the natural logarithm of emissions measured from addition fuels 1, 2, and 3 only (as specified at § 80.49(a) and adjusted as per paragraph (c)(1)(iv) of this section and § 80.49(d)) that includes the following terms:
(i) A term for each vehicle that shall reflect the effect of the vehicle on emissions independent of fuel compositions. These terms shall be of the form D
(ii) A linear term in the parameter being tested for each emitter class, of the form A
(iii) For the VOC and NO
(iv) To the extent that the properties of fuels 1, 2, and 3 which are incorporated in the complex model differ in value among the three fuels, the complex model shall be used to adjust the observed emissions from test vehicles on those fuels to compensate for those differences prior to fitting the regression model.
(v) The A
(2) After completing the steps outlined in paragraph (c)(1) of this section, the analysis shall fit a regression model to a combined data set that includes vehicle testing results from all seven addition fuels specified at § 80.49(a), the vehicle testing results used to develop the model specified at § 80.45, and vehicle testing results used to support any prior augmentation requests which the Administrator deems necessary.
(i) The analysis shall fit the regression models described in paragraphs (c)(2) (ii) through (v) of this section to the natural logarithm of measured emissions.
(ii) All regressions shall include a term for each vehicle that shall reflect the effect of the vehicle on emissions independent of fuel compositions. These terms shall be of the form D
(iii) All regressions shall include existing complex model terms and their coefficients, including those augmentations that the Administrator deems necessary. All terms and coefficients shall be expressed in centered form. The Administrator shall make available upon request existing complex model terms and coefficients in centered form.
(iv) All regressions shall include the linear and squared terms, and their coefficients, estimated in the final regression model described in paragraph (c)(1) of this section.
(v) The VOC and NO
(3) The model described in paragraphs (c) (1) and (2) of this section shall be developed separately for normal-emitting and higher-emitting vehicles. Each emitter class shall be treated as a distinct population for the purposes of determining regression coefficients.
(4) Once the augmented models described in paragraphs (c) (1) through (3) of this section have been developed, they shall be converted to an uncentered form through appropriate algebraic manipulation.
(5) The augmented model described in paragraph (c)(4) of this section shall be used to determine the effects of the parameter in question at levels between the levels in Fuels 1 and 3, as defined at § 80.49(a)(1), for all fuels which claim emission benefits from the parameter in question.
(d)(1) In the case of petitions to augment the complex model defined at § 80.45 by extending the range of an existing complex model parameter, the effect of the parameter being tested shall be determined separately, for each pollutant and for each technology group and emitter class category, at levels between the extension level and the nearest limit of the core of the data used to develop the unaugmented complex model as follows:
(2) The emission performance of each vehicle on the fuels specified at § 80.49(b)(2), as measured through vehicle testing in accordance with §§ 80.50 through 80.62, shall be analyzed to determine the effects of the fuel parameter being tested on emissions according to the following procedure:
(i) The analysis shall incorporate the vehicle testing data from the extension fuels specified at § 80.49(b), the vehicle testing results used to develop the model specified at § 80.45, and vehicle testing results used to support any prior augmentation requests which the Administrator deems necessary. A regression incorporating the following terms shall be fitted to the natural logarithm of emissions contained in this combined data set:
(A) A term for each vehicle that shall reflect the effect of the vehicle on emissions independent of fuel compositions. These terms shall be of the form D
(B) Existing complex model terms that do not include the parameter being extended and their coefficients, including those augmentations that the Administrator deems necessary. The centering values for these terms shall be identical to the centering values used to develop the complex model described at § 80.45.
(C) Existing complex model terms that include the parameter being extended. The coefficients for these terms shall be estimated by the regression. The centering values for these terms shall be identical to the centering values used to develop the complex model described at § 80.45.
(D) If the unaugmented VOC or NO
(E) The terms defined in paragraphs (d)(2)(i)(C) and (D) of this section shall be evaluated against the statistical criteria defined in paragraph (e) of this section.
(ii) The model described in paragraph (d)(2)(i) of this section shall be developed separately for normal-emitting and higher-emitting vehicles, as defined at § 80.62. Each emitter class shall be treated as a distinct population for the purposes of determining regression coefficients.
(e)
(i) Evidence demonstrating that colinearity problems are not severe, including but not limited to variance inflation statistics of less than 10 for the second-order and interactive terms included in the regression model.
(ii) Evidence demonstrating that the regression residuals are normally distributed, including but not limited to the skewness and Kurtosis statistics for the residuals.
(iii) Evidence demonstrating that overfitting and underfitting risks have been balanced, including but not limited to the use of Mallow's C
(2) The petitioner shall be required to submit evidence with the petition which demonstrates that the appropriate terms have been included in the regression, including at minimum:
(i) Descriptions of the analysis methods used to develop the regressions, including any computer code used to analyze emissions data and the results of regression runs used to develop the proposed augmentation, including intermediate regressions produced during the stepwise regression process.
(ii) Evidence demonstrating that the significance level used to include terms in the model was equal to 0.90.
(f) The complex emission model shall be augmented with the results of vehicle testing as follows:
(1) The terms and coefficients determined in paragraph (c) or (d) of this section shall be used to supplement the complex emission model equation for the corresponding pollutant and emitter category. These terms and coefficients shall be weighted to reflect the contribution of the emitter category to in-use emissions as shown at § 80.45.
(2) If the candidate parameter is not included in the unaugmented complex model and is not represented in whole or in part by one or more parameters included in the model, the modification shall be accomplished by adding the terms and coefficients to the complex model equation for that pollutant, technology group, and emitter category.
(3) If the parameter is included in the complex model but is being tested at levels beyond the current range of the
(i) The terms and coefficients of the complex model described at § 80.45 shall be used to evaluate the emissions performance of fuels with levels of the parameter being tested that are within the valid range of the model, as defined at § 80.45.
(ii) The emissions performance of fuels with levels of the parameter that are beyond the valid range of the unaugmented model shall be given in percentage change terms by 100 − [(100 + A) × (100 + C) / (100 + B)], where:
(A) “A” shall be set equal to the percentage change in emissions for a fuel with identical fuel property values to the fuel being evaluated except for the parameter being extended, which shall be set equal to the nearest limit of the data core, using the unaugmented complex model.
(B) “B” shall be set equal to the percentage change in emissions for the fuel described in paragraph (f)(3)(i) of this section according to the augmented complex model.
(C) “C” shall be set equal to the percentage change in emissions of the actual fuel being evaluated using the augmented complex model.
(g) EPA reserves the right to analyze the data generated during vehicle testing, to use such analyses to determine the validity of other augmentation petitions, and to use such data to update the complex model for use in certifying all reformulated gasolines.
(h) Duration of acceptance of emission effects determined through vehicle testing:
(1) If the Agency does not accept, modify, or reject a particular augmentation for inclusion in an updated complex model (performed through rulemaking), then the augmentation shall remain in effect until the next update to the complex model takes effect.
(2) If the Agency does reject or modify a particular augmentation for inclusion in an updated complex model, then the augmentation shall no longer be able to be used as of the date the updated complex model is deemed to take effect, unless the following conditions and limitations apply:
(i) The augmentation in question may continue to be used by those fuel suppliers which can prove, to the Administrator's satisfaction, that the fuel supplier had already begun producing a fuel utilizing the augmentation at the time the revised model is promulgated.
(ii) The augmentation in question may only be used to evaluate the emissions performance of fuels in conjunction with the complex emission model in effect as of the date of production of the fuels.
(iii) The augmentation may only be used for three years of fuel production, or a total of five years from the date the augmentation first took effect, whichever is shorter.
(3) The Administrator shall determine when sufficient new information on the effects of fuel properties on vehicle emissions has been obtained to warrant development of an updated complex model.
(a) Seven fuels (hereinafter called the “addition fuels”) shall be tested for the purpose of augmenting the complex emission model with a parameter not currently included in the complex emission model. The properties of the addition fuels are specified in paragraphs (a) (1) and (2) of this section. The addition fuels shall be specified with at least the same level of detail and precision as in § 80.43(c), and this information must be included in the petition submitted to the Administrator requesting augmentation of the complex emission model.
(1) The seven addition fuels to be tested when augmenting the complex model specified at § 80.45 with a new fuel parameter shall have the properties specified as follows:
(i) For the purposes of vehicle testing, the “baseline” level of the parameter shall refer to the level of the parameter in Clean Air Act baseline gasoline. The “candidate” level of the parameter shall refer to the most extreme value of the parameter, relative to baseline levels, for which the augmentation shall be valid.
(ii) If the fuel parameter for which the fuel supplier is petitioning EPA to augment the complex emission model (hereinafter defined as the “candidate parameter”) is not specified for Clean Air Act summer baseline fuel, then the baseline level for the candidate parameter shall be set at the levels found in typical gasoline. This level and the justification for this level shall be included in the petitioner's submittal to EPA prior to initiating the test program, and EPA must approve this level prior to the start of the program.
(iii) If the candidate parameter is not specified for Clean Air Act summer baseline fuel, and is not present in typical gasoline, its baseline level shall be zero.
(2) The addition fuels shall contain detergent control additives in accordance with section 211(l) of the Clean Air Act Amendments of 1990 and the associated EPA requirements for such additives.
(3) The addition fuels shall be specified with at least the same level of detail and precision as in § 80.43(c), and this information shall be included in the petition submitted to the Administrator requesting augmentation of the complex emission model.
(i) Paraffin levels in Fuels 1 and 2 shall be altered from the paraffin level in Fuel 3 to compensate for the addition or removal of the candidate parameter, if necessary. Paraffin levels in Fuel 4 shall be altered from the paraffin level in Fuel 5 to compensate for the addition or removal of the candidate parameter, if necessary. Paraffin levels in Fuel 6 shall be altered from the paraffin level in Fuel 7 to compensate for the addition or removal of the candidate parameter, if necessary.
(ii) Other properties of Fuels 4 and 6 shall not vary from the levels for Fuels 5 and 7, respectively, unless such variations are the naturally-occurring result of the changes described in paragraphs (a)(1) and (2) of this section. Other properties of Fuels 1 and 2 shall not vary from the levels for Fuel 3, unless such variations are the naturally- occurring result of the changes described in paragraphs (a)(1) and (2) of this section.
(iii) The addition fuels shall be specified with at least the same level of detail and precision as defined in paragraph (a)(5)(i) of this section, and this information must be included in the petition submitted to the Administrator requesting augmentation of the complex emission model.
(4) The properties of the addition fuels shall be within the blending tolerances defined in this paragraph (a)(4) relative to the values specified in paragraphs (a)(1) and (2) of this section. Fuels that do not meet these tolerances shall require the approval of the Administrator to be used in vehicle
(5) The composition and properties of the addition fuels shall be determined by averaging a series of independent tests of the properties and compositional factors defined in paragraph (a)(5)(i) of this section as well as any additional properties or compositional factors for which emission benefits are claimed.
(i) The number of independent tests to be conducted shall be sufficiently large to reduce the measurement uncertainty for each parameter to a sufficiently small value. At a minimum the 95% confidence limits (as calculated using a standard t-test) for each parameter must be within the following range of the mean measured value of each parameter:
(ii) The 95% confidence limits for measurements of fuel parameters for which emission reduction benefits are claimed and for which tolerances are not defined in paragraph (a)(5)(i) of this section must be within
(iii) Each test must be conducted in the same laboratory in accordance with the procedures outlined at § 80.46.
(b) Three fuels (hereinafter called the “extension fuels”) shall be tested for the purpose of extending the valid range of the complex emission model for a parameter currently included in the complex emission model. The properties of the extension fuels are specified in paragraphs (b)(2) through (4) of this section. The extension fuels shall be specified with at least the same level of detail and precision as in § 80.43(c), and this information must be included in the petition submitted to the Administrator requesting augmentation of the complex emission model. Each set of three extension fuels shall be used only to extend the range of a single complex model parameter.
(1) The “extension level” shall refer to the level to which the parameter being tested is to be extended. The three fuels to be tested when extending the range of fuel parameters already included in the complex model or a prior augmentation to the complex model shall be referred to as “extension fuels.”
(2) The composition and properties of the extension fuels shall be as described in paragraphs (b)(2) (i) and (ii) of this section.
(i) The extension fuels shall have the following levels of the parameter being extended:
(ii) The levels of parameters other than the one being extended shall be given by the following table for all three extension fuels:
(3) If the Complex Model for any pollutant includes one or more interactive terms involving the parameter being extended, then two additional extension fuels shall be required to be tested for each such interactive term. These additional extension fuels shall have the following properties:
(i) The parameter being tested shall be present at its extension level.
(ii) The interacting parameter shall be present at the levels specified in paragraph (b)(2)(i) of this section for extension Fuels 2 and 3.
(iii) All other parameters shall be present at the levels specified in paragraph (b)(2)(ii) of this section.
(4) All extension fuels shall contain detergent control additives in accordance with Section 211(l) of the Clean Air Act Amendments of 1990 and the associated EPA requirements for such additives.
(c) The addition fuels defined in paragraph (a) of this section and the extension fuels defined in paragraph (b) of this section shall meet the following requirements for blending and measurement precision:
(1) The properties of the test and extension fuels shall be within the blending tolerances defined in this paragraph (c) relative to the values specified in paragraphs (a) and (b) of this section. Fuels that do not meet the following tolerances shall require the approval of the Administrator to be used in vehicle testing to augment the complex emission model:
(2) The extension and addition fuels shall be specified with at least the same level of detail and precision as defined in paragraph (c)(2)(ii) of this section, and this information must be included in the petition submitted to the Administrator requesting augmentation of the complex emission model.
(i) The composition and properties of the addition and extension fuels shall be determined by averaging a series of independent tests of the properties and compositional factors defined in paragraph (c)(2)(ii) of this section as well as any additional properties or compositional factors for which emission benefits are claimed.
(ii) The number of independent tests to be conducted shall be sufficiently large to reduce the measurement uncertainty for each parameter to a sufficiently small value. At a minimum the 95% confidence limits (as calculated using a standard t-test) for each parameter must be within the following range of the mean measured value of each parameter:
(iii) Petitioners shall obtain approval from EPA for the 95% confidence limits for measurements of fuel parameters for which emission reduction benefits are claimed and for which tolerances are not defined in paragraph (c)(2)(i) of this section.
(iv) Each test must be conducted in the same laboratory in accordance with the procedures outlined at § 80.46.
(v) The complex emission model described at § 80.45 shall be used to adjust the emission performance of the addition and extension fuels to compensate for differences in fuel compositions that are incorporated in the complex model, as described at § 80.48. Compensating adjustments for naturally-resulting variations in fuel parameters shall also be made using the complex model. The adjustment process is described in paragraph (d) of this section.
(d) The complex emission model described at § 80.45 shall be used to adjust the emission performance of addition and extension fuels to compensate for differences in fuel parameters other than the parameter being tested. Compensating adjustments for naturally-resulting variations in fuel parameters shall also be made using the complex model. These adjustments shall be calculated as follows:
(1) Determine the exhaust emissions performance of the actual addition or extension fuels relative to the exhaust emissions performance of Clean Air Act baseline fuel using the complex model. For addition fuels, set the level of the parameter being tested at baseline levels for purposes of emissions performance evaluation using the complex model. For extension fuel
(2) Calculate adjustment factors for each addition fuel as follows:
(i) Adjustment factors shall be calculated using the formula:
(ii) Adjustment factors shall be calculated for each pollutant and for each emitter class.
(3) Multiply the measured emissions from each vehicle by the corresponding adjustment factor for the appropriate addition or extension fuel, pollutant, and emitter class. Use the resulting adjusted emissions to conduct all modeling and emission effect estimation activities described in § 80.48.
(e) All fuels included in vehicle testing programs shall have an octane number of 87.5, as measured by the (R+M)/2 method following the ASTM D4814 procedures, to within the measurement and blending tolerances specified in paragraph (c) of this section.
(f) A single batch of each addition or extension fuel shall be used throughout the duration of the testing program.
(a) The following test procedure must be followed when testing to augment the complex emission model described at § 80.45.
(1) VOC, NO
(2) Toxics emissions must be measured when testing the extension fuels per the requirements of § 80.49(a) or when testing addition fuels 1, 2, and 3 per the requirements of § 80.49(a).
(3) When testing addition fuels 4, 5, 6, and 7 per the requirements of § 80.49(a), toxics emissions need not be measured. However, EPA reserves the right to require the inclusion of such measurements in the test program prior to approval of the test program if evidence exists which suggests that adverse interactive effects of the parameter in question may exist for toxics emissions.
(b) The general requirements per 40 CFR 86.130-96 shall be met.
(c) The engine starting and restarting procedures per 40 CFR 86.136-90 shall be followed.
(d) Except as provided for at § 80.59, general preparation of vehicles being tested shall follow procedures detailed in 40 CFR 86.130-96 and 86.131-96.
The test sequence applicable when augmenting the emission models through vehicle testing is as follows:
(a) Prepare vehicles per § 80.50.
(b) Initial preconditioning per § 80.52(a)(1). Vehicles shall be refueled randomly with the fuels required in § 80.49 when testing to augment the complex emission model.
(c) Exhaust emissions tests, dynamometer procedure per 40 CFR 86.137-90 with:
(1) Exhaust Benzene and 1,3-Butadiene emissions measured per § 80.55; and
(2) Formaldehyde and Acetelaldehyde emissions measured per § 80.56.
(a) Initial vehicle preconditioning and preconditioning between tests with different fuels shall be performed in accordance with the “General vehicle handling requirements” per 40 CFR 86.132-96, up to and including the completion of the hot start exhaust test.
(b) The preconditioning procedure prescribed at 40 CFR 86.132-96 shall be observed for preconditioning vehicles between tests using the same fuel.
(a) Sampling for benzene and 1,3-butadiene must be accomplished by bag sampling as used for total hydrocarbons determination. This procedure is detailed in 40 CFR 86.109.
(b) Benzene and 1,3-butadiene must be analyzed by gas chromatography. Expected values for benzene and 1,3-butadiene in bag samples for the baseline fuel are 4.0 ppm and 0.30 ppm respectively. At least three standards ranging from at minimum 50% to 150% of these expected values must be used to calibrate the detector. An additional standard of at most 0.01 ppm must also be measured to determine the required limit of quantification as described in paragraph (d) of this section.
(c) The sample injection size used in the chromatograph must be sufficient to be above the laboratory determined limit of quantification (LOQ) as defined in paragraph (d) of this section for at least one of the bag samples. A control chart of the measurements of the standards used to determine the response, repeatability, and limit of quantitation of the instrumental method for 1,3-butadiene and benzene must be reported.
(d) As in all types of sampling and analysis procedures, good laboratory practices must be used. See, Lawrence, Principals of Environmental Analysis, 55 Analytical Chemistry 14, at 2210-2218 (1983) (copies may be obtained from the publisher, American Chemical Society, 1155 16th Street NW., Washington, DC 20036). Reporting reproducibility control charts and limits of detection measurements are integral procedures to assess the validity of the chosen analytical method. The repeatability of the test method must be determined by measuring a standard periodically during testing and recording the measured values on a control chart. The control chart shows the error between the measured standard and the prepared standard concentration for the periodic testing. The error between the measured standard and the actual standard indicates the uncertainty in the analysis. The limit of detection (LOD) is determined by repeatedly measuring a blank and a standard prepared at a concentration near an assumed value of the limit of detection. If the average concentration minus the average of the blanks is greater than three standard deviations of these measurements, then
(e) Other sampling and analytical techniques will be allowed if they can be proven to have equal specificity and equal or better limits of quantitation. Data from alternative methods that can be demonstrated to have equivalent or superior limits of detection, precision, and accuracy may be accepted by the Administrator with individual prior approval.
(a) Formaldehyde and acetaldehyde will be measured by drawing exhaust samples from heated lines through either 2,4-Dinitrophenylhydrazine (DNPH) impregnated cartridges or impingers filled with solutions of DNPH in acetonitrile (ACN) as described in §§ 86.109 and 86.140 of this chapter for formaldehyde analysis. Diluted exhaust sample volumes must be at least 15 L for impingers containing 20 ml of absorbing solution (using more absorbing solution in the impinger requires proportionally more gas sample to be taken) and at least 4 L for cartridges. As required in § 86.109 of this chapter, two impingers or cartridges must be connected in series to detect breakthrough of the first impinger or cartridge.
(b) In addition, sufficient sample must be drawn through the collecting cartridges or impingers so that the measured quantity of aldehyde is sufficiently greater than the minimum limit of quantitation of the test method for at least a portion of the exhaust test procedure. The limit of quantitation is determined using the technique defined in § 80.55(d).
(c) Each of the impinger samples are quantitatively transferred to a 25 mL volumetric flask (5 mL more than the sample impinger volume) and brought to volume with ACN. The cartridge samples are eluted in reversed direction by gravity feed with 6mL of ACN. The eluate is collected in a graduated test tube and made up to the 5mL mark with ACN. Both the impinger and cartridge samples must be analyzed by HPLC without additional sample preparation.
(d) The analysis of the aldehyde derivatives collected is accomplished with a high performance liquid chromatograph (HPLC). Standards consisting of the hydrazone derivative of formaldehyde and acetaldehyde are used to determine the response, repeatability, and limit of quantitation of the HPLC method chosen for acetaldehyde and formaldehyde.
(e) Other sampling and analytical techniques will be allowed if they can be proven to have equal specificity and equal or better limits of quantitation. Data from alternative methods that can be demonstrated to have equivalent or superior limits of detection, precision, and accuracy may be accepted by the Administrator with individual prior approval.
(a) The test fleet must consist of only 1989-91 MY vehicles which are technologically equivalent to 1990 MY vehicles, or of 1986-88 MY vehicles for which no changes to the engine or exhaust system that would significantly affect emissions have been made through the 1990 model year. To be technologically equivalent vehicles at minimum must have closed-loop systems and possess adaptive learning.
(b) No maintenance or replacement of any vehicle component is permitted except when necessary to ensure operator safety or as specifically permitted in § 80.60 and § 80.61. All vehicle maintenance procedures must be reported to the Administrator.
(c) Each vehicle in the test fleet shall have no fewer than 4,000 miles of accumulated mileage prior to being included in the test program.
(a) Candidate vehicles which conform to the emission performance requirements defined in paragraphs (b)
(b) Candidate vehicles for the test fleet must be screened for their exhaust VOC emissions in accordance with the provisions in § 80.62.
(c) On the basis of pretesting pursuant to paragraph (b) of this section, the test fleet shall be subdivided into two emitter group sub-fleets: the normal emitter group and the higher emitter group.
(1) Each vehicle with an exhaust total hydrocarbon (THC) emissions rate which is less than or equal to twice the applicable emissions standard shall be placed in the normal emitter group.
(2) Each vehicle with an exhaust THC emissions rate which is greater than two times the applicable emissions standard shall be placed in the higher emitter group.
(d) The test vehicles in each emitter group must conform to the requirements of paragraphs (d)(1) through (4) of this section.
(1) Test vehicles for the normal emitter sub-fleet must be selected from the list shown in this paragraph (d)(1). This list is arranged in order of descending vehicle priority, such that the order in which vehicles are added to the normal emitter sub-fleet must conform to the order shown (e.g., a ten-vehicle normal emitter group sub-fleet must consist of the first ten vehicles listed in this paragraph (d)(1)). If more vehicles are tested than the minimum number of vehicles required for the normal emitter sub-fleet, additional vehicles are to be added to the fleet in the order specified in this paragraph (d)(1), beginning with the next vehicle not already included in the group. The vehicles in the normal emitter sub-fleet must possess the characteristics indicated in the list. If the end of the list is reached in adding vehicles to the normal emitter sub-fleet and additional vehicles are desired then they shall be added beginning with vehicle number one, and must be added to the normal emitter sub-fleet in accordance with the order in table A:
(2) Test vehicles for the higher emitter sub-fleet shall be selected from the in-use fleet in accordance with paragraphs (a) and (b) of this section and with § 80.59. Test vehicles for the higher emitter sub-fleet are not required to follow the pattern established in paragraph (d)(1) of this section.
(3) The minimum test fleet size is 20 vehicles. Half of the vehicles tested must be included in the normal emitter sub-fleet and half of the vehicles tested must be in the higher emitter sub-fleet. If additional vehicles are tested beyond the minimum of twenty vehicles, the additional vehicles shall be distributed equally between the normal and higher emitter sub-fleets.
(4) For each emitter group sub-fleet, 70
One of the two following test procedures must be used to screen candidate vehicles for their exhaust THC emissions to place them within the emitter group sub-fleets in accordance with the requirements of § 80.60.
(a) Candidate vehicles may be tested for their exhaust THC emissions using the Federal test procedure as detailed in 40 CFR part 86, with gasoline conforming to requirements detailed in 40 CFR 86.113-90. The results shall be used in accordance with the requirements in § 80.60 to place the vehicles within their respective emitter groups.
(b) Alternatively, candidate vehicles may be screened for their exhaust THC emissions with the IM240 short test procedure.
(1) A candidate vehicle with IM240 test results <0.367 grams THC per vehicle mile shall be classified as a normal emitter.
(2) A candidate vehicle with IM240 test results "0.367 grams THC per vehicle mile shall be classified as a higher emitter.
(a)
(1) At any location other than retail outlets and wholesale purchaser-consumer facilities on or after December 1, 1994; and
(2) At any location on or after January 1, 1995.
(b)
(c)
(i) Those standards and requirements it designated under paragraph (d) of this section for per-gallon compliance on a per-gallon basis; and
(ii) Those standards and requirements it designated under paragraph (d) of this section for average compliance on an average basis over the applicable averaging period; except that
(iii) Refiners and importers are not required to meet the oxygen standard for RBOB.
(2) Any oxygenate blender, for each batch of reformulated gasoline it produces by blending oxygenate with RBOB shall, subsequent to the addition of oxygenate, meet the oxygen standard either per-gallon or average over the applicable averaging period.
(3)(i) For each averaging period, and separately for each parameter that may be met either per-gallon or on average, any refiner shall designate for each refinery, and any importer or oxygenate blender shall designate, its gasoline or RBOB as being subject to the standard applicable to that parameter on either a per-gallon or average basis. For any specific averaging period and parameter all batches of gasoline or RBOB shall be designated as being subject to the per-gallon standard, or all batches of gasoline and RBOB shall be designated as being subject to the average standard. For any specific averaging period and parameter a refiner for a refinery, or any importer or oxygenate blender, may not designate certain batches as being subject to the per-gallon standard and others as being subject to the average standard.
(ii) In the event any refiner for a refinery, or any importer or oxygenate blender, fails to meet the requirements of paragraph (c)(3)(i) of this section and for a specific averaging period and parameter designates certain batches as being subject to the per-gallon standard and others as being subject to the average standard, all batches produced or imported during the averaging period that were designated as being subject to the average standard shall,
(d)
(1) All gasoline produced or imported shall be properly designated as either reformulated or conventional gasoline, or as RBOB.
(2) All gasoline designated as reformulated or as RBOB shall be further properly designated as:
(i) Either VOC-controlled or not VOC-controlled;
(ii) In the case of gasoline or RBOB designated as VOC-controlled, either intended for use in VOC-Control Region 1 or VOC-Control Region 2 (as defined in § 80.71);
(iii) [Reserved]
(A) Gasoline must be designated as oxygenated fuels program reformulated gasoline if such gasoline:
(
(
(B) Gasoline may be designated as oxygenated fuels program reformulated gasoline if such gasoline has an oxygen content that is greater than or equal to 2.0 weight percent, regardless of whether the gasoline is intended for use in any oxygenated fuels program control area during an oxygenated fuels program control period.
(iv) For gasoline or RBOB produced, imported, sold, dispensed or used during the period January 1, 1995 through December 31, 1997, either as being subject to the simple model standards, or to the complex model standards;
(v) For each of the following parameters, either gasoline or RBOB which meets the standard applicable to that parameter on a per-gallon basis or on average:
(A) Toxics emissions performance;
(B) NO
(C) Benzene content;
(D) With the exception of RBOB, oxygen content;
(E) In the case of VOC-controlled gasoline or RBOB certified using the simple model, RVP; and
(F) In the case of VOC-controlled gasoline or RBOB certified using the complex model, VOC emissions performance; and
(vi) In the case of RBOB, as RBOB that may be blended with:
(A) Any oxygenate;
(B) Ether only;
(C) Any renewable oxygenate;
(D) Renewable ether only;
(E) Non-VOC controlled renewable ether only.
(3) Every batch of reformulated or conventional gasoline or RBOB produced or imported at each refinery or import facility, or each batch of blendstock produced and sold or transferred if blendstock accounting is required under § 80.102(e), shall be assigned a number (the “batch number”), consisting of the EPA-assigned refiner, importer or oxygenate blender registration number, the EPA-assigned facility registration number, the last two digits of the year in which the batch was produced, and a unique number for the batch, beginning with the number one for the first batch produced or imported each calendar year and each subsequent batch during the calendar year being assigned the next sequential number (e.g., 4321-54321-95-000001, 4321-54321-95-000002, etc.).
(e)
(2) In the event that the values of any of these properties is determined by the refiner or importer and by an independent laboratory in conformance with the requirements of paragraph (f) of this section:
(i) The results of the analyses conducted by the refiner or importer for such properties shall be used as the basis for compliance determinations unless the absolute value of the differences of the test results from the two laboratories is larger than the following values:
(ii) In the event the values from the two laboratories for any property fall outside these ranges, the refiner or importer shall use as the basis for compliance determinations:
(A) The larger of the two values for the property, except the smaller of the two results shall be used for oxygenates; or
(B) The refiner shall have the gasoline analyzed for the property at one additional independent laboratory. If this second independent laboratory obtains a result for the property that is within the range, as listed in paragraph (e)(2)(i) of this section, of the refiner's or importer's result for this property, then the refiner's or importer's result shall be used as the basis for compliance determinations.
(f)
(i)
(ii)
(A) An independent laboratory shall collect a representative sample from each batch of reformulated gasoline that the refiner or importer produces or imports;
(B) EPA will identify up to ten percent of the total number of samples collected under paragraph (f)(1)(ii)(A) of this section; and
(C) The designated independent laboratory shall, for each sample identified by EPA under paragraph (f)(1)(ii)(B) of this section, determine the value for each property using the methodologies specified in § 80.46.
(2)(i) Any refiner or importer shall designate one independent laboratory for each refinery or import facility at which reformulated gasoline or RBOB is produced or imported. This independent laboratory will collect samples and perform analyses in compliance with the requirements of this paragraph (f) of this section.
(ii) Any refiner or importer shall identify this designated independent laboratory to EPA under the registration requirements of § 80.76.
(iii) In order to be considered independent:
(A) The laboratory shall not be operated by any refiner or importer, and shall not be operated by any subsidiary or employee of any refiner or importer;
(B) The laboratory shall be free from any interest in any refiner or importer; and
(C) The refiner or importer shall be free from any interest in the laboratory; however
(D) Notwithstanding the restrictions in paragraphs (f)(2)(iii) (A) through (C) of this section, a laboratory shall be considered independent if it is owned or operated by a gasoline pipeline company, regardless of ownership or operation of the gasoline pipeline company by refiners or importers, provided that such pipeline company is owned and operated by four or more refiners or importers.
(iv) Use of a laboratory that is debarred, suspended, or proposed for debarment pursuant to the Governmentwide Debarment and Suspension regulations, 40 CFR part 32, or the Debarment, Suspension and Ineligibility provisions of the Federal Acquisition Regulations, 48 CFR part 9, subpart 9.4, shall be deemed noncompliance with the requirements of this paragraph (f).
(v) Any laboratory that fails to comply with the requirements of this paragraph (f) shall be subject to debarment or suspension under Governmentwide Debarment and Suspension regulations, 40 CFR part 32, or the Debarment, Suspension and Ineligibility regulations, Federal Acquisition Regulations, 48 CFR part 9, subpart 9.4.
(3) Any refiner or importer shall, for all samples collected or analyzed pursuant to the requirements of this paragraph (f), cause its designated independent laboratory:
(i) At the time the designated independent laboratory collects a representative sample from a batch of reformulated gasoline, to:
(A) Obtain the refiner's or importer's assigned batch number for the batch being sampled;
(B) Determine the volume of the batch;
(C) Determine the identification number of the gasoline storage tank or tanks in which the batch was stored at the time the sample was collected;
(D) Determine the date and time the batch became finished reformulated gasoline, and the date and time the sample was collected;
(E) Determine the grade of the batch (e.g., premium, mid-grade, or regular); and
(F) In the case of reformulated gasoline produced through computer-controlled in-line blending, determine the date and time the blending process began and the date and time the blending process ended, unless exempt under paragraph (f)(4) of this section;
(ii) To retain each sample collected pursuant to the requirements of this
(iii) To submit to EPA periodic reports, as follows:
(A) A report for the period January through March shall be submitted by May 31; a report for the period April through June shall be submitted by August 31; a report for the period July through September shall be submitted by November 30; and a report for the period October through December shall be submitted by February 28;
(B) Each report shall include, for each sample of reformulated gasoline that was analyzed pursuant to the requirements of this paragraph (f):
(
(
(iv) To supply to EPA, upon EPA's request, any sample collected or a portion of any such sample.
(4) Any refiner that produces reformulated gasoline using computer-controlled in-line blending equipment is exempt from the independent sampling and testing requirements specified in paragraphs (f)(1) through (3) of this section and from the requirement of paragraph (e)(1) of this section to obtain test results for each batch prior to the gasoline leaving the refinery, provided that such refiner:
(i) Obtains from EPA an exemption from these requirements. In order to seek such an exemption, the refiner shall submit a petition to EPA, such petition to include:
(A) A description of the refiner's computer-controlled in-line blending operation, including a description of:
(
(
(
(
(
(
(
(
(
(
(B) A description of the independent audit program of the refiner's computer-controlled in-line blending operation that the refiner proposes will satisfy the requirements of this paragraph (f)(4); and
(ii) Carries out an independent audit program of the refiner's computer-controlled in-line blending operation, such program to include:
(A) For each batch of reformulated gasoline produced using the operation, a review of the documents generated that is sufficient to determine the properties and volume of the gasoline produced;
(B) Audits that occur no less frequently than annually;
(C) Reports of the results of such audits submitted to the refiner, and to
(D) Audits that are conducted by an auditor that meets the non-debarred criteria specified in § 80.125 (a) and/or (d); and
(iii) Complies with any other requirements that EPA includes as part of the exemption.
(g)
(h)
(i)
At 59 FR 39289, Aug. 2, 1994, § 80.65 was amended by revising paragraph (d)(2)(vi) effective September 1, 1994. At 59 FR 60715, Nov. 28, 1994, the amendment was stayed effective September 13, 1994.
(a) All volume measurements required by these regulations shall be temperature adjusted to 60 degrees Fahrenheit.
(b) The percentage of oxygen by weight contained in a gasoline blend, based upon its percentage oxygenate by volume and density, shall exclude denaturants and water.
(c) The properties of reformulated gasoline consist of per-gallon values separately and individually determined on a batch-by-batch basis using the methodologies specified in § 80.46 for each of those physical and chemical parameters necessary to determine compliance with the standards to which the gasoline is subject, and per-gallon values for the VOC, NO
(d) Per-gallon oxygen content shall be determined based upon the weight percent oxygen of a representative sample of gasoline, using the method set forth in § 80.46(g). The total oxygen content associated with a batch of gasoline (in percent-gallons) is calculated by multiplying the weight percent oxygen content times the volume.
(e) Per-gallon benzene content shall be determined based upon the volume percent benzene of a representative sample of a batch of gasoline by the method set forth in § 80.46(e). The total benzene content associated with a batch of gasoline (in percent-gallons) is calculated by multiplying the volume percent benzene content times the volume.
(f) Per-gallon RVP shall be determined based upon the measurement of RVP of a representative sample of a batch of gasoline by the sampling methodologies specified in appendix D of this part and the testing methodology specified in appendix E of this part. The total RVP value associated with a batch of gasoline (in RVP-gallons) is calculated by multiplying the RVP times the volume.
(g)(1) Per gallon values for VOC and NO
(2) Per-gallon values for toxic emissions performance reduction shall be established using:
(i) For gasoline subject to the simple model, the methodology under § 80.42 that is appropriate for the gasoline; and
(ii) For gasoline subject to the complex model, the methodology specified in § 80.45 that is appropriate for the gasoline.
(3) The total VOC, NO
The requirements of this section apply to all reformulated gasoline and RBOB produced or imported for which compliance with one or more of the requirements of § 80.41 is determined on average (“averaged gasoline”).
(a)
(2)(i)(A) A refiner or importer that produces or imports reformulated gasoline that exceeds the average standards for oxygen or benzene (but not for other parameters that have average standards) may use such gasoline to offset reformulated gasoline which does not achieve such average standards, but only if the reformulated gasoline that does not achieve such average standards is sold to ultimate consumers in the same covered area as was the reformulated gasoline which exceeds average standards; provided that
(B) Prior to the beginning of the averaging period when the averaging approach described in paragraph (a)(2)(i)(A) of this section is used, the refiner or importer obtains approval from EPA. In order to seek such approval, the refiner or importer shall submit a petition to EPA, such petition to include:
(
(
(C) The refiner or importer properly completes any requirements that are specified by EPA as conditions for approval of the petition.
(ii) Any refiner or importer that meets the requirements of paragraph (a)(2)(i) of this section will be deemed to have satisfied the compliance survey requirements of § 80.68 for the covered area in question.
(b)
(2)(i) Any importer shall meet all applicable averaged standards on the basis of all averaged reformulated gasoline and RBOB imported by the importer; except that
(ii) Any importer to whom different standards apply for gasoline imported at different facilities by operation of § 80.41(i), shall meet the averaged standards separately for the averaged reformulated gasoline and RBOB imported into each group of facilities that is subject to the same standards; and
(3) Any oxygenate blender shall meet the averaged standard for oxygen separately for each of the oxygenate blender's oxygenate blending facilities, except that any oxygenate blender may group the averaged reformulated gasoline produced at facilities at which gasoline is produced for use in a single covered area.
(c)
(i) Gasoline and RBOB designated for VOC Control Region 1 must meet the standards for that Region which are applicable to that refinery or importer; and
(ii) Gasoline and RBOB designated for VOC Control Region 2 must meet the standards for that Region which are applicable to that refinery or importer.
(2) In the case of a refinery or importer subject to the simple model standards, each gallon of reformulated gasoline and RBOB designated as being VOC-controlled may not exceed the maximum standards for RVP specified in § 80.41(b) which are applicable to that refiner or importer.
(3) In the case of a refinery or importer subject to the complex model standards, each gallon of reformulated gasoline designated as being VOC-controlled must equal or exceed the minimum standards for VOC emissions performance specified in § 80.41 which are applicable to that refinery or importer.
(d)
(2) The reformulated gasoline and RBOB produced at any refinery or imported by any importer during the toxics emissions performance and benzene averaging periods that is designated for average compliance for these parameters shall on average meet the standards specified for toxics emissions performance and benzene in § 80.41 which are applicable to that refinery or importer.
(3) Each gallon of reformulated gasoline may not exceed the maximum standard for benzene content specified in § 80.41 which is applicable to that refinery or importer.
(e)
(2) The requirements of this paragraph (e) apply separately to reformulated gasoline and RBOB in the following categories:
(i) All reformulated gasoline and RBOB that is designated as VOC-controlled; and
(ii) All reformulated gasoline and RBOB that is not designated as VOC-controlled.
(3) The reformulated gasoline and RBOB produced at any refinery or imported by any importer during the NO
(f)
(2) The requirements of this paragraph (f) apply separately to reformulated gasoline in the following categories:
(i) All reformulated gasoline;
(ii) [Reserved]
(iii) In the case of reformulated gasoline certified under the simple model, that which is designated as VOC- controlled.
(3) The reformulated gasoline produced at any refinery or imported by any importer during the oxygen averaging period that is designated for average compliance for oxygen shall on average meet the standards for oxygen specified in § 80.41 that is applicable to that refinery or importer.
(4) The reformulated gasoline that is produced at any oxygenate blending facility by blending RBOB with oxygenate that is designated for average compliance for oxygen shall on average meet the standards for oxygen specified in § 80.41 that is applicable to that oxygenate blending facility.
(5) Each gallon of reformulated gasoline must meet the applicable minimum requirements, and in the case of simple model reformulated gasoline the minimum and maximum requirements, for oxygen content specified in § 80.41.
(g)
(1)(i) The compliance total using the following formula:
(ii) The actual total using the following formula:
(2) For each standard, compare the actual total with the compliance total.
(3) For the VOC, NO
(4) For RVP and benzene standards, the actual total must be equal to or less than the compliance totals to achieve compliance.
(5) If the actual total for the oxygen standard is less than the compliance total, or if the actual total for the benzene standard is greater than the compliance total, credits for these parameters must be obtained from another refiner, importer or (in the case of oxygen) oxygenate blender in order to achieve compliance:
(i) The total number of oxygen credits required to achieve compliance is calculated by subtracting the actual total from the compliance total oxygen; and
(ii) The total number of benzene credits required to achieve compliance is calculated by subtracting the compliance total from the actual total benzene.
(6) If the actual total for the oxygen standard is greater than the compliance total, or if the actual total for the benzene standard is less than the compliance totals, credits for these parameters are generated:
(i) The total number of oxygen credits which may be traded to another refinery, importer, or oxygenate blender is calculated by subtracting the compliance total from the actual total for oxygen; and
(ii) The total number of benzene credits which may be traded to another refinery or importer is calculated by subtracting the actual total from the compliance total for benzene.
(h)
(i) The credits were generated in the same averaging period as they are used;
(ii) The credit transfer takes place no later than fifteen working days following the end of the averaging period in which the reformulated gasoline credits were generated;
(iii) The credits are properly created;
(iv) The credits are transferred directly from the refiner, importer, or oxygenate blender that creates the credits to the refiner, importer, or oxygenate blender that uses the credits to achieve compliance;
(v) Oxygen credits are generated, transferred, and used:
(A) In the case of gasoline subject to the simple model standards, only in the following categories:
(
(
(B) [Reserved]
(vi) Oxygen credits generated from gasoline subject to the complex model standards are not used to achieve compliance for gasoline subject to the simple model standards;
(vii) Oxygen credits are not used to achieve compliance with the minimum oxygen content standards in § 80.41; and
(viii) Benzene credits are not used to achieve compliance with the maximum benzene content standards in § 80.41.
(2) No party may transfer any credits to the extent such a transfer would result in the transferor having a negative credit balance at the conclusion of the averaging period for which the credits were transferred. Any credits transferred in violation of this paragraph are improperly created credits.
(3) In the case of credits that were improperly created, the following provisions apply:
(i) Improperly created credits may not be used to achieve compliance, regardless of a credit transferee's good faith belief that it was receiving valid credits;
(ii) No refiner, importer, or oxygenate blender may create, report, or transfer improperly created credits; and
(iii) Where any credit transferor has in its balance at the conclusion of any averaging period both credits which were properly created and credits which were improperly created, the properly created credits will be applied first to any credit transfers before the transferor may apply any credits to achieve its own compliance.
(i)
(1) Any refiner or importer may meet standards specified in § 80.41 for average compliance for such gasoline, provided the refiner or importer has the option of meeting standards on average for 1995 under paragraph (a) of this section, and provided the refiner or importer elects to be subject to average standards under § 80.65(c)(3); and
(2) Any average compliance gasoline under paragraph (i)(1) of this section shall be combined with average compliance gasoline produced during 1995 for purposes of compliance calculations under paragraph (g) of this section.
(a)
(1) The survey program shall consist of at least four surveys which shall occur during the following time periods: one survey during the period January 1 through May 31; two surveys during the period June 1 through September 15; and one survey during the period September 16 through December 31.
(2) The survey program shall meet the criteria stated in paragraph (c) of this section.
(3) In the event that any refiner, importer, or oxygenate blender fails to properly carry out an approved survey program, the refiner, importer, or oxygenate blender shall achieve compliance with all applicable standards on a per-gallon basis for the calendar year in which the failure occurs, and may not achieve compliance with any standard on an average basis during this calendar year. This requirement to achieve compliance per-gallon shall apply
(b)
(1) The initial schedule for the conduct of surveys shall be as follows:
(i) 120 surveys shall be conducted in 1995;
(ii) 80 surveys shall be conducted in 1996;
(iii) 60 surveys shall be conducted in 1997;
(iv) 70 surveys shall be conducted in 1998 and thereafter.
(2) This initial survey schedule shall be adjusted as follows:
(i) In the event one or more ozone nonattainment areas in addition to the nine specified in § 80.70, opt into the reformulated gasoline program, the number of surveys to be conducted in the year the area or areas opt into the program and in each subsequent year shall be increased according to the following formula:
(ii) In the event that any covered area fails a survey or survey series according to the criteria set forth in paragraph (c) of this section, the annual decreases in the numbers of surveys prescribed by paragraph (b)(1) of this section, as adjusted by paragraph (b)(2)(i) of this section, shall be adjusted as follows in the year following the year of the failure. Any such adjustment to the number of surveys shall remain in effect so long as any standard for the affected covered area has been adjusted to be more stringent as a result of a failed survey or survey series. The adjustments shall be calculated according to the following formula:
(3) The survey program shall meet the criteria stated in paragraph (c) of this section.
(4) On each occasion the comprehensive survey program does not occur as specified in the approved plan with regard to any covered area:
(i) Each refiner, importer, and oxygenate blender who supplied any reformulated gasoline or RBOB to the covered area and who has not satisfied the survey requirements described in paragraph (a) of this section shall be deemed to have failed to carry out an approved survey program; and
(ii) The covered area will be deemed to have failed surveys for VOC and NO
(c)
(i) Any sample taken from a retail gasoline storage tank for which the three most recent deliveries were of gasoline designated as meeting:
(A) Simple model standards shall be considered a “simple model sample”; or
(B) Complex model standards shall be considered a “complex model sample.”
(ii) A survey shall consist of the combination of a simple model portion and a complex model portion, as follows:
(A) The simple model portion of a survey shall consist of all simple model samples that are collected pursuant to the applicable survey design in a single covered area during any consecutive seven-day period and that are not excluded under paragraph (c)(6) of this section.
(B) The complex model portion of a survey shall consist of all complex model samples that are collected pursuant to the applicable survey design in a single covered area during any consecutive seven-day period and that are not excluded under paragraph (c)(6) of this section.
(iii)(A) The simple model portion of each survey shall be representative of all gasoline certified using the simple model which is being dispensed in the covered area.
(B) The complex model portion of each survey shall be representative of all gasoline certified using the complex model which is being dispensed in the covered area.
(2) Beginning on January 1, 1998:
(i) A survey shall consist of all samples that are collected pursuant to the applicable survey design in a single covered area during any consecutive seven-day period and that are not excluded under paragraph (c)(6) of this section.
(ii) A survey shall be representative of all gasoline which is being dispensed in the covered area.
(3) A VOC survey and a NO
(4)(i) A toxics, oxygen, and benzene survey series shall consist of all surveys conducted in a single covered area during a single calendar year.
(ii) A NO
(5)(i) Each simple model sample included in a survey shall be analyzed for oxygenate type and content, benzene content, aromatic hydrocarbon content, and RVP in accordance with the methodologies specified in § 80.46; and
(ii) Each complex model sample included in a survey shall be analyzed for oxygenate type and content, olefins, benzene, sulfur, and aromatic hydrocarbons, E-200, E-300, and RVP in accordance with the methodologies specified in § 80.46.
(6)(i) The results of each survey shall be based upon the results of the analysis of each sample collected during the course of the survey, unless the sample violates the applicable per-gallon maximum or minimum standards for the parameter being evaluated plus any enforcement tolerance that applies to the parameter (
(ii) Any sample from a survey that violates any standard under § 80.41, or that constitutes evidence of the violation of any prohibition or requirement under this subpart D, may be used by the Administrator in an enforcement action for such violation.
(7) Each laboratory at which samples in a survey are analyzed shall participate in a correlation program with EPA to ensure the validity of analysis results.
(8)(i) The results of each simple model VOC survey shall be determined as follows:
(A) For each simple model sample from the survey, the VOC emissions reduction percentage shall be determined based upon the tested values for RVP and oxygen for that sample as applied to the VOC emissions reduction equation at § 80.42(a)(1) for VOC-Control Region 1 and § 80.42(a)(2) for VOC-Control Region 2;
(B) The VOC emissions reduction survey standard applicable to each covered area shall be calculated by using the VOC emissions equation at § 80.42(a)(1) with RVP = 7.2 and OXCON = 2.0 for covered areas located in VOC-Control Region 1 and using the VOC emissions equation at § 80.42(a)(2) with RVP = 8.1 and OXCON = 2.0 for covered areas located in VOC-Control Region 2; and
(C) The covered area shall have failed the simple model VOC survey if the VOC emissions reduction average of all survey samples is less than VOC emissions reduction survey standard calculated under paragraph (c)(8)(i)(B) of this section.
(ii) The results of each complex model VOC emissions reduction survey shall be determined as follows:
(A) For each complex model sample from the survey series, the VOC emissions reduction percentage shall be determined based upon the tested parameter values for that sample and the appropriate methodology for calculating VOC emissions reduction at § 80.45;
(B) The covered area shall have failed the complex model VOC survey if the VOC emissions reduction percentage average of all survey samples is less than the applicable per-gallon standard for VOC emissions reduction.
(9)(i) The results of each simple model toxics emissions reduction survey series conducted in any covered area shall be determined as follows:
(A) For each simple model sample from the survey series, the toxics emissions reduction percentage shall be determined based upon the tested parameter values for that sample and the appropriate methodology for calculating toxics emissions performance reduction at § 80.42.
(B) The annual average of the toxics emissions reduction percentages for all samples from a survey series shall be calculated according to the following formula:
(C) The covered area shall have failed the simple model toxics survey series if the annual average toxics emissions reduction is less than the simple model per-gallon standard for toxics emissions reduction.
(ii) The results of each complex model toxics emissions reduction survey series conducted in any covered area shall be determined as follows:
(A) For each complex model sample from the survey series, the toxics emissions reduction percentage shall be determined based upon the tested parameter values for that sample and the appropriate methodology for calculating toxics emissions reduction at § 80.45;
(B) The annual average of the toxics emissions reduction percentages for all samples from a survey series shall be calculated according to the formula specified in paragraph (c)(9)(i)(B) of this section; and
(C) The covered area shall have failed the complex model toxics survey series if the annual average toxics emissions reduction is less than the applicable per-gallon complex model standard for toxics emissions reduction.
(10) The results of each NO
(i) For each sample from the survey and survey series, the NO
(ii) The covered area shall have failed the NO
(11) For any benzene content survey series conducted in any covered area the average benzene content for all samples from the survey series shall be calculated. If this annual average is greater than 1.000 percent by volume, the covered area shall have failed a benzene survey series.
(12) For any oxygen content survey series conducted in any covered area the average oxygen content for all samples from the survey series shall be calculated. If this annual average is less than 2.00 percent by weight, the covered area shall have failed an oxygen survey series.
(13) Each survey program shall:
(i) Be planned and conducted by a person who is independent of the refiner or importer (the surveyor). In order to be considered independent:
(A) The surveyor shall not be an employee of any refiner or importer;
(B) The surveyor shall be free from any obligation to or interest in any refiner or importer; and
(C) The refiner or importer shall be free from any obligation to or interest in the surveyor; and
(ii) Include procedures for selecting sample collection locations, numbers of samples, and gasoline compositions which will result in:
(A) Simple model surveys representing all gasoline certified using the simple model being dispensed at retail outlets within the covered area during the period of the survey; and
(B) Complex model surveys representing all gasoline certified using the complex model being dispensed at retail outlets within the covered area during the period of the survey; and
(iii) Include procedures such that the number of samples included in each survey assures that:
(A) In the case of simple model surveys, the average levels of oxygen, benzene, RVP, and aromatic hydrocarbons are determined with a 95% confidence level, with error of less than 0.1 psi for RVP, 0.05% for benzene (by volume), and 0.1% for oxygen (by weight); and
(B) In the case of complex model surveys, the average levels of oxygen, benzene, RVP, aromatic hydrocarbons, olefins, T-50, T-90 and sulfur are determined with a 95% confidence level, with error of less than 0.1 psi for RVP, 0.05% for benzene (by volume), 0.1% for oxygen (by weight), 0.5% for olefins (by volume), 5 °F. for T-50 and T-90, and 10 ppm for sulfur; or an equivalent level of precision for the complex model-determined emissions parameters; and
(iv) Require that the surveyor shall:
(A) Not inform anyone, in advance, of the date or location for the conduct of any survey;
(B) Upon request by EPA made within thirty days following the submission of the report of a survey, provide a duplicate of any gasoline sample taken during that survey to EPA at a location to be specified by EPA each sample to be identified by the name and address of the facility where collected, the date of collection, and the classification of the sample as simple model or complex model; and
(C) At any time permit any representative of EPA to monitor the conduct of the survey, including sample collection, transportation, storage, and analysis; and
(v) Require the surveyor to submit to EPA a report of each survey, within thirty days following completion of the survey, such report to include the following information:
(A) The identification of the person who conducted the survey;
(B) An attestation by an officer of the surveyor company that the survey was conducted in accordance with the survey plan and that the survey results are accurate;
(C) If the survey was conducted for one refiner or importer, the identification of that party;
(D) The identification of the covered area surveyed;
(E) The dates on which the survey was conducted;
(F) The address of each facility at which a gasoline sample was collected, the date of collection, and the classification of the sample as simple model or complex model;
(G) The results of the analyses of simple model samples for oxygenate type and oxygen weight percent, benzene content, aromatic hydrocarbon content, and RVP, the calculated toxics emission reduction percentage, and for each survey conducted during the period June 1 through September 15 the VOC emissions reduction percentage calculated using the methodology specified in paragraph (c)(8)(i) of this section;
(H) The results of the analyses of complex model samples for oxygenate type and oxygen weight percent, benzene, aromatic hydrocarbon, and olefin content, E-200, E-300, and RVP, the calculated NO
(I) The name and address of each laboratory where gasoline samples were analyzed;
(J) A description of the methodology utilized to select the locations for sample collection and the numbers of samples collected;
(K) For any samples which were excluded from the survey, a justification for such exclusion; and
(L) The average toxics emissions reduction percentage for simple model samples and the percentage for complex model samples, the average benzene and oxygen percentages, and for each survey conducted during the period June 1 through September 15, the average VOC emissions reduction percentage for simple model samples and the percentage for complex model samples, and the average NO
(14) Each survey shall be conducted at a time and in a covered area selected by EPA no earlier than two weeks before the date of the survey.
(15) The procedure for seeking EPA approval for a survey program plan shall be as follows:
(i) The survey program plan shall be submitted to the Administrator of EPA for EPA's approval no later than September 1 of the year preceding the year in which the surveys will be conducted; and
(ii) Such submittal shall be signed by a responsible corporate officer of the refiner, importer, or oxygenate blender, or in the case of a comprehensive survey program plan, by an officer of the organization coordinating the survey program.
(16)(i) No later than December 1 of the year preceding the year in which the surveys will be conducted, the contract with the surveyor to carry out the entire survey plan shall be in effect, and an amount of money necessary to carry out the entire survey plan shall be paid to the surveyor or placed into an escrow account with instructions to the escrow agent to pay the money over to the surveyor during the course of the conduct of the survey plan.
(ii) No later than December 15 of the year preceding the year in which the surveys will be conducted, the Administrator of EPA shall be given a copy of the contract with the surveyor, proof that the money necessary to carry out the plan has either been paid to the surveyor or placed into an escrow account, and if placed into an escrow account, a copy of the escrow agreement.
The requirements of this section apply to all reformulated gasoline blendstock for oxygenate blending, or RBOB, to which oxygenate is added at any oxygenate blending facility.
(a)
(1) Produce or import the RBOB such that, when blended with a specified type and percentage of oxygenate, it meets the applicable standards for reformulated gasoline;
(2) In order to determine the properties of RBOB for purposes of calculating compliance with per-gallon or averaged standards, conduct tests on each batch of the RBOB by:
(i) Adding the specified type and amount of oxygenate to a representative sample of the RBOB; and
(ii) Determining the properties and characteristics of the resulting gasoline using the methodology specified in § 80.65(e);
(3) Carry out the independent analysis requirements specified in § 80.65(f);
(4) Determine properties of the RBOB which are sufficient to allow parties downstream from the refinery or import facility to establish, through sampling and testing, if the RBOB has been altered or contaminated such that it will not meet the applicable reformulated gasoline standards subsequent to the addition of the specified type and amount of oxygenate;
(5) Transfer ownership of the RBOB only to an oxygenate blender who is registered with EPA as such, or to an intermediate owner with the restriction that it only be transferred to a registered oxygenate blender;
(6) Have a contract with each oxygenate blender who receives any RBOB produced or imported by the refiner or importer that requires the oxygenate blender, or, in the case of a contract with an intermediate owner, that requires the intermediate owner to require the oxygenate blender to:
(i) Comply with blender procedures that are specified by the contract and are calculated to assure blending with the proper type and amount of oxygenate;
(ii) Allow the refiner or importer to conduct quality assurance sampling and testing of the reformulated gasoline produced by the oxygenate blender;
(iii) Stop selling any gasoline found to not comply with the standards under which the RBOB was produced or imported; and
(iv) Carry out the quality assurance sampling and testing that this section requires the oxygenate blender to conduct;
(7) Conduct a quality assurance sampling and testing program to be carried out at the facilities of each oxygenate blender who blends any RBOB produced or imported by the refiner or importer with any oxygenate, to determine whether the reformulated gasoline which has been produced through blending complies with the applicable standards, using the methodology specified in § 80.46 for this determination.
(i) The sampling and testing program shall be conducted as follows:
(A) All samples shall be collected subsequent to the addition of oxygenate, and either:
(
(
(B) Sampling and testing shall be at one of the following rates:
(
(
(
(ii) In the event the test results for any sample indicate the gasoline does not comply with applicable standards (within the correlation ranges specified in § 80.65(e)(2)(i)), the refiner or importer shall:
(A) Immediately take steps to stop the sale of the gasoline that was sampled;
(B) Take steps which are reasonably calculated to determine the cause of the noncompliance and to prevent future instances of noncompliance;
(C) Increase the rate of sampling and testing to one of the following rates:
(
(
(
(D) Continue the increased frequency of sampling and testing until the results of ten consecutive samples and tests indicate the gasoline complies with applicable standards, at which time the sampling and testing may be conducted at the original frequency;
(iii) This quality assurance program is in addition to any quality assurance requirements carried out by other parties;
(8) A refiner or importer of RBOB may, in lieu of the contractual and quality assurance requirements specified in paragraphs (a) (6) and (7) of this section, base its compliance calculations on the following assumptions:
(i) In the case of RBOB designated for any-oxygenate, assume that ethanol will be added;
(ii) In the case of RBOB designated for ether-only, assume that MTBE will be added; and
(iii) In the case of any-oxygenate and ether-only designated RBOB, assume that the volume of oxygenate added will be such that the resulting reformulated gasoline will have an oxygen content of 2.0 weight percent;
(9) Any refiner or importer who does not meet the contractual and quality assurance requirements specified in paragraphs (a) (6) and (7) of this section, and who does not designate its RBOB as ether-only or any-oxygenate, shall base its compliance calculations on the assumption that 4.0 volume percent ethanol is added to the RBOB; and
(10) Specify in the product transfer documentation for the RBOB each oxygenate type or types and amount or range of amounts which is consistent with the designation of the RBOB as any-oxygenate, or ether-only, and which, if blended with the RBOB will result in reformulated gasoline which:
(i) Has VOC, toxics, or NO
(ii) Has a benzene content and RVP level which are no higher than the values for these characteristics that formed the basis for the refiner's or importer's compliance determinations for these parameters; and
(iii) Will not cause the reformulated gasoline to violate any standard specified in § 80.41.
(b)
(1) Add oxygenate of the type(s) and amount (or within the range of amounts) specified in the product transfer documents for the RBOB;
(2) Designate each batch of the resulting reformulated gasoline as meeting the oxygen standard per-gallon or on average;
(3) Meet the standard requirements specified in § 80.65(c) and § 80.67(f), the record keeping requirements specified in § 80.74, and the reporting requirements specified in § 80.75; and
(4) In the case of each batch of reformulated gasoline which is designated for compliance with the oxygen standard on average:
(i) Determine the volume and the weight percent oxygen of the batch using the testing methodology specified in § 80.46;
(ii) Assign a number to the batch (the “batch number”), beginning with the number one for the first batch produced each calendar year and each subsequent batch during the calendar year being assigned the next sequential number, and such numbers to be preceded by the oxygenate blender's registration number, the facility number, and the second two digits of the year in which the batch was produced (e.g., 4321-4321-95-001, 4321-4321-95-002, etc.); and
(iii) Meet the compliance audit requirements specified in § 80.65(h).
(c)
(d)
(1) Transfer the RBOB only to an oxygenate blender who has registered with the Administrator of EPA as such;
(2) Transfer any RBOB designated as ether-only RBOB only if the distributor has a reasonable basis for knowing the oxygenate blender will blend an oxygenate other than ethanol with the RBOB; and
(3) Obtain from the oxygenate blender the oxygenate blender's EPA registration number.
(e)
(1) On each occasion it obtains RBOB from a distributor, supply the distributor with the oxygenate blender's EPA registration number;
(2) Conduct a quality assurance sampling and testing program to determine whether the proper type and amount of oxygenate is added to RBOB. The program shall be conducted as follows:
(i) All samples shall be collected subsequent to the addition of oxygenate, and either:
(A) Prior combining the resulting gasoline with any other gasoline; or
(B) Subsequent to the delivery of the gasoline to a retail outlet or wholesale purchaser-consumer facility provided that the three most recent deliveries to the retail outlet or wholesale purchaser facility were of gasoline that was produced by that oxygenate blender and that had the same oxygenate requirements, and provided that any discrepancy in oxygenate type or amount found through the retail outlet or wholesale purchaser facility sampling is followed-up with measures reasonably designed to discover the cause of the discrepancy;
(ii) Sampling and testing shall be at one of the following rates:
(A) In the case computer-controlled in-line blending is used, a rate of not less than one sample per each five hundred occasions RBOB and oxygenate are loaded into a truck by that oxygenate blender, or one sample every three months, whichever is more frequent; or
(B) In the case computer-controlled in-line blending is not used, a rate of not less than one sample per each one hundred occasions RBOB and oxygenate are blended in a truck by that oxygenate blender, or one sample per month, whichever is more frequent;
(iii) Sampling and testing shall be of the gasoline produced through one of the RBOB-oxygenate blends produced by that oxygenate blender;
(iv) Samples shall be analyzed for oxygenate type and oxygen content using
(v) In the event the testing results for any sample indicate the gasoline does not contain the specified type and amount of oxygenate (within the ranges specified in § 80.70(b)(2)(i)):
(A) Immediately stop selling (or where possible, to stop any transferee of the gasoline from selling) the gasoline which was sampled;
(B) Take steps to determine the cause of the noncompliance;
(C) Increase the rate of sampling and testing to one of the following rates:
(
(
(D) This increased frequency shall continue until the results of ten consecutive samples and tests indicate the gasoline complies with applicable standards, at which time the frequency may revert to the original frequency.
For purposes of subparts D, E, and F of this part, the covered areas are as follows:
(a) The Los Angeles-Anaheim-Riverside, California, area, comprised of:
(1) Los Angeles County;
(2) Orange County;
(3) Ventura County;
(4) That portion of San Bernadino County that lies south of latitude 35 degrees, 10 minutes north and west of longitude 115 degrees, 45 minutes west; and
(5) That portion of Riverside County, which lies to the west of a line described as follows:
(i) Beginning at the northeast corner of Section 4, Township 2 South, Range 5 East, a point on the boundary line common to Riverside and San Bernadino Counties;
(ii) Then southerly along section lines to the centerline of the Colorado River Aqueduct;
(iii) Then southeasterly along the centerline of said Colorado River Aqueduct to the southerly line of Section 36, Township 3 South, Range 7 East;
(iv) Then easterly along the township line to the northeast corner of Section 6, Township 4 South, Range 9 East;
(v) Then southerly along the easterly line of Section 6 to the southeast corner thereof;
(vi) Then easterly along section lines to the northeast corner of Section 10, Township 4 South, Range 9 East;
(vii) Then southerly along section lines to the southeast corner of Section 15, Township 4 South, Range 9 East;
(viii) Then easterly along the section lines to the northeast corner of Section 21, Township 4 South, Range 10 East;
(ix) Then southerly along the easterly line of Section 21 to the southeast corner thereof;
(x) Then easterly along the northerly line of Section 27 to the northeast corner thereof;
(xi) Then southerly along section lines to the southeast corner of Section 34, Township 4 South, Range 10 East;
(xii) Then easterly along the township line to the northeast corner of Section 2, Township 5 South, Range 10 East;
(xiii) Then southerly along the easterly line of Section 2, to the southeast corner thereof;
(xiv) Then easterly along the northerly line of Section 12 to the northeast corner thereof;
(xv) Then southerly along the range line to the southwest corner of Section 18, Township 5 South, Range 11 East;
(xvi) Then easterly along section lines to the northeast corner of Section 24, Township 5 South, Range 11 East; and
(xvii) Then southerly along the range line to the southeast corner of Section 36, Township 8 South, Range 11 East, a point on the boundary line common to Riverside and San Diego Counties.
(b) San Diego County, California.
(c) The Greater Connecticut area, comprised of:
(1) The following Connecticut counties:
(i) Hartford;
(ii) Middlesex;
(iii) New Haven;
(iv) New London;
(v) Tolland;
(vi) Windham; and
(2) Portions of certain Connecticut counties, described as follows:
(i) In Fairfield County, the City of Shelton; and
(ii) In Litchfield County, all cities and townships except the towns of Bridgewater and New Milford.
(d) The New York-Northern New Jersey-Long Island-Connecticut area, comprised of:
(1) Portions of certain Connecticut counties, described as follows:
(i) In Fairfield County, all cities and townships except Shelton City;
(ii) In Litchfield County, the towns of Bridgewater and New Milford;
(2) The following New Jersey counties:
(i) Bergen;
(ii) Essex;
(iii) Hudson;
(iv) Hunterdon;
(v) Middlesex;
(vi) Monmouth;
(vii) Morris;
(viii) Ocean;
(ix) Passaic;
(x) Somerset;
(xi) Sussex;
(xii) Union; and
(3) The following New York counties:
(i) Bronx;
(ii) Kings;
(iii) Nassau;
(iv) New York (Manhattan);
(v) Queens;
(vi) Richmond;
(vii) Rockland;
(viii) Suffolk;
(ix) Westchester;
(x) Orange; and
(xi) Putnam.
(e) The Philadelphia-Wilmington-Trenton area, comprised of:
(1) The following Delaware counties:
(i) New Castle; and
(ii) Kent;
(2) Cecil County, Maryland;
(3) The following New Jersey counties:
(i) Burlington;
(ii) Camden;
(iii) Cumberland;
(iv) Gloucester;
(v) Mercer;
(vi) Salem; and
(4) The following Pennsylvania counties:
(i) Bucks;
(ii) Chester;
(iii) Delaware;
(iv) Montgomery; and
(v) Philadelphia.
(f) The Chicago-Gary-Lake County, Illinois-Indiana-Wisconsin area, comprised of:
(1) The following Illinois counties:
(i) Cook;
(ii) Du Page;
(iii) Kane;
(iv) Lake;
(v) McHenry;
(vi) Will;
(2) Portions of certain Illinois counties, described as follows:
(i) In Grundy County, the townships of Aux Sable and Goose Lake; and
(ii) In Kendall County, Oswego township; and
(3) The following Indiana counties:
(i) Lake; and
(ii) Porter.
(g) The Baltimore, Maryland area, comprised of:
(1) The following Maryland counties:
(i) Anne Arundel;
(ii) Baltimore;
(iii) Carroll;
(iv) Harford;
(v) Howard; and
(2) The City of Baltimore.
(h) The Houston-Galveston-Brazoria, Texas area, comprised of the following Texas counties:
(1) Brazoria;
(2) Fort Bend;
(3) Galveston;
(4) Harris;
(5) Liberty;
(6) Montgomery;
(7) Waller; and
(8) Chambers.
(i) The Milwaukee-Racine, Wisconsin area, comprised of the following Wisconsin counties:
(1) Kenosha;
(2) Milwaukee;
(3) Ozaukee;
(4) Racine;
(5) Washington; and
(6) Waukesha.
(j) The ozone nonattainment areas listed in this paragraph (j) are covered areas for purposes of subparts D, E, and F of this part. The geographic extent of each covered area listed in this paragraph (j) shall be the nonattainment area boundaries as specified in 40 CFR part 81, subpart C:
(1) Sussex County, Delaware;
(2) District of Columbia portion of the Washington ozone nonattainment area;
(3) The following Kentucky counties:
(i) Boone;
(ii) Campbell;
(iii) Jefferson; and
(iv) Kenton;
(4) Portions of the following Kentucky counties:
(i) Portion of Bullitt County described as follows:
(A) Beginning at the intersection of Ky 1020 and the Jefferson-Bullitt County Line proceeding to the east along the county line to the intersection of county road 567 and the Jefferson-Bullitt County Line;
(B) Proceeding south on county road 567 to the junction with Ky 1116 (also known as Zoneton Road);
(C) Proceeding to the south on KY 1116 to the junction with Hebron Lane;
(D) Proceeding to the south on Hebron Lane to Cedar Creek;
(E) Proceeding south on Cedar Creek to the confluence of Floyds Fork turning southeast along a creek that meets Ky 44 at Stallings Cemetery;
(F) Proceeding west along Ky 44 to the eastern most point in the Shepherdsville city limits;
(G) Proceeding south along the Shepherdsville city limits to the Salt River and west to a point across the river from Mooney Lane;
(H) Proceeding south along Mooney Lane to the junction of Ky 480;
(I) Proceeding west on Ky 480 to the junction with Ky 2237;
(J) Proceeding south on Ky 2237 to the junction with Ky 61 and proceeding north on Ky 61 to the junction with Ky 1494;
(K) Proceeding south on Ky 1494 to the junction with the perimeter of the Fort Knox Military Reservation;
(L) Proceeding north along the military reservation perimeter to Castleman Branch Road;
(M) Proceeding north on Castleman Branch Road to Ky 44;
(N) Proceeding a very short distance west on Ky 44 to a junction with Ky 1020; and
(O) Proceeding north on Ky 1020 to the beginning.
(ii) Portion of Oldham County described as follows:
(A) Beginning at the intersection of the Oldham-Jefferson County Line with the southbound lane of Interstate 71;
(B) Proceeding to the northeast along the southbound lane of Interstate 71 to the intersection of Ky 329 and the southbound lane of Interstate 71;
(C) Proceeding to the northwest on Ky 329 to the intersection of Zaring Road on Ky 329;
(D) Proceeding to the east-northeast on Zaring Road to the junction of Cedar Point Road and Zaring Road;
(E) Proceeding to the north-northeast on Cedar Point Road to the junction of Ky 393 and Cedar Point Road;
(F) Proceeding to the south-southeast on Ky 393 to the junction of county road 746 (the road on the north side of Reformatory Lake and the Reformatory);
(G) Proceeding to the east-northeast on county road 746 to the junction with Dawkins Lane (also known as Saddlers Mill Road) and county road 746;
(H) Proceeding to follow an electric power line east-northeast across from the junction of county road 746 and Dawkins Lane to the east-northeast across Ky 53 on to the La Grange Water Filtration Plant;
(I) Proceeding on to the east-southeast along the power line then south across Fort Pickens Road to a power substation on Ky 146;
(J) Proceeding along the power line south across Ky 146 and the Seaboard System Railroad track to adjoin the incorporated city limits of La Grange;
(K) Then proceeding east then south along the La Grange city limits to a point abutting the north side of Ky 712;
(L) Proceeding east-southeast on Ky 712 to the junction of Massie School Road and Ky 712;
(M) Proceeding to the south-southwest and then north-northwest on Massie School Road to the junction of Ky 53 and Massie School Road;
(N) Proceeding on Ky 53 to the north-northwest to the junction of Moody Lane and Ky 53;
(O) Proceeding on Moody Lane to the south-southwest until meeting the city limits of La Grange;
(P) Then briefly proceeding north following the La Grange city limits to the intersection of the northbound lane of Interstate 71 and the La Grange city limits;
(Q) Proceeding southwest on the northbound lane of Interstate 71 until intersecting with the North Fork of Currys Fork;
(R) Proceeding south-southwest beyond the confluence of Currys Fork to the south-southwest beyond the confluence of Floyds Fork continuing on to the Oldham-Jefferson County Line; and
(S) Proceeding northwest along the Oldham-Jefferson County Line to the beginning.
(5) The following Maine counties:
(i) Androscoggin;
(ii) Cumberland;
(iii) Kennebec;
(iv) Knox;
(v) Lincoln;
(vi) Sagadahoc;
(vii) York;
(6) The following Maryland counties:
(i) Calvert;
(ii) Charles;
(iii) Frederick;
(iv) Montgomery;
(v) Prince Georges;
(vi) Queen Anne's; and
(vii) Kent;
(7) The entire State of Massachusetts;
(8) The following New Hampshire counties:
(i) Strafford;
(ii) Merrimack;
(iii) Hillsborough; and
(iv) Rockingham;
(9) The following New Jersey counties:
(i) Atlantic;
(ii) Cape May; and
(iii) Warren;
(10) The following New York counties:
(i) Dutchess;
(ii) The portion of Essex County that consists of the portion of Whiteface Mountain above 4,500 feet in elevation.
(11) The entire State of Rhode Island;
(12) The following Texas counties: and
(i) Collin;
(ii) Dallas;
(iii) Denton; and
(iv) Tarrant;
(13) The following Virginia areas:
(i) Alexandria;
(ii) Arlington County;
(iii) Fairfax;
(iv) Fairfax County;
(v) Falls Church;
(vi) Loudoun County;
(vii) Manassas;
(viii) Manassas Park;
(ix) Prince William County;
(x) Stafford County;
(xi) Charles City County;
(xii) Chesterfield County;
(xiii) Colonial Heights;
(xiv) Hanover County;
(xv) Henrico County;
(xvi) Hopewell;
(xvii) Richmond;
(xviii) Chesapeake;
(xix) Hampton;
(xx) James City County;
(xxi) Newport News;
(xxii) Norfolk;
(xxiii) Poquoson;
(xxiv) Portsmouth;
(xxv) Suffolk;
(xxvi) Virginia Beach;
(xxvii) Williamsburg; and
(xxviii) York County.
(k) Any other area currently or previously designated as a nonattainment area for ozone under 40 CFR 50.9 and part D of Title I of the Clean Air Act, as of November 15, 1990, or any time later, may be included on petition of the governor of the state in which the area is located. Effective one year after an area has been reclassified as a severe ozone nonattainment area, such severe area shall also be a covered area for purposes of this subpart D.
(l) Upon the effective date for removal under § 80.72(a), the geographic area covered by such approval shall no longer be considered a covered area for purposes of subparts D, E and F of this part.
(m) The prohibitions of section 211(k)(5) will apply to all persons other
(n) The prohibitions of section 211(k)(5) of the act will apply to all persons other than retailers and wholesale purchaser-consumers on May 1, 1999. The prohibitions of section 211(k)(5) of the act will apply to retailers and wholesale purchaser-consumers on June 1, 1999. As of the effective date for retailers and wholesale purchaser-consumers, the St. Louis, Missouri ozone nonattainment area is a covered area. The geographical extent of the covered area listed in this paragraph shall be the nonattainment boundaries for the St. Louis ozone nonattainment area as specified in 40 CFR 81.326.
(a) Reformulated gasoline covered areas which are located in the following States are included in VOC-Control Region 1:
(b) Reformulated gasoline covered areas which are located in the following States are included in VOC-Control Region 2:
(c) Reformulated gasoline covered areas which are partially in VOC Control Region 1 and partially in VOC Control Region 2 shall be included in VOC Control Region 1, except in the case of the Philadelphia-Wilmington-Trenton CMSA which shall be included in VOC Control Region 2.
(a) In accordance with paragraph (b) of this section, the Administrator may approve a petition from a state asking for removal of any opt-in area, or portion of an opt-in area, from inclusion as a covered area under § 80.70. If the Administrator approves a petition, he or she shall set an effective date as provided in paragraph (c) of this section. The Administrator shall notify the state in writing of the Agency's action on the petition and the effective date of the removal when the petition is approved.
(b) To be approved under paragraph (a) of this section, a petition must be signed by the Governor of a State, or his or her authorized representative, and must include the following:
(1) A geographic description of each opt-in area, or portion of each opt-in area, which is covered by the petition;
(2) A description of all ways in which reformulated gasoline is relied upon as a control measure in any approved State or local implementation plan or plan revision, or in any submission to the Agency containing any proposed plan or plan revision (and any associated request for redesignation) that is pending before the Agency when the petition is submitted; and
(3) For any opt-in areas covered by the petition for which reformulated gasoline is relied upon as a control measure as described under paragraph (b)(2) of this section, the petition shall include the following information:
(i) Identify whether the State is withdrawing any such pending plan submission;
(ii)(A) Identify whether the State intends to submit a revision to any such approved plan provision or pending plan submission that does not rely on reformulated gasoline as a control measure, and describe the alternative air quality measures, if any, that the State plans to use to replace reformulated gasoline as a control measure;
(B) A description of the current status of any proposed revision to any such approved plan provision or pending plan submission, as well as a projected schedule for submission of such proposed revision;
(iii) If the State is not withdrawing any such pending plan submission and does not intend to submit a revision to any such approved plan provision or pending plan submission, describe why no revision is necessary;
(iv) If reformulated gasoline is relied upon in any pending plan submission, other than as a contingency measure consisting of a future opt-in, and the Agency has found such pending plan submission complete or made a protectiveness finding under 40 CFR 51.448 and 93.128, demonstrate whether the removal of the reformulated gasoline program will affect the completeness and/or protectiveness determinations;
(4) The Governor of a State, or his or her authorized representative, shall submit additional information upon request of the Administrator,
(c)(1) For opt-out petitions received on or before December 31, 1997, except as provided in paragraphs (c)(2) and (c)(3) of this section, the Administrator shall set an effective date for removal of an area under paragraph (a) of this section as requested by the Governor, but no less than 90 days from the Agency's written notification to the state approving the opt-out petition, and no later than December 31, 1999.
(2) For opt-out petitions received on or before December 31, 1997, except as provided in paragraph (c)(3) of this section, where RFG is contained as an element of any plan or plan revision that has been approved by the Agency, other than as a contingency measure consisting of a future opt-in, then the effective date under paragraph (a) of this section shall be the date requested by the Governor, but no less than 90 days from the effective date of Agency approval of a revision to the plan that removes RFG as a control measure.
(3)(i) The Administrator may extend the deadline for submitting opt-out petitions in paragraphs (c)(1) and (2) of this section for a state if:
(A) The Governor or his authorized representative requests an extension prior to December 31, 1997;
(B) The request indicates that there is active or pending legislation before the state legislature that was introduced prior to March 28, 1997;
(C) The legislation is concerning opting out of or remaining in the reformulated gasoline program; and
(D) The request demonstrates that the legislation cannot reasonably be acted upon prior to December 31, 1997.
(ii) The Administrator may extend the deadline until no later than May 31, 1998. If the deadline is extended, then opt-out requests from that state received during the extension shall be considered under the provisions of paragraphs (c)(1) and (2) of this section.
(4) For opt-out petitions received January 1, 1998 through December 31, 2003, except as provided in paragraph (c)(5) of this section, the Administrator shall set an effective date for removal of an area under paragraph (a) of this section as requested by the Governor but no earlier than January 1, 2004 or 90 days from the Agency's written notification to the state approving the opt-out petition, whichever date is later.
(5) For opt-out petitions received January 1, 1998 through December 31, 2003, where RFG is contained as an element of any plan or plan revision that has been approved by the Agency, other than as a contingency measure consisting of a future opt-in, then the effective date for removal of an area under paragraph (a) of this section shall be the date requested by the Governor, but no earlier than January 1, 2004, or 90 days from the effective date of Agency approval of a revision to the
(6) For opt-out petitions received on or after January 1, 2004, except as provided in paragraph (c)(7) of this section, the Administrator shall set an effective date for removal of an area as requested by the Governor, but no less than 90 days from the Agency's written notification to the state approving the opt-out petition.
(7) For opt-out petitions received on or after January 1, 2004, where RFG is contained as an element of any plan or plan revision that has been approved by the Agency, other than as a contingency measure consisting of a future opt-in, then the effective date for removal of an area under paragraph (a) of this section shall be the date requested by the Governor, but no less than 90 days from the effective date of Agency approval of a revision to the plan that removes RFG as a control measure.
(d) The Administrator shall publish a notice in the
In appropriate extreme and unusual circumstances (e.g., natural disaster or Act of God) which are clearly outside the control of the refiner, importer, or oxygenate blender and which could not have been avoided by the exercise of prudence, diligence, and due care, EPA may permit a refiner, importer, or oxygenate blender, for a brief period, to distribute gasoline which does not meet the requirements for reformulated gasoline, if:
(a) It is in the public interest to do so (e.g., distribution of the nonconforming gasoline is necessary to meet projected shortfalls which cannot otherwise be compensated for);
(b) The refiner, importer, or oxygenate blender exercised prudent planning and was not able to avoid the violation and has taken all reasonable steps to minimize the extent of the nonconformity;
(c) The refiner, importer, or oxygenate blender can show how the requirements for reformulated gasoline will be expeditiously achieved;
(d) The refiner, importer, or oxygenate blender agrees to make up air quality detriment associated with the nonconforming gasoline, where practicable; and
(e) The refiner, importer, or oxygenate blender pays to the U.S. Treasury an amount equal to the economic benefit of the nonconformity minus the amount expended, pursuant to paragraph (d) of this section, in making up the air quality detriment.
All parties in the gasoline distribution network, as described in this section, shall maintain records containing the information as required in this section. These records shall be retained for a period of five years from the date of creation, and shall be delivered to the Administrator of EPA or to the Administrator's authorized representative upon request.
(a)
(1) The product transfer documentation for all reformulated gasoline or RBOB for which the party is the transferor or transferee; and
(2) For any sampling and testing on RBOB or reformulated gasoline:
(i) The location, date, time, and storage tank or truck identification for each sample collected;
(ii) The identification of the person who collected the sample and the person who performed the testing;
(iii) The results of the tests; and
(iv) The actions taken to stop the sale of any gasoline found not to be in compliance, and the actions taken to identify the cause of any noncompliance and prevent future instances of noncompliance.
(b)
(1) Results of the tests to determine reformulated gasoline properties and characteristics specified in § 80.65;
(2) Results of the tests for the presence of the marker specified in § 80.82;
(3) The volume of gasoline associated with each of the above test results using the method normally employed at the refinery or import facility for this purpose;
(4) In the case of RBOB:
(i) The results of tests to ensure that, following blending, RBOB meets applicable standards; and
(ii) Each contract with each oxygenate blender to whom the refiner or importer transfers RBOB; or
(iii) Compliance calculations described in § 80.69(a)(8) based on an assumed addition of oxygenate;
(5) In the case of any refinery or importer subject to the simple model standards, the calculations used to determine the 1990 baseline levels of sulfur, T-90, and olefins, and the calculations used to determine compliance with the standards for these parameters; and
(6) In the case of any refinery or importer subject to the complex model standards before January 1, 1998, the calculations used to determine the baseline levels of VOC, toxics, and NO
(c)
(1) The calculations used to determine compliance with the relevant standards on average, for each averaging period and for each quantity of gasoline for which standards must be separately achieved; and
(2) For any credits bought, sold, traded or transferred pursuant to § 80.67(h), the dates of the transactions, the names and EPA registration numbers of the parties involved, and the number(s) and type(s) of credits transferred.
(d)
(i) The date, time, location, and identification of the blending tank or truck in which the blending occurred;
(ii) The volume and oxygenate requirements of the RBOB to which oxygenate was added; and
(iii) The volume, type, and purity of the oxygenate which was added, and documents which show the source(s) of the oxygenate used.
(e)
(1) The name and EPA registration number of the oxygenate blender that received the RBOB; and
(2) The volume and oxygenate requirements of the RBOB dispensed.
(f)
(g)
Any refiner, importer, and oxygenate blender shall report as specified in this
(a)
(1) The quarterly reports shall be for all such reformulated gasoline or RBOB produced or imported during the following time periods:
(i) The first quarterly report shall include information for reformulated gasoline or RBOB produced or imported from January 1 through March 31, and shall be submitted by May 31 of each year beginning in 1995;
(ii) The second quarterly report shall include information for reformulated gasoline or RBOB produced or imported from April 1 through June 30, and shall be submitted by August 31 of each year beginning in 1995;
(iii) The third quarterly report shall include information for reformulated gasoline or RBOB produced or imported from July 1 through September 30, and shall be submitted by November 30 of each year beginning in 1995; and
(iv) The fourth quarterly report shall include information for reformulated gasoline or RBOB produced or imported from October 1 through December 31, and shall be submitted by the last day of February of each year beginning in 1996.
(2) The following information shall be included in each quarterly report for each batch of reformulated gasoline or RBOB which is included under paragraph (a)(1) of this section:
(i) The batch number;
(ii) The date of production;
(iii) The volume of the batch;
(iv) The grade of gasoline produced (i.e., premium, mid-grade, or regular);
(v) For any refiner or importer:
(A) Each designation of the gasoline, pursuant to § 80.65; and
(B) The properties, pursuant to §§ 80.65 and 80.66;
(vi) For any importer, the PADD in which the import facility is located; and
(vii) For any oxygenate blender, the oxygen content.
(3) Information pertaining to gasoline produced or imported during 1994 shall be included in the first quarterly report in 1995.
(b)
(A) Gasoline or RBOB which is designated as VOC-controlled intended for areas in VOC-Control Region 1; and
(B) Gasoline or RBOB which is designated as VOC-controlled intended for VOC-Control Region 2.
(ii) The following information shall be reported:
(A) The total volume of averaged reformulated gasoline or RBOB in gallons;
(B) The compliance total value for RVP; and
(C) The actual total value for RVP.
(2)
(A) For each refinery or importer; or
(B) In the case of refiners who operate more than one refinery, for each grouping of refineries as designated by the refiner pursuant to § 80.41(h)(2)(iii).
(ii) The following information shall be reported:
(A) The total volume of reformulated gasoline or RBOB in gallons;
(B) The applicable sulfur content standard under § 80.41(h)(2)(i) in parts per million;
(C) The average sulfur content in parts per million;
(D) The difference between the applicable sulfur content standard under § 80.41(h)(2)(i) in parts per million and the average sulfur content under paragraph (b)(2)(ii)(C) of this section in parts per million, indicating whether the average is greater or lesser than the applicable standard;
(E) The applicable olefin content standard under § 80.41(h)(2)(i) in volume percent;
(F) The average olefin content in volume percent;
(G) The difference between the applicable olefin content standard under § 80.41(h)(2)(i) in volume percent and the average olefin content under paragraph (b)(2)(ii)(F) of this section in volume percent, indicating whether the average is greater or lesser than the applicable standard;
(H) The applicable T90 distillation point standard under § 80.41(h)(2)(i) in degrees Fahrenheit;
(I) The average T90 distillation point in degrees Fahrenheit; and
(J) The difference between the applicable T90 distillation point standard under § 80.41(h)(2)(i) in degrees Fahrenheit and the average T90 distillation point under paragraph (b)(2)(ii)(I) of this section in degrees Fahrenheit, indicating whether the average is greater or lesser than the applicable standard.
(c)
(i) Gasoline or RBOB which is designated as VOC-controlled intended for areas in VOC-Control Region 1; and
(ii) Gasoline or RBOB which is designated as VOC-controlled intended for VOC-Control Region 2.
(2) The following information shall be reported:
(i) The total volume of averaged reformulated gasoline or RBOB in gallons;
(ii) The compliance total value for VOC emissions performance; and
(iii) The actual total value for VOC emissions performance.
(d)
(2) The following information shall be reported:
(i) The volume of averaged reformulated gasoline or RBOB in gallons;
(ii) The compliance total content of benzene;
(iii) The actual total content of benzene;
(iv) The number of benzene credits generated as a result of actual total benzene being less than compliance total benzene;
(v) The number of benzene credits required as a result of actual total benzene being greater than compliance total benzene;
(vi) The number of benzene credits transferred to another refinery or importer; and
(vii) The number of benzene credits obtained from another refinery or importer.
(e)
(2) The following information shall be reported:
(i) The volume of averaged reformulated gasoline or RBOB in gallons;
(ii) The compliance value for toxics emissions performance; and
(iii) The actual value for toxics emissions performance.
(f)
(2)(i) The following information shall be included in each report required by paragraph (f)(1) of this section:
(A) The total volume of averaged RBOB in gallons;
(B) The total volume of averaged reformulated gasoline in gallons;
(C) The compliance total content for oxygen;
(D) The actual total content for oxygen;
(E) The number of oxygen credits generated as a result of actual total oxygen being greater than compliance total oxygen;
(F) The number of oxygen credits required as a result of actual total oxygen being less than compliance total oxygen;
(G) The number of oxygen credits transferred to another refinery, importer, or oxygenate blending facility; and
(H) The number of oxygen credits obtained from another refinery, importer, or oxygenate blending facility.
(ii) The information required by paragraph (f)(2)(i) of this section shall be reported separately for the following categories:
(A) For gasoline subject to the simple model standards:
(
(
(B) For gasoline subject to the Phase I or Phase II complex model standards:
(
(
(iii) The results of the compliance calculations required in § 80.67(f) shall also be included in each report required by paragraph (f)(1) of this section, for each of the following categories:
(A) All reformulated gasoline;
(B) Gasoline which is designated as non-OPRG; and
(C) For gasoline subject to the simple model standards, gasoline which is designated as VOC-controlled.
(g)
(2) The following information shall be reported:
(i) The volume of averaged reformulated gasoline or RBOB in gallons;
(ii) The compliance value for NO
(iii) The actual value for NO
(3) The information required by paragraph (g)(2) of this section shall be reported separately for the following categories:
(i) Gasoline and RBOB which is designated as VOC-controlled; and
(ii) Gasoline and RBOB which is not designated as VOC-controlled.
(h)
(i) The names, EPA-assigned registration numbers and facility identification numbers of the transferor and transferee of the credits;
(ii) The number(s) and type(s) of credits that were transferred; and
(iii) The date(s) of transaction(s).
(2) For purposes of this paragraph (h), oxygen credit transfers shall be reported separately for each of the following oxygen credit types:
(i) For gasoline subject to the simple model standards:
(A) VOC controlled; and
(B) Non-VOC controlled.
(ii) [Reserved]
(i)
(j)
(k)
(l)
(m)
(n)
(1) Submitted on forms and following procedures specified by the Administrator; and
(2) Signed and certified as correct by the owner or a responsible corporate officer of the refiner, importer, or oxygenate blender.
(a) Registration with the Administrator of EPA is required for any refiner and importer, and any oxygenate blender that produces any reformulated gasoline.
(b) Any person required to register shall do so by November 1, 1994, or not later than three months in advance of the first date that such person will produce or import reformulated gasoline or RBOB, or conventional gasoline or applicable blendstocks, whichever is later.
(c) Registration shall be on forms prescribed by the Administrator, and shall include the following information:
(1) The name, business address, contact name, and telephone number of the refiner, importer, or oxygenate blender;
(2) For each separate refinery and oxygenate blending facility, the facility name, physical location, contact name, telephone number, and type of facility; and
(3) For each separate refinery and oxygenate blending facility, and for each importer's operations in a single PADD:
(i) Whether records are kept on-site or off-site of the refinery or oxygenate blending facility, or in the case of importers, the registered address;
(ii) If records are kept off-site, the primary off-site storage facility name, physical location, contact name, and telephone number; and
(iii) The name, address, contact name and telephone number of the independent laboratory used to meet the independent analysis requirements of § 80.65(f).
(d) EPA will supply a registration number to each refiner, importer, and oxygenate blender, and a facility registration number for each refinery and oxygenate blending facility that is identified, which shall be used in all reports to the Administrator.
(e)(1) Any refiner, importer, or oxygenate blender shall submit updated registration information to the Administrator within thirty days of any occasion when the registration information previously supplied becomes incomplete or inaccurate; except that
(2) EPA must be notified in writing of any change in designated independent laboratory at least thirty days in advance of such change.
On each occasion when any person transfers custody or title to any reformulated gasoline or RBOB, other than when gasoline is sold or dispensed for use in motor vehicles at a retail outlet or wholesale purchaser-consumer facility, the transferor shall provide to the transferee documents which include the following information:
(a) The name and address of the transferor;
(b) The name and address of the transferee;
(c) The volume of gasoline which is being transferred;
(d) The location of the gasoline at the time of the transfer;
(e) The date of the transfer;
(f) The proper identification of the gasoline as conventional or reformulated;
(g) In the case of reformulated gasoline or RBOB:
(1) The proper identification as:
(i)(A) VOC-controlled for VOC-Control Region 1; or VOC-controlled for VOC-Control Region 2; or Not VOC-controlled; or
(B) In the case of gasoline or RBOB that is VOC-controlled for VOC-Control Region 1, the gasoline may be identified as suitable for use either in VOC-Control Region 1 or VOC-Control Region 2;
(ii) [Reserved]
(iii) Prior to January 1, 1998, certified under the simple model standards or certified under the complex model standards; and
(2) The minimum and/or maximum standards with which the gasoline or RBOB conforms for:
(i) Benzene content;
(ii) Except for RBOB, oxygen content;
(iii) In the case of VOC-controlled gasoline subject to the simple model standards, RVP;
(iv) In the case of gasoline subject to the complex model standards:
(A) Prior to January 1, 1998, the NOx emissions performance minimum, and for VOC-controlled gasoline the VOC emissions performance minimum, in milligrams per mile; and
(B) Beginning on January 1, 1998, for VOC-controlled gasoline, the VOC emissions performance minimum; and
(3) Identification of VOC-controlled reformulated gasoline or RBOB as gasoline or RBOB which contains ethanol, or which does not contain any ethanol.
(h) Prior to January 1, 1998, in the case of reformulated gasoline or RBOB subject to the complex model standards:
(1) The name and EPA registration number of the refinery at which the gasoline was produced, or importer that imported the gasoline; and
(2) Instructions that the gasoline or RBOB may not be combined with any other gasoline or RBOB that was produced at any other refinery or was imported by any other importer;
(i) In the case of reformulated gasoline blendstock for which oxygenate blending is intended:
(1) Identification of the product as RBOB and not reformulated gasoline;
(2) The designation of the RBOB as suitable for blending with:
(A) Any-oxygenate;
(B) Ether-only; or
(C) Other specified oxygenate type(s) and amount(s); and
(3) The oxygenate type(s) and amount(s) which the RBOB requires in order to meet the properties claimed by the refiner or importer of the RBOB;
(4) Instructions that the RBOB may not be combined with any other RBOB except other RBOB having the same requirements for oxygenate type(s) and amount(s), or, prior to blending, with reformulated gasoline; and
(j) In the case of transferrers or transferees who are refiners, importers or oxygenate blenders, the EPA-assigned registration number of those persons.
(a)
(i) Unless each gallon of such gasoline meets the applicable benzene maximum standard specified in § 80.41;
(ii) Unless each gallon of such gasoline meets the applicable oxygen content:
(A) Minimum standard specified in § 80.41; and
(B) In the case of gasoline subject to simple model standards, maximum standard specified in § 80.41;
(iii) Unless each gallon is properly designated as oxygenated fuels program reformulated gasoline, within any oxygenated gasoline program control areas during the oxygenated gasoline control period;
(iv) Unless the product transfer documentation for such gasoline complies with the requirements in § 80.77; and
(v) During the period May 1 through September 15 for all persons except retailers and wholesale purchaser-consumers, and during the period June 1 through September 15 for all persons including retailers and wholesale purchaser-consumers:
(A) Unless each gallon of such gasoline is VOC-controlled for the proper VOC Control Region, except that gasoline designated for VOC-Control Region 1 may be used in VOC-Control Region 2;
(B) Unless each gallon of such gasoline that is subject to simple model standards has an RVP which is less than or equal to the applicable RVP maximum specified in § 80.41;
(C) Unless each gallon of such gasoline that is subject to complex model standards has a VOC emissions reduction percentage which is greater than or equal to the applicable minimum specified in § 80.41.
(2) No refiner or importer may produce or import any gasoline represented as reformulated or RBOB, and intended for sale or use in any covered area:
(i) Unless such gasoline meets the definition of reformulated gasoline or RBOB; and
(ii) Unless the properties of such gasoline or RBOB correspond to the product transfer documents.
(3) No person may manufacture and sell or distribute, or offer for sale or distribution, dispense, supply, or offer for supply, store, transport or cause the transportation of gasoline represented as conventional which does not contain at least the minimum concentration of the conventional gasoline marker specified in § 80.82.
(4) Gasoline shall be presumed to be intended for sale or use in a covered area unless:
(i) Product transfer documentation as described in § 80.77 accompanying such gasoline clearly indicates the gasoline is intended for sale and use only outside any covered area; or
(ii) The gasoline is contained in the storage tank of a retailer or wholesale purchaser-consumer outside any covered area.
(5) No person may combine any reformulated gasoline with any non-oxygenate blendstock except:
(i) A person that meets each requirement specified for a refiner under this subpart; and
(ii) The blendstock that is added to reformulated gasoline meets all reformulated gasoline standards without regard to the properties of the reformulated gasoline to which the blendstock is added.
(6) No person may add any oxygenate to reformulated gasoline, except that such oxygenate may be added to reformulated gasoline provided that such gasoline is used in an oxygenated fuels program control area during an oxygenated fuels control period.
(7) No person may combine any reformulated gasoline blendstock for oxygenate blending with any other gasoline, blendstock, or oxygenate except:
(i) Oxygenate of the type and amount (or within the range of amounts) specified by the refiner or importer at the time the RBOB was produced or imported; or
(ii) Other RBOB for which the same oxygenate type and amount (or range of amounts) was specified by the refiner or importer.
(8) No person may combine any VOC-controlled reformulated gasoline that is produced using ethanol with any VOC-controlled reformulated gasoline that is produced using any other oxygenate during the period January 1 through September 15.
(9) Prior to January 1, 1998:
(i) No person may combine any reformulated gasoline or RBOB that is subject to the simple model standards with any reformulated gasoline or RBOB that is subject to the complex model standards, except that such gasolines may be combined at a retail outlet or wholesale purchaser-consumer facility;
(ii) No person may combine any reformulated gasoline subject to the complex model standards that is produced at any refinery or is imported by any importer with any other reformulated gasoline that is produced at a different refinery or is imported by a different importer, unless the other refinery or importer has an identical baseline for meeting complex model standards during this period; and
(iii) No person may combine any RBOB subject to the complex model standards that is produced at any refinery or is imported by any importer with any RBOB that is produced at a different refinery or is imported by a different importer, unless the other refinery or importer has an identical baseline for meeting complex model standards during this period.
(10) No person may combine any reformulated gasoline with any conventional gasoline and sell the resulting mixture as reformulated gasoline.
(b)
(c)
(d)
(a)
(1) Each refiner, importer, oxygenate blender, carrier, distributor, reseller, retailer, or wholesale purchaser-consumer who owns, leases, operates, controls or supervises the facility where the violation is found;
(2) Each refiner or importer whose corporate, trade, or brand name, or whose marketing subsidiary's corporate, trade, or brand name, appears at the facility where the violation is found;
(3) Each refiner, importer, oxygenate blender, distributor, and reseller who manufactured, imported, sold, offered for sale, dispensed, supplied, offered for supply, stored, transported, or caused the transportation of any gasoline which is in the storage tank containing gasoline found to be in violation; and
(4) Each carrier who dispensed, supplied, stored, or transported any gasoline which is in the storage tank containing gasoline found to be in violation, provided that EPA demonstrates, by reasonably specific showings by direct or circumstantial evidence, that the carrier caused the violation.
(b)
(i) That the violation was not caused by the regulated party or its employee or agent;
(ii) That product transfer documents account for all of the gasoline in the storage tank found in violation and indicate that the gasoline met relevant requirements; and
(iii)(A) That it has conducted a quality assurance sampling and testing program, as described in paragraph (c) of this section; except that
(B) A carrier may rely on the quality assurance program carried out by another party, including the party that owns the gasoline in question, provided that the quality assurance program is carried out properly.
(2)(i) Where a violation is found at a facility which is operating under the corporate, trade or brand name of a refiner, that refiner must show, in addition to the defense elements required by paragraph (b)(1) of this section, that the violation was caused by:
(A) An act in violation of law (other than the Act or this part), or an act of sabotage or vandalism;
(B) The action of any reseller, distributor, oxygenate blender, carrier, or a retailer or wholesale purchaser- consumer supplied by any of these persons, in violation of a contractual undertaking imposed by the refiner designed to prevent such action, and despite periodic sampling and testing by the refiner to ensure compliance with such contractual obligation; or
(C) The action of any carrier or other distributor not subject to a contract with the refiner but engaged by the refiner for transportation of gasoline, despite specification or inspection of procedures and equipment by the refiner which are reasonably calculated to prevent such action.
(ii) In this paragraph (b), to show that the violation “was caused” by any of the specified actions the party must demonstrate by reasonably specific showings, by direct or circumstantial evidence, that the violation was caused or must have been caused by another.
(c)
(1) Of a periodic sampling and testing program to determine if the applicable maximum and/or minimum standards for oxygen, benzene, RVP, or VOC emission performance are met.
(2) That on each occasion when gasoline is found in noncompliance with one of the requirements referred to in paragraph (c)(1) of this section:
(i) The party immediately ceases selling, offering for sale, dispensing, supplying, offering for supply, storing, transporting, or causing the transportation of the violating product; and
(ii) The party promptly remedies the violation (such as by removing the violating product or adding more complying product until the applicable standards are achieved).
(3) An oversight program conducted by a carrier under paragraph (c)(1) of
(a) Any person that violates any requirement or prohibition of subpart D, E, or F of this part shall be liable to the United States for a civil penalty of not more than the sum of $25,000 for every day of each such violation and the amount of economic benefit or savings resulting from each such violation.
(b) Any violation of a standard for average compliance during any averaging period, or for per-gallon compliance for any batch of gasoline, shall constitute a separate violation for each and every standard that is violated.
(c) Any violation of any standard based upon a multi-day averaging period shall constitute a separate day of violation for each and every day in the averaging period. Any violation of any credit creation or credit transfer requirement shall constitute a separate day of violation for each and every day in the averaging period.
(d)(1)(i) Any violation of any per- gallon standard or of any per-gallon minimum or per-gallon maximum, other than the standards specified in paragraph (e) of this section, shall constitute a separate day of violation for each and every day such gasoline giving rise to such violations remains any place in the gasoline distribution system, beginning on the day that the gasoline that violates such per-gallon standard is produced or imported and distributed and/or offered for sale, and ending on the last day that any such gasoline is offered for sale or is dispensed to any ultimate consumer for use in any motor vehicle; unless
(ii) The violation is corrected by altering the properties and characteristics of the gasoline giving rise to the violations and any mixture of gasolines that contains any of the gasoline giving rise to the violations such that the said gasoline or mixture of gasolines has the properties and characteristics that would have existed if the gasoline giving rise to the violations had been produced or imported in compliance with all per-gallon standards.
(2) For the purposes of this paragraph (d), the length of time the gasoline in question remained in the gasoline distribution system shall be deemed to be twenty-five days; unless the respective party or EPA demonstrates by reasonably specific showings, by direct or circumstantial evidence, that the gasoline giving rise to the violations remained any place in the gasoline distribution system for fewer than or more than twenty-five days.
(e)(1) Any reformulated gasoline that is produced or imported and offered for sale and for which the requirements to determine the properties and characteristics under § 80.65(f) is not met, or any conventional gasoline for which the refiner or importer does not sample and test to determine the relevant properties, shall be deemed:
(i)(A) Except as provided in paragraph (e)(1)(i)(B) of this section to have the following properties:
(B) To have the following properties in paragraph (e)(1)(i)(A) of this section unless the respective party or EPA demonstrates by reasonably specific showings, by direct or circumstantial evidence, different properties for the gasoline giving rise to the violations; and
(ii) In the case of reformulated gasoline, to have been designated as meeting all applicable standards on a per-gallon basis.
(2) For the purposes of paragraph (e)(1) of this section, any refiner or importer that fails to meet the independent analysis requirements of § 80.65(f) may not use the results of sampling and testing that is carried out by that refiner or importer as direct or circumstantial evidence of the properties of the gasoline giving rise to the violations, unless this failure was not caused by the refiner or importer.
(f) Any violation of any affirmative requirement or prohibition not included in paragraph (c) or (d) of this section shall constitute a separate day of violation for each and every day such affirmative requirement is not properly accomplished, and/or for each and every day the prohibited activity continues. For those violations that may be ongoing under subparts D, E, and F of this part, each and every day the prohibited activity continues shall constitute a separate day of violation.
(a)(1) The requirements of subparts D, E, and F of this part are modified in accordance with the provisions contained in this section in the case of California gasoline.
(2) For the purposes of this section, “California gasoline” means any gasoline that is sold, intended for sale, or made available for sale as a motor vehicle fuel in the State of California and that:
(i) Is manufactured within the State of California;
(ii) Is imported into the State of California from outside the United States; or
(iii) Is imported into the State of California from inside the United States and that is manufactured at a refinery that does not produce reformulated gasoline for sale in any covered area outside the State of California.
(b)(1) Any refiner, importer, or oxygenate blender of gasoline that is sold, intended for sale, or made available for sale as a motor fuel in the State of California is, with regard to such gasoline, exempt from the compliance survey provisions contained in § 80.68.
(2) Any refiner, importer, or oxygenate blender of California gasoline is, with regard to such gasoline, exempt from the independent analysis requirements contained in § 80.65(f).
(3) Any refiner, importer, or oxygenate blender of California gasoline that elects to meet any benzene content, oxygen content, or toxics emission reduction standard specified in § 80.41 on average for any averaging period specified in § 80.67 that is in part before March 1, 1996, and in part subsequent to such date, shall, with regard to such gasoline that is produced or imported prior to such date, demonstrate compliance with each of the standards specified in § 80.41 for each of the following averaging periods in lieu of those specified in § 80.67:
(i) January 1 through December 31, 1995; and
(ii) March 1, 1995, through February 29, 1996.
(4) The compliance demonstration required by paragraph (b)(3)(ii) of this section shall be submitted no later than May 31, 1996, along with the report for the first quarter of 1996 required to be submitted under § 80.75(a)(1)(i).
(c) Any refiner, importer, or oxygenate blender of California gasoline that is manufactured or imported subsequent to March 1, 1996, and that meets the requirements of the California Phase 2 reformulated gasoline regulations, as set forth in Title 13, California Code of Regulations, sections 2260 et seq., is, with regard to such gasoline, exempt from the following requirements (in addition to the requirements specified in paragraph (b) of this section):
(1) The parameter value reconciliation requirements contained in § 80.65(e)(2);
(2) The designation of gasoline requirements contained in § 80.65(d), except in the case of RBOB that is designated as “any renewable oxygenate,” “non-VOC controlled renewable ether only”, or “renewable ether only”;
(3) The reformulated gasoline and RBOB compliance requirements contained in § 80.65(c);
(4) The marking of conventional gasoline requirements contained in §§ 80.65(g) and 80.82;
(5) The annual compliance audit requirements contained in § 80.65(h), except where such audits are required with regard to the renewable oxygenate requirements contained in § 80.83;
(6) The downstream oxygenate blending requirements contained in § 80.69, except where such requirements apply to the renewable oxygenate requirements contained in § 80.83;
(7) The record keeping requirements contained in §§ 80.74 and 80.104, except that records required to be maintained under Title 13, California Code of Regulations, section 2270, shall be maintained for a period of five years from the date of creation and shall be delivered to the Administrator or to the Administrator's authorized representative upon request;
(8) The reporting requirements contained in §§ 80.75 and 80.105;
(9) The product transfer documentation requirements contained in § 80.77; and
(10) The compliance attest engagement requirements contained in subpart F of this part, except where such requirements apply to the renewable oxygenate requirements contained in § 80.83.
(d) Any refiner, importer, or oxygenate blender that produces or imports gasoline that is sold, intended for sale, or made available for sale as a motor vehicle fuel in the State of California subsequent to March 1, 1996, shall demonstrate compliance with the standards specified in §§ 80.41 and 80.90 by excluding the volume and properties of such gasoline from all conventional gasoline and reformulated gasoline that it produces or imports that is not sold, intended for sale, or made available for sale as a motor vehicle fuel in the State of California subsequent to such date. The exemption provided in this section does not exempt any refiner or importer from demonstrating compliance with such standards for all gasoline that it produces or imports.
(e)(1) The exemption provisions contained in paragraphs (b)(2), (b)(3), (c), and (f) of this section shall not apply under the circumstances set forth in paragraphs (e)(2) and (e)(3) of this section.
(2) Such exemption provisions shall not apply to any refiner, importer, or oxygenate blender of California gasoline with regards to any gasoline formulation that it produces or imports is certified under Title 13, California Code of Regulations, section 2265 or section 2266 (as amended July 2, 1996), unless:
(i)
(B) If the Administrator determines that the written demonstration submitted under paragraph (e)(2)(i)(A) of this section does not demonstrate that all certified gasoline formulations meet each of the complex model per-gallon standards specified in § 80.41(c), the Administrator shall provide notice to the party (by first class mail) of such determination and of the date on which the exemption provisions specified in paragraph (e)(1) of this section shall no longer be applicable, which date shall be no earlier than 90 days after the date of the Administrator's notification.
(ii)
(A) The survey series must determine compliance only with the oxygen content standard of 2.0 weight-percent;
(B) The survey series must consist of at least four surveys a year for each covered area;
(C) The surveys shall not be included in determining the number of surveys under § 80.68(b)(2);
(D) In the event a survey series conducted under this paragraph (e)(2)(ii)
(E) Not withstanding § 80.41(o), in the event a covered area passes the oxygen content series in a year, the minimum oxygen content standard for that covered area beginning in the year following the passed survey series shall be made less stringent by decreasing the minimum oxygen content standard by 0.1%, except that in no case shall the minimum oxygen content standard be less than that specified in § 80.41(d).
(3)(i) Such exemption provisions shall not apply to any refiner, importer, or oxygenate blender of California gasoline who has been assessed a civil, criminal or administrative penalty for a violation of subpart D, E or F of this part or for a violation of the California Phase 2 reformulated gasoline regulations set forth in Title 13, California Code of Regulations, sections 2260 et seq., effective 90 days after the date of final agency or district court adjudication of such penalty assessment.
(ii) Any refiner, importer, or oxygenate blender subject to the provisions of paragraph (e)(3)(i) of this section may submit a petition to the Administrator for relief, in whole or in part, from the applicability of such provisions, for good cause. Good cause may include a showing that the violation for which a penalty was assessed was not a substantial violation of the Federal or California reformulated gasoline regulations.
(f) In the case of any gasoline that is sold, intended for sale, or made available for sale as a motor vehicle fuel in the State of California subsequent to March 1, 1996, any person that manufactures, sells, offers for sale, dispenses, supplies, offers for supply, stores, transports, or causes the transportation of such gasoline is, with regard to such gasoline, exempt from the following prohibited activities provisions:
(1) The oxygenated fuels provisions contained in § 80.78(a)(1)(iii);
(2) The product transfer provisions contained in § 80.78(a)(1)(iv);
(3) The oxygenate blending provisions contained in § 80.78(a)(7); and
(4) The segregation of simple and complex model certified gasoline provision contained in § 80.78(a)(9).
(g)(1) Any refiner that operates a refinery located outside the State of California at which California gasoline (as defined in paragraph (a)(2)(iii) of this section) is produced shall, with regard to such gasoline, provide to any person to whom custody or title of such gasoline is transferred, and each transferee shall provide to any subsequent transferee, documents which include the following information:
(i) The name and address of the transferor;
(ii) The name and address of the transferee;
(iii) The volume of gasoline which is being transferred;
(iv) The location of the gasoline at the time of the transfer;
(v) The date and time of the transfer;
(vi) The identification of the gasoline as California gasoline; and
(vii) In the case of transferrors and transferrees who are refiners, importers or oxygenate blenders, the EPA- assigned registration number of such persons.
(2) Each refiner and transferee of such gasoline shall maintain copies of the product transfer documents required to be provided by paragraph (g)(1) of this section for a period of five years from the date of creation and shall deliver such documents to the Administrator or to the Administrator's authorized representative upon request.
(h)(1) For the purposes of the batch sampling and analysis requirements contained in § 80.65(e)(1)and § 80.101(i)(1)(i)(A), any refiner, importer or oxygenate blender of California gasoline may use a sampling and/or analysis methodology prescribed in Title 13, California Code of Regulations, sections 2260
(i) Such gasoline; or
(ii) That portion of its gasoline produced or imported for use in other
(A) The gasoline must be produced by a refinery that is located in the state of California that produces California gasoline, or imported into California from outside the United States as California Phase 2 gasoline;
(B) The gasoline must be classified as conventional gasoline upon exportation from the California; and
(C) The refiner or importer must correlate the results from the applicable sampling and /or analysis methodology prescribed in Title 13, California Code of Regulations, sections 2260
(2) Nothwithstanding the requirements of § 80.65(e)(1) regarding when the properties of a batch of reformulated gasoline must be determined, a refiner of California gasoline may determine the properties of gasoline as specified under § 80.65(e)(1) at off site tankage provided that:
(i) The samples are properly collected under the terms of a current and valid protocol agreement between the refiner and the California Air Resources Board with regard to sampling at the off site tankage and consistent with requirements prescribed in Title 13, California Code of Regulations, sections 2260
(ii) The refiner provides a copy of the protocol agreement to EPA upon request.
(i) The exemption provisions contained in this section shall not be applicable after December 31, 1999.
1. At 59 FR 39289, Aug. 2, 1994, § 80.81 was amended by revising paragraphs (c)(2), (c)(5), (c)(6), and (c)(10) effective September 1, 1994. At 59 FR 60715, Nov. 28, 1994, the amendment was stayed effective September 13, 1994.
(a)
(1) In the case of oxygenate added to reformulated gasoline or RBOB that is not designated as VOC-controlled or that is not subject to the additional requirements associated with an extended non-commingling season pursuant to § 80.83(i), renewable oxygenate shall be:
(i) An oxygenate that is derived from non-fossil fuel feedstocks; or
(ii) An ether that is produced using an oxygenate that is derived from non-fossil fuel feedstocks.
(2) In the case of oxygenate added to reformulated gasoline or RBOB that is designated as VOC-controlled or that is subject to the additional requirements associated with an extended non-commingling season pursuant to § 80.83(i), renewable oxygenate shall be an ether that meets the requirements of paragraph (a)(1)(ii) or (a)(3) of this section.
(3) An oxygenate other than those ethers specified in paragraphs (a)(1) or (a)(2) of this section may be considered a renewable oxygenate if the Administrator approves a petition to that effect. The Administrator may approve such a petition if it is demonstrated to the satisfaction of the Administrator that the oxygenate does not cause volatility increases in gasoline that are non-linear in nature (i.e., a non-linear vapor pressure blending curve). The Administrator may approve a petition subject to any appropriate conditions or limitations.
(4)(i) Oxygenate shall be renewable only if the refiner, importer, or oxygenate blender who uses the oxygenate is able to establish in the form of documentation that the oxygenate was produced from a non-fossil fuel feedstock.
(ii)(A) Any person who produces renewable oxygenate, as defined in paragraph (a)(1) of this section, or who stores, transports, transfers, or sells
(B) Any person who imports oxygenate that is represented by the importer to be renewable oxygenate, as defined in paragraph (a) of this section, shall maintain documents, obtained from the person who produced the oxygenate, that include a certification signed by the owner or chief executive officer of the company that produced the oxygenate that states:
(
(
(iii) No person may represent any oxygenate as renewable unless the oxygenate meets the renewable definition under paragraph (a) of this section.
(5) For purposes of this section, an oxygenate shall be considered to be derived from non-fossil fuel feedstocks only if the oxygenate is:
(i) Derived from a source other than petroleum, coal, natural gas, or peat; or
(ii) Derived from a product:
(A) That was produced using petroleum, coal, natural gas, or peat through a substantial transformation of the fossil fuel;
(B) When the product was initially produced, it was not commonly used to generate energy (e.g. automobile tires); and
(C) The product was sold or transferred for a use other than energy generation, and was later treated as a waste product.
(b)
(2) The averaging period for the renewable oxygenate standard specified in paragraph (b)(1) of this section shall be:
(i) Each calendar year; except that
(ii)Any reformulated gasoline and RBOB that is produced or imported prior to January 1, 1995 shall be averaged with reformulated gasoline and RBOB produced or imported during 1995.
(3)(i) The oxygenate used to meet the standard under paragraph (b)(1) of this section may also be used to meet any oxygen standard under § 80.41; except that
(ii) The renewable oxygenate added by a downstream oxygenate blender shall not be used by any refiner or importer to meet the oxygen standard under § 80.41, except through the transfer of oxygen credits.
(c)
(i) The oxygenate meets the applicable renewable oxygenate definition under paragraph (a) of this section; and
(ii) The refiner or importer meets the downstream oxygenate blending oversight requirements specified in §§ 80.69(a)(6) and (7); or
(iii)(A) In the case of RBOB designated for “any renewable oxygenate” the refiner or importer assumes that ethanol will be blended with the RBOB;
(B) In the case of RBOB designated for “renewable ether only” or “non-VOC controlled renewable ether only “, the refiner or importer assumes that ETBE will be blended with the RBOB; and
(C) In the case of “any renewable oxygenate,” “non-VOC controlled renewable ether only” and “renewable ether only RBOB,” the refiner or importer assumes that the volume of oxygenate added will be such that the resulting
(2)(i) No person may combine any oxygenate with RBOB designated as “any renewable oxygenate” unless the oxygenate meets the criteria specified in paragraph (a) of this section.
(ii) No person may combine any oxygenate with RBOB designated as “renewable ether only” or “non-VOC controlled renewable ether only” unless the oxygenate meets the criteria specified in paragraph (a) of this section.
(d)
(i) Prior to January 1, 1996, renewable oxygen compliance total using the following formula:
(ii) Beginning on January 1, 1996, the renewable oxygen compliance total using the following formula:
(iii) The renewable oxygen actual total using the following formula:
(iv) Compare the renewable oxygen actual total with the renewable oxygen compliance total.
(2)(i) The actual total must be equal to or greater than the compliance totals to achieve compliance, subject to the credit transfer provisions of paragraph (e) of this section.
(ii) If the renewable oxygen actual total is less than the renewable oxygen compliance total, renewable oxygen credits must be obtained from another refinery or importer in order to achieve compliance.
(iii) The total number of renewable oxygen credits required to achieve compliance is calculated by subtracting the renewable oxygen actual total from the renewable oxygen compliance total.
(iv) If the renewable oxygen actual total is greater than the renewable oxygen compliance total, renewable oxygen credits are generated.
(v) The total number of renewable oxygen credits which may be traded to a refiner for a refinery, or to another importer, is calculated by subtracting the renewable oxygen compliance total from the renewable oxygen actual total.
(e)
(f)
(1)(i) Documents demonstrating the renewable nature and source of the oxygenate used, consistent with the requirements of paragraph (a)(3) of this section;
(ii) The volume, type, and purity of any renewable oxygenate used; and
(iii) Product transfer documentation for all renewable oxygenate, reformulated gasoline, or RBOB for which the party is the transferor or transferee.
(2) The requirements of this paragraph (f) shall apply in addition to the recordkeeping requirements specified in § 80.74(e).
(g)
(2) Any refiner for each refinery, or any importer, shall submit to the Administrator, with the fourth quarterly report required by § 80.75(a), a report for all reformulated gasoline and RBOB that was produced or imported during the previous calendar year averaging period, that includes the following information:
(i) The total volume of reformulated gasoline and RBOB;
(ii) The compliance total for renewable oxygen;
(iii) The actual total for renewable oxygen;
(iv) The number of renewable oxygen credits generated as a result of actual total renewable oxygen being greater than compliance total renewable oxygen;
(v) The number of renewable oxygen credits required as a result of actual total renewable oxygen being less than compliance total renewable oxygen;
(vi) The number of renewable oxygen credits transferred to another refinery or importer;
(vii) The number of renewable oxygen credits obtained from another refinery or importer; and
(viii) For any renewable oxygen credits that are transferred from or to another refinery or importer, for any such transfer:
(A) The names, EPA-assigned registration numbers and facility identification numbers of the transferor and transferee of the credits;
(B) The number of renewable oxygen credits that were transferred; and
(C) The date of the transaction.
(h)
(2) Any California gasoline shall be presumed to be used in a reformulated gasoline covered area:
(i)(A) If the gasoline is produced at a refinery that is located within a reformulated gasoline covered area; or
(B) If the gasoline is transported to a facility that is located within a reformulated gasoline covered area, or to a facility from which gasoline is transported by truck into a reformulated gasoline covered area; unless
(ii) The refiner or importer is able to establish with documentation that the gasoline was used outside any reformulated gasoline covered area.
(3) Any California gasoline shall be considered to be designated as VOC-controlled (for purposes of paragraph (a)(1) of this section) if the Reid vapor pressure of the gasoline, or RBOB subsequent to oxygenate blending, is intended to meet a standard of:
(i) 7.8 psi or less in the case of gasoline intended for use before March 1, 1996; or
(ii) 7.0 psi or less in the case of gasoline intended for use on or after March 1, 1996.
(i)
(i) Such petition must satisfy the following criteria:
(A) Evidence showing an increase in the market share and/or use of oxygenates which produce commingling-related RVP increases in the area(s) that are covered by the petition;
(B) Evidence demonstrating a pattern of exceedances for the period for which the extension is sought, including
(C) An analysis showing that the pattern of ozone exceedances is likely to continue even with implementation of other ozone air quality control measures and/or programs currently planned by the State; and
(D) Evidence that the responsible State agency or authority has given the public an opportunity for a public hearing and the submission of written comments with respect to the petition.
(ii) Effective data and publication of decision.
(A) If the Administrator determines that the petition meets the requirements of paragraph (i)(1)(i) of this section, to the satisfaction of the Administrator, then EPA shall publish a notice in the
(
(
(B) If the Administrator receives adverse comments or information demonstrating to the satisfaction of the Administrator that the criteria of paragraph (i)(1)(i) of this section have not been met, that the tentative effective date is not reasonable, or that other good reasons exist to deny the petition, then the Administrator may reject the Governor's request for an extended non-commingling season, in whole or in part, or may delay the effective date by up to two (2) additional years. Absent receipt of such adverse comments or information, EPA shall publish a notice in the
(2) In the case of any refiner that produces RBOB, or any importer that imports RBOB, the oxygenate that is blended with the RBOB may be included with the refiner's or importer's compliance calculations under paragraph (d) of this section only if:
(i) The oxygenate meets the applicable renewable oxygenate definition under paragraph (a) of this section; and
(ii) In the case of RBOB designated for “non VOC controlled ether only” the refiner or importer assumes that ETBE or other oxygenate that does not exhibit volatility-related commingling effects when mixed with other gasolines and approved by the EPA Administrator under subparagraph (a)(3) of this section will be blended with the RBOB and so labels the transfer documentation.
At 59 FR 39290, Aug. 2, 1994, § 80.83 was added effective September 1, 1994, except for paragraphs (g) and (h), which will not become effective until approval has been given by the Office of Management and Budget. At 59 FR 60715, Nov. 28, 1994, this section was stayed, effective September 13, 1994.
(a)
(b)
(2) The simple model annual average baseline exhaust benzene emissions for any facility of a refiner or importer of conventional gasoline shall be determined as follows:
(i) The simple model baseline exhaust benzene emissions shall be determined separately for summer and winter using the facility's oxygenated individual baseline fuel parameter values for summer and winter (per § 80.91), respectively, in the equation specified in paragraph (b)(1) of this section.
(ii) The simple model annual average baseline exhaust benzene emissions of the facility shall be determined using the emissions values determined in paragraph (b)(2)(i) of this section in the equation specified in paragraph (a) of this section.
(c)
(1) The summer and winter complex model baseline exhaust benzene emissions shall be determined separately using the facility's oxygenated individual baseline fuel parameter values for summer and winter (per § 80.91), respectively, in the appropriate complex model for exhaust benzene emissions described in § 80.45.
(2) The complex model annual average baseline exhaust benzene emissions of the facility shall be determined using the emissions values determined in paragraph (c)(1) of this section in the equation specified in paragraph (a) of this section.
(d)
(1) The summer and winter baseline exhaust emissions of benzene, formaldehyde, acetaldehyde, 1,3-butadiene, and polycyclic organic matter shall be determined using the oxygenated individual baseline fuel parameter values for summer and winter (per § 80.91), respectively, in the appropriate complex model for each exhaust toxic (per § 80.45).
(2) The summer and winter baseline total exhaust toxics emissions shall be determined separately by summing the summer and winter baseline exhaust emissions of each toxic (per paragraph (d)(1) of this section), respectively.
(3) The annual average baseline exhaust toxics emissions of the facility shall be determined using the emissions values determined in paragraph (d)(2) of this section in the equation specified in paragraph (a) of this section.
(e)
(1) The summer and winter baseline NO
(2) The annual average baseline NO
(3) The requirements specified in paragraphs (e) (1) and (2) of this section shall be determined separately using the oxygenated and nonoxygenated individual baseline fuel parameters, per § 80.91.
(f)
(g)
(a)
(i) An estimate of the quality, composition and volume of its 1990 gasoline, or allowable substitute, based on the requirements specified in §§ 80.91 through 80.93; and
(ii) Its baseline emissions values calculated per paragraph (f) of this section; and
(iii) Its 1990-1993 blendstock-to-gasoline ratios calculated per § 80.102.
(2)(i) The quality and composition of the 1990 gasoline of a refinery, refiner or importer, as applicable, shall be the set of values of the following fuel parameters: benzene content; aromatic content; olefin content; sulfur content; distillation temperature at 50 and 90 percent by volume evaporated; percent evaporated at 200 °F and 300 °F; oxygen content; RVP.
(ii) A refiner, per paragraph (b)(3)(i) of this section, shall also determine the API gravity of its 1990 gasoline.
(3) The methodology outlined in this section shall be followed in determining a baseline value for each fuel parameter listed in paragraph (a)(2) of this section.
(b)
(ii) A refinery which was in operation for at least 6 months in 1990, was shut down after 1990, and which restarts after June 15, 1994, and for which insufficient 1990 and post-1990 data was collected prior to January 1, 1995 from which to determine an individual baseline, shall have the values listed in paragraph (c)(5) of this section as its individual baseline parameters.
(iii) A refinery which was in operation for less than 6 months in 1990 shall have the values listed in paragraph (c)(5) of this section as its individual baseline parameters.
(2)
(3)
(ii) If Method 1-type data on every batch of the refiner's or refinery's 1990 gasoline does not exist, that refiner or refinery shall have the values listed in paragraph (c)(5) of this section as its individual baseline parameters.
(4)
(ii) An importer which is also a foreign refiner must determine its individual baseline using Method 1, 2 and/or 3-type data (per paragraph (c) of this section) if it imported at least 75 percent, by volume, of the gasoline produced at its foreign refinery in 1990 into the United States in 1990.
(iii) An importer which cannot meet the criteria of paragraphs (b)(4)(i) or (ii) of this section for baseline determination shall have the parameter values listed in paragraph (c)(5) of this section as its individual baseline parameter values.
(5)
(c)
(ii) Gasoline blendstock which left a facility in 1990 and which could become gasoline solely upon the addition of oxygenate shall be included in the baseline determination.
(A) Fuel parameter values of such blendstock shall be accounted for as if the gasoline blendstock were blended with ten (10.0) volume percent ethanol.
(B) If the refiner or importer can provide evidence that such gasoline blendstock was not blended per paragraph (c)(1)(ii)(A) of this section, and that such gasoline blendstock was blended with another oxygenate or a different volume of ethanol, the fuel parameter values of the final gasoline (including oxygenate) shall be included in the baseline determination.
(C) If the refiner or importer can provide evidence that such gasoline blendstock was not blended per paragraph (c)(1)(ii)(A) or (B) of this section, and that such gasoline blendstock was sold with out further changes downstream, the fuel parameter values of the original product shall be included in the baseline determination.
(iii) Data on 1990 gasoline purchased or otherwise received, including intracompany transfers, shall not be included in the baseline determination of a refiner's or importer's facility if the gasoline exited the receiving refinery unchanged from its arrival state.
(2)
(3)
(ii) In order to use Method 3-type data, the refiner or importer must do all of the following:
(A) Include a detailed discussion comparing its 1990 and post-1990 refinery operations and all other differences which would cause the 1990 and post-1990 fuel parameter values to differ; and
(B) Perform the appropriate calculations so as to adjust for the differences determined in paragraph (c)(3)(ii)(A) of this section; and
(C) Include a narrative, discussing the methodology and reasoning for the adjustments made per paragraph (c)(3)(ii)(B) of this section.
(iii) In order to use post-1990 gasoline data, either of the following must be
(A) The post-1990 volumetric fraction of a blendstock is within (+/−)10.0 percent of the volumetric fraction of that blendstock in 1990 gasoline. For example, if a 1990 blendstock constituted 30 volume percent of 1990 gasoline, this criterion would be met if the post-1990 volumetric fraction of the blendstock in post-1990 gasoline was 27.0-33.0 volume percent.
(B) The post-1990 volumetric fraction of a blendstock is within (+/−)2.0 volume percent of the absolute value of the 1990 volumetric fraction. For example, if a 1990 blendstock constituted 5 volume percent of 1990 gasoline, this criterion would be met if the post-1990 volumetric fraction of the blendstock in post-1990 gasoline was 3-7 volume percent.
(iv) If using post-1990 gasoline data, post-1990 gasoline blendstock which left a facility and which could become gasoline solely upon the addition of oxygenate shall be included in the baseline determination, per the requirements specified in paragraph (c)(1)(ii) of this section.
(4)
(ii) If a refiner has insufficient Method 1-type data for a baseline parameter value determination, it must supplement that data with all available Method 2-type data, until it has sufficient data, per paragraph (d)(1)(iii) of this section.
(iii) If a refiner has insufficient Method 1- and Method 2-type data for a baseline parameter value determination, it must supplement that data with all available Method 3-type data, until it has sufficient data, per paragraph (d)(1)(iii) of this section.
(iv) The protocol for the determination of baseline fuel parameter values in paragraphs (c)(4)(i) through (iii) of this section shall be applied to each fuel parameter one at a time.
(5)
(ii) The winter anti-dumping statutory baseline shall have the set of fuel parameter values identified as “winter” in § 80.45(b)(2), except that winter RVP shall be 8.7 psi. The anti-dumping winter API gravity shall be 60.2 API.
(iii) The annual average anti-dumping statutory baseline shall have the following set of fuel parameter values:
(iv) The annual average anti-dumping statutory baseline shall have the following set of emission values:
(d)
(
(
(
(B) Once the minimum sampling requirements have been met, data collection may cease. Additional data may only be included for the remainder of the calendar year in which the minimum sampling requirements were met. In any case, all data collected through the date of collection of the last data point included in the determination of a baseline fuel parameter value must be utilized in the baseline determination of that fuel parameter.
(C) Less than the minimum requirements specified in paragraph (d)(1) of this section may be allowed, upon petition and approval (per § 80.93), if it can be shown that the available data is sufficient in quality and quantity to use in the baseline determination.
(ii)
(iii)
(B) For blendstocks produced on a batch basis, at least half of all batches of a single blendstock type produced in a calendar month shall have been sampled over a minimum of six months in 1990.
(iv)
(
(B)
(2)
(3)
(4)
(ii) Blendstock samples of a single blendstock type obtained from continuous processes over a calendar month may be mixed together in equal volumes to form one blendstock sample and the sample subsequently analyzed for the required fuel parameters.
(iii)(A) Samples shall have been collected and stored per the method normally employed at the refinery in order to prevent change in product composition with regard to baseline properties and to minimize loss of volatile fractions of the sample.
(B) Properties of the retained samples shall be adjusted for loss of butane by comparing the RVP measured right after blending with the RVP determined at the time that the supplemental properties are measured.
(C) The volume of each batch or shipment sampled shall have been noted
(D) For each batch or shipment sampled, the ratio of its volume to the total volume determined in paragraph (d)(4)(iii)(C) of this section shall be determined to three (3) decimal places. This shall be the volumetric fraction of the shipment in the mixture.
(E) The total minimum volume required to perform duplicate analyses to obtain values of all of the required fuel parameters shall be determined.
(F) The volumetric fraction determined in paragraph (d)(4)(iii)(D) of this section for each batch or shipment shall be multiplied by the value determined in paragraph (d)(4)(iii)(E) of this section.
(G) The resulting value determined in paragraph (d)(4)(iii)(F) of this section for each batch or shipment shall be the volume of each batch or shipment's sample to be added to the mixture. This volume shall be determined to the nearest milliliter.
(H) The appropriate volumes of each shipment's sample shall be thoroughly mixed and the solution analyzed per the methods normally employed at the refinery.
(5)
(ii) Oxygen content may have been determined analytically or from oxygenate blending records.
(A) The fuel parameter values, other than oxygen content, specified in paragraph (a) of this section, must be established as for any blendstock, per the requirements of this paragraph (d).
(B) All oxygen associated with allowable gasoline oxygenates per § 80.2(jj) shall be included in the determination of the baseline oxygen content, if oxygen content was determined analytically.
(C) Oxygen content shall be assumed to be contributed solely by the oxygenate which is indicated on the blending records, if oxygen content was determined from blending records.
(6)
(i) Improper labeling; or
(ii) Improper testing; or
(iii) Other reasons as verified by the auditor specified in § 80.92.
(e)
(i) Two or more refineries or sets of gasoline blendstock-producing units of a refiner engaged in the production of gasoline per paragraph (b)(1) of this section which are geographically proximate to each other, yet not within a single refinery gate, and whose 1990 operations were significantly interconnected.
(ii) A gasoline blending facility operating per paragraph (b)(3) of this section received at least 75 percent of its 1990 blendstock volume from a single refinery, or from one or more refineries which are part of an aggregate baseline per § 80.101(h). The blending facility and associated refinery(ies) must be owned by the same refiner.
(iii) For facilities determined to be closely integrated gasoline producing facilities and for which EPA has granted a single set of baseline fuel parameter values per this paragraph (e)(1)(i):
(A) All reformulated gasoline and anti-dumping standards shall be met by such closely integrated facilities on an aggregate basis;
(B) A combined facility registration shall be submitted under §§ 80.76 and 80.103; and
(C) Record keeping requirements under §§ 80.74 and 80.104 and reporting requirements under §§ 80.75 and 80.105 shall be met for such closely integrated facilities on an aggregate basis.
(2)
(ii)
(A) All gasoline produced to meet EPA's 1990 summertime volatility requirements shall be considered summer gasoline. All other gasoline shall be considered winter gasoline.
(B)(
(
(
(C) Fuel parameter values shall be determined in the same units and at least to the same number of decimal places as the corresponding fuel parameter listed in paragraph (c)(5) of this section.
(D) Volumes shall be reported to the nearest barrel or to the degree at which historical records were kept.
(iii)
(iv)
(v)
(B) Post-1990 gasoline. Summer and winter Method 3-type gasoline data, per paragraph (c)(3) of this section, shall be evaluated separately according tothe following equation:
(3)
(ii) If the data per paragraph (e)(3)(i) of this section are unavailable, upon petition and approval, baseline E200 and E300 values shall be determined from the following equations using the baseline T50 and T90 values, if the baseline T50 and T90 values are otherwise acceptable:
(4)
(i) If baseline values are determined first on an oxygenated basis, per paragraph (e) of this section, the calculations in paragraphs (e)(4)(i) (A) through (C) of this section shall be performed to determine the value of each baseline parameter on a non-oxygenated basis.
(A) Benzene, aromatic, olefin and sulfur content shall be determined on a non-oxygenated basis according to the following equation:
(B) Reid vapor pressure (RVP) shall be determined on a non-oxygenated basis according to the following equation:
(C) Test data and engineering judgement shall be used to estimate T90, T50, E300 and E200 baseline values on a non-oxygenated basis. Allowances shall be made for physical dilution and distillation effects only, and not for refinery operational changes, e.g., decreased reformer severity required due to the
(ii) If baseline values are determined first on a non-oxygenated basis, the calculations in paragraphs (e)(4)(ii) (A) through (C) of this section shall be performed to determine the value of each baseline parameter on an oxygenated basis.
(A) Benzene, aromatic, olefin and sulfur content shall be determined on an oxygenated basis according to the following equation:
(B) Reid vapor pressure (RVP) shall be determined on an oxygenated basis according to the following equation:
(C) Test data and engineering judgement shall be used to estimate T90, T50, E300 and E200 baseline values on an oxygenated basis. Allowances shall be made for physical dilution and distillation effects only, and not for refinery operational changes, e.g., decreased reformer severity required due to the octane value of oxygenate which would reduce aromatics.
(5)
(i) Work-in-progress shall include:
(A) Refinery modification projects involving gasoline blendstock or distillate producing units which were under construction in 1990; or
(B) Refinery modification projects involving gasoline blendstock or distillate producing units which were contracted for prior to or in 1990 such that the refiner was committed to purchasing materials and constructing the project.
(ii) The modifications discussed in paragraph (e)(5)(i) of this section must have been initiated with intent of complying with a legislative or regulatory environmental requirement enacted or promulgated prior to January 1, 1991.
(iii) When comparing emissions or parameter values determined with and without the anticipated work-in-progress adjustment, at least one of the following situations results when comparing annual average baseline values per § 80.90:
(A) A 2.5 percent or greater difference in exhaust benzene emissions (per § 80.90); or
(B) A 2.5 percent or greater difference in total exhaust toxics emissions (per § 80.90(d)); or
(C) A 2.5 percent or greater difference in NO
(D) A 10.0 percent or greater difference in sulfur values; or
(E) A 10.0 percent or greater difference in olefin values; or
(F) A 10.0 percent or greater difference in T90 values.
(iv) The requirements of paragraph (e)(5)(iii) of this section shall be determined according to the following equation:
(v) The capital involved in the work-in-progress is at least:
(A) 10.0 percent of the refinery's depreciated book value as of the work-in-progress start-up date; or
(B) $10 million.
(vi) Sufficient data shall have been obtained since reliable operation of the work-in-progress was achieved. Such data shall be used in the determination of the baseline value, due to the work-in-progress, of each of the fuel parameters specified in § 80.91(a)(2)(i) and as verification of the effect of the work-in-progress.
(A) The baseline value, due to the work-in-progress, of each of the fuel parameters specified in § 80.91(a)(2)(i) shall be used in the determination of the emissions specified in § 80.90.
(B) The baseline values of sulfur, olefins and E300, due to the work-in-progress, shall be used in the determination of the emissions specified in § 80.41(j)(3).
(vii) The annual average baseline values of exhaust benzene emissions, per § 80.90(b) and § 80.90(c), exhaust toxics emissions, per § 80.90(d), and NO
(A) The unadjusted annual average baseline value of each emission specified in this paragraph (e)(5)(vii); or
(B) The following values:
(
(
(
(
(viii) When compliance is achieved using the simple model, per § 80.41 and/or § 80.101, the baseline values of sulfur, olefins and T90 are the values resulting from the work-in-progress baseline adjustment, not to exceed the larger of:
(A) The unadjusted annual average baseline value of each fuel parameter specified in paragraph (e)(5)(viii) of this section; or
(B) The following values:
(
(
(
(C) An adjusted annual average baseline fuel parameter value for sulfur, olefins and T90 such that exhaust emissions of VOC, toxics, and NO
(ix) All work-in-progress adjustments must be accompanied by:
(A) Unadjusted and adjusted fuel parameters, emissions, and volumes; and
(B) A description of the current status of the work-in-progress (i.e., the refinery modification project) and the date on which normal operations were achieved; and
(C) A narrative describing the situation, the types of calculations, and the reasoning supporting the types of calculations done to determine the adjusted values.
(6)
(A) Unplanned, unforeseen circumstances; or
(B) Non-annual maintenance (turnaround).
(ii) Fuel parameter and volume adjustments shall be made by assuming that the downtime did not occur in 1990.
(iii) All extenuating circumstance adjustments must be accompanied by:
(A) Unadjusted and adjusted fuel parameters, emissions, and volumes; and
(B) A description of the current status of the extenuating circumstance and the date on which normal operations were achieved; and
(C) A narrative describing the situation, the types of calculations, and the reasoning supporting the types of calculations done to determine the adjusted values.
(7)
(A) Refinery type.
(
(
(
(B) No refinery of a given refiner produces reformulated gasoline. If any refinery of the refiner produces reformulated gasoline at any time in a calendar year, the compliance baselines of all the refiner's refineries receiving a baseline adjustment per this paragraph (e)(7) shall revert to the unadjusted baselines of each respective refinery for that year and all subsequent years.
(C) 1990 JP-4 to gasoline ratio.
(
(
(
(ii) Fuel parameter and volume adjustments shall be made by assuming that no JP-4 was produced in 1990.
(iii) All adjustments due to 1990 JP-4 production must be accompanied by:
(A) Unadjusted and adjusted fuel parameters, emissions, and volumes; and
(B) A narrative describing the situation, the types of calculations, and the reasoning supporting the types of calculations done to determine the adjusted values.
(8) Baseline adjustments due to increasing crude sulfur content.
(i) Baseline adjustments may be allowed, upon petition and approval (per § 80.93), if a refinery meets all of the following requirements:
(A) The refinery does not produce reformulated gasoline. If the refinery produces reformulated gasoline at any time in a calendar year, its compliance baseline shall revert to its unadjusted baseline for that year and all subsequent years;
(B) Has an unadjusted baseline sulfur value which is less than or equal to 50 parts per million (ppm);
(C) Is not aggregated with one or more other refineries (per § 80.101(h)). If a refinery which received an adjustment per this paragraph (e)(8) subsequently is included in an aggregate baseline, its compliance baseline shall revert to its unadjusted baseline for that year and all subsequent years;
(D) Can show that installation of the refinery units necessary to process higher sulfur crude oil supplies to comply with the refinery's unadjusted baseline would cost at least $10 million or be greater than or equal to 10 percent of the depreciated book value of the refinery as of January 1, 1995;
(E) Can show that it could not reasonably or economically obtain crude oil from an alternative source that would permit it to produce conventional gasoline which would comply with its unadjusted baseline;
(F) Has experienced an increase of greater than or equal to 25 percent in the average sulfur content of the crude oil used in the production of gasoline in the refinery since 1990, calculated as follows:
(G) Can show that gasoline sulfur changes are directly and solely attributable to the crude sulfur change, and not due to alterations in refinery operation nor choice of products.
(ii) The adjusted baseline sulfur value shall be the actual baseline sulfur value, in ppm, plus 100 ppm.
(iii) All adjustments made pursuant to this paragraph (e)(8) must be accompanied by:
(A) Unadjusted and adjusted fuel parameters and emissions; and
(B) A narrative describing the situation, the types of calculations, and the reasoning supporting the types of calculations done to determine the adjusted values.
(9) Baseline adjustment for low sulfur and olefins.
(i) Baseline adjustments may be allowed if a refinery meets all of the following requirements:
(A) The unadjusted annual average baseline sulfur value of the refinery is less than or equal to 30 parts per million (ppm);
(B) The unadjusted annual average baseline olefin value of the refinery is less than or equal to 1.0 percent by volume (vol%).
(ii) Adjusted baseline values.
(A) The adjusted baseline shall have an annual average sulfur value of 30 ppm, and an annual average olefin value of 1.0 vol%.
(B) The adjusted baseline shall have a summer sulfur value of 30 ppm, and a summer olefin value of 1.0 vol%.
(C) The adjusted baseline shall have a winter sulfur value of 30 ppm, and a winter olefin value of 1.0 vol%.
(f)
(ii) Gasoline brought into the refinery in 1990 which exited the refinery, in 1990, unchanged shall not be included in determining the refinery's baseline volume.
(iii) If a refiner is allowed to adjust its baseline per paragraphs (e)(5) through (e)(7) of this section, its individual baseline volume shall be the volume determined after the adjustment.
(iv) The individual baseline volume for facilities deemed closely integrated, per paragraph (e)(1) of this section, shall be the combined 1990 gasoline production of the facilities, so long as mutual volumes are not double-counted, i.e., volumes of blendstock sent from the refinery to the blending facility should not be included in the blending facility's volume.
(v) The baseline volume of a refiner, per paragraph (b)(3) of this section, shall be the larger of the total gasoline volume produced in or shipped from the refinery in 1990, excluding gasoline blendstocks and exported gasoline.
(vi) The baseline volume of an importer, per paragraph (b)(4) of this section, shall be the total gasoline volume imported into the U.S. in 1990.
(2)
(ii) If the baseline fuel value for aromatics, olefins, and/or benzene (determined per paragraph (e) of this section) is higher than the high end of the valid range limits specified in § 80.42(c)(1) if compliance is being determined under the Simple Model, or in § 80.45(f)(1)(ii) if compliance is being determined under the Complex Model, then the valid range limits may be extended for conventional gasoline in the following manner:
(A) The new high end of the valid range for aromatics is determined from the following equation:
(B) The new high end of the valid range for olefins is determined from the following equation:
(C) The new high end of the valid range for benzene is determined from the following equation:
(D) The extension of the valid range is limited to the applicable summer or winter season in which the baseline fuel values for aromatics, olefins, and/or benzene exceed the high end of the valid range as described in paragraph (f)(2)(ii) of this section. Also, the extension of the valid range is limited to use by the refiner whose baseline value for aromatics, olefins, and/or benzene was higher than the valid range limits as described in paragraph (f)(2)(ii) of this section.
(E) Any extension of the Simple Model valid range limits is applicable only to the Simple Model. Likewise any extension of the Complex Model valid range limits is applicable only to the Complex Model.
(F) The valid range extensions calculated in paragraphs (f)(2)(ii)(A), (B), and (C) of this section are applicable to both the baseline fuel and target fuel for the purposes of determining the compliance status of conventional gasolines. The extended valid range limit represents the maximum value for that parameter above which fuels cannot be evaluated with the applicable compliance model.
(G) Under the Simple Model, baseline and compliance calculations shall subscribe to the following limitations:
(
(
(H) Under the Complex Model, baseline and compliance calculations shall subscribe to the following limitations:
(
(
(
At 62 FR 68207, Dec. 31, 1997, § 80.91 was amended by adding paragraph (f)(2)(ii); however, (f)(2)(ii) already exists. The recently added subparagraph appears below.
(ii) [Reserved]
(iii) Facilities deemed closely integrated, per paragraph (e)(1) of this section, shall have a single set of annual average individual baseline emissions.
(iv) Aggregate baselines (per § 80.101(h)) must have the NO
(3)
(ii) If EPA agrees with the finding of paragraph (f)(4)(i) of this section, it shall require that the baselines of such refineries be separate from refineries not located in the area.
(iii) If two (2) or more of a refiner's refineries are located in the geographic area of concern, the refiner may aggregate the baseline emissions and sulfur, olefin and T90 values of the refineries or have an individual baseline for one or more of the refineries, per paragraph (f)(3) of this section.
(4)
(i) A refinery included in an aggregate baseline is entirely shutdown. If the shutdown refinery was part of an aggregate baseline, the aggregate baseline emissions, aggregate baseline sulfur, olefin and T90 values and aggregate volume shall be recalculated to account for the removal of the shutdown refinery's contributions to the aggregate baseline.
(ii) A refinery exchanges owners.
(A) All aggregate baselines affected by the exchange shall be recalculated to reflect the addition or subtraction of the baseline exhaust emissions, sulfur, olefin and T90 values and volumes of that refinery.
(B) The new owner may elect to establish an individual baseline for the refinery or to include it in an aggregate baseline.
(C) If the refinery was part of an aggregate of three or more refineries, the remaining refineries in the aggregate from which that refinery was removed will have a new aggregate baseline. If the refinery was part of an aggregate of only two refineries, the remaining refinery will have an individual baseline.
(g)
At 62 FR 68207, Dec. 31, 1997, § 80.91 was amended by revising paragraph (e)(1)(iii); however, (e)(1)(iii) did not exist in the 1997 edition of this volume.
(a)
(2) An auditor may be an individual or organization, and may utilize contractors and subcontractors to assist in the verification of a baseline.
(3) If an auditor is an organization, one or more persons shall be designated as primary analyst(s). The primary analyst(s) shall meet the requirements described in paragraphs (c) (2) and (3) of this section and shall be responsible for the baseline audit per paragraph (f) of this section.
(b)
(1)
(ii) Auditor personnel may have been a contractor or subcontractor to the refiner or importer, as long as all other criteria listed in this section are met.
(iii) Auditor personnel may also have developed the baseline of the refiner or importer whose baseline they are auditing, but not as an employee (per paragraph (b)(1)(i) of this section). Those involved only in the development of the baseline of the refiner or importer need not meet the requirements specified in this section.
(2)
(i) Have received more than one quarter of its revenue from the refiner or importer during the year prior to the date of hire of the auditor by the refiner or importer for auditing purposes. Income received from the refiner or importer to develop the baseline being audited is excepted; nor
(ii) Have a total of more than 10 percent of its net worth with the refiner or importer; nor
(iii) Receive compensation for the audit which is dependent on the outcome of the audit.
(c)
(1) The auditor shall be technically capable of evaluating a baseline determination. It shall have personnel familiar with petroleum refining processes, including associated computational procedures, methods of product analysis and economics, and expertise in conducting the auditing process, including skills for effective data gathering and analysis.
(2) The primary analyst must understand all technical details of the entire baseline audit process.
(3)(i) The primary analyst shall have worked at least five (5) years in either refinery operations or as a consultant for the refining industry.
(ii) If one or more computer models designed for refinery planning and/or economic analysis are used in the verification of an individual baseline, the primary analyst must have at least three (3) years experience working with the model(s) utilized in the verification.
(iii) EPA may, upon petition, waive one or more of the requirements specified in paragraph (c)(3) of this section if the technical capability of the primary analyst is demonstrated to the satisfaction of the Director of the Office of Mobile Sources, or designee.
(d)
(1)
(ii) The auditor qualification statement may be submitted by the refiner or importer with its baseline submission (per § 80.93). If the auditor does not meet the criteria specified in this section, the baseline submission will not be accepted.
(2)
(i) The name and address of each person and organization involved in substantive aspects of the baseline audit, including the auditor, primary analyst(s), others within the organization, and contractors and subcontractors;
(ii) The refiners and/or importers for which the auditor, its contractors and subcontractors and their organizations do not meet the independence criteria described in paragraph (b) of this section; and
(iii) The technical qualifications and experience of each person involved in the baseline audit, including a showing that the requirements described in paragraph (c) of this section are met.
(e)
(2) A refiner's or importer's baseline submission will not be accepted until it has been verified using an auditor which meets the requirements specified in paragraphs (b) and (c) of this section.
(f)
(i) Verifying that all data is correctly accounted for;
(ii) Verifying that all calculations are performed correctly;
(iii) Verifying that all adjustments to the data and/or calculations to account for post-1990 data, work-in-progress, and/or extenuating or other circumstances, as allowed per § 80.91, are valid and performed correctly.
(2) The primary analyst shall prepare and sign a statement, to be included in the baseline submission of the refiner or importer, stating that:
(i) He/she has thoroughly reviewed the sampling methodology and baseline calculations; and
(ii) To the best of his/her knowledge, the requirements and intentions of the rulemaking are met in the baseline determination; and
(iii) He/she agrees with the final baseline parameter, volume and emission values listed in the baseline submission.
(3) The auditor may be subject to debarment under U.S.C. 1001 if it displays gross incompetency, intentionally commits an error in the verification process or misrepresents itself or information in the baseline verification.
(a)
(2) If a refiner must collect data after December 15, 1993 (per § 80.91(d)(2)), it shall submit two copies of its individual baseline to EPA (per § 80.93(a)(1)) by September 1, 1994.
(3)(i) All petitions required for baseline adjustments or methodology deviations will be approved or disapproved by the Director of the Office of Mobile Sources, or designee. All instances where a “showing” or other proof is required are also subject to approval by the Director of the Office of Mobile Sources, or designee.
(ii) Petitions, “showings,” and other associated proof may be submitted to EPA prior to submittal of the individual baseline (per paragraphs (a)(1) and (a)(2) of this section). EPA will attempt to review and approve, disapprove or otherwise comment on the petition, etc., prior to the deadline for baseline submittal.
(iii) In the event that EPA does not comment on the petition prior to the deadline for baseline submittal, the refiner or importer must still comply with the applicable baseline submittal deadline.
(iv) Petitions submitted prior to the deadline for baseline submittals shall be submitted to the EPA at the following address: Fuels Studies and Standards Branch, Baseline Petition, U.S. EPA, 2565 Plymouth Road, Ann Arbor, Michigan 48105.
(4) If a baseline recalculation is required per § 80.91(f), documentation and recalculation of all affected baselines shall be submitted to EPA within 30
(b)
(i) During its review and evaluation of the baseline submission, EPA may require a refiner or importer to submit additional information in support of the baseline determination.
(ii) Additional information which may assist EPA during its review and evaluation of the baseline may be included at the submitter's discretion.
(2) Administrative information shall include:
(i) Name and business address of the refiner or importer;
(ii) Name, business address and business phone number of the company contact;
(iii) Address and physical location of each refinery, terminal or import facility;
(iv) Address and physical location where documents which are supportive of the baseline determination for each facility are kept;
(3) The chief executive officer statement shall be:
(i) A statement signed by the chief executive officer of the company, or designee, which states that:
(A) The company is complying with the requirements as a refiner, blender or importer, as appropriate;
(B) The data used in the baseline determination is the extent of the data available for the determination of all required baseline fuel parameters;
(C) All calculations and procedures followed per §§ 80.90 through 80.93 have been done correctly;
(D) Proper adjustments have been made to the data or in the calculations, as applicable;
(E) The requirements and intentions of the rulemaking have been met in determining the baseline fuel parameters; and
(F) The baseline fuel parameter values determined for each facility represent that facility's 1990 gasoline to the fullest extent possible.
(ii) A refiner or importer which is permitted to utilize the parameter values specified in § 80.91(c)(5), and does so, shall submit a statement signed by the chief executive officer of the company, or designee, indicating that insufficient data exist for a baseline determination by the types of data allowed for that entity, as specified in § 80.91.
(4) The auditor-related requirements are:
(i) Name, address, telephone number and date of hire of each auditor hired for baseline verification, whether or not the auditor was retained through the baseline approval process.
(ii) Identification of the auditor responsible for the verification. A copy of this auditor's qualification statement, per § 80.92, must be included if the auditor has not been approved by EPA, per § 80.92;
(iii) Indication of the primary analyst(s) involved in each refinery's baseline verification; and
(iv) The signed auditor verification statement, per § 80.92.
(5) The following baseline information for each refinery, refiner or importer, as applicable, shall be provided:
(i) Individual baseline fuel parameter values, on an oxygenated and non-oxygenated basis, and on a summer and winter basis, per § 80.91;
(ii) Individual baseline exhaust emissions shall be shown separately, on a summer, winter and annual average basis (per § 80.90) as follows:
(A) Simple model exhaust benzene emissions;
(B) Complex model exhaust benzene emissions;
(C) Complex model exhaust toxics emissions, for Phase I;
(D) Complex model exhaust NO
(E) Complex model exhaust NO
(F) Complex model exhaust toxics emissions, for Phase II;
(G) Complex model exhaust NO
(H) Complex model exhaust NO
(iii) Individual 1990 baseline gasoline volumes, per § 80.91, shall be shown separately on a summer, winter and annual average basis; and
(iv) Blendstock-to-gasoline ratios for each calendar year 1990 through to 1993, per § 80.102.
(6)
(i) Upon approval of an individual baseline, EPA will publish the individual annualized baseline exhaust emissions, on an annual average basis, specified in paragraph (b)(5)(ii) of this section. Such individual baseline exhaust emissions shall not be considered confidential. In addition, the reporting information required under § 80.75(b)(2)(ii) (D), (G) and (J), and § 80.105(a)(4)(i) (E), (H) and (K) shall not be considered confidential.
(ii) Information in the baseline submission which the submitter desires to be considered confidential business information (per 40 CFR part 2, subpart B) must be clearly identified. If no claim of confidentiality accompanies a submission when it is received by EPA, the information may be made available to the public without further notice to the submitter pursuant to the provisions of 40 CFR part 2, subpart B.
(7) Information related to baseline determination as specified in § 80.91 and paragraph (c) of this section.
(c)
(1)
(i) The number of months in 1990 during which the facility was operating;
(ii) 1990 summer gasoline production volume, per § 80.91, total and by grade, for all gasoline produced but not exported;
(iii) 1990 winter gasoline production volume, per § 80.91, total and by grade, for all gasoline produced, excluding gasoline exported; and
(iv) Whether this facility is actually two facilities which are closely integrated, per § 80.91.
(2)
(i) Narrative of the development of the baseline value of the fuel parameter, including discussion of the sampling and calculation methodologies, technical judgment used, effects of petition results on calculated values, and any additional information which may assist EPA in its review of the baseline;
(ii) Identification of the data-type(s), per § 80.91, used in the determination of a given fuel parameter;
(iii) Identification of test method. If not per § 80.46, include a narrative, explain differences and describing adequacy, per § 80.91;
(iv) Documentation that the minimum sampling requirements per § 80.91 have been met;
(v) Petition and narrative, if needed, for use of less than the minimum required data, per § 80.91;
(vi) Identification of instances of sample compositing per § 80.91;
(vii) Identification of streams for which one or more parameter values were deemed negligible per § 80.91; and
(viii) Discussion of the calculation of oxygenated or non-oxygenated fuel parameter values from non-oxygenated or oxygenated values, respectively, per § 80.91.
(3)
(i) First and last sampling dates;
(ii) The following shall be indicated separately on a summer and winter basis, by month:
(A) Number of months sampled;
(B) Number of 1990 batches, or shipments if not batch blended;
(C) Total volume of all batches or shipments;
(D) Number of batches or shipments sampled;
(E) Total volume of all batches or shipments sampled;
(F) Baseline fuel parameter value, per § 80.91; and
(iii) A showing that data was available on every batch of 1990 gasoline, if applicable, per § 80.91 (b)(3) or (b)(4).
(4)
(i) First and last sampling dates; and
(ii) The following shall be indicated separately on a summer and winter basis, by month:
(A) Number of months sampled;
(B) Each type of blendstock used in 1990 gasoline and total number of blendstocks. Include all blendstocks produced, purchased or otherwise received which were blended to produce gasoline within the facility. Identify all blendstocks not produced in the facility but used in the facility's 1990 gasoline;
(C) Total volume of each blendstock used in gasoline in 1990;
(D) Identification of blendstock streams as batch or continuous;
(E) Number of blendstock samples from continuous blendstock streams;
(F) Number of blendstock samples from batch processes, including volume of each batch sampled; and
(G) Baseline fuel parameter value, per § 80.91.
(5)
(i) First and last sampling dates;
(ii) The following shall be indicated separately on a summer and winter basis, by month:
(A) Number of post-1990 months sampled;
(B) Each type of blendstock used in 1990 gasoline and total number of blendstocks. Include all blendstocks produced, purchased or otherwise received which were blended to produce gasoline within the facility. Identify all blendstocks not produced in the facility but used in the facility's 1990 gasoline;
(C) Total volume of each blendstock used in gasoline in 1990;
(D) Identification of post-1990 blendstock streams as batch or continuous;
(E) Number of post-1990 blendstock samples from continuous blendstock streams;
(F) Number of post-1990 blendstock samples from batch processes, including volume of each batch sampled; and
(G) Baseline fuel parameter value, per § 80.91; and
(iii) Support documentation showing that the criteria of § 80.91 for using Method 3-type blendstock data are met.
(6)
(i) First and last sampling dates;
(ii) The following shall be indicated separately for summer and winter production, by month:
(A) Number of post-1990 months sampled;
(B) Number of post-1990 batches, or shipments if not batch blended;
(C) Total volume of all post-1990 batches or shipments;
(D) Number of post-1990 batches or shipments sampled;
(E) Volume of each post-1990 batch or shipment sampled; and
(F) Baseline fuel parameter value, per § 80.91; and
(iii) Support documentation showing that the criteria of § 80.91 for using post-1990 gasoline data are met.
(7)
(i) Petition including identification of the specific baseline emission(s) or parameter for which the WIP adjustment is desired;
(ii) Showing that all WIP criteria, per § 80.91(e)(5), are met;
(iii) Unadjusted and adjusted baseline fuel parameters, emissions and volume for the facility; and
(iv) Narrative, per § 80.91 (e)(5).
(8)
(i) Petition including identification of the allowable circumstance, per § 80.91 (e)(6) through (e)(7);
(ii) Showing that all applicable criteria, per § 80.91 (e)(6) through (e)(7), are met;
(iii) Unadjusted and adjusted baseline fuel parameters, emissions and volume for the facility; and
(iv) Narrative, per § 80.91.
(9)
(10)
(i) Refinery block flow diagram, showing principal refining units;
(ii) Principal refining unit charge rates and capacities;
(iii) Crude types utilized (names, gravities, and sulfur content) and crude charge rates; and
(iv) Information on the following units, if utilized in the refinery:
(A) Catalytic Cracking Unit: conversion, unit yields, gasoline fuel parameter values (per § 80.91(a)(2));
(B) Hydrocracking Unit: unit yields, gasoline fuel parameter values (per § 80.91(a)(2));
(C) Catalytic Reformer: unit yields, severities;
(D) Bottoms Processing Units (including, but not limited to, coking, extraction and hydrogen processing): gasoline stream yields;
(E) Yield structures for other principal units in the refinery (including but not limited to Alkylation, Polymerization, Isomerization, Etherification, Steam Cracking).
(d) Requirements for petition applicable to Puerto Rico gasoline.
(1) Any refiner or importer with Puerto Rico gasoline, or Puerto Rico and U.S. Virgin Islands gasoline, in its individual baseline may petition EPA to use the summer Complex Model to evaluate its Puerto Rico and Virgin Islands gasoline for compliance under § 80.101.
(2) The petition must be sent to: U.S. EPA, Fuels and Energy Division, 2000 Traverwood, Ann Arbor, MI 48105.
(3) The petition must include the following:
(i) Identification of the refinery;
(ii) Identification of contact person;
(iii) A revised individual baseline determination, wherein the baseline Puerto Rico and U.S. Virgin Islands gasoline has been evaluated using the summer Complex Model. The calculations should be clearly and fully described and displayed.
(iv) Baseline auditor agreement with the revised baseline.
(4) EPA reserves the right to request additional information. If such information is not forthcoming in a timely manner, the petition will not be approved.
At 64 FR 30910, June 9, 1999, in § 80.93, paragraph (d) was added, effective July 26, 1999.
(a)
(2) A
(3)
(4)
(5)
(6)
(b)
(1) The provisions for baselines as specified in §§ 80.90 through 80.93 shall apply to a foreign refinery, except where provided otherwise in this section.
(2) The baseline for a foreign refinery shall reflect only the volume and properties of gasoline produced in 1990 that was imported into the United States.
(3) A baseline petition shall establish the volume of conventional gasoline produced at a foreign refinery and imported into the United States during the calendar year immediately preceding the year the baseline petition is submitted.
(4) In making determinations for foreign refinery baselines EPA will consider all information supplied by a foreign refiner, and in addition may rely on any and all appropriate assumptions necessary to make such a determination.
(5) Where a foreign refiner submits a petition that is incomplete or inadequate to establish an accurate baseline, and the refiner fails to cure this defect after a request for more information, then EPA shall not assign an individual refinery baseline.
(6) Baseline petitions under this paragraph (b) of this section must be submitted before January 1, 2002.
(c)
(1)(i) In the case of certified FRGAS, the foreign refiner shall meet all requirements that apply to refiners under 40 CFR part 80, subparts D, E and F.
(ii) If the foreign refinery baseline is assigned, or a foreign refiner begins early use of a refinery baseline under paragraph (r) of this section, on a date other than January 1, the compliance baseline for the initial year shall be calculated under § 80.101(f) using an adjusted baseline volume, as follows:
(2) In the case of non-certified FRGAS, the foreign refiner shall meet the following requirements, except the foreign refiner shall substitute the name “non-certified FRGAS” for the names “reformulated gasoline” or “RBOB” wherever they appear in the following requirements:
(i) The designation requirements in § 80.65(d)(1);
(ii) The recordkeeping requirements in § 80.74 (a), and (b)(3);
(iii) The reporting requirements in § 80.75 (a), (m), and (n);
(iv) The registration requirements in § 80.76;
(v) The product transfer document requirements in § 80.77 (a) through (f), and (j);
(vi) The prohibition in § 80.78(a)(10), (b) and (c); and
(vii) The independent audit requirements in §§ 80.125 through 80.127, 80.128 (a) through (c), and (g) through (i), and 80.130.
(3)(i) Any foreign refiner that has been assigned an individual baseline for a foreign refinery under paragraph (b) of this section may elect to classify no gasoline imported into the United States as FRGAS, provided the foreign refiner notifies EPA of the election no later than November 1 of the prior calendar year.
(ii) An election under paragraph (c)(3)(i) of this section shall:
(A) Be for an entire calendar year averaging period and apply to all gasoline produced during the calendar year at the foreign refinery that is imported into the United States; and
(B) Remain in effect for each succeeding calendar year averaging period, unless and until the foreign refiner notifies EPA of a termination of the election. The change in election shall take effect at the beginning of the next calendar year.
(iii) A foreign refiner who has aggregated refineries under § 80.101(h) shall
(d)
(2) On each occasion when any person transfers custody or title to any FRGAS prior to its being imported into the United States, the following information shall be included as part of the product transfer document information in §§ 80.77 and 80.106:
(i) Identification of the gasoline as certified FRGAS or as non-certified FRGAS; and
(ii) The name and EPA refinery registration number of the refinery where the FRGAS was produced.
(3) On each occasion when FRGAS is loaded onto a vessel or other transportation mode for transport to the United States, the foreign refiner shall prepare a certification for each batch of the FRGAS that meets the following requirements:
(i) The certification shall include the report of the independent third party under paragraph (f) of this section, and the following additional information:
(A) The name and EPA registration number of the refinery that produced the FRGAS;
(B) The identification of the gasoline as certified FRGAS or non-certified FRGAS;
(C) The volume of FRGAS being transported, in gallons;
(D) A declaration that the FRGAS is being included in the compliance baseline calculations under § 80.101(f) for the refinery that produced the FRGAS; and
(E) In the case of certified FRGAS:
(
(
(ii) The certification shall be made part of the product transfer documents for the FRGAS.
(e)
(1)(i) The foreign refiner excludes:
(A) The volume of gasoline from the refinery's compliance baseline calculations under § 80.101(h); and
(B) In the case of certified FRGAS, the volume and parameter values of the gasoline from the compliance calculations under § 80.101(g);
(ii) The exclusions under paragraph (e)(1)(i) of this section shall be on the basis of the parameter and volumes determined under paragraph (f) of this section; and
(2) The foreign refiner obtains sufficient evidence in the form of documentation that the gasoline was not imported into the United States.
(f)
(i) Inspect the vessel prior to loading and determine the volume of any tank bottoms;
(ii) Determine the volume of FRGAS loaded onto the vessel (exclusive of any tank bottoms present before vessel loading);
(iii) Obtain the EPA-assigned registration number of the foreign refinery;
(iv) Determine the name and country of registration of the vessel used to transport the FRGAS to the United States; and
(v) Determine the date and time the vessel departs the port serving the foreign refinery.
(2) On each occasion certified FRGAS is loaded onto a vessel for transport to the United States a foreign refiner shall have an independent third party:
(i) Collect a representative sample of the certified FRGAS from each vessel
(ii) Prepare a volume-weighted vessel composite sample from the compartment samples, and determine the values for sulfur, benzene, gravity, E200 and E300 using the methodologies specified in § 80.46, by:
(A) The third party analyzing the sample; or
(B) The third party observing the foreign refiner analyze the sample;
(iii) Determine the values for aromatics, olefins, RVP and each oxygenate specified in § 80.65(e)(2) for the gasoline loaded onto the vessel, by:
(A) Completing the analysis procedures under paragraph (f)(2)(ii) of this section for the additional parameters; or
(B) Obtaining from the foreign refiner the test results of samples collected from each shore tank containing gasoline that was loaded onto the vessel, and calculating the parameter values for the gasoline loaded onto the vessel from the tank parameter values and the gasoline volume from each such shore tank that was loaded;
(iv) Review original documents that reflect movement and storage of the certified FRGAS from the refinery to the load port, and from this review determine:
(A) The refinery at which the FRGAS was produced; and
(B) That the FRGAS remained segregated from:
(
(
(3) The independent third party shall submit a report:
(i) To the foreign refiner containing the information required under paragraphs (f) (1) and (2) of this section, to accompany the product transfer documents for the vessel; and
(ii) To the Administrator containing the information required under paragraphs (f) (1) and (2) of this section, within thirty days following the date of the independent third party's inspection. This report shall include a description of the method used to determine the identity of the refinery at which the gasoline was produced, that the gasoline remained segregated as specified in paragraph (n)(1) of this section, and a description of the gasoline's movement and storage between production at the source refinery and vessel loading.
(4) A person may be used to meet the third party requirements in this paragraph (f) only if:
(i) The person is approved in advance by EPA, based on a demonstration of ability to perform the procedures required in this paragraph (f);
(ii) The person is independent under the criteria specified in § 80.65(f)(2)(iii); and
(iii) The person signs a commitment that contains the provisions specified in paragraph (i) of this section with regard to activities, facilities and documents relevant to compliance with the requirements of this paragraph (f).
(g)
(ii) Where a vessel transporting certified FRGAS off loads this gasoline at more than one United States port of entry, and the conditions of paragraph (g)(2)(i) of this section are not met at the first United States port of entry, the requirements of paragraph (g)(1) and (g)(2) of this section do not apply at subsequent ports of entry if the United States importer obtains a certification from the vessel owner or his immediate designee that the vessel has not loaded any gasoline or blendstock between the first United States port of entry and the subsequent port of entry.
(2)(i) The requirements of paragraph (g)(2)(ii) apply if:
(A)(
(
(B) The NO
(ii) The United States importer and the foreign refiner shall treat the gasoline as non-certified FRGAS, and the foreign refiner shall:
(A) Exclude the gasoline volume and properties from its conventional gasoline NO
(B) Include the gasoline volume in its compliance baseline calculation under § 80.101(f), unless the foreign refiner establishes that the United States importer classified the gasoline only as conventional gasoline and not as reformulated gasoline.
(h)
(1) Include in the inventory reconciliation analysis under § 80.128(b) and the tender analysis under § 80.128(c) non-FRGAS in addition to the gasoline types listed in § 80.128 (b) and (c).
(2) Obtain separate listings of all tenders of certified FRGAS, and of non-certified FRGAS. Agree the total volume of tenders from the listings to the gasoline inventory reconciliation analysis in § 80.128(b), and to the volumes determined by the third party under paragraph (f)(1) of this section.
(3) For each tender under paragraph (h)(2) of this section where the gasoline is loaded onto a marine vessel, report as a finding the name and country of registration of each vessel, and the volumes of FRGAS loaded onto each vessel.
(4) Select a sample from the list of vessels identified in paragraph (h)(3) of this section used to transport certified FRGAS, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(i) Obtain the report of the independent third party, under paragraph (f) of this section, and of the United States importer under paragraph (o) of this section.
(A) Agree the information in these reports with regard to vessel identification, gasoline volumes and test results.
(B) Identify, and report as a finding, each occasion the load port and port of entry parameter and volume results differ by more than the amounts allowed in paragraph (g) of this section, and determine whether the foreign refiner adjusted its refinery calculations as required in paragraph (g) of this section.
(ii) Obtain the documents used by the independent third party to determine transportation and storage of the certified FRGAS from the refinery to the load port, under paragraph (f) of this section. Obtain tank activity records for any storage tank where the certified FRGAS is stored, and pipeline activity records for any pipeline used to transport the certified FRGAS, prior to being loaded onto the vessel. Use these records to determine whether the certified FRGAS was produced at the refinery that is the subject of the attest engagement, and whether the certified FRGAS was mixed with any non-certified FRGAS, non-FRGAS, or any certified FRGAS produced at a different refinery that was not aggregated under § 80.101(h).
(5)(i) Select a sample from the list of vessels identified in paragraph (h)(3) of this section used to transport certified and non-certified FRGAS, in accordance with the guidelines in § 80.127, and for each vessel selected perform the following:
(ii) Obtain a commercial document of general circulation that lists vessel arrivals and departures, and that includes the port and date of departure of the vessel, and the port of entry and date of arrival of the vessel. Agree the vessel's departure and arrival locations and dates from the independent third
(6) Obtain separate listings of all tenders of non-FRGAS, and perform the following:
(i) Agree the total volume of tenders from the listings to the gasoline inventory reconciliation analysis in § 80.128(b).
(ii) Obtain a separate listing of the tenders under paragraph (h)(6) of this section where the gasoline is loaded onto a marine vessel. Select a sample from this listing in accordance with the guidelines in § 80.127, and obtain a commercial document of general circulation that lists vessel arrivals and departures, and that includes the port and date of departure and the ports and dates where the gasoline was off loaded for the selected vessels. Determine and report as a finding the country where the gasoline was off loaded for each vessel selected.
(7) In order to complete the requirements of this paragraph (h) an auditor shall:
(i) Be independent of the foreign refiner;
(ii) Be licensed as a Certified Public Accountant in the United States and a citizen of the United States, or be approved in advance by EPA based on a demonstration of ability to perform the procedures required in §§ 80.125 through 80.130 and this paragraph (h); and
(iii) Sign a commitment that contains the provisions specified in paragraph (i) of this section with regard to activities and documents relevant to compliance with the requirements of §§ 80.125 through 80.130 and this paragraph (h).
(i)
(1) Any United States Environmental Protection Agency inspector or auditor will be given full, complete and immediate access to conduct inspections and audits of the foreign refinery.
(i) Inspections and audits may be either announced in advance by EPA, or unannounced.
(ii) Access will be provided to any location where:
(A) Gasoline is produced;
(B) Documents related to refinery operations are kept;
(C) Gasoline or blendstock samples are tested or stored; and
(D) FRGAS is stored or transported between the foreign refinery and the United States, including storage tanks, vessels and pipelines.
(iii) Inspections and audits may be by EPA employees or contractors to EPA.
(iv) Any documents requested that are related to matters covered by inspections and audits will be provided to an EPA inspector or auditor on request.
(v) Inspections and audits by EPA may include review and copying of any documents related to:
(A) Refinery baseline establishment, including the volume and parameters, and transfers of title or custody, of any gasoline or blendstocks, whether FRGAS or non-FRGAS, produced at the foreign refinery during the period January 1, 1990 through the date of the refinery baseline petition or through the date of the inspection or audit if a baseline petition has not been approved, and any work papers related to refinery baseline establishment;
(B) The parameters and volume of FRGAS;
(C) The proper classification of gasoline as being FRGAS or as not being FRGAS, or as certified FRGAS or as non-certified FRGAS;
(D) Transfers of title or custody to FRGAS;
(E) Sampling and testing of FRGAS;
(F) Work performed and reports prepared by independent third parties and by independent auditors under the requirements of this section, including work papers; and
(G) Reports prepared for submission to EPA, and any work papers related to such reports.
(vi) Inspections and audits by EPA may include taking samples of gasoline or blendstock, and interviewing employees.
(vii) Any employee of the foreign refiner will be made available for interview by the EPA inspector or auditor, on request, within a reasonable time period.
(viii) English language translations of any documents will be provided to an EPA inspector or auditor, on request, within 10 working days.
(ix) English language interpreters will be provided to accompany EPA inspectors and auditors, on request.
(2) An agent for service of process located in the District of Columbia will be named, and service on this agent constitutes service on the foreign refiner or any officer, or employee of the foreign refiner for any action by EPA or otherwise by the United States related to the requirements of 40 CFR part 80, subparts D, E and F.
(3) The forum for any civil or criminal enforcement action related to the provisions of this section for violations of the Clean Air Act or regulations promulgated thereunder shall be governed by the Clean Air Act, including the EPA administrative forum where allowed under the Clean Air Act.
(4) United States substantive and procedural laws shall apply to any civil or criminal enforcement action against the foreign refiner or any employee of the foreign refiner related to the provisions of this section.
(5) Submitting a petition for an individual refinery baseline, producing and exporting gasoline under an individual refinery baseline, and all other actions to comply with the requirements of 40 CFR part 80, subparts D, E and F relating to the establishment and use of an individual refinery baseline constitute actions or activities covered by and within the meaning of 28 U.S.C. 1605(a)(2), but solely with respect to actions instituted against the foreign refiner, its agents, officers, and employees in any court or other tribunal in the United States for conduct that violates the requirements applicable to the foreign refiner under 40 CFR part 80, subparts D, E and F, including such conduct that violates Title 18 U.S.C. section 1001, Clean Air Act section 113(c)(2), or other applicable provisions of the Clean Air Act.
(6) The foreign refiner, or its agents, officers, or employees, will not seek to detain or to impose civil or criminal remedies against EPA inspectors or auditors, whether EPA employees or EPA contractors, for actions performed within the scope of EPA employment related to the provisions of this section.
(7) The commitment required by this paragraph (i) shall be signed by the owner or president of the foreign refiner business.
(8) In any case where FRGAS produced at a foreign refinery is stored or transported by another company between the refinery and the vessel that transports the FRGAS to the United States, the foreign refiner shall obtain from each such other company a commitment that meets the requirements specified in paragraphs (i) (1) through (7) of this section, and these commitments shall be included in the foreign refiner's baseline petition.
(j)
(k)
(1) The foreign refiner shall post a bond of the amount calculated using the following equation:
(2) Bonds shall be posted by:
(i) Paying the amount of the bond to the Treasurer of the United States;
(ii) Obtaining a bond in the proper amount from a third party surety agent that is payable to satisfy United States judicial judgments against the foreign refiner, provided EPA agrees in advance as to the third party and the nature of the surety agreement; or
(iii) An alternative commitment that results in assets of an appropriate liquidity and value being readily available to the United States, provided EPA agrees in advance as to the alternative commitment.
(3) If the bond amount for a foreign refinery increases the foreign refiner shall increase the bond to cover the shortfall within 90 days of the date the bond amount changes. If the bond amount decreases, the foreign refiner may reduce the amount of the bond beginning 90 days after the date the bond amount changes.
(4) Bonds posted under this paragraph (k) shall be used to satisfy any judicial judgment that results from an administrative or judicial enforcement action for conduct in violation of 40 CFR part 80, subparts D, E and F, including such conduct that violates Title 18 U.S.C. section 1001, Clean Air Act section 113(c)(2), or other applicable provisions of the Clean Air Act.
(5) On any occasion a foreign refiner bond is used to satisfy any judgment, the foreign refiner shall increase the bond to cover the amount used within 90 days of the date the bond is used.
(l)
(m)
(n)
(2) No foreign refiner or other person may cause another person to commit an action prohibited in paragraph (n)(1) of this section, or that otherwise violates the requirements of this section.
(o)
(1) Each batch of imported gasoline shall be classified by the importer as being FRGAS or as non-FRGAS, and each batch classified as FRGAS shall be further classified as certified FRGAS or as non-certified FRGAS.
(2) Gasoline shall be classified as certified FRGAS or as non-certified FRGAS according to the designation by the foreign refiner if this designation is supported by product transfer documents prepared by the foreign refiner as required in paragraph (d) of this section, unless the gasoline is classified as non-certified FRGAS under paragraph (g) of this section.
(3) For each gasoline batch classified as FRGAS, any United States importer shall perform the following procedures.
(i) In the case of both certified and non-certified FRGAS, have an independent third party:
(A) Determine the volume of gasoline in the vessel;
(B) Use the foreign refiner's FRGAS certification to determine the name and EPA-assigned registration number of the foreign refinery that produced the FRGAS;
(C) Determine the name and country of registration of the vessel used to transport the FRGAS to the United States; and
(D) Determine the date and time the vessel arrives at the United States port of entry.
(ii) In the case of certified FRGAS, have an independent third party:
(A) Collect a representative sample from each vessel compartment subsequent to the vessel's arrival at the United States port of entry and prior to off loading any gasoline from the vessel;
(B) Prepare a volume-weighted vessel composite sample from the compartment samples; and
(C) Determine the values for sulfur, benzene, gravity, E200 and E300 using the methodologies specified in § 80.46, by:
(
(
(4) Any importer shall submit reports within thirty days following the date any vessel transporting FRGAS arrives at the United States port of entry:
(i) To the Administrator containing the information determined under paragraph (o)(3) of this section; and
(ii) To the foreign refiner containing the information determined under paragraph (o)(3)(ii) of this section.
(5)(i) Any United States importer shall meet the requirements specified for conventional gasoline in § 80.101 for any imported conventional gasoline that is not classified as certified FRGAS under paragraph (o)(2) of this section.
(ii) The baseline applicable to a United States importer who has not been assigned an individual importer baseline under § 80.91(b)(4) shall be the baseline specified in paragraph (p) of this section.
(p)
(i) Shall use the Phase II Complex Model;
(ii) Shall include all conventional gasoline in the following categories:
(A) Imported conventional gasoline that is classified as conventional gasoline, and included in the conventional gasoline compliance calculations of importers for each year; and
(B) Imported conventional gasoline that is classified as certified FRGAS, and included in the conventional gasoline compliance calculations of foreign refiners for each year;
(iii)(A) In 2000 only, shall be for the 1998 and 1999 averaging periods and also shall include all conventional gasoline classified as FRGAS and included in the conventional gasoline compliance calculations of a foreign refiner for 1997, and all conventional gasoline batches not classified as FRGAS that are imported during 1997 beginning on the date the first batch of FRGAS arrives at a United States port of entry; and
(B) Starting in 2001, shall include imported conventional gasoline during the prior three calendar year averaging periods.
(2)(i) If the volume-weighted average NO
(ii) For the 1998 and 1999 multi-year averaging period only the value of AB
(3)(i) Notwithstanding the provisions of § 80.91(b)(4)(iii), the baseline NO
(ii) On or before June 1 of each calendar year, the Administrator shall announce the NO
(q)
(1) A foreign refiner fails to meet any requirement of this section;
(2) A foreign government fails to allow EPA inspections as provided in paragraph (i)(1) of this section;
(3) A foreign refiner asserts a claim of, or a right to claim, sovereign immunity in an action to enforce the requirements in 40 CFR part 80, subparts D, E and F; or
(4) A foreign refiner fails to pay a civil or criminal penalty that is not satisfied using the foreign refiner bond specified in paragraph (k) of this section.
(r)
(i) A baseline petition has been submitted as required in paragraph (b) of this section;
(ii) EPA has made a provisional finding that the baseline petition is complete;
(iii) The foreign refiner has made the commitments required in paragraph (i) of this section;
(iv) The persons who will meet the independent third party and independent attest requirements for the foreign refinery have made the commitments required in paragraphs (f)(3)(iii) and (h)(7)(iii) of this section; and
(v) The foreign refiner has met the bond requirements of paragraph (k) of this section.
(2) In any case where a foreign refiner uses an individual refinery baseline before final approval under paragraph (r)(1) of this section, and the foreign refinery baseline values that ultimately are approved by EPA are more stringent than the early baseline values used by the foreign refiner, the foreign refiner shall recalculate its compliance,
(s)
(1) Submitted in accordance with procedures specified by the Administrator, including use of any forms that may specified by the Administrator.
(2) Be signed by the president or owner of the foreign refiner company, or in the case of (g)(1)(ii) the vessel owner, or by that person's immediate designee, and shall contain the following declaration:
I hereby certify: (1) that I have actual authority to sign on behalf of and to bind [insert name of foreign refiner or vessel owner] with regard to all statements contained herein; (2) that I am aware that the information contained herein is being certified, or submitted to the United States Environmental Protection Agency, under the requirements of 40 CFR part 80, subparts D, E and F and that the information is material for determining compliance under these regulations; and (3) that I have read and understand the information being certified or submitted, and this information is true, complete and correct to the best of my knowledge and belief after I have taken reasonable and appropriate steps to verify the accuracy thereof.
I affirm that I have read and understand that the provisions of 40 CFR part 80, subparts D, E and F, including 40 CFR 80.94 (i), (j) and (k), apply to [insert name of foreign refiner or vessel owner]. Pursuant to Clean Air Act section 113(c) and Title 18, United States Code, section 1001, the penalty for furnishing false, incomplete or misleading information in this certification or submission is a fine of up to $10,000, and/or imprisonment for up to five years.
Any refiner or importer of conventional gasoline shall meet the standards specified in this section over the specified averaging period, beginning on January 1, 1995.
(a)
(b)
(i) Annual average exhaust benzene emissions, calculated according to paragraph (g)(1)(i) of this section, shall not exceed the refiner's or importer's compliance baseline for exhaust benzene emissions;
(ii) Annual average levels of sulfur shall not exceed 125% of the refiner's or importer's compliance baseline for sulfur;
(iii) Annual average levels of olefins shall not exceed 125% of the refiner's or importer's compliance baseline for olefins; and
(iv) Annual average values of T-90 shall not exceed 125% of the refiner's or importer's compliance baseline for T-90.
(2)
(3)
(ii) Annual average levels of RVP, benzene, aromatics, olefins, sulfur, E200 and E300 shall not be greater than the conventional gasoline complex model valid range limits for the parameter under § 80.45(f)(1)(ii), or the refiner or importer's annual 1990 baseline for the parameter if outside the valid range limit, whichever is greater.
(c)
(i) The Simple Model Standards if the refiner or importer uses the Simple Model Standards for reformulated gasoline; or
(ii) The Optional Complex Model Standards if the refiner or importer used the Complex Model Standards for reformulated gasoline.
(2) Beginning January 1, 1998, each refiner and importer shall be subject to the Complex Model Standards for each averaging period.
(d)
(1) Any conventional gasoline produced or imported during the averaging period;
(2) Any non-gasoline petroleum products that are produced or imported and sold or transferred from the refinery or group of refineries or importer during the averaging period, if required pursuant to § 80.102(e)(2), unless the refiner or importer is able to establish in the form of documentation that the petroleum products were used for a purpose other than the production of gasoline within the United States;
(3) Any gasoline blending stock produced or imported during the averaging period which becomes conventional gasoline solely upon the addition of oxygenate;
(4)(i) Any oxygenate that is added to conventional gasoline, or gasoline blending stock as described in paragraph (d)(3) of this section, where such gasoline or gasoline blending stock is produced or imported during the averaging period;
(ii) In the case of oxygenate that is added at a point downstream of the refinery or import facility, the oxygenate may be included only if the refiner or importer can establish the oxygenate was in fact added to the gasoline or gasoline blendstock produced, by showing that the oxygenate was added by:
(A) The refiner or importer; or
(B) By a person other than the refiner or importer, provided that the refiner or importer:
(
(
(e)
(1) Gasoline that was not produced at the refinery or was not imported by the importer;
(2) Blendstocks that have been included in another refiner's compliance calculations, pursuant to § 80.102(e)(2) or otherwise;
(3) California gasoline as defined in § 80.81(a)(2); and
(4) Gasoline that is exported.
(f)
(2) In the case of any refiner or importer for whom the anti-dumping statutory baseline applies under § 80.91, the anti-dumping statutory baseline for each parameter or emissions performance shall be the compliance baseline for that refiner or importer.
(3) [Reserved]
(4)(i)[Reserved]
(ii)[Reserved]
(iii) Any refiner or importer with Puerto Rico gasoline, or Puerto Rico and U.S. Virgin Islands gasoline, in its individual baseline and which has met the requirements specified in paragraph (g)(1)(ii)(B) of this section, and whose total volume of conventional gasoline, RBOB, reformulated gasoline, and California gasoline, as defined in § 80.81(a)(2), produced or imported by the refiner or importer during the averaging period is greater than that refiner's or importer's 1990 baseline volume as determined under § 80.91(f)(1), must calculate the compliance baseline for each parameter or emissions performance according to the following formula:
(4) Any compliance baseline under paragraph (f)(1) of this section shall be adjusted for each averaging period as follows:
(g)
(A) The average value for sulfur, T-90, olefin, benzene, and aromatics for an averaging period shall be calculated as follows:
(B) Exhaust benzene emissions under the Simple Model for an averaging period are calculated as follows:
(ii) Complex Model calculations.
(A) Exhaust benzene, exhaust toxics, and exhaust NO
(B) A refiner which has Puerto Rico gasoline, or Puerto Rico and U.S. Virgin Islands gasoline, in its baseline shall use the summer Complex Model to evaluate its averaging period Puerto Rico and U.S. Virgin Islands gasoline provided it has petitioned the Agency, per § 80.93(d), and has received Agency approval on the petition, and has revised its individual baseline, such that the Puerto Rico and U.S. Virgin Islands gasoline in its individual baseline has been evaluated using the summer Complex Model.
(2) In the case of any refiner or importer subject to the anti-dumping statutory baseline, the refiner or importer shall determine compliance using the following methodology:
(i) Calculate the compliance total for the averaging period for sulfur, T-90, olefins, exhaust benzene emissions, exhaust toxics and exhaust NO
(ii) Calculate the actual total for the averaging period for sulfur, T-90, olefins, exhaust benzene emissions, exhaust toxics and exhaust NO
(iii) The actual total for exhaust benzene emissions, exhaust toxics and exhaust NO
(3) Exhaust toxics and NO
(i) Determine the volume and properties of the blendstock.
(ii) Determine the blendstock volume fraction (F) based on the volume of blendstock, and the volume of gasoline with which the blendstock is blended, using the following equation:
(iii) For each parameter required by the complex model, calculate the parameter value that would result by combining, at the blendstock volume fraction (F), the blendstock with a gasoline having properties equal to the refinery's or importer's baseline, using the following formula:
(A) The baseline value shall be the refinery's “summer” or “winter” baseline, based on the “summer” or “winter” classification of the gasoline produced as determined under paragraphs (g)(5) or (g)(6) of this section. In the case of a refinery that is aggregated under paragraph (h) of this section, the refinery baseline shall be used, and not the aggregate baseline.
(B) The sulfur content and oxygen wt% computations under paragraph (g)(3)(iii) of this section shall be adjusted for the specific gravity of the gasoline and blendstock using specific gravities of 0.749 for “summer” gasoline and of 0.738 for “winter” gasoline.
(C) In the case of “summer” gasoline, where the blendstock is ethanol and the volume fraction calculated under paragraph (g)(3)(ii) is equal to or greater than 0.015, the value for RVP calculated under paragraph (g)(3)(iii) of this section shall be 1.0 psi greater than the RVP of the gasoline with which the blendstock is blended.
(iv) Using the summer or winter complex model, as appropriate, calculate the exhaust toxics and NO
(A) A hypothetical gasoline having properties equal to those calculated in paragraph (g)(3)(iii) of this section (HEP); and
(B) A gasoline having properties equal to the refinery's or importer's baseline (BEP).
(v) Calculate the exhaust toxics and NO
(vi) For each blendstock batch, the volume, and exhaust toxics and NO
(4) Compliance calculations under this subpart E shall be based on computations to the same degree of accuracy that are specified in establishing individual baselines under § 80.91.
(5) The emissions performance of gasoline that has an RVP that is equal to or less than the RVP required under § 80.27 (“summer gasoline”) shall be determined using the applicable summer complex model under § 80.45.
(6) The emissions performance of gasoline that has an RVP greater than the RVP required under § 80.27 (“winter
(7)(i) For the 1998 averaging period any refiner or importer may elect to determine compliance with the requirement for exhaust NO
(ii)(A) Any refiner or importer must use the with- or without-oxygen approach elected under paragraph (g)(7)(i) of this section for all subsequent averaging periods; except that
(B) In the case of any refiner or importer who elects to determines compliance for the calendar year 1998 averaging period without the inclusion of oxygenates, such refiner or importer may elect to include oxygenates in its compliance calculations for the 1999 averaging period.
(iii) Any refiner or importer who elects to use the with-oxygen approach under paragraph (g)(7)(ii)(B) of this section must use this approach for all subsequent averaging periods.
(8)
(h)
(i) Elect to achieve compliance individually for the refineries; or
(ii) Elect to achieve compliance on an aggregate basis for a group, or for groups, of refineries, some of which may be individual refineries; provided that
(iii) Compliance is achieved for each refinery separately or as part of a group; and
(iv) The data for any refinery is included only in one compliance calculation.
(2) Any election by a refiner to group refineries under paragraph (h)(1) of this section shall:
(i) Be made as part of the report for the 1995 averaging period required by § 80.105;
(ii) Apply for the 1995 averaging period and for each subsequent averaging period, and may not thereafter be changed; and
(iii) Apply for purposes of the blendstock tracking and accounting provisions under § 80.102.
(3)(i) Any standards under this section shall apply, and compliance calculations shall be made, separately for each refinery or refinery group; except that
(ii) Any refiner that produces conventional gasoline for distribution to a specified geographic area which is the subject of a petition approved by EPA pursuant to § 80.91(f)(3) shall achieve compliance separately for gasoline supplied to such specified geographic area.
(i)
(i)(A) Determine the value of each of the properties required for determining compliance with the standards that are applicable to the refiner or importer, by collecting and analyzing a representative sample of gasoline or blendstock taken from the batch, using the methodologies specified in § 80.46; except that
(B) Any refiner that produces gasoline by combining blendstock with gasoline that has been included in the
(ii) Assign a number to the batch (the “batch number”), as specified in § 80.65(d)(3);
(2) For the purposes of meeting the sampling and testing requirements under paragraph (i)(1) of this section, any refiner or importer may, prior to analysis, combine samples of gasoline collected from more than one batch of gasoline or blendstock (“composite sample”), and treat such composite sample as one batch of gasoline or blendstock provided that the refiner or importer:
(i) Meets each of the requirements specified in § 80.91(d)(4)(iii) for the samples contained in the composite sample;
(ii) Combines samples of gasoline that are produced or imported over a period no longer than one month;
(iii) Uses the total of the volumes of the batches of gasoline that comprise the composite sample, and the results of the analyses of the composite sample, for purposes of compliance calculations under paragraph (g) of this section; and
(iv) Does not combine summer and winter gasoline, as specified under paragraphs (g) (5) and (6) of this section, in a composite sample.
(j)
At 64 FR 30910, June 9, 1999, § 80.101 was amended by revising paragraphs (f)(4) and (g)(1)(ii), effective July 26, 1999. For the convenience of the user, the superseded text is set forth as follows:
(f) ***
(4) Any compliance baseline under paragraph (f)(1) of this section shall be adjusted for each averaging period as follows:
(g) ***
(1) ***
(ii) Calculate the actual total for the averaging period for sulfur, T-90, olefins, exhaust benzene emissions, exhaust toxics and exhaust NO
(a) For the purposes of this subpart E:
(1) All of the following petroleum products that are produced by a refiner or imported by an importer shall be considered “applicable blendstocks”:
(i) Reformate;
(ii) Light coker naphtha;
(iii) FCC naphtha;
(iv) Benzene/toluene/xylene;
(v) Pyrolysis gas;
(vi) Aromatics;
(vii) Polygasoline; and
(viii) Dimate; and
(2) Any gasoline blendstock with properties such that, if oxygenate only is added to the blendstock the resulting blend meets the definition of gasoline under § 80.2(c), shall be considered gasoline.
(b)(1) Any refiner or importer of conventional gasoline or blendstocks shall determine the baseline blendstock-to-gasoline ratio for each calendar year 1990 through 1993 according to the following formula:
(2)(i) Only those volumes of applicable blendstocks for which the refiner is able to demonstrate the blendstock was used in the production of gasoline may be included in baseline blendstock-to-gasoline ratios under paragraph (b)(1) of this section.
(ii) The baseline volume data for applicable blendstocks and gasoline shall be confirmed through the baseline audit requirements specified in § 80.92 and submitted in accordance with the requirements of § 80.93.
(c) Any refiner or importer shall calculate the baseline cumulative blendstock-to-gasoline ratio according to the following formula:
(d)(1) For each averaging period, any refiner or importer shall:
(i) Determine the averaging period blendstock-to-gasoline ratio according to the following formula:
(ii) For each averaging period until January 1, 1998, calculate the peak year blendstock-to-gasoline ratio percentage change according to the following formula:
(2) Beginning on January 1, 1998, for each averaging period any refiner or importer shall:
(i) Determine the running cumulative compliance period blendstock-to-gasoline ratio according to the following formula:
(ii) Calculate the cumulative blendstock-to-gasoline ratio percentage change according to the following formula:
(3) For purposes of this paragraph (d), all applicable blendstocks produced or imported shall be included, except those for which the refiner or importer has sufficient evidence in the form of documentation that the blendstocks were:
(i) Exported;
(ii) Used for other than gasoline blending purposes;
(iii) Transferred to a refiner that used the blendstock as a “feedstock” in a refining process during which the blendstock underwent a substantial chemical or physical transformation; or
(iv) Transferred between refineries which have been grouped pursuant to § 80.101(h) by a refiner for the purpose of determining compliance under this subpart; or
(v) Used to produce California gasoline as defined in § 80.81(a)(2).
(e)(1) Any refiner or importer shall have exceeded the blendstock-to-gasoline ratio percentage change threshold if:
(i) The peak year blendstock-to-gasoline ratio percentage change calculated under paragraph (d)(1)(ii) of this section is more than ten; or
(ii) Beginning on January 1, 1998, the cumulative blendstock-to-gasoline ratio percentage change calculated under paragraph (d)(2)(ii) of this section is more than ten.
(2) Any refiner or importer that exceeds the blendstock-to-gasoline ratio percentage change threshold shall, without further notification:
(i) Include all blendstocks produced or imported and transferred to others in its compliance calculations under § 80.101(g) for two averaging periods beginning on January 1 of the averaging period subsequent to the averaging period when the exceedance occurs;
(ii) Provide transfer documents to the recipient of such blendstock that contain the language specified at § 80. 106(b); and
(iii) Transfer such blendstock in a manner such that the ultimate blender of such blendstocks has a reasonable basis to know that such blendstock has been accounted for.
(3) Any refiner or importer that has previously exceeded the blendstock-to-gasoline ratio percentage change threshold, and subsequently exceeds the threshold for an averaging period and is not granted a waiver pursuant to paragraph (f)(2)(i) of this section, shall, without further notification, meet the requirements specified in paragraphs (e)(2) (i) through (iii) of this section for four averaging periods, beginning on January 1 of the averaging period following the averaging period when the subsequent exceedance occurs.
(f)(1) The refiner or importer blendstock accounting requirements specified under paragraph (e) of this section shall not apply in the case of any refiner or importer:
(i) Whose 1990 baseline value for each regulated fuel property and emission performance, as determined in accordance with §§ 80.91 and 80.92, is less stringent than the anti-dumping statutory baseline value for that parameter or emissions performance;
(ii) Whose averaging period blendstock-to-gasoline ratio, calculated according to paragraph (d)(1)(i) of this section, is equal to or less than .0300; or
(iii) Who obtains a waiver from EPA, provided that a petition for such a waiver is filed no later than fifteen days following the end of the averaging period for which the blendstock-to-gasoline ratio percentage change threshold is exceeded.
(2)(i) EPA may grant the waiver referred to in paragraph (f)(1)(iii) of this section if the level of blendstock production was the result of extreme or unusual circumstances (e.g., a natural disaster or act of God) which clearly are outside the control of the refiner or importer, and which could not have been avoided by the exercise of prudence, diligence, and due care.
(ii) Any petition filed under paragraph (f) of this section shall include information which describes the extreme or unusual circumstance which caused the increased volume of blendstock produced or imported, the steps taken to avoid the circumstance,
(g) Notwithstanding the requirements of paragraphs (a) through (f) of this section, any refiner or importer that transfers applicable blendstock to another refiner or importer with a less stringent baseline requirement, either directly or indirectly, for the purpose of evading a more stringent baseline requirement, shall include such blendstock(s) in determining compliance with the applicable requirements of this subpart.
Any refiner or importer of conventional gasoline must register with the Administrator in accordance with the provisions specified at § 80.76.
Any refiner or importer shall maintain records containing the information as required by this section.
(a) Beginning in 1995, for each averaging period:
(1) Documents containing the information specified in paragraph (a)(2) of this section shall be obtained for:
(i) Each batch of conventional gasoline, and blendstock if blendstock accounting is required under § 80.102(e)(2); or
(ii) Each batch of blendstock received in the case of any refiner that determines compliance on the basis of blendstocks properties under § 80.101(g)(3).
(2)(i) The results of tests performed in accordance with § 80.101(i);
(ii) The volume of the batch;
(iii) The batch number;
(iv) The date of production, importation or receipt;
(v) The designation regarding whether the batch is summer or winter gasoline;
(vi) The product transfer documents for any conventional gasoline produced or imported;
(vii) The product transfer documents for any conventional gasoline received;
(viii) For any gasoline blendstocks received by or transferred from a refiner or importer, documents that reflect:
(A) The identification of the product;
(B) The date the product was transferred; and
(C) The volume of product;
(ix) In the case of any refinery-produced or imported products listed in § 80.102(a) that are excluded under § 80.102(d)(3), documents which demonstrate that basis for exclusion; and
(x) In the case of oxygenate that is added by a person other than the refiner or importer under § 80.101(d)(4)(ii)(B), documents that support the volume of oxygenate claimed by the refiner or importer, including the contract with the oxygenate blender and records relating to the audits, sampling and testing, and inspections of the oxygenate blender operation.
(xi) In the case of blendstocks that are included in refinery compliance calculations using the procedures under § 80.101(g)(3), documents that reflect the volume of blendstock and the volume of gasoline with which the blendstock is blended.
(b) Any refiner or importer shall retain the documents required in this section for a period of five years from the date the conventional gasoline or blendstock is produced or imported, and deliver such documents to the Administrator of EPA upon the Administrator's request.
(a) Beginning with the 1995 averaging period, and for each subsequent averaging period, any refiner for each refinery or group of refineries at which any conventional gasoline is produced, and any importer that imports any conventional gasoline, shall submit to the Administrator a report which contains the following information:
(1) The total gallons of conventional gasoline produced or imported;
(2)(i) The total gallons of applicable blendstocks produced or imported and transferred to others that are not excluded under § 80.102(d)(3); and
(ii) The total gallons of applicable blendstocks produced or imported and
(3) The total gallons of blendstocks included in compliance calculations pursuant to § 80.102(e)(2);
(4)(i) If using the simple model:
(A) The applicable exhaust benzene emissions standard under § 80.101(b)(1)(i);
(B) The average exhaust benzene emissions under § 80.101(g);
(C) The applicable sulfur content standard under § 80.101(b)(1)(ii) in parts per million;
(D) The average sulfur content under § 80.101(g) in parts per million;
(E) The difference between the applicable sulfur content standard under § 80.101(b)(1)(ii) in parts per million and the average sulfur content under paragraph (a)(4)(i)(D) of this section in parts per million, indicating whether the average is greater or lesser than the applicable standard;
(F) The applicable olefin content standard under § 80.101(b)(1)(iii) in volume percent;
(G) The average olefin content under § 80.101(g) in volume percent;
(H) The difference between the applicable olefin content standard under § 80.101(b)(1)(iii) in volume percent and the average olefin content under paragraph (a)(4)(i)(G) of this section in volume percent, indicating whether the average is greater or lesser than the applicable standard;
(I) The applicable T90 distillation point standard under § 80.101(b)(1)(iv) in degrees Fahrenheit;
(J) The average T90 distillation point under § 80.101(g) in degrees Fahrenheit; and
(K) The difference between the applicable T90 distillation point standard under § 80.101(b)(1)(iv) in degrees Fahrenheit and the average T90 distillation point under paragraph (a)(4)(i)(J) of this section in degrees Fahrenheit, indicating whether the average is greater or lesser than the applicable standard.
(ii) If using the optional complex model, the applicable exhaust benzene emissions standard and the average exhaust benzene emissions, under § 80.101(b)(2) and (g).
(iii) If using the complex model:
(A) The applicable exhaust toxics emissions standard and the average exhaust toxics emissions, under § 80.101(b)(3) and (g); and
(B) The applicable NO
(5) The following information for each batch of conventional gasoline or batch of blendstock included under paragraph (a) of this section:
(i) The batch number;
(ii) The date of production;
(iii) The volume of the batch;
(iv) The grade of gasoline produced (i.e., premium, mid-grade, or regular); and
(v) The properties, pursuant to § 80.101(i); and
(6) Such other information as EPA may require.
(b) The reporting requirements of paragraph (a) of this section do not apply in the case of any conventional gasoline or gasoline blendstock that is excluded from a refiner's or importer's compliance calculation pursuant to § 80.101(e).
(c) For each averaging period, each refiner and importer shall cause to be submitted to the Administrator of EPA, by May 30 of each year, a report in accordance with the requirements for the Attest Engagements of §§ 80.125 through 80.131.
(d) The report required by paragraph (a) of this section shall be:
(1) Submitted on forms and following procedures specified by the Administrator of EPA;
(2) Submitted to EPA by the last day of February each year for the prior calendar year averaging period; and
(3) Signed and certified as correct by the owner or a responsible corporate officer of the refiner or importer.
(a)(1) On each occasion when any person transfers custody or title to any conventional gasoline, the transferor shall provide to the transferee documents which include the following information:
(i) The name and address of the transferor;
(ii) The name and address of the transferee;
(iii) The volume of gasoline being transferred;
(iv) The location of the gasoline at the time of the transfer;
(v) The date of the transfer;
(vi) In the case of transferors or transferees who are refiners or importers, the EPA-assigned registration number of those persons; and
(vii) The following statement: “This product does not meet the requirements for reformulated gasoline, and may not be used in any reformulated gasoline covered area.”
(2) The requirements of paragraph (a)(1) of this section apply to product that becomes gasoline upon the addition of oxygenate only.
(b) On each occasion when any person transfers custody or title to any blendstock that has been included in the refiner's or importer's compliance calculations under § 80.102(e)(2), the transferor shall provide to the transferee documents which include the following statement: “For purposes of the Anti-Dumping requirements under 40 CFR part 80, subpart E, this blendstock has been accounted for by the refiner that produced it, and must be excluded from any subsequent compliance calculations.”
(a) Any refiner, importer, and oxygenate blender subject to the requirements of this subpart F shall engage an independent certified public accountant, or firm of such accountants (hereinafter referred to in this subpart F as “CPA”), to perform an agreed-upon procedure attestation engagement of the underlying documentation that forms the basis of the reports required by §§ 80.75 and 80.105.
(b) The CPA shall perform the attestation engagements in accordance with the Statements on Standards for Attestation Engagements.
(c) The CPA may complete the requirements of this subpart F with the assistance of internal auditors who are employees or agents of the refiner, importer, or oxygenate blender, so long as such assistance is in accordance with the Statements on Standards for Attestation Engagements.
(d) Notwithstanding the requirements of paragraph (a) of this section, any refiner, importer, or oxygenate blender may satisfy the requirements of this subpart F if the requirements of this subpart F are completed by an auditor who is an employee of the refiner, importer, or oxygenate blender, provided that such employee:
(1) Is an internal auditor certified by the Institute of Internal Auditors, Inc. (hereinafter referred to in this subpart F as “CIA”); and
(2) Completes the internal audits in accordance with the Codification of Standards for the Professional Practice of Internal Auditing.
(e) Use of a CPA or CIA who is debarred, suspended, or proposed for debarment pursuant to the Governmentwide Debarment and Suspension Regulations, 40 CFR part 32, or the Debarment, Suspension, and Ineligibility Provisions of the Federal Acquisition Regulations, 48 CFR part 9, subpart 9.4, shall be deemed in noncompliance with the requirements of this section.
(f) The following documents are incorporated by reference: the Statements on Standards for Attestation Engagements, Codification of Statements on Auditing Standards, written by the American Institute of Certified Public Accountants, Inc., 1991, and published by the Commerce Clearing House, Inc., Identification Number 059021, and the Codification of Standards for the Professional Practice of Internal Auditing, written and published by the Institute of Internal Auditors, Inc., 1989, Identification Number ISBN 0-89413-207-5. These incorporations by reference were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies of the Statements on Standards for Attestation Engagements may be obtained from the American Institute of Certified Public Accountants, Inc., 1211 Avenue of the Americas, New York, New York 10036, and copies of the Codification of Standards for the Professional Practice of Internal Auditing may be obtained from
The following definitions shall apply for the purposes of this subpart F:
(a)
(b)
(c)
(d)
(e) Product transfer documents shall include documents that reflect the transfer of ownership or physical custody of gasoline or blendstock, including invoices, receipts, bills of lading, manifests, and pipeline tickets.
(f) A
(g)
In performing the attest engagement, the auditor shall sample relevant populations to which agreed-upon procedures will be applied using the methods specified in this section, which shall constitute a representative sample.
(a) Sample items shall be selected in such a way as to comprise a simple random sample of each relevant population; and
(b) Sample size shall be determined using one of the following options:
(1)
(2)
(3)
The following are the minimum attest procedures that shall be carried out for each refinery and importer. Agreed upon procedures may vary from the procedures stated in this section due to the nature of the refiner's or importer's business or records, provided that any refiner or importer desiring to modify procedures obtains prior approval from EPA.
(a) Read the refiner's or importer's reports filed with EPA for the previous year as required by §§ 80.75, 80.83(g), and 80.105.
(b) Obtain a gasoline inventory reconciliation analysis for the current year from the refiner or importer which includes reformulated gasoline, RBOB, conventional gasoline, and non-finished-gasoline petroleum products.
(1) Test the mathematical accuracy of the calculations contained in the analysis.
(2) Agree the beginning and ending inventories to the refiner's or importer's perpetual inventory records.
(c) Obtain separate listings of all tenders during the current year of reformulated gasoline, RBOB, conventional gasoline, and non-finished-gasoline petroleum products.
(1) Test the mathematical accuracy of the calculations contained in the listings.
(2) Agree the listings of tenders’ volumes to the gasoline inventory reconciliation in paragraph (b) of this section.
(3) Agree the listings of tenders’ volumes, where applicable, to the EPA reports.
(d) Select a representative sample from the listing of reformulated gasoline tenders, and for this sample:
(1) Agree the volumes to the product transfer documents;
(2) Compare the product transfer documents designation for consistency with the time and place, and compliance model designations for the tender (VOC-controlled or non-VOC-controlled, VOC region for VOC-controlled, summer or winter gasoline, and simple or complex model certified); and
(3) Trace back to the batch or batches in which the gasoline was produced or imported. Obtain the refiner's or importer's internal laboratory analyses for each batch and compare such analyses for consistency with the analyses results reported to EPA and to the time and place designations for the tender's product transfer documents.
(e) Select a representative sample from the listing of RBOB tenders, and for this sample:
(1) Agree the volumes to the original product transfer documents;
(2) Determine that the requisite contract was in place with the downstream blender designating the required blending procedures, or that the refiner or importer accounted for the RBOB using the assumptions in § 80.69(a)(8) in the case of RBOB designated as “any oxygenate,” or “ether only,” or using the assumptions in §§ 80.83(c)(1)(ii) (A) and (B) in the case of RBOB designated as “any renewable oxygenate,” “non VOC controlled renewable ether only,” or “renewable ether only”;
(3) Review the product transfer documents for the indication of the type and amount of oxygenate required to be added to the RBOB;
(4) Trace back to the batch or batches in which the RBOB was produced or imported. Obtain refiner's or importer's internal lab analysis for each batch and agree the consistency of the type and volume of oxygenate required to be added to the RBOB with that indicated in applicable tender's product transfer documents;
(5) Agree the sampling and testing frequency of the refiner's or importer's downstream oxygenated blender quality assurance program with the sampling and testing rates as required in § 80.69(a)(7); and
(6) In the case of RBOB designated as “any renewable oxygenate,” “non VOC controlled renewable ether” or “renewable ether only”, review the documentation from the producer of the oxygenate to determine if the oxygenate meets the requirements of § 80.83(a).
(f) Select a representative sample of reformulated gasoline and RBOB batches produced by computerized in-line blending, and for this sample:
(1) Obtain the composite sample internal laboratory analyses results; and
(2) Agree the results of the internal laboratory analyses to the quarterly
(g) Select a representative sample from the listing of the tenders of conventional gasoline and conventional gasoline blendstock that becomes gasoline through the addition of oxygenate only, and for this sample:
(1) Agree the volumes to the product transfer documents;
(2) For a representative sample of tenders, trace back to the batch or batches in which the gasoline was produced or imported. Obtain the refiner's or importer's internal laboratory analyses for each batch and compare such analyses for consistency with the analyses results reported to EPA; and
(3) Where the refiner or importer has included oxygenate that is blended downstream of the refinery or import facility in its compliance calculations in accordance with § 80.101(d)(4)(ii), obtain a listing of each downstream oxygenate blending operation from which the refiner or importer is claiming oxygenate for use in compliance calculations, and for each such operation:
(i) Determine if the refiner or importer had a contract in place with the downstream blender during the period oxygenate was blended;
(ii) Determine if the refiner or importer has records reflecting that it conducted physical inspections of the downstream blending operation during the period oxygenate was blended;
(iii) Obtain a listing from the refiner or importer of the batches of conventional gasoline or conventional sub-octane blendstock, and the compliance calculations which include oxygenate blended by the downstream oxygenate blender, and test the mathematical accuracy of the calculations contained in this listing;
(iv) Obtain a listing from the downstream oxygenate blender of the oxygenate blended with conventional gasoline or sub-octane blendstock that was produced or imported by the refiner or importer. Test the mathematical accuracy of the calculations in this listing. Agree the overall oxygenate blending listing obtained from the refiner or importer with the listing obtained from the downstream oxygenate blender. Select a representative sample of oxygenate blending listing obtained from the downstream oxygenate blender, and for this sample:
(A) Using product transfer documents, determine if the oxygenate was blended with conventional gasoline or conventional sub-octane blendstock that was produced by the refiner or imported by the importer; and
(B) Agree the oxygenate volume with the refiner's or importer's listing of oxygenate claimed for this gasoline;
(v) Obtain a listing of the sampling and testing conducted by the refiner or importer over the downstream oxygenate blending operation. Select a representative sample of the test results from this listing, and for this sample agree the tested oxygenate volume with the oxygenate use listings from the refiner or importer, and from the oxygenate blender; and
(vi) Obtain a copy of the records reflecting the refiner or importer audit over the downstream oxygenate blending operation. Review these records for indications that the audit included review of the overall volumes and type of oxygenate purchased and used by the oxygenate blender to be consistent with the oxygenate claimed by the refiner or importer and that this oxygenate was blended with the refiner's or importer's gasoline or blending stock.
(h) In the case of a refiner or importer that is not exempt from blendstock tracking under § 80.102(f):
(1) Obtain listings for those tenders of non-finished-gasoline classified by the refiner or importer as:
(i) Applicable blendstock which is included in the refiner's or importer's blendstock tracking calculations pursuant to § 80.102(b) through (d);
(ii) Applicable blendstock which is exempt pursuant to § 80.102(d)(3) from inclusion in the refiner's or importer's blendstock tracking calculations pursuant to § 80.102 (b) through (d); and
(iii) All other non-finished-gasoline petroleum products.
(2) Test the mathematical accuracy of the calculations contained in the analysis.
(3) Agree the listings of tenders’ volumes to the gasoline inventory reconciliation in paragraph (b) of this section.
(4) Agree the EPA report for the volume classified as applicable blendstock
(5) Select a representative sample from the listing of applicable blendstock which is reported to EPA, and for such sample:
(i) Agree the volumes to records supporting the transfer of the tender to another person; and
(ii) Trace back to the batch or batches in which the non-finished-gasoline petroleum product was produced or imported. Obtain the refiner's or importer's internal laboratory analysis for each batch and compare such analysis for consistency with the product type assigned by the refiner or importer (e.g., reformate, light coker naphtha, etc.), and that this product type is included in the applicable blendstock list at § 80.102(a).
(6) Select a representative sample from the listing of applicable blendstock which is exempt from inclusion in the blendstock tracking report to EPA, and for such sample:
(i) Agree the volumes to records supporting the transfer of the tender to another person;
(ii) Trace back to the batch or batches in which the non-finished-gasoline petroleum product was produced or imported. Obtain the refiner's or importer's internal laboratory analysis for each batch and compare such analysis for consistency with the product type assigned by the refiner or importer (e.g., reformate, light coker naphtha, etc.), and that this product type is included in the applicable blendstock list at § 80.102(a); and
(iii) Obtain the documents that demonstrate the purpose for which the product was used, and agree that the documented purpose is one of those specified at § 80.102(d)(3).
(7) Select a representative sample from the listing of all other non-finished-gasoline petroleum products, and for such sample:
(i) Agree the volumes to records supporting the transfer of the tender to another person;
(ii) Trace back to the batch or batches in which the non-finished-gasoline petroleum product was produced or imported. Obtain the refiner's or importer's internal laboratory analysis for each batch and compare such analysis for consistency with the product-type assigned by the refiner or importer (e.g., alkylate, isobutane, etc.), and agree that this product type is excluded from the applicable blendstock list at § 80.102(a).
(i) In the case of a refiner or importer required to account for blendstocks produced or imported under § 80.102(e)(2):
(1) Obtain listings for those tenders of non-finished-gasoline tenders classified by the refiner or importer as:
(i) Blendstock which is included in the compliance calculations for the refinery or importer; and
(ii) All other non-finished-gasoline petroleum products;
(2) Test the mathematical accuracy of the calculations contained in the listings under paragraph (i)(1) of this section;
(3) Agree the listings of tenders’ volumes to the gasoline inventory reconciliation in paragraph (b) of this section;
(4) Select a representative sample from the listing of blendstock tenders which are included in the compliance calculations for the refinery or importer, and for such sample:
(i) Agree the volumes to records supporting the transfer of the tender to another person;
(ii) Review the product transfer documents for the statement indicating the blendstock has been accounted-for, and may not be included in another party's compliance calculations; and
(iii) Trace back to the batch or batches in which the blendstock was produced or imported. Obtain the refiner's or importer's internal laboratory analyses for each batch and compare such analyses for consistency with the analyses results reported to EPA; and
(5) Select a representative sample from the listing of tenders of non-finished-gasoline petroleum products that are excluded from the refiner's or importer's compliance calculations, and for such sample confirm that documents demonstrate the petroleum products were used for a purpose other than the production of gasoline within the United States.
At 59 FR 39292, Aug. 2, 1994, § 80.128 was amended by revising paragraphs (a) and (e)(2); removing “and” at the end of paragraph (e)(4); removing the period at the end of paragraph (e)(5) and adding “; and” in its place; and adding paragraph (e)(6) effective September 1, 1994. At 59 FR 60715, Nov. 28, 1994, the amendment was stayed effective September 13, 1994.
The following are the procedures to be carried out at each oxygenate blending facility that is subject to the requirements of this subpart F:
(a) Read the oxygenate blender's reports filed with the EPA for the previous year as required by §§ 80.75 and 80.83(g).
(b) Obtain a material balance analysis summarizing receipts of RBOB and oxygenate to the blender, and the deliveries of reformulated gasoline from the blender.
(1) Test the mathematical accuracy of the calculations contained in the analysis.
(2) Agree the beginning and ending inventory to the blender's perpetual inventory records.
(3) Agree the analysis, where applicable, to the EPA reports.
(c) Obtain a listing of all RBOB receipts for the previous year.
(1) Test the mathematical accuracy of the volumetric calculations contained in the listing.
(2) Agree the volumetric calculations of RBOB receipts to the calculations contained in the material balance analysis.
(3) Select a representative sample of RBOB receipts from the listing. Review the product transfer documents for the indication of the type and volume of oxygenate required to be added to the RBOB.
(d) Obtain a listing of all reformulated gasoline batches produced by the blender during the previous year.
(1) Test the mathematical accuracy of the volumetric calculations contained in the listing.
(2) Agree the volumetric calculations contained in the listing to the calculations contained in the material balance analysis.
(3) Select a representative sample of the batches from the listing, and for these batches:
(i) Obtain the blender's records that indicate the volume and type of oxygenate that was blended, the volume of RBOB that was blended and the product transfer documents for the RBOB, and the internal lab analysis where applicable;
(ii) Agree the consistency of the type and volume of oxygenate added to the RBOB with that indicated to be added in the RBOB's product transfer documents;
(iii) In the case of RBOB designated as “any renewable oxygenate,” “non VOC controlled renewable ether only,” or “renewable ether only,” review the documentation from the producer of the oxygenate to determine if the oxygenate meets the requirements of § 80.83(a);
(iv) Recalculate the actual oxygen content based on the volumes blended and agree to the report to EPA on oxygen; and
(v) Review the time and place designations in the product transfer documents prepared for the batch by the blender, for consistency with the time and place designations in the product transfer documents for the RBOB (e.g. VOC-controlled or non-VOC-controlled, VOC region for VOC-controlled, and simple or complex model).
(e) Agree the sampling and testing frequency of the blender's quality assurance program with the sampling and testing rates required in § 80.69.
At 59 FR 39292, Aug. 2, 1994, § 80.129 was amended by revising paragraphs (a), (d)(3)(iii) and (d)(3)(iv), and adding paragraph (d)(3)(v) effective September 1, 1994. At 59 FR 60715, Nov. 28, 1994, the amendment was stayed effective September 13, 1994.
(a)
(2) The refiner, importer or blender shall provide a copy of the auditor's report to the EPA within the time specified in § 80.75(m).
(b)
The definitions in this section apply only to subpart G of this part. Any terms not defined in this subpart shall have the meaning given them in 40 CFR part 80, subpart A, or, if not defined in 40 CFR part 80, subpart A, shall have the meaning given them in 40 CFR part 79, subpart A.
(a)
(i) All gasoline sold or transferred to a party who sells or transfers gasoline to the ultimate consumer;
(ii) All additized post-refinery component (PRC); and
(iii) All detergent additives sold or transferred for use in gasoline or PRC for compliance with the requirements of this subpart.
(2) Until July 31, 1997, all gasoline sold or transferred to the ultimate consumer must contain detergent additive(s) meeting either the interim requirements of this § 80.141 or the certification program requirements of § 80.161. Beginning August 1, 1997, such gasoline must contain detergent additive(s) meeting the certification requirements of § 80.161.
(b)
(2) Pursuant to paragraphs (c) through (f) of this section, compliance with these requirements is the responsibility of parties who directly or indirectly sell or dispense gasoline to the ultimate consumer as well as parties who manufacture, supply, or transfer detergent additives or detergent-additized post-refinery components.
(c)
(1)
(i) A complete listing of the components of the detergent additive package, using standard chemical nomenclature when possible or providing the chemical structure of any component for which the standard chemical name is not precise. Polymeric components may be reported as the product of other chemical reactants, provided that the supporting data specified in § 80.162(b) is also reported for such components.
(ii) The weight and/or volume percent (as applicable) of each component of the package, with variability in these amounts restricted according to the provisions of paragraph (c)(2) of this section.
(iii) For each detergent-active component of the package, classification into one of the following designations:
(A) Polyalkyl amine;
(B) Polyether amine;
(C) Polyalkylsuccinimide;
(D) Polyalkylaminophenol;
(E) Detergent-active carrier oil; and
(F) Other detergent-active component.
(2)
(ii) A single detergent additive registration may specify a range of concentrations for identified detergent-active components, provided that, if each such component were present in the detergent additive package at the lower bound of its reported range of concentration, the minimum recommended concentration reported in accordance with the requirements of paragraph (c)(3) of this section would still provide the deposit control effectiveness claimed by the detergent registrant.
(iii) The identity or concentration of non-detergent-active components of the detergent additive package may vary under a single registration, provided that the range of such variation is specified in the registration, and that such variability does not reduce the deposit control effectiveness of the additive package as compared with the level of effectiveness claimed by the detergent registrant pursuant to the requirements of paragraph (c)(3) of this section.
(iv) Except as provided in paragraph (c)(2)(v) of this section, detergent additive packages which do not satisfy these restrictions must be separately registered. EPA may disqualify an additive for use in satisfying the requirements of this subpart if EPA determines that the variability included within a given detergent additive registration may reduce the deposit control effectiveness of the detergent package such that it could invalidate the minimum recommended concentration reported in accordance with the requirements of paragraph (c)(3) of this section.
(v) A change in minimum concentration requirements resulting from a modification of detergent additive composition shall not require a new detergent additive registration or a change in existing registration if:
(A) The modification is effected by a detergent blender only for its own use
(B) The modification is a dilution of the additive for the purpose of ensuring proper detergent flow in cold weather; and
(C) Gasoline is the only diluting agent used; and
(D) The diluted detergent is subsequently added to gasoline at a rate that attains the detergent's registered minimum recommended concentration, taking into account the dilution; and
(E) EPA is notified, either before or within seven days after the dilution action, of the identity of the detergent, the identity of the diluting material, the amount or percentage of the dilution, the change in treat rate necessitated by the dilution, and the locations and time period of diluted detergent usage. The notification shall be sent or faxed to the address in § 80.174(c).
(3)
(ii) The minimum concentration reported in the detergent registration according to the provisions of paragraph (c)(3)(i) of this section must also be communicated in writing by the additive manufacturer to each fuel manufacturer who purchases the subject detergent for purpose of compliance with the gasoline detergency requirements of this subpart, and to any additive manufacturer who purchases the subject additive with the intent of reselling it to a fuel manufacturer for this purpose.
(iii) Pursuant to the requirements of paragraph (e) of this section, EPA may require the additive manufacturer to submit data to support the deposit control effectiveness of the detergent package at the specified minimum effective concentration. EPA may disqualify an additive for use in satisfying the requirements of this subpart upon finding that the supporting data is inadequate. Manufacturers may be subject to the liabilities and enforcement actions in §§ 80.156 and 80.159 if such a finding is made.
(iv) Once included in the registration for a detergent additive package, the minimum concentration recommended by the detergent manufacturer to detergent blenders and other users of the detergent additive, pursuant to paragraph (c)(3)(ii) of this section, may not be changed without first notifying EPA. The notification must be sent by certified mail to the address specified in § 80.174(b). Changes to the minimum recommended concentration must be supported by available test data pursuant to paragraph (c)(3)(iii) of this section.
(v) A manufacturer may use a single set of test data to demonstrate the deposit control effectiveness of more than one registered detergent additive product, provided that:
(A) The additive products contain all of the same detergent-active components and no detergent-active components other than those contained in common; and
(B) The minimum concentration recommended for the use of each such additive product is specified such that, when each additive product is mixed in gasoline at the recommended concentration, each of its detergent-active components will be present at a final concentration no less than the lowest concentration for that component shown to be effective by the data available for the tested additive product.
(d) The rate at which a detergent blender treats gasoline with a detergent additive package must be no less than the minimum recommended concentration reported for the subject detergent additive pursuant to paragraph
(1) If a detergent blender believes that the minimum treat rate recommended by the manufacturer of a detergent additive exceeds the amount of detergent actually required for effective deposit control, and possesses substantiating data consistent with the guidelines in paragraph (e) of this section, then, upon informing EPA in writing of these circumstances, the detergent blender may use the detergent at a lower concentration.
(2) The notification to EPA must clearly specify the name of the detergent product and its manufacturer, the concentration recommended by the detergent manufacturer, and the lower concentration which the detergent blender intends to use. The notification must also attest that data are available to substantiate the deposit control effectiveness of the detergent at the intended lower concentration. The notification must be sent by certified mail to the address specified in § 80.174(b).
(3) At its discretion, EPA may require that the detergent blender submit the test data purported to substantiate the claimed effectiveness of the lower concentration of the detergent additive. EPA may also require the manufacturer of the subject detergent additive to submit test data substantiating the minimum recommended concentration specified in the detergent additive registration. In either case, EPA will send a letter to the appropriate party, and the supporting data will be due to EPA within 30 days of receipt of EPA's letter.
(i) If the detergent blender fails to submit the required supporting data to EPA in the allotted time period, or if EPA judges the submitted data to be inadequate to support the detergent blender's claim that the lower concentration provides a level of deposit control consistent with the requirements of this section, then EPA will disapprove the use of the detergent at the lower concentration. Further, the detergent blender may be subject to applicable liabilities and penalties pursuant to §§ 80.156 and 80.159 for any gasoline or PRC it has additized at the lower concentration.
(ii) If the detergent manufacturer fails to submit the required test data to EPA within the allotted time period, EPA will proceed on the assumption that data are not available to substantiate the minimum recommended concentration specified in the detergent registration, and the subject additive may be disqualified for use in complying with the requirements of this subpart, pursuant to the procedures in paragraph (g) of this section. The detergent manufacturer may also be subject to applicable liabilities and penalties pursuant to §§ 80.156 and 80.159.
(iii) If both parties submit the required information, EPA will evaluate the quality and results of both sets of test data in relation to each other and to industry-consensus test practices and standards, in a manner consistent with the guidelines described in paragraph (e) of this section. EPA will approve or disapprove the use of the detergent at the lower concentration, and will inform both the detergent blender and the detergent manufacturer of the results of its analysis within 60 days of receipt of both sets of data.
(e)
(1)
(2) EPA will evaluate the adequacy of other supporting data according to the following guidelines:
(i) Test fuel guidelines.
(A) The gasoline used in the supporting tests must contain the detergent-active components of the subject detergent additive package in an amount which corresponds to the minimum recommended concentrations recorded in the respective detergent registration, or less than this amount.
(B) The test fuels must not contain any detergent-active components other than those recorded in the subject detergent registration.
(C) The test fuels used must be reasonably typical of in-use fuels in their tendency to form deposits. Test fuel taken directly from commercial refinery production stock is acceptable. Specially refined low-deposit-forming fuels such as indolene are not acceptable. Other specially blended test fuels will be evaluated by EPA for acceptability based on the extent to which such fuels adequately represent the deposit-forming tendency of typical (average) in-use fuels, as reflected in the levels of the following fuel parameters: sulfur content, aromatic content, olefin content, T-90, and oxygenate content.
(D) The composition of the blended test fuel(s) used in carburetor deposit control testing, conducted to support the claimed effectiveness of detergents used in leaded gasoline, should be reasonably typical of in-use gasoline in its tendency to form carburetor deposits (or more severe than typical in-use fuels) as defined by the olefin and sulfur content. Test data using leaded fuels is preferred for this purpose, but data collected using unleaded fuels may also be acceptable provided that some correlation with additive performance in leaded fuels is available.
(ii) Test procedure guidelines.
(A) To be acceptable, test data submitted to support the deposit control effectiveness of a detergent additive must derive from testing conducted in conformity with good engineering practices.
(B) For demonstration of fuel injector and intake valve deposit control performance, the tests specified in §§ 80.165, or other vehicle-based tests using generally accepted industry procedures and standards, are preferred. Engine-based tests may also be acceptable, assuming a reasonable correlation with vehicle-based tests and standards can be demonstrated. Bench test data may be acceptable to demonstrate fuel injector deposit control performance, assuming the results can be correlated with vehicle- or engine-based tests and standards. Bench testing will not be considered acceptable for demonstration of IVD control performance. Examples of acceptable test procedures are contained in the following references:
(
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(
(
(
(
(
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(C) For demonstration of carburetor deposit control performance, any generally accepted vehicle, engine, or bench test procedure for carburetor deposit control will be considered adequate. Port and throttle body fuel injector deposit control test data will also be considered to be adequate demonstration of an additive's ability to control carburetor deposits. Examples of acceptable test procedures for demonstration of carburetor deposit control, in addition to the fuel injector test procedures listed above in paragraph (e)(2)(ii)(B)(
(
(
(f)
(2) The analytical procedure submitted by the registrant must be able to both qualitatively and quantitatively identify each component of the detergent additive package. To be acceptable, the procedure must provide results that conform to reasonable and customary standards of repeatability and reproducibility, and reasonable and customary limits of detection and accuracy, for the type of test in question.
(3) A fourier transform infrared spectroscopy (FTIR)-based procedure, including an actual infrared spectrum of the detergent additive package and each component part of the detergent package obtained from this test method, is preferred.
(g)
(2) If EPA determines that the detergent registration was created by fraud or other misconduct, such as a negligent disregard for the truthfulness or accuracy of the required information or of the application, the detergent registration will be considered void
(3) The registrant will be afforded 60 days from the date of receipt of the notice of intent of detergent disqualification to submit written comments concerning the notice, and to demonstrate or achieve compliance with the specific data requirements which provide the basis for the proposed disqualification. If the registrant does not respond in writing within 60 days from the date of receipt of the notice of intent of disqualification, the detergent disqualification shall become final by operation of law and the Administrator shall notify the registrant of such disqualification. If the registrant responds in writing within 60 days from the date of receipt of the notice of intent to disqualify, the Administrator shall review and consider all comments submitted by the registrant before taking final action concerning the proposed disqualification. All correspondence regarding a disqualification must be sent to the address specified in § 80.174(b).
(4) As part of a written response to a notice of intent to disqualify, a registrant may request an informal hearing concerning the notice. Any such request shall state with specificity the information the registrant wishes to present at such a hearing. If an informal hearing is requested, EPA shall schedule such a hearing within 90 days from the date of receipt of the request. If an informal hearing is held, the subject matter of the hearing shall be confined solely to whether or not the registrant has complied with the specific data requirements which provide the basis for the proposed disqualification. If an informal hearing is held, the designated presiding officer may be any EPA employee, the hearing procedures shall be informal, and the hearing shall not be subject to or governed by 40 CFR part 22 or by 5 U.S.C. 554, 556, or 557. A verbatim transcript of each informal hearing shall be kept and the Administrator shall consider all relevant evidence and arguments presented at the hearing in making a final decision concerning a proposed cancellation.
(5) If a registrant who has received a notice of intent to disqualify submits a timely written response, and the Administrator decides after reviewing the response and the transcript of any informal hearing to disqualify the detergent for use in complying with the requirements of this subpart, the Administrator shall issue a final disqualification order, forward a copy of the disqualification order to the registrant by certified mail, and promptly publish the disqualification order in the
(6) Upon making a final decision to disqualify a detergent additive package pursuant to this paragraph (g), EPA shall inform all fuel manufacturers and secondary additive manufacturers whose product registrations report the potential use of the disqualified detergent that such detergent is no longer eligible for compliance with the requirements of this subpart. Such fuel manufacturers and secondary additive manufacturers shall have 45 days in which to stop using the ineligible detergent additive package and substitute an eligible detergent additive. When applicable, EPA shall also notify such parties that the detergent registration had been created by fraud or other misconduct, pursuant to paragraph (g)(2) of this section.
(a)(1) No person shall sell, offer for sale, dispense, supply, offer for supply, transport, or cause the transportation of gasoline to the ultimate consumer for use in motor vehicles or in any off-road engines (except as provided in § 80.160), or to a gasoline retailer or wholesale purchaser-consumer, and no person shall detergent-additize gasoline, unless such gasoline is additized in conformity with the requirements of § 80.141. No person shall cause the presence of any gasoline in the gasoline distribution system unless such gasoline is additized in conformity with the requirements of § 80.141.
(2) Gasoline has been additized in conformity with the requirements of § 80.141 when the detergent component satisfies the requirements of § 80.141 and when:
(i) The gasoline has been additized in conformity with the detergent composition and purpose-in-use specifications of an applicable detergent registered under 40 CFR part 79, and in accordance with at least the minimum concentration specifications of that detergent as registered under 40 CFR part 79 or as otherwise provided under § 80.141(d); or
(ii) The gasoline is composed of two or more commingled gasolines and each component gasoline has been additized in conformity with the detergent composition and purpose-in-use specifications of a detergent registered under 40 CFR part 79, and in accordance with at least the minimum concentration specifications of that detergent as registered under 40 CFR part 79 or as otherwise provided under § 80.141(d); or
(iii) The gasoline is composed of a gasoline commingled with a post-refinery component (PRC), and both of these components have been additized in conformity with the detergent composition and use specifications of a detergent registered under 40 CFR part 79, and in accordance with at least the minimum concentration specifications of that detergent as registered under 40 CFR part 79 or as otherwise provided under § 80.141(d).
(b) No person shall blend detergent into gasoline or PRC unless such person complies with the volumetric additive reconciliation requirements of § 80.157.
(c) No person shall sell, offer for sale, dispense, supply, offer for supply, store, transport, or cause the transportation of any gasoline, detergent, or detergent-additized PRC unless the product transfer document for the gasoline, detergent or detergent-additized PRC complies with the requirements of § 80.158.
(d) No person shall refine, import, manufacture, sell, offer for sale, dispense, supply, offer for supply, store, transport, or cause the transportation of any detergent that is to be used as a component of detergent-additized gasoline or detergent-additized PRC, unless such detergent conforms with the composition specifications of a detergent registered under 40 CFR part 79 and the detergent otherwise complies with the requirements of § 80.141. No person shall cause the presence of any detergent in the detergent, PRC, or gasoline distribution systems unless such detergent complies with the requirements of § 80.141.
(e)(1) No person shall sell, offer for sale, dispense, supply, offer for supply, transport, or cause the transportation of detergent-additized PRC, unless the PRC has been additized in conformity with the requirements of § 80.141. No person shall cause the presence in the PRC or gasoline distribution systems of any detergent-additized PRC that fails to conform to the requirements of § 80.141.
(2) PRC has been additized in conformity with the requirements of § 80.141 when the detergent component satisfies the requirements of § 80.141 and:
(i) The PRC has been additized in accordance with the detergent composition and use specifications of a detergent registered under 40 CFR part 79, and in accordance with at least the minimum concentration specifications of that detergent as registered under 40 CFR part 79 or as otherwise provided under § 80.141(d); or
(ii) The PRC is composed of two or more commingled PRCs, and each component has been additized in accordance with the detergent composition and use specifications of a detergent registered under 49 CFR part 79, and in accordance with at least the minimum concentration specifications of that detergent as registered under 40 CFR part 79 or as otherwise provided under § 80.141(d).
(a)
(i) Each gasoline refiner, importer, carrier, distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate blender, or detergent blender, who owns, leases, operates, controls or supervises the facility (including, but not limited to, a truck or individual storage tank) where the violation is found;
(ii) Each gasoline refiner, importer, distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate blender, detergent manufacturer, distributor, or blender, who refined, imported, manufactured, sold, offered for sale, dispensed, supplied, offered for supply, stored, detergent additized, transported, or caused the transportation of the detergent-additized gasoline (or the base gasoline component, the detergent component, or the detergent-additized post-refinery component of the gasoline) that is in violation, and each such party that caused the gasoline that is in violation to be present in the gasoline distribution system; and
(iii) Each gasoline carrier who dispensed, supplied, stored, or transported any gasoline in the storage tank containing gasoline found to be in violation, and each detergent carrier who dispensed, supplied, stored, or transported the detergent component of any post-refinery component or gasoline in the storage tank containing gasoline found to be in violation, provided that the EPA demonstrates, by reasonably specific showings by direct or circumstantial evidence, that the gasoline or detergent carrier caused the violation.
(2)
(i) Each gasoline refiner, importer, carrier, distributor, reseller, retailer, wholesale-purchaser consumer, oxygenate blender, detergent manufacturer, carrier, distributor, or blender, who owns, leases, operates, controls or supervises the facility (including, but not limited to, a truck or individual storage tank) where the violation is found;
(ii) Each gasoline refiner, importer, distributor, reseller, retailer, wholesale-purchaser consumer, oxygenate blender, detergent manufacturer, distributor, or blender, who sold, offered for sale, dispensed, supplied, offered for supply, stored, detergent additized, transported, or caused the transportation of the detergent-additized PRC (or the detergent component of the PRC) that is in violation, and each such party that caused the PRC that is in violation to be present in the PRC or gasoline distribution systems; and
(iii) Each carrier who dispensed, supplied, stored, or transported any detergent-additized post-refinery component in the storage tank containing post-refinery component in violation, and each detergent carrier who dispensed, supplied, stored, or transported the detergent component of any detergent-additized post-refinery component which is in the storage tank containing detergent-additized post-refinery component found to be in violation, provided that the EPA demonstrates by reasonably specific showings by direct or circumstantial evidence, that the gasoline or detergent carrier caused the violation.
(3)
(i) Each gasoline refiner, importer, carrier, distributor, reseller, retailer, wholesale-purchaser consumer, oxygenate blender, detergent manufacturer,
(ii) Each gasoline refiner, importer, distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate blender, detergent manufacturer, distributor, or blender, who sold, offered for sale, dispensed, supplied, offered for supply, stored, transported, or caused the transportation of the detergent that is in violation, and each such party that caused the detergent that is in violation to be present in the detergent, gasoline, or PRC distribution systems; and
(iii) Each gasoline or detergent carrier who dispensed, supplied, stored, or transported any detergent which is in the storage tank or container containing detergent found to be in violation, providing that EPA demonstrates, by reasonably specific showings by direct or circumstantial evidence, that the gasoline or detergent carrier caused the violation.
(4)
(i) Each detergent blender who owns, leases, operates, controls or supervises the facility (including, but not limited to, a truck or individual storage tank) where the violation has occurred; and
(ii) Each gasoline refiner, importer, carrier, distributor, reseller, retailer, wholesale purchaser-consumer, or oxygenate blender, and each detergent manufacturer, carrier, distributor, or blender, who refined, imported, manufactured, sold, offered for sale, dispensed, supplied, offered for supply, stored, transported, or caused the transportation of the detergent-additized gasoline, the base gasoline component, the detergent component, or the detergent-additized post-refinery component, of the gasoline that is in violation, provided that the EPA demonstrates, by reasonably specific showings by direct or circumstantial evidence, that such person caused the violation.
(5)
(b)
(c)
(i) That the violation was not caused by the regulated party or its employee or agent (unless otherwise provided in this paragraph (c));
(ii) That product transfer documents account for the gasoline, detergent, or detergent-additized post-refinery component in violation and indicate that the gasoline, detergent, or detergent-additized post-refinery component satisfied relevant requirements when it left their control; and
(iii) That the party has fulfilled the requirements of paragraphs (c) (2) or (3) of this section, as applicable.
(2)
(A) An act in violation of law (other than these regulations), or an act of sabotage or vandalism, whether or not such acts are violations of law in the jurisdiction where the violation of the prohibitions of § 80.155 occurred; or
(B) The action of any gasoline refiner, importer, reseller, distributor, oxygenate blender, detergent manufacturer, distributor, blender, or retailer or wholesale purchaser-consumer supplied by any of these persons, in violation of a contractual undertaking imposed by the refiner designed to prevent such action, and despite the implementation of an oversight program, including, but not limited to, periodic review of product transfer documents by the refiner to ensure compliance with such contractual obligation; or
(C) The action of any gasoline or detergent carrier, or other gasoline or detergent distributor not subject to a contract with the refiner but engaged by the refiner for transportation of gasoline, post-refinery component, or detergent, to a gasoline or detergent distributor, oxygenate blender, detergent blender, gasoline retailer or wholesale purchaser consumer, despite specification or inspection of procedures or equipment by the refiner which are reasonably calculated to prevent such action.
(ii) In this paragraph (c)(2), to show that the violation “was caused” by any of the specified actions, the party must demonstrate by reasonably specific showings, by direct or circumstantial evidence, that the violation was caused or must have been caused by another.
(3)
(i) That it obtained or supplied, as appropriate, prior to the detergent blending, accurate written instructions from the detergent manufacturer or other party with knowledge of such instructions, specifying the detergent's minimum recommended concentration (lowest additive concentration) pursuant to § 80.141(c)(3) and, if applicable, the limitations of this concentration for use in leaded product.
(ii) That it has implemented a quality assurance program that includes, but is not limited to, a periodic review of its supporting product transfer and volume measurement documents to confirm the correctness of its product transfer and volumetric additive reconciliation documents created for all products it additized.
(4)
(A) Product transfer documents which account for the detergent component of the product in violation and which indicate that such detergent satisfied all relevant requirements when it left the detergent manufacturer's control; and
(B) Written blending instructions which, pursuant to § 80.141(c)(3)(ii), were supplied by the detergent manufacturer to its customer who purchased or obtained from the manufacturer the detergent component of the product determined to be in violation. The written blending instructions must have been supplied by the manufacturer prior to the customer's use or sale of the detergent. The instructions must accurately identify the minimum recommended concentration (lowest additive concentration) specified in the detergent's 40 CFR part 79 registration, and must also accurately identify if the detergent, at that concentration, is only registered as effective for use in leaded gasoline.
(C) If the detergent batch used in the noncomplying product was produced less than one year before the manufacturer was notified by EPA of the possible violation, then the manufacturer must provide FTIR or other test results for the batch of detergent used in the noncomplying product, performed in accordance with the detergent testing procedure submitted by the manufacturer, or available for submission, pursuant to § 80.141(f).
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(D) If the detergent batch used in the noncomplying product was produced more than one year prior to the manufacturer's notification by EPA of the possible violation, then the manufacturer must provide either:
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(ii)
(5)
(i) Prior to the violation it had entered into a written contract with another potentially liable detergent blender party (“the assuming party”), under which that other party assumed legal responsibility for fulfilling the VAR requirement that had been violated;
(ii) The contract included reasonable oversight provisions to ensure that the assuming party fulfilled its VAR responsibilities (including, but not limited to, periodic review of VAR records) and the oversight provision was actually implemented by the party raising the defense;
(iii) The assuming party is fiscally sound and able to pay its penalty for the VAR violation; and
(iv) The employees or agents of the party raising the defense did not cause the violation.
(6)
(7)
(i) The commingling must occur during a legitimate detergent transitioning event,
(ii) If the new detergent is restricted to use in leaded gasoline, then such restriction must be applied to the combined detergents; and
(iii) The commingling event must be documented, either on the VAR formula record or on attached supporting records; and
(iv) Notwithstanding any contrary provisions in § 80.157, a VAR formula record must be created for the combined detergents. The VAR compliance period must begin no later than the time of the commingling event. However, at the blender's option, the compliance period may begin earlier, thus including use of the uncombined original detergent within the same period, provided that the 31-day limitation pursuant to § 80.157(a)(6) is not exceeded; and
(v) The VAR formula record must also satisfy the requirements in one of the following paragraphs (c)(7)(v)(A) through (C) of this section, whichever applies to the commingling event. If neither paragraph (c)(7)(v)(A) nor (B) of this section initially applies, then the blender may drain and subsequently redeliver the original detergent into the tank in restricted amounts, in order to meet the conditions of paragraph (c)(7)(v)(A) or (B) of this section. Otherwise, the blender must comply with paragraph (c)(7)(v)(C) of this section.
(A) If both detergents have the same LAC, and the original detergent accounts for no more than 20 percent of the tank's total delivered volume after addition of the new detergent, then the VAR formula record is required to identify only the use of the new detergent.
(B) If the two detergents have different LACs and the original detergent accounts for 10 percent or less of the tank's total delivered volume after addition of the new detergent, then the VAR formula record is required to identify only the use of the new detergent, and must attain the LAC of the new detergent. If the original detergent's LAC is greater than that of the new detergent, then the compliance period may begin earlier than the date of the commingling event (pursuant to paragraph (c)(7)(iv) of this section) only if the original detergent does not exceed 10 percent of the total detergent used during the compliance period.
(C) If neither of the preceding paragraphs (c)(7)(v)(A) or (B) of this section applies, then the VAR formula record must identify both of the commingled detergents, and must use and attain the higher LAC of the two detergents. Once the commingled detergent has been depleted by an amount equal to the volume of the original detergent in the tank at the time the new detergent was added, subsequent VAR formula records must identify and use the LAC of only the new detergent.
(8)
(d)
This section contains requirements for automated detergent blending facilities and hand-blending detergent facilities. All gasolines and all PRC intended for use in gasoline must be additized, unless otherwise noted in supporting VAR records, and must be accounted for in VAR records. The VAR reconciliation standard is attained under this section when the actual concentration of detergent used per VAR formula record equals or exceeds the lowest additive concentration (LAC) specified for that detergent pursuant to § 80.141(c)(3), or, if appropriate, under § 80.141(d). A separate VAR formula record must be created for leaded gasoline additized with a detergent registered for use only with leaded gasoline, or used at a concentration that is registered as effective for leaded gasoline only. Detergent so used must be accurately and separately measured, either through the use of a separate storage tank, a separate meter, or some other measurement system that is able to accurately distinguish its use. Recorded volumes of gasoline, detergent, and PRC must be expressed to the nearest gallon (or smaller units), except that detergent volumes of five gallons or less must be expressed to the nearest tenth of a gallon (or smaller units). However, if the blender's equipment cannot accurately measure to the nearest tenth of a gallon, then such volumes must be rounded downward to the next lower gallon. PRC included in the reconciliation must be identified. Each VAR formula record must also contain the following information:
(a)
(1) The manufacturer and commercial identifying name of the detergent additive package being reconciled, and the LAC specified in the detergent registration for use with the applicable type of gasoline (i.e., unleaded or leaded). The LAC must be expressed in terms of gallons of detergent per thousand gallons of gasoline or PRC, and expressed to four digits. If the specified LAC is only effective for use with leaded gasoline, the record must so indicate. If the detergent storage system which is the subject of the VAR formula record is a proprietary system under the control of a customer, this fact must be indicated on the record.
(2) The total volume of detergent blended into gasoline and PRC, in accordance with one of the following paragraphs, as applicable.
(i) For a facility which uses in-line meters to measure detergent usage, the total volume of detergent measured, together with supporting data which includes one of the following: the beginning and ending meter readings for each meter being measured, the metered batch volume measurements for each meter being measured, or other comparable metered measurements. The supporting data may be supplied on the VAR formula record or in the form of computer printouts or other comparable VAR supporting documentation.
(ii) For a facility which uses a gauge to measure the inventory of the detergent storage tank, the total volume of detergent shall be calculated from the following equation:
(3) The total volume of gasoline plus PRC to which detergent has been added, together with supporting data which includes one of the following:
(4) The actual detergent concentration, calculated as the total volume of detergent added (pursuant to paragraph (a)(2) of this section), divided by the total volume of gasoline plus PRC (pursuant to paragraph (a)(3) of this section). The concentration must be calculated and recorded to four digits.
(5) A list of each detergent concentration rate initially set for the detergent that is the subject of the VAR record, together with the date and description of each adjustment to any initially set concentration. The concentration adjustment information may be supplied on the VAR formula record or in the form of computer printouts or other comparable VAR supporting documentation. No concentration setting is permitted below the applicable LAC, except as may be modified pursuant to § 80.141(d) or as described in paragraph (a)(7) of this section.
(6) The dates of the VAR period, which shall be no longer than thirty-one days. If the VAR period is contemporaneous with a calendar month, then specifying the month will fulfill this requirement; if not, then the beginning and ending dates and times of the VAR period must be listed. The times may be supplied on the VAR formula record or in supporting documentation. Any adjustment to any detergent concentration rate more than 10 percent over the concentration rate initially set in the VAR period shall terminate that VAR period and initiate a new VAR period, except as provided in paragraph (a)(7) of this section.
(7) The concentration setting for a detergent injector may be set below the applicable LAC, or it may be adjusted more than 10 percent above the concentration initially set in the VAR period without terminating that VAR period, provided that:
(i) The purpose of the change is to correct a batch misadditization prior to the end of the VAR period and prior to the transfer of the batch to another party, or to correct an equipment malfunction; and
(ii) The concentration is immediately returned after the correction to a concentration that fulfills the requirements of paragraphs (a)(5) and (6) of this section; and
(iii) The blender creates and maintains documentation establishing the date and adjustments of the correction; and
(iv) If the correction is initiated only to rectify an equipment malfunction, and the amount of detergent used in this procedure is not added to gasoline in the compliance period, then this amount is subtracted from the detergent volume listed on the VAR formula record.
(8) If unadditized gasoline has been transferred from the facility, other than bulk transfers from refineries or pipelines to non-retail outlets or non-WPC facilities, the total amount of such gasoline must be specified.
(b)
(1) The manufacturer and commercial identifying name of the detergent additive package being reconciled, and the LAC specified in the detergent registration for use with the applicable type of gasoline (i.e., unleaded or leaded). The LAC must be expressed in terms of gallons of detergent per thousand gallons of gasoline or PRC, and expressed to four digits. If the specified LAC is only effective for use with leaded gasoline, the record must so indicate.
(2) The date of the additization that is the subject of the VAR formula record.
(3) The volume of added detergent.
(4) The volume of the gasoline and/or PRC to which the detergent has been added. If gasoline has intentionally been overadditized in anticipation of the later addition of unadditized PRC, then the total volume of gasoline plus PRC recorded must include the expected amount of unadditized PRC to be added later. In addition, the amount of gasoline which was overadditized for this purpose must be specified.
(5) The brand (if known), grade, and leaded/unleaded status of gasoline, and/or the type of PRC.
(6) The actual detergent concentration, calculated as the volume of added detergent (pursuant to paragraph (b)(3) of this section), divided by the volume of gasoline and/or PRC (pursuant to paragraph (b)(4) of this section). The concentration must be calculated and recorded to four digits.
(c) Every VAR formula record created pursuant to paragraphs (a) and (b) of this section shall contain the following:
(1) The signature of the creator of the VAR record;
(2) The date of the creation of the VAR record; and
(3) A certification of correctness by the creator of the VAR record.
(d)
(2) Electronically-generated VAR formula records may use an electronic user identification code to satisfy the signature requirements of paragraph (c)(1) of this section, provided that:
(i) The use of the ID is limited to the record creator; and
(ii) A paper record is maintained, which is signed and dated by the VAR formula record creator, acknowledging that the use of that particular user ID on a VAR formula record is equivalent to his/her signature on the document.
(e) Automated detergent blenders must calibrate their detergent equipment once in each calendar half year, with the acceptable calibrations being no less than one hundred twenty days apart. Equipment recalibration is also required each time the detergent package is changed, unless written documentation indicates that the new detergent package has the same viscosity as the previous detergent package. Detergent package change calibrations may be used to satisfy the semiannual requirement provided that the calibrations occur in the appropriate half calendar year and are no less than one hundred twenty days apart.
(f) The following VAR supporting documentation must also be created and maintained:
(1) For all automated detergent blending facilities, documentation reflecting performance of the calibrations required by paragraph (e) of this section, and any associated adjustments of the automated detergent equipment;
(2) For all hand-blending facilities which are terminals, a record specifying, for each calendar month, the total volume in gallons of transfers from the facility of unadditized base gasoline;
(3) For all detergent blending facilities, product transfer documents for all gasoline, detergent and detergent-additized PRC transferred into or out of the facility; in addition, bills of lading, transfer, or sale for all unadditized PRC transferred into the facility;
(4) For all automated detergent blending facilities, documentation establishing the brands (if known) and grades of the gasoline which is the subject of the VAR formula record;
(5) For all hand blending detergent blenders, the documentation, if in the party's possession, supporting the volumes of gasoline, PRC, and detergent reported on the VAR formula record; and
(6) For all detergent blending facilities, documentation establishing the curing of a batch or amount of misadditized gasoline or PRC, or the curing of a use restriction on the additized gasoline or PRC, and providing at least the following information: the date of the curing procedure; the problem that was corrected; the amount, name, and LAC of the original detergent used; the amount, name, and LAC of the added curing detergent; and the actual detergent concentration attained in, and the volume of, the total cured product.
(g)
(1) Except as provided in paragraph (g)(3) of this section, automated detergent blender facilities and hand-blender facilities which are terminals, which physically blend detergent into gasoline, must make immediately available to EPA, upon request, the preceding twelve months of VAR formula records plus the preceding two months of VAR supporting documentation.
(2) Except as provided in paragraph (g)(3) of this section, other hand-blending detergent facilities which physically blend detergent into gasoline must make immediately available to EPA, upon request, the preceding two months of VAR formula records and VAR supporting documentation.
(3) Facilities which have centrally maintained records at other locations, or have customers who maintain their own records at other locations for their proprietary detergent systems, and which can document this fact to the Agency, may have until the start of the next business day after the request to supply VAR supporting documentation, or longer if approved by the Agency.
(4) In this paragraph (g) of this section, the term immediately available means that the records must be provided, electronically or otherwise, within approximately one hour of EPA's request, or within a longer time frame as approved by EPA.
(a)
(1) The names and addresses of the transferee and transferor; the address requirement may be fulfilled, in the alternative, through separate documentation which establishes said addresses and is maintained by the parties and made available to EPA for the same length of time as required for the PTDs, provided that the normal business procedure of these parties is not to identify addresses on PTDs.
(2) The date of the transfer.
(3) The volume of product transferred.
(4)(i) The identity of the product being transferred (i.e., its identity as base gasoline, detergent, detergent-additized gasoline, or specified detergent-additized oxygenate or detergent-additized gasoline blending stock that comprises a detergent-additized PRC). PTDs for detergent-additized gasoline or PRC are not required to identify the particular detergent used to additize the product.
(ii) If the product being transferred consists of two or more different types of product subject to this regulation, i.e., base gasoline, detergent-additized gasoline, or specified detergent-additized PRC, then the PTD for the commingled product must identify each such type of component contained in the commingled product.
(5) If the product being transferred is base gasoline, then in addition to the base gasoline identification, the following warning must be stated on the PTD: “Not for sale to the ultimate consumer”. If, pursuant to § 80.160(a), the product being transferred is exempt base gasoline to be used for research, development, or test purposes only, the following warning must also be stated on the PTD: “For use in research, development, and test programs only.”
(6) The name of the detergent additive as reported in its registration must be used to identify the detergent package on its PTD.
(7) If the product being transferred is leaded gasoline, then the PTD must disclose that the product contains lead and/or phosphorous, as applicable.
(8) If the product being transferred is detergent that is only authorized for the control of carburetor deposits, then the following must be stated on the detergent's transfer document: “For use with leaded gasoline only.”
(9) If the product being transferred is detergent-additized gasoline that has been overadditized in anticipation of the later (or earlier) addition of PRC, then the PTD must include a statement that the product has been overadditized to account for a specified volume in gallons, or a specified percentage of the product's total volume, of additional, specified PRC.
(b) Gasoline may not be additized with a detergent authorized only for the control of carburetor deposits and whose product transfer document states “For use with leaded gasoline only”, and gasoline may not be additized at the lower concentration specified for a detergent authorized at a lower concentration for the control of carburetor deposits only, unless the product transfer document for the gasoline to be additized identifies it as leaded gasoline.
(c)
(i) The specified warning language may be omitted for bulk transfers of base gasoline from a refinery to a pipeline if there is a prior written agreement between the parties specifying that all such gasoline is unadditized and will not be transferred to the ultimate consumer;
(ii) Product codes may be used as a substitute for the specified warning language provided that the PTD is an electronic data interchange (EDI) document being used solely for the transfer of title to the base gasoline, and provided that the product codes otherwise comply with the requirements of this section.
(2) Product codes and other language not specified in this section may otherwise be used to comply with PTD information requirements, provided that they are clear, accurate, and not misleading.
(3) If product codes are used, they must be standardized throughout the distribution system in which they are used, and downstream parties must be informed of their full meaning.
(d)
(1) The product is being transferred by a distributor who is not the product's detergent blender; and
(2) The recipient is a wholesale purchaser-consumer (WPC) or other ultimate consumer of gasoline, for its own use only or for that of its agents or employees; and
(3) The volume of additized gasoline being transferred is not greater than 550 gallons.
(e)
(a)
(b)
(c)
(d)
(e)
(f)
(g)
(h)
(a)
(1) The detergent (or fuel containing the detergent), or the gasoline, is kept segregated from non-exempt product, and the party possessing the product maintains documentation identifying the product as research, development, or testing detergent or fuel, as applicable, and stating that it is to be used only for research, development, or testing purposes; and
(2) The detergent (or fuel containing the detergent), or the gasoline, is not
(3) The party using the product for research, development, or testing purposes, or the party sponsoring this usage, notifies the EPA, on at least an annual basis and prior to the use of the product, of the purpose(s) of the program(s) in which the product will be used and the anticipated volume of the product to be used. The information must be submitted to the address or fax number provided in § 80.174(c).
(b)
(1) The fuel is kept segregated from non-exempt fuel, and the party possessing the fuel for the purposes of refining, selling, dispensing, transferring, or offering for sale, dispensing, or transfer as automotive racing fuel or as aircraft engine fuel, maintains documentation identifying the product as racing fuel, restricted for non-highway use in racing motor vehicles, or as aviation fuel, restricted for use in aircraft, as applicable;
(2) Each pump stand at a regulated party's facility, from which such fuel is dispensed, is labeled with the applicable fuel identification and use restrictions described in paragraph (b)(1) of this section; and
(3) The fuel is not sold, dispensed, transferred, or offered for sale, dispensing, or transfer for highway use in a motor vehicle.
(c)
(i) For all such gasoline or PRC, whether intended for sale within or outside of California, records of the type required for California gasoline (specified in title 13, California Code of Regulations, section 2257) are maintained; and
(ii) Such records, with the exception of daily additization records, are maintained for a period of five years from the date they were created and are delivered to EPA upon request.
(2) Gasoline or PRC that is transferred and/or sold solely within the State of California is exempt from the PTD provisions of the interim detergent program, specified in §§ 80.155(c) and 80.158.
(3) Nothing in this paragraph (c) exempts such gasoline or PRC from the requirements of § 80.155(a) and (e), as applicable. EPA will base its determination of California gasoline's conformity with the detergent's LAC on the additization records required by CARB, or records of the same type.
(a)
(i) Detergent additives for the control of port fuel injector deposits (PFID) and/or intake valve deposits (IVD) in gasoline engines may not be transferred or sold for use in compliance with this subpart unless such additives have been certified according to the requirements of this section.
(ii) Except as provided in § 80.169(c)(8), PFID and IVD control additives may not be added to gasoline or post-refinery component (PRC) for compliance with this subpart unless such additives have been certified according to the requirements of this section.
(iii) Gasoline may not be sold or transferred to a party who sells or transfers gasoline to the ultimate consumer unless such gasoline contains detergent additives which have been certified according to the requirements of this section.
(2) Beginning August 1, 1997, all gasoline sold or transferred to the ultimate consumer must contain detergent additive(s) which have been certified, according to the requirements of this section, to be effective for the control of PFID and IVD in gasoline engines.
(3) Except as specifically exempted in § 80.173, these detergency requirements apply to all gasoline, whether intended for on-highway or nonroad use, including conventional, oxygenated, reformulated, and leaded gasolines, as well as the gasoline component in mixtures of petroleum and alcohol fuels, gasoline used as marine fuel, gasoline service accumulation fuel (as described in § 86.113-94(a)(1) of this chapter), the gasoline component of fuel mixtures of petroleum and methanol used for service accumulation in flexible fuel vehicles (as described in § 86.113-94(d) of this chapter), the gasoline used for factory fill purposes, and all additized PRC.
(4) The specific controls and prohibitions applicable to persons subject to these regulations are set forth in § 80.168.
(b)
(1) The detergent additive manufacturer must properly register the detergent additive under 40 CFR part 79. For this purpose:
(i) The compositional data required under § 79.21(a) of this chapter shall include the information specified in § 80.162.
(ii) The minimum recommended additive concentration required under § 79.21(d) of this chapter shall be reported to EPA in units of gallons of detergent additive package per 1000 gallons of gasoline or PRC, provided to four digits. This concentration is the lowest additive concentration (LAC) referred to in § 80.170, and shall be reported as follows:
(A) For a detergent additive registered for use in unleaded gasoline, the minimum concentration must be determined and reported for each certification option under which the manufacturer wishes to certify the additive pursuant to § 80.163.
(
(
(B) For a detergent registered for use in leaded gasoline, the minimum recommended concentration must be no less than the amount shown to be needed for control of carburetor deposits, pursuant to the test procedure and test fuel guidelines in § 80.166.
(C) Once it has been registered by EPA, the minimum recommended concentration specified by a detergent manufacturer to detergent blenders and other users of the additive, pursuant to paragraph (c) of this section, may not be changed without first notifying EPA. Such notification should be sent by certified mail to the address specified in § 80.174(b). The change in minimum concentration must be supported by existing certification data or else the notification to EPA must be accompanied by new certification information which demonstrates that the modification is consistent with the requirements of paragraphs (b)(1)(ii)(A) and (B) of this section.
(D) A manufacturer may use a single set of certification test data to demonstrate the deposit control effectiveness of more than one registered detergent additive product, provided that:
(
(
(2) The detergent additive manufacturer (or other certifying party) must submit to EPA a sample of the actual detergent additive package which was used in the certification testing specified in § 80.164 or, if such sample is not available, then a sample which has the same composition as the package used in certification testing.
(i) The sample volume shall be between 250 ml and 500 ml.
(ii) The sample shall be packaged in a container which has a resealable closure and which will maintain sample integrity for at least one year. The container shall be labeled with the name and address of the manufacturer and the name of the detergent additive package.
(iii) Any known shelf life limitations, and any available information on optimal temperature, light exposure, or other conditions to prolong sample shelf life, shall be provided.
(iv) If the certifying party wishes to claim that the sample or any accompanying documents are entitled to special handling for reasons of business confidentiality, the party must clearly identify the sample or documents as such. EPA will handle any samples or documents with such claims according to the regulations at 40 CFR part 2.
(v) The sample shall be submitted to EPA, at the address provided in § 80.174(a), within seven days of the date on which the certification letter for the detergent package is sent to EPA as required by paragraph (b)(3) of this section.
(3) The detergent additive manufacturer (or other certifying party) shall submit a certification letter for the detergent additive package to the address in § 80.174(b). The party must use certified or express mail with return receipt service. The letter shall be signed by a person legally authorized to represent the certifying party and shall contain the following information:
(i) Identifying information.
(A) The name and address of the detergent additive manufacturer.
(B) In any case where the certifier is not the detergent additive manufacturer, such as in the case of a fuel-specific certification pursuant to § 80.163(c), the name and address of the certifier.
(C) The commercial identifying name of the detergent additive product as registered under the requirements of § 79.21 of this chapter.
(ii) A statement attesting that:
(A) The detergent package which is the subject of this certification has been tested according to applicable procedural and test fuel requirements in this subpart and has met the applicable performance standards; and
(B) The testing was conducted in a manner consistent with good engineering practices; and
(C) Complete documentation of the test fuel formulation and IVD demonstration procedures, detergent performance test procedures, and test results are available for EPA's inspection upon request.
(iii) The name and location of the laboratory(ies) at which the certification testing was conducted and the dates during which the testing was conducted.
(iv) For each option under which certification is sought pursuant to § 80.163, specifications of the test fuel(s) in which the detergent underwent performance testing. These fuel specifications must include:
(A) The sulfur content in weight percent.
(B) The T-90 distillation point in degrees Fahrenheit.
(C) The olefin content in volume percent.
(D) The aromatic content in volume percent.
(E) The identity and volume percent of any oxygenate compound.
(F) The source of the test fuel(s) and/or fuel blend stocks used to formulate the test fuel(s).
(v) In the case of a national or PADD certification (pursuant to § 80.163 (a) or
(vi) In the case of a fuel-specific detergent certification, pursuant to § 80.163(c), the definition of the segregated gasoline pool, including any permitted PRC, for which the certification is sought, and the fuel parameter percentile distributions determined for the subject gasoline pool, as specified in § 80.164(c). The percentile distributions must include all of the fuel parameters listed in paragraph (b)(3)(iv) (A) through (D) of this section, along with any other fuel parameter(s) which the certifier wishes to use to define the certification fuel. As specified in § 80.164(c)(1)(iv), the procedures used to measure the additional parameters must be identified, as well as the levels of these additional parameters present in the test fuel(s).
(vii) In the case of a certification for California gasoline based on an existing certification granted by CARB, pursuant to § 80.163(d), a copy of the CARB certificate.
(viii) The test concentration(s) of the subject detergent additive in each test fuel, and the corresponding test results (percent flow restriction demonstrated in the PFID test and milligrams of deposit per valve demonstrated in the IVD test).
(ix) For each option under which certification of the detergent is sought, the minimum recommended concentration which the certifying party seeks to establish for the detergent additive package, pursuant to paragraph (b)(1)(ii) of this section.
(4) EPA will acknowledge receipt of the detergent certification letter. The effective date of certification will be the sooner of 60 days from the date on which EPA receives the certification letter, or the certifier's receipt of EPA's acknowledgement of the certification letter. However, neither the passage of 60 days nor EPA's acknowledgement will signify acceptance by EPA of the validity of the information in the certification letter or the adequacy or potency of the detergent sample submitted pursuant to paragraph (b)(2) of this section. EPA may elect at any time to review the detergent certification data, analyze the submitted detergent additive sample, or subject the detergent additive package to confirmatory testing as described in § 80.167 and, where appropriate, may disqualify a detergent certification according to the provisions in paragraph (e) of this section.
(c) The minimum concentration reported in the detergent registration according to the provisions of paragraph (b)(1)(ii) of this section, plus any restrictions in use associated with that concentration, must be accurately communicated in writing by the additive manufacturer to each fuel manufacturer or detergent blender who purchases the subject detergent for purpose of compliance with the gasoline detergency requirements of this subpart, and to any additive manufacturer who purchases the subject additive with the intent of reselling it to a fuel manufacturer for this purpose.
(d) The rate at which a detergent blender treats gasoline with a detergent additive package must be no less than the minimum recommended concentration reported for the subject detergent additive pursuant to paragraph (b)(1)(ii) of this section, except under the following conditions:
(1) If a detergent blender possesses deposit control performance test results as specified in § 80.165 or § 80.166 which show that the minimum treat rate recommended by the manufacturer of a detergent additive product exceeds the amount of that detergent actually required for effective deposit control, then, upon informing EPA in writing of these circumstances, the detergent blender may use the detergent at the lower concentration substantiated by these test results.
(2) The notification to EPA must clearly specify the name of the detergent product and its manufacturer, the concentration recommended by the detergent manufacturer, and the lower concentration which the detergent blender intends to use. The notification must also attest that the required data are available to substantiate the deposit control effectiveness of the detergent at the intended lower concentration. The notification must be sent by
(3) At its discretion, EPA may require that the detergent blender submit the test data purported to substantiate the claimed effectiveness of the lower concentration of the detergent additive. In addition, EPA may require the manufacturer of the subject detergent additive to submit test data substantiating the minimum recommended concentration specified in the detergent additive registration. In either case, EPA will send a letter to the appropriate party; the supporting data will be due to EPA within 30 days of receipt of EPA's letter.
(i) If the detergent blender fails to submit the required supporting data to EPA in the allotted time period, or if EPA judges the submitted data to be inadequate to support the detergent blender's claim that the lower concentration provides a level of deposit control consistent with the requirements of this section, then EPA will disapprove the use of the detergent at the lower concentration. Further, the detergent blender may be subject to applicable liabilities and penalties pursuant to §§ 80.169 and 80.172 for any gasoline or PRC it has additized at the lower concentration.
(ii) If the detergent manufacturer fails to submit the required test data to EPA within the allotted time period, EPA will proceed on the assumption that data are not available to substantiate the minimum recommended concentration specified in the detergent registration, and the subject additive may be disqualified for use in complying with the requirements of this subpart, pursuant to the procedures in paragraph (e) of this section. The detergent manufacturer may also be subject to applicable liabilities and penalties in §§ 80.169 and 80.172.
(iii) If both parties submit the required information, EPA will evaluate the quality and results of both sets of test data, and will either approve or disapprove the use of the lower treat rate submitted by the detergent blender. EPA will inform both parties of the results of its analysis.
(e)
(2) If EPA determines that the detergent certification was created by fraud or other misconduct, such as a negligent disregard for the truthfulness or accuracy of the required information, the detergent certification will be considered void
(3) The certifier will be afforded 60 days from the date of receipt of the notice of intent of detergent disqualification to submit written comments concerning the notice, and to demonstrate or achieve compliance with the specific requirements which provide the basis for the proposed disqualification. If the certifier does not respond in writing within 60 days from the date of receipt of the notice of intent of disqualification, the detergent disqualification shall become final and the Administrator shall notify the certifier of such final disqualification order. If the certifier responds in writing within 60 days from the date of receipt of the notice of intent to disqualify, the Administrator shall review and consider all comments submitted by the certifier before taking final action concerning the proposed disqualification. All correspondence regarding a disqualification must be sent to the address provided in § 80.174(b).
(4) As part of a written response to a notice of intent to disqualify, a certifier may request an informal hearing concerning the notice. Any such request shall state with specificity the information the certifier wishes to
(5) If a certifier who has received a notice of intent to disqualify submits a timely written response, and the Administrator (or designee) decides after reviewing the response and the transcript of any informal hearing to disqualify the detergent for use in complying with the requirements of this subpart, the Administrator (or designee) shall issue a final disqualification order and forward a copy of the disqualification order to the certifier by certified mail. Notice of the disqualification order will also be published in the
(6) Within 10 days of receipt of EPA's notification of the final decision to disqualify a detergent additive package pursuant to this paragraph (e), the detergent certifier must submit to EPA, at the address specified in § 80.174(b), a list of its customers who use the disqualified detergent. Failure to do so may subject the certifier to liabilities for violations of § 80.168 that result from the use of the uncertified detergent. EPA shall inform the certifier's customers by certified mail that the detergent is no longer eligible for compliance with the requirements of this subpart. These parties must stop using the ineligible detergent additive package and substitute an eligible detergent additive within 45 days of receiving the notification, or within 45 days of publication of the disqualification notice in the
For a detergent additive product to be eligible for use by detergent blenders in complying with the gasoline detergency requirements of this subpart, the compositional data to be supplied to EPA by the additive manufacturer for the purpose of registering a detergent additive package under § 79.21(a) of this chapter must include the items listed in this section. In the case of items requiring measurement or other technical analysis, and for which a specific test procedure is not stipulated herein, the procedure must conform to reasonable and customary standards of repeatability and reproducibility, and reasonable and customary limits of detection and accuracy for the type of test procedure or analytic procedure in question. At EPA's request, detailed documentation of any such test procedure must be submitted within 10 days of the registrant's receipt of EPA's request.
(a) A complete listing of the components of the detergent additive package and the weight and/or volume percent (as applicable) of each component of the package.
(1) When possible, standard chemical nomenclature shall be used or the chemical structure of the component shall be given. Polymeric components may be reported as the product of other chemical reactants, provided that the supporting data specified in paragraph (b) of this section is also reported.
(2) Each detergent-active component of the package shall be classified into one of the following designations:
(i) Polyalkyl amine;
(ii) Polyether amine;
(iii) Polyalkylsuccinimide;
(iv) Polyalkylaminophenol;
(v) Detergent-active petroleum-based carrier oil;
(vi) Detergent-active synthetic carrier oil; and
(vii) Other detergent-active component (identify category, if feasible.)
(3) Composition variability.
(i) The composition of a detergent additive reported in a single additive registration (and the detergent additive product sold under a single additive registration) may not:
(A) Include detergent-active components which differ in identity from those contained in the detergent additive package at the time of certification testing; or
(B) Include a range of concentration for any detergent-active component such that, if the component were present in the detergent additive package at the lower bound of the reported range, the deposit control effectiveness of the additive package would be reduced as compared with the level of effectiveness demonstrated during certification testing.
(ii) The identity or concentration of non-detergent-active components of the detergent additive package may vary under a single registration, provided that the range of such variation is specified in the registration and that such variability does not reduce the deposit control effectiveness of the additive package as compared with the level of effectiveness demonstrated during certification testing.
(iii) Except as provided in paragraph (a)(3)(iv) of this section, detergent additive packages which do not satisfy the restrictions in this paragraph (a)(3) must be separately registered. EPA may disqualify an additive for use in satisfying the requirements of this subpart if EPA determines that the variability included within a given detergent additive registration may reduce the deposit control effectiveness of the detergent package such that it may invalidate the minimum recommended concentration reported in accordance with the applicable requirements of § 80.161(b)(1)(ii).
(iv) A change in minimum concentration requirements resulting from a modification of detergent additive composition shall not require a new detergent additive registration or a change in existing registration if:
(A) The modification is effected by a detergent blender only for its own use or for the use of parties which are subsidiaries of, or share common ownership with, the blender, and the modified detergent is not sold or transferred to other parties; and
(B) The modification is a dilution of the additive for the purpose of ensuring proper detergent flow in cold weather; and
(C) Gasoline is the only diluting agent used; and
(D) The diluted detergent is subsequently added to gasoline at a rate that attains the detergent's registered minimum recommended concentration, taking into account the dilution; and
(E) EPA is notified, either before or within seven days after the dilution action, of the identity of the detergent, the identity of the diluting material, the amount or percentage of the dilution, the change in treat rate necessitated by the dilution, and the locations and time period of diluted detergent usage. The notification shall be sent or faxed to the address in § 80.174(c).
(b) For detergent-active polymers and detergent-active carrier oils which are reported as the product of other chemical reactants:
(1) Identification of the reactant materials and the manufacturer's acceptance criteria for determining that these materials are suitable for use in synthesizing detergent components. The manufacturer must maintain documentation, and submit it to EPA upon request, demonstrating that the acceptance criteria reported to EPA are the same criteria which the manufacturer specifies to the suppliers of the reactant materials.
(2) A Gel Permeation Chromatograph (GPC), providing the molecular weight distribution of the polymer or detergent-active carrier oil components and the concentration of each chromatographic peak representing more than one percent of the total
(c) For non-detergent-active carrier oils, the following parameters:
(1) T10, T50, and T90 distillation points, and end boiling point, measured according to applicable test procedures cited in § 80.46.
(2) API gravity and viscosity
(3) Concentration of oxygen, sulfur, and nitrogen, if greater than or equal to 0.5 percent (by weight) of the carrier oil
(d) Description of an FTIR-based method appropriate for identifying the detergent additive package and its detergent-active components (polymers, carrier oils, and others) both qualitatively and quantitatively, together with the actual infrared spectra of the detergent additive package and each detergent-active component obtained by this test method.
(e) To provide a basis for establishing an affirmative defense to presumptive liability pursuant to § 80.169(c)(4)(i)(D)(
(1) Such parameters shall include (but need not be limited to) viscosity, density, and basic nitrogen content, unless the additive manufacturer specifically requests, and EPA approves, the substitution of other parameter(s) which the manufacturer considers to be more appropriate for a particular additive package. The request must be made in writing and must include an explanation of how the requested physical parameter(s) are helpful as indicator(s) of detergent production quality control. EPA will respond to such requests in writing; the additional parameters are not approved until the certifier receives EPA's written approval.
(2) The manufacturer shall identify a standardized measurement method, consistent with the chemical and physical nature of the detergent product, which will be used to measure each parameter. The documented ASTM repeatability for the method shall also be cited. The manufacturer's target value for each parameter in the detergent package, and the expected range of production values for each parameter, shall be specified.
(3) EPA will consider the parameter measurements to be an acceptable basis for establishing an affirmative defense to presumptive liability, if the expected range of variability differs from the target value by an amount no greater than five times the standard repeatability of the test procedure, or by no more than 10 percent of the target value, whichever is less. However, in the case of nitrogen analysis or other procedures for measuring concentrations of specific chemical compounds or elements, when the target value is less than 10 parts per million, a range of variability up to 50 percent of the target value will be considered acceptable.
(4) If a manufacturer wishes to rely on measurement methods or production variability ranges which do not conform to the above limitations, then the manufacturer must receive prior written approval from EPA in order to be assured that any related parameter measurements will be considered an acceptable basis for establishing an affirmative defense. A request for such allowance must be made in writing. It must fully justify the adequacy of the test procedure, explain why a broader range of variability is required, and provide evidence that the production detergent will perform adequately throughout the requested range of variability.
To be used to satisfy the detergency requirements under § 80.161(a), a detergent additive must be certified in accordance with the requirements of one or more of the options and suboptions
(a)
(1)
(i)
(ii)
(2)
(i)
(ii)
(b)
(1)
(i)
(ii)
(2)
(i)
(ii)
(c)
(1) A detergent certified under this option is eligible to be used at a conforming LAC only in the defined gasoline pool reported in the certification letter pursuant to § 80.161(b)(3).
(i) The gasoline pool may only include gasoline produced or distributed from the facilities covered by the fuel survey which was used to define the fuel-specific certification test fuels, pursuant to § 80.164(c)(1).
(ii) The gasoline pool must be kept segregated from any other gasoline prior to blending with the detergent additive.
(iii) Depending on the oxygenate components added to the test fuel pursuant to § 80.164(a)(2), the gasoline pool may be inclusive of all grades and all oxygenate blending characteristics (i.e., generic), or may be restricted to non-oxygenated gasoline, or to gasoline containing a specific oxygenate compound. The certification may also be restricted to premium grade gasoline. Any such use restrictions must be specified in the certification letter. Provisions in §§ 80.168 and 80.171(a)(9) through
(2) Detergent certification under this option entails special initial and annual reporting requirements, specified under §§ 80.161(b)(3)(vi) and 80.164(c)(3), which necessitate that the responsible party have control over and access to the segregated gasoline pool for which the detergent is certified. For this reason, the certifying party under this option is likely to be (but is not required to be) a fuel manufacturer or detergent blender, rather than the additive manufacturer.
(3) If a certifier demonstrates that the required test fuel representing a segregated pool of gasoline meets the deposit control performance standards specified in § 80.165 in the absence of a detergent additive, or using a detergent additive which has only PFID-control activity, then this gasoline pool (and PFID detergent, if applicable) can be certified accordingly under the fuel-specific option.
(4) Gasoline properly additized with a detergent certified under the fuel-specific option may be transferred or sold anywhere within the United States and its territories (subject to approved State programs).
(d)
(1) A detergent certified under this option may be used at the LAC specified in the CARB certification only in gasoline that meets the requirements of California Phase II reformulated gasoline (pursuant to Title 13, Chapter 5, Article 1, Subarticle 2, California Code of Regulations, Standards for Gasoline Sold Beginning March 1, 1996). The grade(s) of California gasoline which may be so additized, and the oxygenate(s) which may be present, are as specified in the CARB certification for the detergent in question.
(2) The gasoline must be either: Additized in California; or sold or dispensed to the ultimate consumer in California (or to parties who sell or dispense to the ultimate consumer in California); or both additized and ultimately dispensed in California.
(3) A certification under this option will continue to be valid only as long as the CARB certification remains valid. The certifier must cease selling or using a detergent immediately upon being notified by CARB that the CARB certification for this detergent has been invalidated, and must notify EPA within 7 days of receipt of this notification.
(a)
(1) Quantitative specifications for the four basic fuel parameters, provided in paragraphs (b) and (c) of this section, refer to the levels of these parameters in the base gasoline prior to the addition of any oxygenate. The levels of the basic fuel parameters must be measured in accordance with applicable procedures in § 80.46.
(2) Oxygenate components of certification test fuels must be of fuel grade quality. The type and amount of oxygenate to be blended into the test fuel (if any) shall be as follows:
(i) To certify a detergent for generic use (i.e., for use in gasoline containing any oxygenate compound, as well as for use in nonoxygenated gasoline), the finished test fuel shall contain ethanol at 10 volume percent.
(ii) To certify a detergent specifically for use in nonoxygenated gasoline, no oxygenate compounds shall be added to the test fuel.
(iii) To certify a detergent specifically for use in gasoline blended with a specified oxygenate compound other
(3) No detergent-active substance other than the detergent additive package undergoing testing may be added to a certification test fuel. Typical nondetergent additives, such as antioxidants, corrosion inhibitors, and metal deactivators, may be present in the test fuel at the discretion of the additive certifier. In addition, any nondetergent additives (other than oxygenate compounds) which are commonly blended into gasoline and which are known or suspected to affect IVD or PFID formation, or to reduce the ability of the detergent in question to control such deposits, should be added to the test fuel for certification testing.
(4) Certification test requirements may be satisfied for a detergent additive using more than one batch of test fuel, provided that each batch satisfies all applicable test fuel requirements under this section.
(5) Unless otherwise required by this section, finished test fuels must conform to the requirements for commercial gasoline described in ASTM D 4814-95c, “Standard Specification for Automotive Spark-IgnitionEngine Fuel”, which is incorporated by reference. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be inspected at U.S. EPA, OAR, 401 M Street, Southwest, Washington, DC 20460, or at the Office of the Federal Register, 800 North Capitol Street, NW., suite 700, Washington, DC. Copies of this material may be obtained from ASTM, 1916 Race St., Philadelphia, PA 19103.
(b)
(2) National and PADD certification test fuels must either be formulated to specification from normal refinery blend stocks, or drawn from finished gasoline supplies. The source of such samples must be normally-operating gasoline production or distribution facilities located in the U.S. Samples must not be drawn from a segregated gasoline pool that is or will be covered by a fuel-specific certification under § 80.163(c) on the date when the certification information under this option is submitted to EPA.
(3) To be eligible for use in detergent additive certification testing, in addition to the specifications above, national and PADD test fuels which are specially formulated from refinery blend stocks must themselves undergo testing to demonstrate their deposit-forming tendency. For this purpose, the unadditized, nonoxygenated test fuel must be subjected to the IVD control test procedure described in § 80.165(b). At the discretion of the tester, the duration of the demonstration test may be less than 10,000 miles, provided the results satisfy the standard of this paragraph. In order to qualify for use in certification testing, the formulated fuel's test results must meet or exceed the values shown in Table 4 for the relevant certification option. If the demonstration test results do not meet these criteria, then the formulated fuel may not be used for detergent certification testing.
(c)
(i) At least once monthly for at least one complete year prior to the certification, the certifier must measure the levels of the required parameters in representative fuel samples contributed to the segregated gasoline pool by each participating refinery, terminal, or other fuel production or distribution facility. The fuel parameters must be measured in accordance with the test procedures in § 80.46. If the applicability of the fuel-specific certification is to be limited to premium gasoline, then the required fuel compositional data must be collected only from samples of premium gasoline.
(ii) The fuel composition survey results, weighted according to the percentage of gasoline contributed to the segregated gasoline pool from each participating facility, shall be used to construct a percentile distribution of the measured values for each of the fuel parameters.
(iii) Data from more than one year may be used to construct the required statistical distribution provided that
(iv) At the discretion of the certifier, other fuel parameters may be used to define the certification test fuels in addition to the four required parameters. To be taken into account by EPA in case of confirmatory testing pursuant to § 80.167, such additional parameters must be surveyed and analyzed according to the same requirements applicable to the four standard parameters. In addition, any optional parameters must be measured using test procedures which conform to reasonable and customary standards of repeatability and reproducibility, and reasonable and customary limits of detection and accuracy for the type of test procedure or analytic procedure in question.
(v) Using the percentile distributions calculated from the survey data for the four required parameters and any additional discretionary parameters, the 65th percentile value for each such parameter shall be determined. Prior to the addition of any oxygenate compound, the fuel-specific certification test fuel shall contain each specified parameter at a level or concentration no less than this 65th percentile value. Test fuel oxygenate requirements for generic, nonoxygenate, and oxygenate-specific certification suboptions are specified in paragraph (a)(2) of this section.
(2) Fuel-specific certification test fuels must either be formulated to specification from the same refinery blend stocks which are normally used to blend the gasolines included in the subject gasoline pool, or drawn from the finished fuel supplies which contribute to this pool of gasoline. Fuel-specific certification test fuels need not undergo an IVD demonstration test prior to use in certification testing.
(3) The certifier must submit an annual report to EPA within 30 days of the anniversary of the initial certification effective date. Failure to submit the annual report by the required date will invalidate the fuel-specific certification and may subject the certifier to liability and penalties under §§ 80.169 and 80.172. The purpose of the annual report is to update the information on the composition of the segregated gasoline pool that was characterized by the initial fuel survey.
(i) For this purpose, the same fuel survey and statistical analysis requirements that were conducted pursuant to paragraphs (c)(1)(i),(ii), and (iv) of this section must be repeated, using data for the most current twelve-month period from each of the production/distribution facilities that contributed to the original fuel survey.
(ii) The annual report must present the percentile distributions for each fuel parameter as determined from the new survey data and, for each measured fuel parameter, must compare the newly determined 50th percentile value with the 60th percentile value for that parameter as determined in the original fuel survey.
(iii) If the new 50th percentile level for any fuel parameter is greater than or equal to the 60th percentile level reported in the initial certification, then the fuel-specific certification is no longer valid. In such instance, the certifier must immediately discontinue the sale and use of the subject detergent under the conditions of the fuel-specific certification and must immediately notify any downstream customers/recipients of the subject detergent that the certification is no longer valid and that their use of the detergent must discontinue within seven days. To avoid liability and penalties under §§ 80.169 and 80.172, the certifier must take these remedial steps within 45 days of the anniversary of the original fuel-specific certification. Downstream customers/recipients must discontinue usage of the detergent within seven days of receipt of notification of the detergent's invalidity to avoid such liability.
(4) The fuel composition survey results which support the original test fuel specifications and the annual statistical analyses, along with related documentation on test methods and statistical procedures, shall be retained by the certifier for a period of at least five years, and shall be made available to EPA upon request.
This section specifies the deposit control test requirements and performance standards which must be met in order to certify detergent additives for use in unleaded gasoline, pursuant to § 80.161(b)(1)(ii)(A)(
(a)
(2) At the option of the certifier, fuel injector flow may be measured at intervals during the 10,000 mile test cycle described in ASTM D 5598-94, in addition to the flow measurements required at the completion of the test cycle, but not more than every 1,000 miles.
(b)
(c) If conducted using test fuels meeting all relevant requirements of § 80.164, and completed prior to September 3, 1996, then the PFID and IVD control test procedures required for detergent certification in California (specified in section 2257 of Title 13, California Code of Regulations) will also be considered acceptable. California Air Resources Board, “Test Method for Evaluating Port Fuel Injector (PFI) Deposits in Vehicle Engines”, March 1, 1991, and California Air Resources Board, “BMW—10,000 Miles Intake Valve Test Procedure”, March 1, 1991, are incorporated by reference. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be inspected at U.S. EPA, OAR, 401 M Street, Southwest, Washington, DC 20460, or at the Office of the Federal Register, 800 North Capitol Street, NW., suite 700, Washington, DC. Copies of this material may be obtained from the California Air Resource Board, Stationary Source Division, 2020 L Street, PO Box 2815, Sacramento, CA, 95814.
EPA will use the guidelines in this section to evaluate the adequacy of carburetor deposit control test data, used to support the minimum concentration recommended for detergents used in leaded gasoline pursuant to § 80.161(b)(1)(ii)(B).
(a)
(1) “Test Method for Evaluating Port Fuel Injector (PFI) Deposits in Vehicle Engines”, March 1, 1991, Section 2257, Title 13, California Code of Regulations.
(2) “A Vehicle Test Technique for Studying Port Fuel Injector Deposits—A Coordinating Research Council Program”, Robert Tupa et al., SAE Technical paper No. 890213, 1989.
(3) “The Effects of Fuel Composition and Additives on Multiport Fuel Injector Deposits”, Jack Benson et al., SAE Technical Paper Series No. 861533, 1986.
(4) “Injector Deposits—The Tip of Intake System Deposit Problems”, Brian Taneguchi, et al., SAE Technical Paper Series No. 861534, 1986.
(5) “Fuel Injector, Intake Valve, and Carburetor Detergency Performance of Gasoline Additives”, C.H. Jewitt et al., SAE Technical Paper No. 872114, 1987.
(6) “Carburetor Cleanliness Test Procedure, State-of-the-Art Summary, Report: 1973-1981”, Coordinating Research Council, CRC Report No. 529, Coordinating Research Council Inc. (CRC), 219 perimeter Center Parking, Atlanta, Georgia, 30346.
(b)
(2) The test fuel must not contain any detergent-active components other than those recorded in the subject detergent certification.
(3) The composition of the test fuel used in carburetor deposit control testing, conducted to support the claimed effectiveness of detergents used in leaded gasoline, should be reasonably typical of in-use gasoline in its tendency to form carburetor deposits (or more severe than typical in-use fuels) as defined by the olefin and sulfur content. A test fuel conforming to these compositional guidelines may be sampled directly from finished gasolines or may be blended to specification using typical refinery blend stocks. Test data using leaded fuels is preferred for this purpose, but data collected using unleaded fuels may also be acceptable provided that some correlation with additive performance in leaded fuels is available.
EPA may test a detergent to confirm that the required performance levels are met. Based on the findings of this confirmatory testing, a detergent certification may be denied or revoked under the provisions of § 80.161(e).
(a) Confirmatory testing conducted to evaluate the validity of detergent certifications under the national, PADD, or fuel-specific options will generally entail a single vehicle test using the procedures detailed in § 80.165. The test fuel(s) used in conducting confirmatory certification testing will contain the specified fuel parameters at or below the minimum levels specified in § 80.164, and will otherwise conform to the applicable certification test fuel specifications therein.
(b) Confirmatory certification testing conducted to evaluate the validity of CARB-based detergent certifications will use the subject detergent in test fuel(s) containing the relevant fuel parameters at levels no greater than the maximum levels for which the CARB certification was granted. The test procedures will be conducted pursuant to the procedures specified under section 2257 of Title 13, California Code of Regulations.
(c) Confirmatory testing conducted to evaluate the validity of registration and certification information specific to detergent use in leaded gasoline will use the subject detergent in a test fuel
(d) When EPA decides to conduct confirmatory testing on a fuel or additive which is not readily available in the open market, EPA may request that the detergent certifier and/or manufacturer of such fuel or additive furnish a sample in the needed quantity. If testing is conducted to evaluate the validity of a detergent certification under the fuel-specific option, the detergent blender must supply EPA with test fuel, or with blend stocks with which to formulate such test fuel, in sufficient quantity to conduct the specified deposit control performance testing. The fuel or additive manufacturer shall comply with a sample request made pursuant to this paragraph within 30 days of receipt of the request.
(a)(1) No person shall sell, offer for sale, dispense, supply, offer for supply, transport, or cause the transportation of gasoline to the ultimate consumer for use in motor vehicles or in any off-road engines (except as provided in § 80.173), or to a gasoline retailer or wholesale purchaser-consumer, and no person shall detergent-additize gasoline, unless such gasoline is additized in conformity with the requirements of § 80.161. No person shall cause the presence of any gasoline in the gasoline distribution system unless such gasoline is additized in conformity with the requirements of § 80.161.
(2) Gasoline has been additized in conformity with the requirements of § 80.161 when the detergent component satisfies the requirements of § 80.161 and when:
(i) The gasoline has been additized in conformity with the detergent composition and purpose-in-use specifications of a detergent certified in accordance with this subpart, and in accordance with at least the minimum concentration specifications of that detergent as certified or as otherwise provided under § 80.161(d); or
(ii) The gasoline is composed of two or more commingled gasolines and each component gasoline has been additized in conformity with the detergent composition and purpose-in-use specifications of a detergent certified in accordance with this subpart, and in accordance with at least the minimum concentration specifications of that detergent as certified or as otherwise provided under § 80.161(d); or
(iii) The gasoline is composed of a gasoline commingled with a post-refinery component (PRC), and both of these components have been additized in conformity with the detergent composition and use specifications of a detergent certified in accordance with this subpart, and in accordance with at least the minimum concentration specifications of that detergent as certified or as otherwise provided under § 80.161(d).
(b) No person shall blend detergent into gasoline or PRC unless such person complies with the volumetric additive reconciliation requirements of § 80.170.
(c) No person shall sell, offer for sale, dispense, supply, offer for supply, store, transport, or cause the transportation of any gasoline, detergent, or detergent-additized PRC, unless the product transfer document for the gasoline, detergent or detergent-additized PRC complies with the requirements of § 80.171.
(d) No person shall refine, import, manufacture, sell, offer for sale, dispense, supply, offer for supply, store, transport, or cause the transportation of any detergent that is to be used as a component of detergent-additized gasoline or detergent-additized PRC unless such detergent conforms with the composition specifications of a detergent certified in accordance with this subpart and the detergent otherwise complies with the requirements of § 80.161. No person shall cause the presence of any detergent in the detergent, PRC, or gasoline distribution systems unless such detergent complies with the requirements of § 80.161.
(e)(1) No person shall sell, offer for sale, dispense, supply, offer for supply, transport, or cause the transportation
(2) PRC has been additized in conformity with the requirements of § 80.161 when the detergent component satisfies the requirements of § 80.161 and when:
(i) The PRC has been additized in accordance with the detergent composition and use specifications of a detergent certified in accordance with this subpart and in conformity with at least the minimum concentration specifications of that detergent as certified or as otherwise provided under § 80.161(d), or
(ii) The PRC is composed of two or more commingled PRCs, and each component has been additized in accordance with the detergent composition and use specifications of a detergent certified in accordance with this subpart, and in conformity with at least the minimum concentration specifications of that detergent as certified or as otherwise provided under § 80.161(d).
(a)
(i) Each gasoline refiner, importer, carrier, distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate blender, or detergent blender, who owns, leases, operates, controls or supervises the facility (including, but not limited to, a truck or individual storage tank) where the violation is found;
(ii) Each gasoline refiner, importer, distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate blender, detergent manufacturer, distributor, or blender, who refined, imported, manufactured, sold, offered for sale, dispensed, supplied, offered for supply, stored, detergent additized, transported, or caused the transportation of the detergent-additized gasoline (or the base gasoline component, the detergent component, or the detergent-additized post-refinery component of the gasoline) that is in violation, and each such party that caused the gasoline that is in violation to be present in the gasoline distribution system; and
(iii) Each gasoline carrier who dispensed, supplied, stored, or transported any gasoline in the storage tank containing gasoline found to be in violation, and each detergent carrier who dispensed, supplied, stored, or transported the detergent component of any PRC or gasoline in the storage tank containing gasoline found to be in violation, provided that EPA demonstrates, by reasonably specific showings by direct or circumstantial evidence, that the gasoline or detergent carrier caused the violation.
(2)
(i) Each gasoline refiner, importer, carrier, distributor, reseller, retailer, wholesale-purchaser consumer, oxygenate blender, detergent manufacturer, carrier, distributor, or blender, who owns, leases, operates, controls or supervises the facility (including, but not limited to, a truck or individual storage tank) where the violation is found;
(ii) Each gasoline refiner, importer, distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate blender, detergent manufacturer, distributor, or blender, who sold, offered for sale, dispensed, supplied, offered for supply, stored, detergent additized,
(iii) Each carrier who dispensed, supplied, stored, or transported any detergent-additized PRC in the storage tank containing PRC that is in violation, and each detergent carrier who dispensed, supplied, stored, or transported the detergent component of any detergent-additized PRC which is in the storage tank containing detergent-additized PRC found to be in violation, provided that EPA demonstrates by reasonably specific showings by direct or circumstantial evidence, that the gasoline or detergent carrier caused the violation.
(3)
(i) Each gasoline refiner, importer, carrier, distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate blender, detergent manufacturer, carrier, distributor, or blender, who owns, leases, operates, controls or supervises the facility (including, but not limited to, a truck or individual storage tank) where the violation is found;
(ii) Each gasoline refiner, importer, distributor, reseller, retailer, wholesale purchaser-consumer, oxygenate blender, detergent manufacturer, distributor, or blender, who sold, offered for sale, dispensed, supplied, offered for supply, stored, transported, or caused the transportation of the detergent that is in violation, and each such party that caused the detergent that is in violation to be present in the detergent, gasoline, or PRC distribution systems; and
(iii) Each gasoline or detergent carrier who dispensed, supplied, stored, or transported any detergent which is in the storage tank or container containing detergent found to be in violation, provided that EPA demonstrates, by reasonably specific showings by direct or circumstantial evidence, that the gasoline or detergent carrier caused the violation.
(4)
(i) Each detergent blender who owns, leases, operates, controls or supervises the facility (including, but not limited to, a truck or individual storage tank) where the violation has occurred; and
(ii) Each gasoline refiner, importer, carrier, distributor, reseller, retailer, wholesale purchaser-consumer, or oxygenate blender, and each detergent manufacturer, carrier, distributor, or blender, who refined, imported, manufactured, sold, offered for sale, dispensed, supplied, offered for supply, stored, transported, or caused the transportation of the detergent-additized gasoline, the base gasoline component, the detergent component, or the detergent-additized PRC of the gasoline that is in violation, provided that EPA demonstrates, by reasonably specific showings by direct or circumstantial evidence, that such person caused the violation.
(5)
(b)
(c)
(i) That the violation was not caused by the regulated party or its employee or agent (unless otherwise provided in this paragraph (c));
(ii) That product transfer documents account for the gasoline, detergent, or detergent-additized PRC in violation and indicate that the gasoline, detergent, or detergent-additized PRC satisfied relevant requirements when it left the party's control; and
(iii) That the party has fulfilled the requirements of paragraphs (c) (2) or (3) of this section, as applicable.
(2)
(i) An act in violation of law (other than these regulations), or an act of sabotage or vandalism, whether or not such acts are violations of law in the jurisdiction where the violation of the prohibitions of § 80.168 occurred; or
(ii) The action of any gasoline refiner, importer, reseller, distributor, oxygenate blender, detergent manufacturer, distributor, blender, or retailer or wholesale purchaser-consumer supplied by any of these persons, in violation of a contractual undertaking imposed by the refiner designed to prevent such action, and despite the implementation of an oversight program, including, but not limited to, periodic review of product transfer documents by the refiner to ensure compliance with such contractual obligation; or
(iii) The action of any gasoline or detergent carrier, or other gasoline or detergent distributor not subject to a contract with the refiner but engaged by the refiner for transportation of gasoline, PRC, or detergent, to a gasoline or detergent distributor, oxygenate blender, detergent blender, gasoline retailer or wholesale purchaser consumer, despite specification or inspection of procedures or equipment by the refiner which are reasonably calculated to prevent such action.
(iv) In this paragraph (c)(2), to show that the violation “was caused” by any of the specified actions, the party must demonstrate by reasonably specific showings, by direct or circumstantial evidence, that the violation was caused or must have been caused by another.
(3)
(i) That it obtained or supplied, as appropriate, prior to the detergent blending, accurate written instructions from the detergent manufacturer or other party with knowledge of such instructions, specifying the appropriate LAC for the detergent, as specified in § 80.161(b)(1)(ii), together with any use restrictions which pertain to this LAC pursuant to the detergent's certification; and
(ii) That it has implemented a quality assurance program that includes, but is not limited to, a periodic review of its supporting product transfer and volume measurement documents to confirm the correctness of its product transfer and volumetric additive reconciliation documents created for all products it additized.
(4)
(A) Product transfer documents which account for the detergent component of the product in violation and which indicate that such detergent satisfied all relevant requirements when it left the detergent manufacturer's control.
(B) Written blending instructions which, pursuant to § 80.161(c), were supplied by the detergent manufacturer to its customer who purchased or obtained from the manufacturer the detergent component of the product determined to be in violation. The written blending instructions must have been supplied by the manufacturer prior to the customer's use or sale of the detergent. The instructions must accurately specify both the appropriate LAC for the detergent, pursuant to § 80.161(b)(1)(ii), plus any use restrictions which may pertain to this LAC pursuant to the detergent's certification.
(C) If the detergent batch used in the noncomplying product was produced less than one year before the manufacturer was notified by EPA of the possible violation, then the manufacturer must provide FTIR test results for the batch in question.
(
(
(D) If the detergent batch used in the noncomplying product was produced more than one year prior to the manufacturer's notification by EPA of the possible violation, then the manufacturer must provide either:
(
(
(
(
(ii)
(5)
(i) Prior to the violation it had entered into a written contract with another potentially liable detergent blender party (“the assuming party”), under which that other party assumed legal responsibility for fulfilling the
(ii) The contract included reasonable oversight provision to ensure that the assuming party fulfilled its VAR responsibilities (including, but not limited to, periodic review of VAR records) and the oversight provision was actually implemented by the party raising the defense;
(iii) The assuming party is fiscally sound and able to pay its penalty for the VAR violation; and
(iv) The employees or agents of the party raising the defense did not cause the violation.
(6)
(7)
(i) The commingling must occur during a legitimate detergent transitioning event,
(ii) Any use restrictions applicable to the new detergent's certification also apply to the combined detergents; and
(iii) The commingling event must be documented, either on the VAR formula record or on attached supporting records; and
(iv) Notwithstanding any contrary provisions in § 80.170, a VAR formula record must be created for the combined detergents. The VAR compliance period must begin no later than the time of the commingling event. However, at the blender's option, the compliance period may begin earlier, thus including use of the uncombined original detergent within the same period, provided that the 31-day limitation pursuant to § 80.170(a)(6) is not exceeded; and
(v) The VAR formula record must also satisfy the requirements in one of the following paragraphs (c)(7)(v) (A) through (C) of this section, whichever applies to the commingling event. If neither paragraph (c)(7)(v) (A) nor (B) of this section initially applies, then the blender may drain and subsequently redeliver the original detergent into the tank in restricted amounts, in order to meet the conditions of paragraph (c)(7)(v) (A) or (B) of this section. Otherwise, the blender must comply with paragraph (c)(7)(v)(C) of this section.
(A) If both detergents have the same LAC, and the original detergent accounts for no more than 20 percent of the tank's total delivered volume after addition of the new detergent, then the VAR formula record is required to identify only the use of the new detergent.
(B) If the two detergents have different LACs and the original detergent accounts for 10 percent or less of the tank's total delivered volume after addition of the new detergent, then the VAR formula record is required to identify only the use of the new detergent, and must attain the LAC of the new detergent. If the original detergent's LAC is greater than that of the new detergent, then the compliance period may begin earlier than the date of the commingling event (pursuant to paragraph (c)(7)(iv) of this section) only if the original detergent does not exceed 10 percent of the total detergent used during the compliance period.
(C) If neither of the preceding paragraphs (c)(7)(v) (A) or (B) of this section applies, then the VAR formula record must identify both of the commingled detergents, and must use and attain the higher LAC of the two detergents. Once the commingled detergent has been depleted by an amount equal to the volume of the original detergent in the tank at the time the new detergent was added, subsequent VAR formula records must identify and use the LAC of only the new detergent.
(8)
(i) The detergent was received by the detergent blender prior to July 1, 1997 and is used prior to January 1, 1998. Documentation which supports these dates must be maintained for at least five years and must be available for EPA's inspection upon request;
(ii) The detergent is added to gasoline or PRC only in combination with a certified detergent and, at any one time, accounts for no more than 10 percent of the detergent tank's delivered volume;
(iii) The total volume of detergent added to the gasoline or PRC is sufficient to attain the LAC of the certified detergent; and
(iv) Use restrictions associated with the certified detergent are adhered to.
(9)
(i) Additional detergent must be added in sufficient quantity to provide effective deposit control, taking into account both the amount of detergent previously added and the final anticipated volume and composition of the subject fuel product.
(ii) The additional detergent may be either the original detergent or a different detergent, so long as the additional detergent has been separately certified both for use with the subject fuel product and for use with the type of fuel product associated with the restriction which the party wishes to negate by the curing procedure. Detergents which have not been separately certified for both types of fuel products are not eligible to be used for this curing procedure.
(iii) If a fuel product has been detergent additized under the conditions of a use-restricted certification which would preclude the addition of an oxygenate or other PRC, then such oxygenate or other PRC may nevertheless be added to that fuel product under this curing procedure, provided that additional eligible detergent is added, in an amount which equals or exceeds the number of gallons (D
(iv) In other instances in which gasoline or PRC has been additized in violation of a detergent use restriction, and no additional fuel components are to be added, such use restriction can be cured by the addition of eligible detergent in an amount which equals or exceeds the number of gallons (DA) derived from the following equation, which is a simplified version of the previous equation:
(v) In all such instances, a curing VAR must be created and maintained, which documents the use of the appropriate equation as specified above, and otherwise complies with the requirements of § 80.170(f)(6).
This section contains requirements for automated detergent blending facilities and hand-blending detergent facilities. All gasoline and all PRC intended for use in gasoline must be additized unless otherwise noted in supporting VAR records, and must be accounted for in VAR records. The VAR reconciliation standard is attained under this section when the actual concentration of detergent used per VAR formula record equals or exceeds the applicable LAC certified for that detergent pursuant to § 80.161(b)(3)(ix) or, if appropriate, § 80.161(d). If a given detergent package has been certified under more than one certification option pursuant to § 80.163, then a separate VAR formula record must be created for gasoline or PRC additized on the basis of each certification and its respective LAC. In such cases, the amount of the detergent used under different certification options must be accurately and separately measured, either through the use of a separate storage tank, a separate meter, or some other measurement system that is able to accurately distinguish its use. Recorded volumes of gasoline, detergent, and PRC must be expressed to the nearest gallon (or smaller units), except that detergent volumes of five gallons or less must be expressed to the nearest tenth of a gallon (or smaller units). However, if the blender's equipment cannot accurately measure to the nearest tenth of a gallon, then such volumes must be rounded downward to the next lower gallon. PRC included in the reconciliation must be identified. Each VAR formula record must also contain the following information:
(a)
(1) The manufacturer and commercial identifying name of the detergent additive package being reconciled, the LAC, and any use restriction applicable to the LAC. The LAC must be expressed in terms of gallons of detergent per thousand gallons of gasoline or PRC, and expressed to four digits. If the detergent storage system which is the subject of the VAR formula record is a proprietary system under the control of a customer, this fact must be indicated on the record.
(2) The total volume of detergent blended into gasoline and PRC, in accordance with one of the following paragraphs (a)(2)(i) or (ii) of this section, as applicable.
(i) For a facility which uses in-line meters to measure detergent usage, the total volume of detergent measured, together with supporting data which includes one of the following: the beginning and ending meter readings for each meter being measured, the metered batch volume measurements for each meter being measured, or other comparable metered measurements. The supporting data may be supplied on the VAR formula record or in the form of computer printouts or other comparable VAR supporting documentation.
(ii) For a facility which uses a gauge to measure the inventory of the detergent storage tank, the total volume of detergent shall be calculated from the following equation:
(3) The total volume of gasoline plus PRC to which detergent has been added, together with supporting data which includes one of the following: the beginning and ending meter measurements for each meter being measured, the metered batch volume measurements for each meter being measured, or other comparable metered measurements. The supporting data may be supplied on the VAR formula record or in the form of computer printouts or other comparable VAR supporting documentation. If gasoline has intentionally been overadditized in anticipation of the later addition of unadditized PRC, then the total volume of gasoline plus PRC recorded must include the expected amount of unadditized PRC to be added later. In addition, the amount of gasoline which was overadditized for this purpose must be specified.
(4) The actual detergent concentration, calculated as the total volume of detergent added (pursuant to paragraph (a)(2) of this section), divided by the total volume of gasoline plus PRC (pursuant to paragraph (a)(3) of this section). The concentration must be calculated and recorded to four digits.
(5) A list of each detergent concentration rate initially set for the detergent that is the subject of the VAR record, together with the date and description of each adjustment to any initially set concentration. The concentration adjustment information may be supplied on the VAR formula record or in the form of computer printouts or other comparable VAR supporting documentation. No concentration setting is permitted below the applicable certified LAC, except as may be modified pursuant to § 80.161(d) or as described in paragraph (a)(7) of this section.
(6) The dates of the VAR period, which shall be no longer than thirty-one days. If the VAR period is contemporaneous with a calendar month, then specifying the month will fulfill this requirement; if not, then the beginning and ending dates and times of the VAR period must be listed. The times may be supplied on the VAR formula record or in supporting documentation. Any adjustment to any detergent concentration rate more than 10 percent over the concentration rate initially set in the VAR period shall terminate that VAR period and initiate a new VAR period, except as provided in paragraph (a)(7) of this section.
(7) The concentration setting for a detergent injector may be set below the applicable LAC, or it may be adjusted more than 10 percent above the concentration initially set in the VAR period without terminating that VAR period, provided that:
(i) The purpose of the change is to correct a batch misadditization prior to the end of the VAR period and prior to the transfer of the batch to another party, or to correct an equipment malfunction; and
(ii) The concentration is immediately returned after the correction to a concentration that fulfills the requirements of paragraphs (a) (5) and (6) of this section; and
(iii) The blender creates and maintains documentation establishing the date and adjustments of the correction; and
(iv) If the correction is initiated only to rectify an equipment malfunction, and the amount of detergent used in this procedure is not added to gasoline within the compliance period, then this amount is subtracted from the detergent volume listed on the VAR formula record.
(8) If unadditized gasoline has been transferred from the facility, other than bulk transfers from refineries or pipelines to non-retail outlets or non-WPC facilities, the total amount of such gasoline must be specified.
(b)
(1) The manufacturer and commercial identifying name of the detergent additive package being reconciled, the LAC, and any use restriction applicable to the LAC. The LAC must be expressed in terms of gallons of detergent
(2) The date of the additization that is the subject of the VAR formula record.
(3) The volume of added detergent.
(4) The volume of the gasoline and/or PRC to which the detergent has been added. If gasoline has intentionally been overadditized in anticipation of the later addition of unadditized PRC, then the total volume of gasoline plus PRC recorded must include the expected amount of unadditized PRC to be added later. In addition, the amount of gasoline which was overadditized for this purpose must be specified.
(5) The brand (if known), grade, and leaded/unleaded status of gasoline, and/or the type of PRC.
(6) The actual detergent concentration, calculated as the volume of added detergent (pursuant to paragraph (b)(3) of this section), divided by the volume of gasoline and/or PRC (pursuant to paragraph (b)(4) of this section). The concentration must be calculated and recorded to four digits.
(c) Every VAR formula record created pursuant to paragraphs (a) and (b) of this section shall contain the following:
(1) The signature of the creator of the VAR record;
(2) The date of the creation of the VAR record; and
(3) A certification of correctness by the creator of the VAR record.
(d) Electronically-generated VAR formula and supporting records.
(1) Electronically-generated records are acceptable for VAR formula records and supporting documentation (including PTDs), provided that they are complete, accessible, and easily readable. VAR formula records must also be stored with access and audit security, which must restrict to a limited number of specified people those who have the ability to alter or delete the records. In addition, parties maintaining records electronically must make available to EPA the hardware and software necessary to review the records.
(2) Electronically-generated VAR formula records may use an electronic user identification code to satisfy the signature requirements of paragraph (c)(1) of this section, provided that:
(i) The use of the ID is limited to the record creator; and
(ii) A paper record is maintained, which is signed and dated by the VAR formula record creator, acknowledging that the use of that particular user ID on a VAR formula record is equivalent to his/her signature on the document.
(e) Automated detergent blenders must calibrate their detergent equipment once in each calendar half year, with the acceptable calibrations being no less than one hundred twenty days apart. Equipment recalibration is also required each time the detergent package is changed, unless written documentation indicates that the new detergent package has the same viscosity as the previous detergent package. Detergent package change calibrations may be used to satisfy the semiannual requirement provided that the calibrations occur in the appropriate half calendar year and are no less than one hundred twenty days apart.
(f) The following VAR supporting documentation must also be created and maintained:
(1) For all automated detergent blending facilities, documentation reflecting performance of the calibrations required by paragraph (e) of this section, and any associated adjustments of the automated detergent equipment;
(2) For all hand-blending facilities which are terminals, a record specifying, for each VAR period, the total volume in gallons of transfers from the facility of unadditized base gasoline;
(3) For all detergent blending facilities, product transfer documents for all gasoline, detergent and detergent-additized PRC transferred into or out of the facility; in addition, bills of lading, transfer, or sale for all unadditized PRC transferred into the facility;
(4) For all automated detergent blending facilities, documentation establishing the brands (if known) and grades of the gasoline which is the subject of the VAR formula record; and
(5) For all hand blending detergent blenders, the documentation, if in the party's possession, supporting the volumes of gasoline, PRC, and detergent reported on the VAR formula record.
(6) For all detergent blending facilities, documentation establishing the curing of a batch or amount of misadditized gasoline or PRC, or the curing of a use restriction on the additized gasoline or PRC, and providing at least the following information: the date of the curing procedure; the problem that was corrected; the amount, name, and LAC of the original detergent used; the amount, name, and LAC of the added curing detergent; and the actual detergent concentration attained in, and the volume of, the total cured product.
(g) Document retention and availability. All detergent blenders shall retain the documents required under this section for a period of five years from the date the VAR formula records and supporting documentation are created, and shall deliver them upon request to the EPA Administrator or the Administrator's authorized representative.
(1) Except as provided in paragraph (g)(3) of this section, automated detergent blender facilities and hand-blender facilities which are terminals, which physically blend detergent into gasoline, must make immediately available to EPA, upon request, the preceding twelve months of VAR formula records plus the preceding two months of VAR supporting documentation.
(2) Except as provided in paragraph (g)(3) of this section, other hand-blending detergent facilities which physically blend detergent into gasoline must make immediately available to EPA, upon request, the preceding two months of VAR formula records and VAR supporting documentation.
(3) Facilities which have centrally maintained records at other locations, or have customers who maintain their own records at other locations for their proprietary detergent systems, and which can document this fact to the Agency, may have until the start of the next business day after the EPA request to supply VAR supporting documentation, or longer if approved by the Agency.
(4) In this paragraph (g) of this section, the term
(a)
(1) The name and address of the transferee and transferor; the address requirement may be fulfilled, in the alternative, through separate documentation which establishes said addresses and is maintained by the parties and made available to EPA for the same length of time as required for the PTDs, provided that the normal business procedure of these parties is not to identify addresses on PTDs.
(2) The date of the transfer.
(3) The volume of product transferred.
(4)(i) The identity of the product being transferred (
(ii) If the product being transferred consists of two or more different types of product subject to this regulation,
(5) If the product being transferred is base gasoline, then in addition to the
(6) The name of the detergent additive as reported in its registration must be used to identify the detergent package on its PTD.
(7) If the product being transferred is leaded gasoline, then the PTD must disclose that the product contains lead and/or phosphorous, as applicable.
(8) If the product being transferred is gasoline or PRC that has been additized with detergent under a PADD-specific or CARB-based certification, or under a certification option which creates an oxygenate or PRC use restriction, then the PTD for the additized product must identify the applicable use restriction. The PTD for commingled additized gasolines or PRCs containing such restrictions must indicate the applicable restriction(s) from each component.
(9) If the product being transferred is detergent-additized gasoline or PRC that has been overadditized in anticipation of the later (or earlier) addition of PRC, then the PTD must include a statement that the product has been overadditized to account for a specified volume in gallons, or a specified percentage of the product's total volume, of additional, specified PRC.
(10) If a detergent package has been certified under only one certification option, and that option places a use restriction on the respective LAC, then the PTD must identify the detergent as use-restricted; the PTD for a detergent package certified with more than one LAC must identify that the detergent has special use options available.
(11) Base gasoline designated for fuel-specific certification.
(i) The PTD for segregated base gasoline intended for additization with a specific fuel-specific detergent pursuant to § 80.163(c) must indicate that it is for use with the designated, fuel-specific detergent.
(ii) A PTD for base gasoline may not indicate that the product is for use with a designated, fuel-specific detergent, unless the entire quantity of base gasoline is from the segregated fuel supply specified in the detergent's certification and the gasoline contains only those oxygenates or PRCs, if any, specified and approved in the detergent's certification.
(iii) If, pursuant to § 80.163(c)(3), the fuel-specific certification for the segregated pool of gasoline has established that no detergent additives are necessary for such gasoline to comply with this subpart, then the PTD must identify this gasoline as detergent-equivalent gasoline.
(b)
(i) The specified warning language may be omitted for bulk transfers of base gasoline from a refinery to a pipeline if there is a prior written agreement between the parties specifying that all such gasoline is unadditized and will not be transferred to the ultimate consumer;
(ii) Product codes may be used as a substitute for the specified warning language provided that the PTD is an electronic data interchange (EDI) document being used solely for the transfer of title to the base gasoline, and provided that the product codes otherwise comply with the requirements of this section.
(2) Product codes and other non-regulatory language may not be used in place of the PTD language specified in paragraph (a)(11) of this section regarding detergent package use restrictions.
(3) Product codes and other language not specified in this section may otherwise be used to comply with PTD information requirements, provided that they are clear, accurate, and not misleading.
(4) If product codes are used, they must be standardized throughout the distribution system in which they are used, and downstream parties must be informed of their full meaning.
(c)
(1) The product is being transferred by a distributor who is not the product's detergent blender; and
(2) The recipient is a wholesale purchaser-consumer (WPC) or other ultimate consumer of gasoline, for its own use only or for that of its agents or employees; and
(3) The volume of additized gasoline being transferred is no greater than 550 gallons.
(d)
(a)
(b)
(c)
(d)
(e)
(1) The day that the document is corrected and comes into compliance; or
(2) The day that gasoline not additized in conformity with detergent certification program requirements, as a result of the PTD non-conformity, is offered for sale or is dispensed to the ultimate consumer.
(f)
(g)
(h)
(a)
(1) The detergent (or fuel containing the detergent), or the gasoline, is kept segregated from non-exempt product, and the party possessing the product maintains documentation identifying the product as research, development, or testing detergent or fuel, as applicable, and stating that it is to be used only for research, development, or testing purposes; and
(2) The detergent (or fuel containing the detergent), or the gasoline, is not sold, dispensed, or transferred, or offered for sale, dispensing, or transfer, from a retail outlet. It shall also not be sold, dispensed, or transferred or offered for sale, dispensing, or transfer from a wholesale purchaser-consumer facility, unless such facility is associated with detergent, fuel, automotive, or engine research, development or testing; and
(3) The party using the product for research, development, or testing purposes, or the party sponsoring this usage, notifies the EPA, on at least an annual basis and prior to the use of the product, of the purpose(s) of the program(s) in which the product will be used and the anticipated volume of the product to be used. The information must be submitted to the address or fax number specified in § 80.174(c).
(b)
(1) The fuel is kept segregated from non-exempt fuel, and the party possessing the fuel for the purposes of refining, selling, dispensing, transferring, or offering for sale, dispensing, or transfer as automotive racing fuel or as aircraft engine fuel, maintains documentation identifying the product as racing fuel, restricted for non-highway use in racing motor vehicles, or as aviation fuel, restricted for use in aircraft, as applicable;
(2) Each pump stand at a regulated party's facility, from which such fuel is dispensed, is labeled with the applicable fuel identification and use restrictions described in paragraph (b)(1) of this section; and
(3) The fuel is not sold, dispensed, transferred, or offered for sale, dispensing, or transfer for highway use in a motor vehicle.
(c)
(i) For all such gasoline or PRC, whether intended for sale within or outside of California, records of the type required for California gasoline (specified in title 13, California Code of Regulations, section 2257) are maintained; and
(ii) Such records, with the exception of daily additization records, are maintained for a period of five years from the date they were created and are delivered to EPA upon request.
(2) Gasoline or PRC that is transferred and/or sold solely within the State of California is exempt from the PTD provisions of the detergent certification program, specified in §§ 80.168(c) and 80.171.
(3) Nothing in this paragraph (c) exempts such gasoline or PRC from the requirements of § 80.168 (a) and (e), as applicable. EPA will base its determination of California gasoline's conformity with the detergent's LAC on the additization records required by CARB, or records of the same type.
(a) The detergent additive sample required under § 80.161(b)(2) shall be sent to: Manager, Fuels and Technical Analysis Group, Testing Services Division, U.S. Environmental Protection Agency, National Vehicle and Fuel Emissions Laboratory, 2565 Plymouth Road, Ann Arbor, Michigan 48105.
(b) Other detergent registration and certification data, and certain other information which may be specified in this subpart, shall be sent to: Detergent Additive Certification, Director, Fuels and Energy Division, U.S. Environmental Protection Agency (6406J), 401 M Street, SW., Washington, DC 20460.
(c) Notifications to EPA regarding program exemptions, detergent dilution and commingling, and certain other information which may be specified in this subpart, shall be sent to: Detergent Enforcement Program, U.S. Environmental Protection Agency, Suite 214, 12345 West Alameda Parkway, Denver, CO 80228, (FAX 303-969-6490).
1.1 This method was developed for the determination of phosphorus generally present as pentavalent phosphate esters or salts, or both, in gasoline. This method is applicable for the determination of phosphorus in the range from 0.0008 to 0.15 g P/U.S. gal, or 0.2 to 49 mg P/liter.
2.1 ASTM Standards:
D 1100 Specification for Filter Paper for Use in Chemical Analysis.
3.1 Organic matter in the sample is decomposed by ignition in the presence of zinc oxide. The residue is dissolved in sulfuric acid and reacted with ammonium molybdate and hydrazine sulfate. The absorbance of the “Molybdenum Blue” complex is proportional to the phosphorus concentration in the sample and is read at approximately 820 nm in a 5-cm cell.
4.1 Buret, 10-ml capacity, 0.05-ml subdivisions.
4.2 Constant-Temperature Bath, equipped to hold several 100-ml volumetric flasks submerged to the mark. Bath must have a large enough reservoir or heat capacity to keep the temperature at 180 to 190 °F (82.2 to 87.8 °C) during the entire period of sample heating.
If the temperature of the hot water bath drops below 180 °F (82.2 °C) the color development may not be complete.
4.3 Cooling Bath, equipped to hold several 100-ml volumetric flasks submerged to the mark in ice water.
4.4 Filter Paper, for quantitative analysis, Class G for fine precipitates as defined in Specification D 1100.
4.5 Ignition Dish—Coors porcelain evaporating dish, glazed inside and outside, with pourout (size no. 00A, diameter 75 mm. capacity 70 ml).
4.6 Spectrophotometer, equipped with a tungsten lamp, a red-sensitive phototube capable of operating at 830 nm and with absorption cells that have a 5-cm light path.
4.7 Thermometer, range 50 to 220 °F (10 to 105 °C).
4.8 Volumetric Flask, 100-ml with ground-glass stopper.
4.9 Volumetric Flask, 1000-ml with ground-glass stopper.
4.10 Syringe, Luer-Lok, 10-ml equipped with 5-cm. 22-gage needle.
5.1 Purity of Reagents—Reagent grade chemicals shall be used in all tests. Unless otherwise indicated, it is intended that all reagents shall conform to the specifications of the Committee on Analytical Reagents of the American Chemical Society, where such specifications are available. Other grades may be used, provided it is first ascertained that the reagent is of sufficiently high purity to permit its use without lessening the accuracy of the determination.
5.2 Purity of Water—Unless otherwise indicated, references to water shall be understood to mean distilled water or water of equal purity.
5.3 Ammonium Molybdate Solution—Using graduated cylinders for measurement add slowly (Note 2), with continuous stirring, 225 ml of concentrated sulfuric acid to 500 ml of water contained in a beaker placed in a bath of cold water. Cool to room temperature and add 20 g of ammonium molybdate tetrahydrate ((NH
Wear a face shield, rubber gloves, and a rubber apron when adding concentrated sulfuric acid to water.
5.4 Hydrazine Sulfate Solution—Dissolve 1.5 of hydrazine sulfate (H
This solution is not stable. Keep it tightly stoppered and in the dark. Prepare a fresh solution after 3 weeks.
5.5 Molybdate-Hydrazine Reagent—Pipet 25 ml of ammonium molybdate solution into a 100-ml volumetric flask containing approximately 50 ml of water, add by pipet 10 ml of N
This reagent is unstable and should be used within about 4 h. Prepare it immediately before use. Each determination (including the blank) uses 50 ml.
5.6 Phosphorus, Standard Solution (10.0
5.7 Phosphorus, Stock Standard Solution (1.00 mg P/ml)—Dry approximately 5 g of potasium dihydrogen phosphate (KH
5.8 Sulfuric Acid (1+10)—Using graduated cylinders for measurement add slowly (Note 2), with continuous stirring, 100-ml of concentrated sulfuric acid (H
5.9 Zinc Oxide.
High-bulk density zinc oxide may cause spattering. Density of approximately 0.5 g/cm
6.1 Transfer by buret, or a volumetric transfer pipet, 0.0, 0.5, 1.0, 1.5, 2.0, 3.0, 3.5, and 4.0 ml of phosphorus standard solution into 100-ml volumetric flasks.
6.2 Pipet 10 ml of H
6.3 Prepare the molybdate-hydrazine solution. Prepare sufficient volume of reagent based on the number of samples being analyzed.
6.4 Pipet 50 ml of the molybdate-hydrazine solution to each volumetric flask. Mix immediately by swirling.
6.5 Dilute to 100 ml with water.
6.6 Mix well and place in the constant-temperature bath so that the contents of the flask are submerged below the level of the bath. Maintain bath temperature at 180 to 190 °F (82.2 to 87.8 °C) for 25 min (Note 1).
6.7 Transfer the flask to the cooling bath and cool the contents rapidly to room temperature. Do not allow the samples to cool more than 5 °F (2.8 °C) below room temperature.
Place a chemically clean thermometer in one of the flasks to check the temperature.
6.8 After cooling the flasks to room temperature, remove them from the cooling water bath and allow them to stand for 10 min. at room temperature.
6.9 Using the 2.0-ml phosphorus standard in a 5-cm cell, determine the wavelength near 820 nm that gives maximum absorbance. The wavelength giving maximum absorbance should not exceed 830 nm.
6.9.1 Using a red-sensitive phototube and 5-cm cells, adjust the spectrophotometer to zero absorbance at the wavelength of maximum absorbance using distilled water in both cells. Use the wavelength of maximum absorbance in the determination of calibration readings and future sample readings.
6.9.2 The use of 1-cm cells for the higher concentrations is permissible.
6.10 Measure the absorbance of each calibration sample including the blank (0.0 ml phosphorus standard) at the wavelength of maximum absorbance with distilled water in the reference cell.
Great care must be taken to avoid possible contamination. If the absorbance of the blank exceeds 0.04 (for 5-cm cell), check for source of contamination. It is suggested that the results be disregarded and the test be rerun with fresh reagents and clean glassware.
6.11 Correct the absorbance of each standard solution by subtracting the absorbance of the blank (0 ml phosphorus standard).
6.12 Prepare a calibration curve by plotting the corrected absorbance of each standard solution against micrograms of phosphorus. One millilitre of phosphorus standard solution provides 10
7.1 Selection of the size of the sample to be tested depends on the expected concentration of phosphorous in the sample. If a concentration of phosphorus is suspected to be less than 0.0038 g/gal (1.0 mg/litre), it will be necessary to use 10 ml of sample.
Two grams of zinc oxide cannot absorb this volume of gasoline. Therefore the 10-ml sample is ignited in aliquots of 2 ml in the presence of 2 g of zinc oxide.
7.2 The following table serves as a guide for selecting sample size:
8.1 Transfer 2
In order to obtain satisfactory accuracy with the small amounts of phosphorus involved, it is necessary to take extensive precautions in handling. The usual precautions of cleanliness, careful manipulation, and avoidance of contamination should be scrupulously observed; also, all glassware should be cleaned before use, with cleaning acid or by some procedure that does not involve use of commercial detergents. These compounds often contain alkali phosphates which are strongly adsorbed by glass surfaces and are not removed by ordinary rinsing. It is desirable to segregate a special stock of glassware for use only in the determination of phosphorus.
8.2 Make a deep depression in the center of the zinc oxide pile with a stirring rod.
8.3 Pipet the gasoline sample (Note 10) (see 7.2 for suggested sample volume) into the depression in the zinc oxide. Record the temperature of the fuel if the phosphorus content is required at 60 °F (15.6 °C) and make correction as directed in 9.2.
For the 10-ml sample use multiple additions and a syringe. Hold the tip of the needle at approximately
8.4 Cover the sample with a small amount of fresh zinc oxide from reagent bottle (use the tip of a small spatula to deliver approximately 0.2 g). Tap the sides of the ignition dish to pack the zinc oxide.
8.5 Prepare the blank, using the same amount of zinc oxide in an ignition dish.
8.6 Ignite the gasoline, using the flame from a bunsen burner. Allow the gasoline to burn to extinction (
8.7 Place the ignition dishes containing the sample and blank in a hot muffle furnace set at a temperature of 1150 to 1300 °F (621 to 704 °C) for 10 min. Remove and cool the ignition dishes. When cool gently tap the sides of the dish to loosen the zinc oxide. Again place the dishes in the muffle furnace for 5 min. Remove and cool the ignition dishes to room temperature. The above treatment is usually sufficient to burn the carbon. If the carbon is not completely burned off place the dish into the oven for further 5-min. periods.
Step 8.7 may also be accomplished by heating the ignition dish with a Meker burner gradually increasing the intensity of heat until the carbon from the sides of the dish has been burned, then cool to room temperature.
8.8 Pipet 25 ml of H
8.9 Cover the ignition dish with a borosilicate watch glass and warm the ignition dish on a hot plate until the zinc oxide is completely dissolved.
8.10 Transfer the solution through filter paper to a 100-ml volumetric flask. Rinse the watch glass and the dish several times with distilled water (do not exceed 25 ml) and transfer the washings through the filter paper to the volumetric flask.
8.11 Prepare the molybdate-hydrazine solution.
8.12 Add 50 ml of the molybdate-hydrazine solution by pipet to each 100-ml volumetric flask. Mix immediately by swirling.
8.13 Dilute to 100 ml with water and mix well. Remove stoppers from flasks after mixing.
8.14 Place the 100-ml flasks in the constant-temperature bath for 25 min. so that the contents of the flasks are below the liquid level of the bath. The temperature of the bath should be 180 to 190 °F (82.2 to 87.8 °C) (
8.15 Transfer the 100-ml flasks to the cooling bath and cool the contents rapidly to room temperature (
8.16 Allow the samples to stand at room temperature before measuring the absorbance.
The color developed is stable for at least 4 h.
8.17 Set the spectrophotometer to the wavelength of maximum absorbance as determined in 6.9. Adjust the spectrophotometer to zero absorbance, using distilled water in both cells.
8.18 Measure the absorbance of the samples at the wavelength of maximum absorbance with distilled water in the reference cell.
8.19 Subtract the absorbance of the blank from the absorbance of each sample (
8.20 Determine the micrograms of phosphorous in the sample, using the calibration curve from 6.12 and the corrected absorbance.
9.1 Calculate the milligrams of phosphorus per litre of sample as follows:
9.2 If the gasoline sample was taken at a temperature other than 60 °F (15.6 °C) make the following temperature correction:
9.3 Concentrations below 2.5 mg/litre or 0.01 g/gal should be reported to the nearest 0.01 mg/litre or 0.0001 g/U.S. gal.
9.3.1 For higher concentrations, report results to the nearest 1 mg P/litre or 0.005 g P/U.S. gal.
10.1 The following criteria should be used for judging the acceptability of results (95 percent confidence):
10.2 Repeatability—Duplicate results by the same operator should be considered suspect if they differ by more than the following amounts:
10.3 Reproducibility—The results submitted by each of two laboratories should not be considered suspect unless they differ by more than the following amounts:
1.1. This method covers the determination of the total lead content of gasoline. The procedure's calibration range is 0.010 to 0.10 gram of lead/U.S. gal. Samples above this level should be diluted to fall within this range or a higher level calibration standard curve must be prepared. The higher level curve must be shown to be linear and measurement of lead at these levels must be shown to be accurate by the analysis of control samples at a higher level of alkyl lead content. The method compensates for variations in gasoline composition and is independent of lead alkyl type.
2.1 The gasoline sample is diluted with methyl isobutyl ketone and the alkyl lead compounds are stabilized by reaction with iodine and a quarternary ammonium salt. The lead content of the sample is determined by atomic absorption flame spectrometry at 2833 A, using standards prepared from reagent grade lead chloride. By the use of this treatment, all alkyl lead compounds give identical response.
3.1 Atomic Absorption Spectometer, capable of scale expansion and nebulizer adjustment, and equipped with a slot burner and premix chamber for use with an air-acetylene flame.
3.2 Volumetric Flasks, 50-ml, 100-ml, 250-ml, and one litre sizes.
3.3 Pipets, 2-ml, 5-ml, 10-ml, 20-ml, and 50-ml sizes.
3.4 Micropipet, 100-
4.1 Purity of Reagents—Reagent grade chemicals shall be used in all tests. Unless otherwise indicated, it is intended that all reagents shall conform to the specifications of the Committee on Analytical Reagents of the American Chemical Society, where such specifications are available. Other grades may be used, provided it is first ascertained that the reagent is of sufficiently high purity to permit its use without lessening the accuracy of the determination.
4.2 Purity of Water—Unless otherwise indicated, references to water shall be understood to mean distilled water or water of equal purity.
4.3 Aliquat 336 (tricapryl methyl ammonium chloride).
4.4 Aliquat 336/MIBK Solution (10 percent v/v)—Dissolve and dilute 100 ml (88.0 g) of Aliquat 336 with MIBK to one liter.
4.5 Aliquat 336/MIBK Solution (1 percent v/v)—Dissolve and dilute 10 ml (8.8 g) of Aliquat 336 with MIBK to one liter.
4.6 Iodine Solution—Dissolve and dilute 3.0 g iodine crystals with Toluene to 100 ml.
4.7 Lead Chloride.
4.8 Lead-Sterile Gasoline—Gasoline containing less than 0.005 g Pb/gal.
4.9 Lead, Standard Solution (5.0 g Pb/gal)—Dissolve 0.4433 g of lead chloride (PbCl
4.10 Lead, Standard Solution (1.0 g Pb/gal)—By means of a pipet, accurately transfer 50.0 ml of the 5.0 g Pb/gal solution to a 250-ml volumetric flask, dilute to volume with 1 percent Aliquat/MIBK solution. Store in a brown bottle having a polyethylene-lined cap.
4.11 Lead, Standard Solutions (0.02, 0.05, and 0.10 g Pb/gal)—Transfer accurately by means of pipets 2.0, 5.0, and 10.0 ml of the 1.0-g Pb/gal solution to 100-ml volumetric flasks; add 5.0 ml of 1 percent Aliquat 336 solution to each flask; dilute to the mark with MIBK. Mix well and store in bottles having polyethylene-lined caps.
4.12 Methyl Isobutyl Ketone (MIBK). (4-methyl-2-pentanone).
5.1 Preparation of Working Standards—Prepare three working standards and a blank using the 0.02, 0.05, and 0.10-g Pb/gal standard lead solutions described in 4.11.
5.1.1 To each of four 50-ml volumetric flasks containing 30 ml of MIBK, add 5.0 ml of low lead standard solution and 5.0 ml of lead-free gasoline. In the case of the blank, add only 5.0 ml of lead-free gasoline.
5.1.2 Add immediately 0.1 ml of iodine/toluene solution by means of the 100-
5.1.3 Add 5 ml of 1 percent Aliquat 336 solution and mix.
5.1.4 Dilute to volume with MIBK and mix well.
5.2 Preparation of Instrument—Optimize the atomic absorption equipment for lead at 2833 A. Using the reagent blank, adjust the gas mixture and the sample aspiration rate to obtain an oxidizing flame.
5.2.1 Aspirate the 0.1-g Pb/gal working standard and adjust the burner position to give maximum response. Some instruments require the use of scale expansion to produce a reading of 0.150 to 0.170 for this standard.
5.2.2 Aspirate the reagent blank to zero the instrument and check the absorbances of the three working standards for linearity.
6.1 To a 50 ml volumetric flask containing 30 ml MIBK, add 5.0 ml of gasoline sample and mix.
6.1.1 Add 0.10 ml (100 μl) of iodine/toluene solution and allow the mixture to react about 1 minute.
6.1.2 Add 5.0 ml of 1 percent Aliquot 336/MIBK solution and mix.
6.1.3 Dilute to volume with MIBK and mix.
6.2 Aspirate the samples and working standards and record the absorbance values with frequent checks of the zero.
6.3Any sample resulting in a peak greater than 0.05 g Pb/gal will be run in duplicate. Samples registering greater than 0.10 g Pb/gal should be diluted with iso-octane or unleaded fuel to fall within the calibration range or a higher level calibration standard curve must be prepared. The higher level curve must be shown to be linear and measurement of lead at these levels must be shown to be accurate by the analysis of control samples at a higher level of alkyl lead content.
7.1 Plot the absorbance values versus concentration represented by the working standards and read the concentrations of the samples from the graph.
8.1 The following criteria should be used for judging the acceptability of results (95 percent confidence):
8.1.1 Repeatability—Duplicate results by the same operator should be considered suspect if they differ by more than 0.005 g/gal.
8.1.2 Reproductibility—The results submitted by each of two laboratories should not be considered suspect unless the two results differ by more than 0.01 g/gal.
1.1This method covers the determination of the total lead content of gasoline. The procedure's calibration range is 0.010 to 0.10 gram of lead/U.S. gal. Samples above this level should be diluted to fall within this range or a higher level calibration standard curve must be prepared. The higher level curve must be shown to be linear and measurement of lead at these levels must be shown to be accurate by the analysis of control samples at a higher level of alkyl lead content. The method compensates for variations in gasoline composition and is independent of lead alkyl type.
1.2This method may be used as an alternative to the Standard Method set forth above.
1.3Where trade names or specific products are noted in the method, equivalent apparatus and chemical reagents may be used. Mention of trade names or specific products is for the assistance of the user and does not constitute endorsement by the U.S. Environmental Protection -Agency.
2.1The gasoline sample is diluted with methly isobutyl ketone (MIBK) and the alkyl lead compounds are stabilized by reacting with iodine and a quarternary ammonium salt. An automated system is used to perform the diluting and the chemical reactions and feed the products to the atomic absorption spectrometer with an air-acetylene flame.
2.2The dilution of the gasoline with MIBK compensates for severe non-atomic absorption, scatter from unburned carbon containing species and matrix effects caused in part by the burning characteristics of gasoline.
2.3The
2.4The addition of the quarternary ammonium salt improves response and increases the stability of the alkyl iodide complex.
3.1Samples should be collected and stored in containers which will protect them from changes in the lead content of the gasoline such as from loss of volatile fractions of the gasoline by evaporation or leaching of the lead into the container or cap.
3.2If samples have been refrigerated they should be brought to room temperature prior to analysis.
4.1AutoAnalyzer system consisting of:
4.1.1Sampler 20/hr cam, 30/hr cam.
4.1.2Proportioning pump.
4.1.3Lead in gas manifold.
4.1.4Disposable test tubes.
4.1.5Two 2-liter and one 0.5 liter Erlenmeyer solvent displacement flasks. Alternatively, high pressure liquid chromatography (HPLC) or syringe pumps may be used.
4.2Atomic Absorption Spectroscopy (AAS) Detector System consisting of:
4.2.1Atomic absorption spectrometer.
4.2.210′′ strip chart recorder.
4.2.3Lead hollow cathode lamp or electrodeless discharge lamp (EDL).
5.1Aliquat 336/MIBK solution (10% v/v): Dissolve and dilute 100 ml (88.0 g) of Aliquat 336 (Aldrich Chemical Co., Milwaukee, Wisconsin) with MIBK (Burdick & Jackson Lab., Inc., Muskegon, Michigan) to one liter.
5.2Aliquat 336/iso-octane solution (1% v/v): Dissolve and dilute 10 ml (8.8 g) of Alquat 336 (reagent 5.1) with iso-octane to one liter.
5.3Iodine solution (3% w/v): Dissolve and dilute 3.0 g iodine crystals (American Chemical Society) with toluene (Burdick & Jackson Lab., Inc., Muskegon, Michigan) to 100 ml.
5.4Iodine working solution (0.24% w/v): Dilute 8 ml of reagent 5.3 to 100 ml with toluene.
5.5Methyl isobutyl ketone (MIBK) (4-methlyl-2-pentanone).
5.6Certified unleaded gasoline (Phillips Chemical Co., Borger, Texas) or iso-octane (Burdick & Jackson Lab, Inc., Muskegon, Michigan).
6.1Stock 5.0 g Pb/gal Standard:
Dissolve 0.4433 gram of lead chloride (PbCl
6.2Intermediate 1.0 g Pb/gal Standard:
Pipet 50 ml of the 5.0 g Pb/gal standard into a 250 ml volumetric flask and dilute to volume with a 1% v/v Aliquat 336/iso-octane solution (reagent 5.2). Store in an amber bottle.
6.3Working 0.02, 0.05, 0.10 g Pb/gal Standards:
Pipet 2.0, 5.0, and 10.0 ml of the 1.0 g Pb/gal solution to 100 ml volumetric flasks. Add 5 ml of a 1% Aliquat 336/iso-octane solution to each flask. Dilute to volume with iso-octane. These solutions contain 0.02, 0.05, and 0.10 g Pb/gal in a 0.05% Aliquat 336/iso-octane solution.
7.1Lead hollow cathode lamp.
7.2Wavelength: 283.3 nm.
7.3Slit: 4 (0.7mm).
7.4Range: UV.
7.5Fuel: Acetylene (approx. 20 ml/min at 8 psi).
7.6Oxidant: Air (approx. 65 ml/min at 31 psi).
7.7Nebulizer: 5.2 ml/min.
7.8Chart speed: 10 in/hr.
8.1AAS start-up.
8.1.1Assure that instrumental conditions have been optimized and aligned according to Section 7 and the instrument has had substantial time for warm-up.
8.2Auto Analyzer start-up [see figure 1].
8.2.1Check all pump tubing and replace as necessary. Iodine tubing should be changed
8.2.2Withdraw any water from the sample wash cup and fill with certified unleaded gasoline (reagent 5.6).
8.2.3Fill the 2-liter MIBK dilution displacement Erlenmeyer flask (reagent 5.5) and the 0.5 liter Aliquat 336/MIBK 1% v/v (reagent 5.2) displacement flask and place the rubber stopper glass tubing assemblies in their respective flasks.
8.2.4Fill a 2-liter Erlenmeyer flask with distilled water. The water will be used to displace the solvents. Therefore, place the appropriate lines in this flask. This procedure is not relevant if syringe pumps are used.
8.2.5Fill the final debubbler reverse displacement 2-liter Erlenmeyer flask with distilled water and place the rubber stopper glass tubing assembly in the flask.
8.2.6Place the appropriate lines for the iodine reagent (reagent 5.4) and the wash solution (reagent 5.6) in their respective bottles.
8.2.7Start the pump and connect the aspiration line from the manifold to the AAS.
8.2.8Some initial checks to assure that the reagents are being added are:
a. A good uniform bubble pattern.
b. Yellow color evident due to iodine in the system.
c. No surging in any tubing.
8.3Calibration.
8.3.1Turn the chart drive on and obtain a steady baseline.
8.3.2Load standards and samples into sample tray.
8.3.3Start the sampler and run the standards (Note: first check the sample probe positioning with an empty test tube).
8.3.4Check the linearity of calibration standards response and slope by running a least squares fit. Check these results against previously obtained results. They should agree within 10%.
8.3.5If the above is in control then start the sample analysis.
8.4Sample Analysis.
8.4.1To minimize gasoline vapor in the laboratory, load the sample tray about 5-10 test tubes ahead of the sampler.
8.4.2Record the sample number on the strip chart corresponding to the appropriate peak.
8.4.3Every ten samples run the high calibration standard and a previously analyzed sample (duplicate). Also let the sampler skip to check the baseline.
8.4.4After an acceptable peak (within the calibration range) is obtained, pour the excess sample from the test tube into the waste gasoline can.
8.4.5Any sample resulting in a peak greater than 0.05 g Pb/gal will be run in duplicate. Samples registering greater than 0.10 g Pb/gal should be diluted with iso-octane or unleaded fuel to fall within the calibration range or a higher level calibration standard curve must be prepared. The higher level curve must be shown to be linear and measurement of lead at these levels must be shown to be accurate by the analysis of control samples at a higher level of alkyl lead content.
8.5Shut Down.
8.5.1Replace the solvent displacement flask with flasks filled with distilled water. Also place all other lines in a beaker of distilled water. Rinse the system with distilled water for 15 minutes.
8.5.2Withdraw the gasoline from the wash cup and fill with water.
8.5.3Dispose of all solvent waste in waste glass bottles.
8.5.4Turn the AAS off after extinguishing the flame. Also turn the recorder and pump off. Remove the platen and release the pump tubing.
8.5.5Shut the acetylene off at the tank and bleed the line.
9.1Precision.
9.1.1All duplicate results should be considered suspect if they differ by more than 0.005 g Pb/gal.
9.2Accuracy.
9.2.1All quality control standard checks should agree within 10% of the nominal value of the standard.
9.2.2All spikes should agree within 10% of the known addition.
10.1Precision.
10.1.1Duplicate analysis for 156 samples in a single laboratory has resulted in an average difference of 0.00011 g Pb/gal with a standard deviation of 0.0023.
10.1.2Replicate analysis in a single laboratory (greater than 5 determinations) of samples at concentrations of 0.010, 0.048, and 0.085 g Pb/gal resulted in relative standard deviations of 4.2%, 3.5%, and 3.3% respectively.
10.2Accuracy.
10.2.1The analysis of National Bureau of Standards (NBS) lead in reference fuel of known concentrations in a single laboratory has resulted in found values deviating from the true value for 11 determinations of 0.0322 g Pb/gal by an average of 0.56% with a standard deviation of 6.8%, for 15 determinations of 0.0519 g Pb/gal by an average of -1.1% with a standard deviation of 5.8%, and for 7 determinations of 0.0725 g Pb/gal by an average of 3.5% with a standard deviation of 4.8%.
10.2.2Twenty-three analyses of blind reference samples in a single laboratory (U.S.
10.2.3In a single laboratory, the average percent recovery of 108 spikes made to samples was 101% with a standard deviation of 5.6%.
1.1This method covers the determination of the total lead content of gasoline. The procedure's calibration range is 0.010 to 5.0 grams of lead/U.S. gallon. Samples above this level should be diluted to fall within the range of 0.05 to 5.0 grams of lead/U.S. gallon. The method compensates for variations in gasoline composition and is independent of lead alkyl type.
1.2This method may be used as an alternative to Method 1—Standard Method Test for Lead in Gasoline by Atomic Absorption Spectrometry, or to Method 2—Automated Method Test for Lead in Gasoline by Atomic Absorption Spectrometry.
1.3Where trade names or specific products are noted in the method, equivalent apparatus and chemical reagents may be used. Mention of trade names or specific products is for the assistance of the user and does not constitute endorsement by the U.S. Environmental Protection Agency.
2.1A portion of the gasoline sample is placed in an appropriate holder and loaded into an X-ray spectrometer. The ratio of the net X-ray intensity of the lead L alpha radiation to the net intensity of the incoherently scattered tungsten L alpha radiation is measured. The lead content is determined by reference to a linear calibration equation which relates the lead content to the measured ratio.
2.2The incoherently scattered tungsten radiation is used to compensate for variations in gasoline samples.
3.1Samples should be collected and stored in containers which will protect them from changes in the lead content of the gasoline, such as loss of volatile fractions of the gasoline by evaporation or leaching of the lead into the container or cap.
3.2If samples have been refrigerated they should be brought to room temperature prior to analysis.
3.3Gasoline is extremely flammable and should be handled cautiously and with adequate ventilation. The vapors are harmful if inhaled and prolonged breathing of vapors should be avoided. Skin contact should be minimized. See precautionary statements in Annex Al.3.
4.1X-ray Spectrometer, capable of exciting and measuring the fluorescence lines mentioned in 2.1 and of being operated under the following instrumental conditions or others giving equivalent results: a tungsten target tube operated at 50 kV, a lithium fluoride analyzing crystal, an air or helium optical path and a proportional or scintillation detector.
4.2Some manufacturers of X-ray Spectrometer units no longer allow use of air as the beam path medium because the X-ray beam produces ozone, which may degrade seals and electronics. In addition, use of the equipment with liquid gasoline in close proximity to the hot X-ray tube could pose flammability problems with any machine in case of a rupture of the sample container. Therefore, use of the helium alternative is recommended.
5.1Isooctane. Isooctane is flammable and the vapors may be harmful. See precautions in Annex Al.1.
5.2Lead standard solution, in isooctane, toluene or a mixture of these two solvents, containing approximately 5 gm Pb/U.S. gallon may be prepared from a lead-in-oil concentrate such as those prepared by Conostan (Conoco, Inc., Ponca City, Oklahoma). Isooctane and toluene are flammable and the vapors may be harmful. See precautionary statements in Annex Al.1 and Al.2.
6.1Make exact dilutions with isooctane of the lead standard solution to give solutions with concentrations of 0.01, 0.05, 0.10, 0.50, 1.0, 3.0 and 5.0 g Pb/U.S. gallon. If a more limited range is desired as required for linearity, such range shall be covered by at least five standard solutions approximately equally spaced and this range shall not be exceeded by any of the samples. Place each of the standard solutions in a sample cell using techniques consistent with good operating practice for the spectrometer employed. Insert the sample in the spectrometer and allow the spectrometer atmosphere to reach equilibrium (if appropriate). Measure the intensity of the lead L alpha peak at 1.175 angstroms, the Compton scatter peak of the tungsten L alpha line at 1.500 angstroms and the background at 1.211 angstroms. Each measured intensity should exceed 200,000 counts or the time of measurement should be at least 30 seconds. The relative standard deviation of each measurement, based on counting statistics, should be one percent or less. The Compton scatter peak given above is for 90
6.2For Each of the standards, as well as for an isooctane blank, determine the net lead intensity by subtracting the corrected
6.3Determine the corrected lead intensity ratio, which is the net lead intensity corrected for matrix effects by division by the net incoherently scattered tungsten radiation. The net scattered intensity is calculated by subtracting the background intensity at 1.211 angstroms from the gross intensity of the incoherently scattered tungsten L alpha peak. The equation for the corrected lead intensity ratio follows:
6.4Obtain a linear calibration curve by performing a least squares fit of the corrected lead intensity ratios to the standard concentrations.
7.1Prepare a calibration curve as described in 6. Since the scattered tungsten radiation serves as an internal standard, the calibration curve should serve for at least several days. Each day the suitability of the calibration curve should be checked by analyzing several National Bureau of Standards (NBS) lead-in-reference-fuel standards or other suitable standards.
7.2Determine the corrected lead intensity ratio for a sample in the same manner as was done for the standards. The samples should be brought to room temperature before analysis.
7.3Determine the lead concentration of the sample from the calibration curve. If the sample concentration is greater than 5.0 g Pb/U.S. gallon or the range calibrated for in 6.1, the sample should be diluted so that the result is within the calibration span of the instrument.
7.4Quality control standards, such as NBS standard reference materials, should be analyzed at least once every testing session.
7.5For each group of ten samples, a spiked sample should be prepared by adding a known amount of lead to a sample. This known addition should be at least 0.05 g Pb/U.S. gallon, at least 50% of the measured lead content of the unspiked sample, and not more than 200% of the measured lead content of the unspiked sample (unless the minimum addition of 0.05 g Pb/U.S. gallon exceeds 200%). Both the spiked and unspiked samples should be analyzed.
8.1The difference between duplicates should not exceed 0.005 g Pb/U.S. gallon or a relative difference of 6%.
8.2All quality control standard check samples should agree within 10% of the nominal value of the standard.
8.3All spiked samples should have a percent recovery of 100%
8.4The difference between independent analyses of the same sample in different laboratories should not exceed 0.01 g Pb/U.S. gallon or a relative difference of 12%.
9.1Duplicate analysis for 26 samples in the range of 0.01 to 0.10 g Pb/U.S. gallon resulted in an average relative difference of 5.2% with a standard deviation of 5.4%. Duplicate analysis of 14 samples in the range 0.1 to 0.5 g Pb/U.S. gallon resulted in an average relative difference of 2.3% with a standard deviation of 2.0. Duplicate analysis of 47 samples in the range of 0.5 to 5 g Pb/U.S. gallon resulted in an average relative difference of 2.1% with a standard deviation of 1.8%.
9.2The average percent recovery for 23 spikes made to samples in the 0.0 to 0.1 g Pb/U.S. gallon range was 103% with a standard deviation of 3.2%. For 42 spikes made to samples in the 0.1 to 5.0 g Pb/U.S. gallon range, the average percent recovery was 102% with a standard deviation of 4.2%.
9.3The analysis of National Bureau of Standards lead-in-reference-fuel standards of known concentrations in a single laboratory has resulted in found values deviating from the true value for 14 determinations of 0.0490 g Pb/U.S. gallon by an average of 2.8% with a standard deviation of 6.4%, for 11 determinations of 0.065 g Pb/U.S. gallon by an average of 4.4% with a standard deviation of 2.9%, and for 15 determinations of 1.994 g Pb/U.S. gallon by an average of 0.3% with a standard deviation of 1.3%.
9.4Eighteen analyses of reference samples (U.S. EPA, Research Triangle Park, NC) have resulted in found values differing from the true value by an average of 0.0004 g Pb/U.S. gallon with a standard deviation of 0.004 g Pb/U.S. gallon.
1.1This method covers procedures for obtaining representative samples of gasoline for the purpose of testing for compliance with the Reid vapor pressure (RVP) standards set forth in § 80.27.
2.1It is necessary that the samples be truly representative of the gasoline in question. The precautions required to ensure the representative character of the samples are numerous and depend upon the tank, carrier, container or line from which the sample is being obtained, the type and cleanliness of the sample container, and the sampling procedure that is to be used. A summary of the sampling procedures and their application is presented in Table 1. Each procedure is suitable for sampling a material under definite storage, transportation, or container conditions. The basic principle of each procedure is to obtain a sample in such manner and from such locations in the tank or other container that the sample will be truly representative of the gasoline.
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
4.1Sample containers may be clear or brown glass bottles, or cans. The clear glass bottle is advantageous because it may be examined visually for cleanliness, and also allows visual inspection of the sample for free water or solid impurities. The brown glass bottle affords some protection from light. Cans with the seams soldered on the exterior surface with a flux of rosin in a suitable solvent are preferred because such a flux is easily removed with gasoline, whereas many others are very difficult to remove. If such cans are not available, other cans made with a welded construction that are not affected by, and that do not affect, the gasoline being sampled are acceptable.
4.2
4.2.1Screw caps must be protected by material that will not affect petroleum or petroleum products. A phenolic screw cap with a teflon coated liner may be used, since it has met the requirements of the above performance test upon EPA analysis.
4.3
5.1Sampling apparatus is described in detail under each of the specific sampling procedures. Clean, dry, and free all sampling apparatus from any substance that might contaminate the material, using the procedure described in 4.3.
6.1When loading or discharging gasoline, take samples from both shipping and receiving tanks, and from the pipeline if required.
6.2
6.3
When taking samples from tanks suspected of containing flammable at-mos-pheres, precautions should be taken to guard against ignitions due to static electricity. No object or material should be lowered into or suspended in a compartment of a tank which is being filled. A recommended waiting period of no less than five minutes after cessation of pumping will generally permit a substantial relaxation of the electrostatic charge for small volume vessels such as tank cars and tank trucks; under certain conditions a longer period may be deemed advisable. A recommended waiting period of no less than 30 minutes will generally permit a substantial relaxation of the electrostatic charge for large volume vessels such as storage tanks or ship tanks; under certain conditions a longer period may be deemed advisable.
7.1Directions for sampling cannot be made explicit enough to cover all cases. Extreme care and good judgment are necessary to ensure samples that represent the general character and average condition of the material. Clean hands are important. Clean gloves may be worn but only when absolutely necessary, such as in cold weather, or when handling materials at high temperature, or for reasons of safety. Select wiping cloths so that lint is not introduced, contaminating samples.
7.2As many petroleum vapors are toxic and flammable, avoid breathing them or igniting them from an open flame or a spark produced by static. Follow all safety precautions specific to the material being sampled.
7.3When sampling relatively volatile products (more than 2 pounds (0.14 kgf/cm
8.1
8.2
9.1To prevent loss of liquid and vapors during shipment, and to protect against moisture and dust, cover the stoppers of glass bottles with plastic caps that have been swelled in water, wiped dry, placed over the tops of the stoppered bottles, and allowed to shrink tightly in place. The caps of metal containers must be screwed down tightly and checked for leakage. Postal and express office regulations applying to the shipment of flammable liquids must be observed.
10.1 Label the container immediately after a sample is obtained. Use waterproof and oilproof ink, or a pencil hard enough to dent the tag, since soft pencil and ordinary ink markings are subject to obliteration from moisture, oil smearing and handling. An indelible identification symbol, such as a bar code, may be used in lieu of a manually addressed label. The label shall reference the following information:
10.1.1Date and time (the period elapsed during continuous sampling);
10.1.2Name of the sample;
10.1.3Name or number and owner of the vessel, car, or container;
10.1.4—Brand and grade of material; and
10.1.5—Reference symbol or identification number.
11.1The standard sampling procedures described in this method are summarized in Table 1. Alternative sampling procedures may be used if a mutually satisfactory agreement has been reached by the party(ies) involved and EPA and such agreement has been put in writing and signed by authorized officials.
11.2Bottle or beaker sampling. The bottle or beaker sampling procedure is applicable for sampling liquids of 16 pounds (1.12 kgf/cm
11.2.1
11.2.2
11.2.2.1
11.2.2.2
11.2.2.3
At the selected level pull out the stopper with a sharp jerk of the cord or chain and allow the bottle or beaker to fill completely, as evidenced by the cessation of air bubbles. When full, raise the bottle or beaker, pour off a small amount, and stopper immediately.
11.2.2.4
11.2.2.5
11.3
11.3.1
11.3.1.1
11.3.1.2
11.3.1.3
11.3.2
11.4
11.4.1
11.4.1.1
11.4.1.1.1A tube extending to the center of the line and beveled at a 45 degree angle facing upstream (Figure 4(a)).
11.4.1.1.2A long-radius forged elbow or pipe bend extending to the center line of the pipe and facing upstream. The end of the probe should be reamed to give a sharp entrance edge (Figure 4(b)).
11.4.1.1.3A closed-end tube with a round orifice spaced near the closed end which should be positioned in such a way that the orifice is in the center of the pipeline and is facing the stream as shown in figure 4(c)).
11.4.1.2
11.4.1.2.1The sampling lines should be as short as practicable and should be cleared before any samples are taken.
11.4.1.2.2Where adequate flowing velocity is not available, a suitable device for mixing the fluid flow to ensure a homogeneous mixture at all rates of flow and to eliminate stratification should be installed upstream of the sampling tap. Some effective devices for obtaining a homogeneous mixture are as follows: Reduction in pipe size; a series of baffles; orifice or perforated plate; and a combination of any of these methods.
11.4.1.2.3The design or sizing of these devices is optional with the user, as long as the flow past the sampling point is homogeneous and stratification is eliminated.
11.4.1.3To control the rate at which the sample is withdrawn, the probe or probes should be fitted with valves or plug cocks.
11.4.1.4Automatic sampling devices that meet the standards set out in 11.4.1.5 may be used in obtaining samples of gasoline. The quality of sample collected must be of sufficient size for analysis, and its composition should be identical with the composition of the batch flowing in the line while the sample is being taken. An automatic sampler installation necessarily includes not only the automatic sampling device that extracts the samples from the line, but also a suitable probe, connecting lines, auxiliary equipment, and a container in which the sample is collected. Automatic samplers may be classified as follows:
11.4.1.4.1Continuous sampler, time cycle (nonproportional) type. A sampler designed and operated in such a manner that it transfers equal increments of liquid from the pipeline to the sample container at a uniform rate of one or more increments per minute is a continuous sampler.
11.4.1.4.2Continuous sampler, flow-responsive (proportional) type. A sampler that is designed and operated in such a manner that it will automatically adjust the quantity of sample in proportion to the rate of flow is a flow-responsive (proportional) sampler. Adjustment of the quantity of sample may be made either by varying the frequency of transferring equal increments of sample to the sample container, or by varying the volume of the increments while maintaining a constant frequency of transferring the increments to the sample container. The apparatus assembly for continuous sampling is shown in figure 4.
11.4.1.4.3
11.4.1.5
11.4.1.5.1Small lines connecting various elements of the installation should be so arranged that complete purging of the automatic sampler and of all lines can be accomplished effectively. All fluid remaining in the sampler and the lines from the preceding sampling cycle should be purged immediately before the start of any given sampling operation.
11.4.1.5.2In those cases where the sampler design is such that complete purging of the sampling lines and the sampler is not possible, a small pump should be installed in order to circulate a continuous stream from the sampling tube past or through the sampler and back into the line. The automatic sampler should then withdraw the sample from the sidestream through the shortest possible connection.
11.4.1.5.3Under certain conditions, there may be a tendency for water and heavy particles to drop out in the discharge line from the sampling device and appear in the sample container during some subsequent sampling period. To circumvent this possibility, the discharge pipe from the sampling device should be free of pockets or enlarged pipe areas, and preferably should be pitched downward to the sample container.
11.4.1.5.4To ensure clean, free-flowing lines, piping should be designed for periodic cleaning.
11.4.1.6
11.4.1.6.1The batch pumped during the test interval should be diverted into a clean tank and a sample taken within one hour after cessation of pumping.
11.4.1.6.2If the sampling of the delivery tank is to be delayed beyond one hour, then the tank selected must be equipped with an adequate mixing means. For valid comparison, the sampling of the delivery tank must be completed within eight hours after cessation of pumping, even though the tank is equipped with a motor-driven mixer.
11.4.1.6.3When making a normal full-tank delivery from a tank, a properly secured sample may be used to check the results of the sampler if the parties (including EPA) mutually agree to this procedure.
11.4.1.7
11.4.1.7.1
11.4.1.7.2
11.4.2
11.4.2.1
11.4.2.2
11.5
11.5.1
11.5.2
11.5.2.1If a nozzle extension as found in figure 7 or 7a is used, 3 gallons of gasoline should first be dispensed from the pump nozzle to purge the pump hose and nozzle. Then a small amount of product should be dispensed through the nozzle extension into the sample container to rinse the sample container. A pump nozzle spacer (figure 6) may be used if the pump is a vapor recovery type. Rinse the sample container and discard the waste product into an appropriate container. Insert the nozzle extension (figure 7 or 7a) into the sample container and insert the pump nozzle into the extension with slot over the air bleed hole (when using figure 7). Fill the sample container slowly through the nozzle extension to 70-85 percent full (figure 8). Remove the nozzle extension. Cap the sample container at once. Check for leaks. Discard the sample container and re-sample if leak occurs. If the sample container is leak tight, label the container and deliver it to the laboratory.
11.5.2.2If a nozzle extension as found in figure 7b is used, 3 gallons of gasoline should first be dispensed from the pump nozzle to purge the pump hose and nozzle. Then screw a dry and dirt free 4 oz sample bottle container onto the bottle filling fixture. Insert the nozzle into the nozzle extension. Insert the discharge end of the modified nozzle extension into a gasoline safety can or into the filler neck of a vehicle. Obtain the sample by pumping at least 0.2 gallon through the sampler. Remove the sample bottle from the fixture. The sample must be 70-85 percent full. Cap the sample container at once. Check for leaks. Discard the sample container and re-sample if a leak occurs. If the sample container is leak tight, label the container and deliver it to the laboratory.
12.1
12.2
12.3
12.4
12.5.
12.6
1.1This method covers the determination of the absolute pressure, measured against a vacuum of a gasoline or gasoline-oxygenate blend sample saturated with air at 32-40 °F (0-4.5 °C). The absolute (measured) pressure is observed with a system volume ratio of 1 part sample and 4 parts evacuated space at 100 °F (37.8 °C).
1.2The values stated in pounds per square inch absolute are standard.
2.1A known volume of air-saturated fuel at 32-40 °F is introduced into an evacuated, thermostatically controlled test chamber, the internal volume of which is or becomes five times that of the total test specimen introduced into the test chamber. After the injection the test specimen is allowed to reach thermal equilibrium at the test temperature, 100 °F (37.8 °C). The resulting pressure increase is measured with an absolute pressure measuring device whose volume is included in the total of the test chamber volume. The
2.2The total measured pressure is converted to Reid vapor pressure by use of a correlation equation (see Section 9).
3.1The apparatus shall employ a thermostatically controlled test chamber which is capable of maintaining a vapor-to-liquid ratio between 3.95 and 4.05 to 1.00.
3.2The pressure measurement device shall have a minimum operation range from 0 to 15 psia (0 to 103 kPa) with a minimum resolution of 0.05 psia (0.34 kPa). The pressure measurement device shall include any necessary electronic and readout devices to display the resulting reading.
3.3The test chamber shall be maintained at 100
3.4A thermometer that meets the specification ASTM 18 F (18 C) or a platinum resistance thermometer shall be used for measuring the temperature of the test chamber. The minimum resolution for the temperature measurement device is 0.2 °F (0.1 °C) and an accuracy of
3.5The vapor pressure apparatus shall have a provision for the introduction of the test specimen into the evacuated or to be evacuated test chamber and for the cleaning or purging of the chamber following the test.
3.6If a vacuum pump is used, it must be capable of reducing the pressure in the test chamber to less than 0.01 psia (0.07 kPa). If the apparatus uses a piston to induce a vacuum in the sample chamber the residual pressure shall be no greater than 0.01 psia (0.07 kPa) upon full expansion of the test chamber devoid of any material at 100
3.7Ice water or air bath for chilling the sample to a temperature between 32-40 °F (0-4.5 °C).
3.8Mercury barometer, 0 to 17.4 psia (0 to 120 kPa) range.
3.9McLeod vacuum gauge, to cover at least the range of 0 to 5 mm Hg (0 to 0.67 kPa). Calibration of the McLeod gauge is checked as in accordance with Annex A6 of ASTM test Method D 2892-84, (Standard test method for distillation of Crude Petroleum (15-Theoretical Plate Column)). ASTM D-2892-84 is incorporated by reference. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C 552(a) and 1 CFR part 51. Copies may be obtained from the American Society for Testing and Materials, 1916 Race St., Philadelphia, PA 19103. Copies may be inspected at the U.S. Environmental Protection Agency, Air Docket Section, room M-1500, 401 M Street, SW., Washington, DC 20460 or at the Office of the Federal Register, 800 North Capitol Street, NW., Washington, DC.
4.1
4.1.12,2,4-trimethylpentane
4.1.22,2-dimethylbutane
4.1.33-methylpentane
4.1.4n-pentane
4.1.5acetone
4.2n-pentane(commercial grade-95% pure)
5.1The sensitivity of vapor pressure measurements to losses through evaporation and the resulting change in composition is such as to require the utmost precaution in the handling of samples. The provisions of this section apply to all samples for vapor pressure determinations.
5.2Sample in accordance with 40 CFR part 80, appendix D.
5.3Sample container size. The minimum size of the sample container from which the vapor pressure sample is taken is 4 ounces (118 ml). It will be 70 to 85% filled with sample.
5.4
5.4.1Determine vapor pressure as the first test on a sample. Multiple analyses may be performed, but must be evaluated given the stated precision for the size of the sample container, and the order in which they were run in relation to the initial analysis.
5.4.2Protect samples from excessive heat prior to testing.
5.4.3Leaking samples should be replaced if possible. Analysis results from leaking sample containers must be marked as such.
5.4.4Samples that have separated into two phases should be replaced if possible. Analysis results from samples that have phase separated must be marked as such.
5.4.5Sample handling temperature. In all cases, cool the sample to a temperature of 32-40 °F (0-4.5 °C) before the container is opened. To ensure sufficient time to reach this temperature, directly measure the temperature of a similar liquid at a similar initial temperature in a like container placed in the cooling bath at the same time as the sample.
6.1
6.1.1Analysis results from samples that contain less than 70 volume % of the container capacity must be marked as such.
6.1.2If the container is more than 85 volume % full, pour out enough sample to bring the container contents within the 70 to 85 volume % range. Under no circumstance may any sample poured out be returned to the container.
6.2Air saturation of the sample in the sample container. With the sample at a temperature of 32-40 °F (0-4.5 °C), take the container from the cooling bath, wipe dry with an absorbent material, unseal it momentarily, taking care to prevent water entry, re-seal it, and shake it vigorously. Return it to the bath for a minimum of 2 minutes. Repeat the air introduction procedure twice, for a total of three air introductions to completely saturate the sample.
6.3Prepare the instrument for operation in accordance with the manufacturer's instructions.
6.3.1
6.3.2
When using a self cleaning apparatus some residual product may be carried over into subsequent analyses. Carryover effect should be investigated when conducting sequential analyses of dissimilar materials, especially calibration standards. Inaccuracies caused by carryover effect should be resolved using testing procedures designed to minimize such interferences.
6.4If a syringe is used for the physical introduction of the sample specimen, it must be either clean and dry before it is used or it may be rinsed out at least three times with the sample. When cleaning the syringe, the rinse may not be returned to the sample container. The syringe must be capable of obtaining, upon filling with the sample charge, a quantity of sample that has an entrained gas volume of less than 3% of the necessary sample volume.
7.1
7.1.1Check the calibration of the pressure measurement device daily or until the stability of the device is documented as having less than or equal to 0.03 psi (0.2 kPa) drift per unit of the appropriate calibration period. When calibration is necessary, follow the procedures in sections 7.1.2 through 7.1.4.
7.1.2Connect a properly calibrated McLeod gauge to the vacuum source line to the test chamber. Apply vacuum to the test chamber. When the McLeod gauge registers a pressure less than 0.8 mm Hg (0.1 kPa) adjust the pressure measurement device's zero control to match to within
7.1.3Open the test chamber to the atmosphere and observe the pressure measurement device's reading. Adjust the pressure measurement devices span control to within
7.1.4Repeat steps 7.1.2 and 7.1.3 until the instrument zero and barometer readings read correctly without further adjustments.
7.2
7.3
If the observed pressure does not fall between the reference values, check the instrument for leaks and its calibration (Section 7).
7.3.1Other compounds, gasolines, and gasoline blends may be used as control standards as long as these materials have been statistically evaluated for their mean total measured pressure using an instrument that conforms to this procedure.
7.3.2The control limits can be calculated with the following formula:
8.1Remove the sample from the cooling bath or refrigerator, dry the exterior of the container with absorbent material, unseal, and insert the transfer tube, syringe, or transfer connection (see section 6). Draw an aliquot (minimize gas bubbles) of sample into a gas tight syringe or transfer the sample using tubing or transfer connection and deliver this test specimen to the test chamber as rapidly as possible. The total time between opening the chilled sample container and inserting/securing the syringe or transfer connection into the sealed test chamber shall not exceed one minute.
8.2Follow the manufacturer's instructions for injection of the test specimen into the test chamber, and for the operation of the instrument to obtain a total measured vapor pressure result for the test specimen.
8.3Set the instrument to read the test results in terms of total measured pressure. If the instrument is capable of calculating a Reid Vapor Pressure equivalent value ensure that only the parameters in section 9.2 are used.
9.1Note the total measured vapor pressure reading for the instrument to the nearest 0.01 psi (0.07 kPa). For instruments which do not automatically display a stable pressure value, manually note the pressure indicator reading every minute to the nearest 0.01 psi (0.07 kPa). When three successive readings agree to within 0.01 psia (0.07 kPa) note the final result to the nearest 0.01 psia (0.07 kPa).
9.2Using the following correlation equation, calculate the Reid Vapor Pressure (RVP) that is equivalent to the total measured vapor pressure obtained from the instrument, in order to compare the vapor pressure standards set out in 40 CFR 80.27. Ensure that the instrument reading in this equation corresponds to the total measured pressure and has not been corrected by an automatically programmed correction factor.
9.3Record the RVP to the nearest 0.01 psi (0.07 kPa) as the official test result.
9.4EPA will use the above method as the official vapor pressure test method. EPA will recognize correlations from regulated parties if the correlations are established directly with EPA's test laboratory. Any test method may be used for defense as long as adequate correlation is demonstrated to this method (i.e., any vapor pressure defense test method could be used if adequate correlation exists directly to this method, which can then be converted to Reid Vapor Pressure by use of
This test method covers the determination of the type and amount of alcohols in gasoline.
Gasoline samples are extracted with water prior to analysis on a gas chromatograph (GC). The extraction eliminates hydrocarbon interference during chromatography. A known quantity of isopropanol is added to the fuel prior to extraction to act as an internal standard.
3.1Sample in accordance with 40 CFR part 80, appendix D.
3.2At least 100 ml. of gasoline suspected of containing ethanol and/or methanol are required.
4.1Gas chromatograph—A gas chromatograph equipped with a flame ionization detector.
4.2Column—A gas chromatograph column, glass, 1800 by 6.35 cm. outside diameter, packed with chromosorb 102.
4.3Recorder—A 1-mv recorder with a 1 second full scale response and a chart speed of 10 mm. per minute (0.4 inches per minute).
4.4Syringe (100 ul.) for adding the internal standard.
4.5Pipet.
4.6Injection syringe (10 ul.).
4.7Extraction syringe (1-5 ml.) with 3-inch needle.
4.8250 ml. (
4.9Calibration standard solutions extracted from gasoline containing known quantities of alcohols.
4.10Reference standard solutions extracted from gasoline containing known quantities of alcohols.
4.11Distilled water.
4.12Reagent grade isopropanol.
4.13Rubber gloves.
4.14I.D. tags.
Gasoline and alcohols are extremely flammable and may be toxic over prolonged exposure. Methanol is particularly hazardous. Persons performing this procedure must be familiar with the chemicals involved and all precautions applicable to each.
5.1Extractions and dilutions must be performed in well-ventilated areas, preferably under a fume hood, away from open flames and sparks.
5.2Rubber gloves must be worn during the handling of gasoline and alcohols.
5.3Avoid breathing fumes from gasoline and alcohols, particularly methanol.
5.4Gas cylinders must be properly secured and the hydrogen FID fuel must be segregated from the compressed air (oxidizer) tank.
6.1Ensure that the samples do not certain sediment or separated phases prior to extraction.
6.2Ensure adequate quantities of GC supply gases to maintain a run.
7.1Gas chromatography—Use carrier gas, flow rates, detector and injection temperatures and column as specified in the GC manufacturer's specifications.
7.2Sample extraction, preparation and analysis.
7.2.1Label two 6 ml. vials with the sample identification number supplied with the original sample. The estimated percent alcohol from any screening tests must also be included on the label.
7.2.2Pipet 4 ml.
7.2.3Measure 100 ul. (0.1 ml.)
This adds an internal standard to the sample which is required for accurate analysis.
7.2.4Add 1 ml.
7.2.5Allow the mixture to separate into two phases (at least 5 minutes).
7.2.6Carefully draw off the aqueous (lower) phase using a 5 ml. syringe and long needle.
Be careful not to allow any of the gasoline phase to get into the needle. Leave a small amount (approximately 0.2 ml.) of the aqueous phase in the vial.
7.2.7Transfer the aqueous phase into the other 6 ml. vial (vial #2).
7.2.8Repeat steps 7.2.4 to 7.2.6 two more times.
7.2.9Fill vial #2 (the aqueous phase) to 4 ml.
7.2.10Retain the remaining original gasoline sample (not the gasoline phase).
7.2.11Discard the extracted gasoline phase in vial #1 in an appropriate manner.
7.2.12Perform a second extraction on one sample in every 20. This sample is to be labeled with the sample number and as a duplicate and run as a normal sample.
7.2.13Transfer approximately 2 ml. of the aqueous solution to vials compatible with the autosampler. Tag the vial with the sample number.
7.2.14Perform analysis of the sample according to the GC manufacturer's specifications.
7.3Standards.
7.3.1Calibration standard solutions (made in gasoline).
7.3.1.1Reagent grade or better alcohols (including undenatured ethanol) are to be diluted with regular unleaded gasoline. The isopropanol internal standard is to be added during extraction of the alcohols. Newly acquired stocks of reagent grade alcohols shall be diluted to 10% with hydrocarbon-free water and analyzed for contamination by GC before use.
7.3.1.2Required calibration standards (% by volume in gasoline):
The standards should be as equally spaced within the range as possible and may contain more than one alcohol.
Level #1 must contain all of the alcohols.
8.1Alcohol(s) in water solution may be used to characterize the GC. The resulting characterization always reflects the absolute sensitivity of the instrument to each alcohol.
8.2Calibration standards are made by extraction of known alcohol(s) in gasoline blends. These standards account for inaccuracies caused by incomplete extraction of alcohols.
8.3The addition of isopropanol as an internal standard reduces errors caused by variations in injection volumes, and further reduces inaccuracies caused by incomplete extraction of alcohols.
8.4Sufficient sample should be retained to permit reanalysis.
8.5Running averages of reference standards data must not exceed 0.75% of applicable limits or investigation should be started for the cause of such variation.
9.1Calculate purity of component as follows:
9.2Calculate response factors as follows:
9.3Calculate the percent alcohols as follows:
10.1Report results to the nearest 0.1%.
11.1Precision—The precision of this test method has not been determined.
11.2Accuracy—The accuracy of this test method has not been determined.
1.1This test method covers a procedure for determination of methanol, ethanol, isopropanol, n-propanol, isobutanol, sec-butanol, tert-butanol, n-butanol, and methyl tertiary butyl ether (MTBE) in gasoline by gas chromatography.
1.2Individual alcohols and MTBE are determined from 0.1 to 10 volume %. Any sample found to contain greater than 10 volume % of an alcohol or MTBE shall be diluted to concentrations within these limits.
1.3Sl (metric) units of measurement are preferred and used throughout this standard. Alternative units, in common usage, are also provided to improve the clarity and aid the user of this test method.
1.4This standard may involve hazardous materials, operations, and equipment. This standard does not purport to address all of the safety problems associated with its use. It is the responsibility of the user of this standard to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to use.
2.
2.1ASTM Standards:
2.2EPA Regulations:
3.1MTBE—methyl tertiary butyl ether.
3.2Low volume connector—a special union for connecting two lengths of tubing 1.6 mm inside diameter and smaller. Sometimes this is referred to as a zero dead volume union.
3.3Oxygenates—used to designate fuel blending components containing oxygen, either in the form of alcohol or ether.
3.4Split ratio—a term used in gas chromatography using capillary columns. The split ratio is the ratio of the total flow of the carrier gas to the sample inlet versus the flow of carrier gas to the capillary column. Typical values range from 10:1 to 500:1 depending upon the amount of sample injected and the type of capillary column used.
3.5WCOT—abbreviation for a type of capillary column used in gas chromatography that is wall-coated open tubular. This type of column is prepared by coating the inside of the capillary with a thin film of stationary phase.
3.6TCEP—1,2,3,-tris-2-cyanoethoxypropane—a gas chromatographic liquid phase.
4.1An internal standard, tertiary amyl alcohol, is added to the sample which is then introduced into a gas chromatograph equipped with two columns and a column switching valve. The sample first passes onto a polar TCEP column which elutes lighter hydrocarbons to vent and retains the oxygenated and heavier hydrocarbons. After methylcyclopentane, but before MTBE elutes from the polar column, the valve is switched to backflush the oxygenates onto a WCOT non-polar column. The alcohols and MTBE elute from the non-polar column in boiling point order, before elution of any major hydrocarbon constituents. After benzene elutes from the non-polar column, the column switching valve is switched back to its original position to backflush the heavy hydrocarbons. The eluted components are detected by a flame ionization or thermal conductivity detector. The detector response, proportional to the component concentration, is recorded; the peak areas are measured; and the concentration of each component is calculated with reference to the internal standard.
5.1Alcohols and other oxygenates may be added to gasoline to increase the octane number. Type and concentration of various oxygenates are specified and regulated to ensure acceptable commercial gasoline quality. Drivability, vapor pressure, phase separation, and evaporative emissions are some of the concerns associated with oxygenated fuels.
5.2This test method is applicable to both quality control in the production of gasoline and for the determination of deliberate or extraneous oxygenate additions or contamination.
6.1Chromatograph:
6.1.1A gas chromatographic instrument which can be operated at the conditions given in Table 1, and having a column switching and backflushing system equivalent to Fig. 1. Carrier gas flow controllers shall be capable of precise control where the required flow rates are low (Table 1). Pressure control devices and gages shall be capable of precise control for the typical pressures required.
6.1.2Detector—A thermal conductivity detector or flame ionization detector may be used. The system shall have sufficient sensitivity and stability to obtain a recorded deflection of at least 2 mm at a signal-to-noise ratio of at least 5 to 1 for 0.005 volume % concentration of an oxygenate.
6.1.3Switching and backflushing valve—A valve, to be located within the gas chrom-a-to-graph-ic column oven, capable of performing the functions described in Section 11. and illustrated in Fig. 1. The valve shall be of low volume design and not contribute significantly to chromatographic deterioration.
6.1.3.1Valco Model No. CM-VSV-10-HT, 1.6-mm (
6.1.3.2Valco Model No. C10W, 0.8-mm (
6.1.4Although not mandatory, an automatic valve switching device is strongly recommended to ensure repeatable switching times. Such a device should be synchronized with injection and data collection times. If no such device is available, a stopwatch, started at the time of injection, should be used to indicate the proper valve switching time.
6.1.5Injection system—The chrom-a-to-graph should be equipped with a splitting-type inlet device. Split injection is necessary to maintain the actual chrom-a-to-graphed sample size within the limits of column and detector optimum efficiency and linearity.
6.1.6Sample introduction—Any system capable of introducing a representative sample into the split inlet device. Microlitre syringes, automatic syringe injectors, and liquid sampling valves have been used successfully.
6.2Data presentation or calculation, or both:
6.2.1Recorder—A recording potentiometer or equivalent with a full-scale deflection of 5 mV or less. Full-scale response time should be l s or less with sufficient sensitivity and stability to meet the requirements of 6.1.2.
6.2.2Integrator or computer—Devices capable of meeting the requirements of 6.1.2, and providing graphic and digital presentation of the chromatographic data, are recommended for use. Means shall be provided for determining the detector response. Peak heights or areas can be measured by computer, electronic integration or manual techniques.
6.3Columns, two as follows:
6.3.1Polar column—This column performs a preseparation of the oxygenates from volatile hydrocarbons in the same boiling point range. The oxygenates and remaining hydrocarbons are backflushed onto the non-polar column in section 6.3.2. Any column with equivalent or better chromatographic efficiency and selectivity to that described in 6.3.1.1 can be used. The column shall perform at the same temperature as required for the column in 6.3.2.
6.3.1.1TCEP micro-packed column, 560 mm (22 in.) by 1.6-mm (
6.3.2Non-polar (analytical) column—Any column with equivalent or better chrom-a-to-graph-ic efficiency and selectivity to that described in 6.3.2.1 and illustrated in Fig. 2 can be used.
6.3.2.1WCOT methyl silicone column, 30m (1181 in.) long by 0.53 mm (0.021-in.) inside diameter fused silica WCOT column with a 2.6-μm film thickness of cross-linked methyl siloxane. This column was used in the (ASTM) cooperative study to provide the Precision and Bias data referred to in Section 15.
7.1Carrier gas—Carrier gas appropriate to the type of detector used. Helium has been used successfully. The minimum purity of the carrier gas used must be 99.95 mol %.
7.2Standards for calibration and identification—Standards of all components to be analyzed and the internal standard are required for establishing identification by retention as well as calibration for quantitative measurements. These materials shall be of known purity and free of the other components to be analyzed.
Warning—These materials are flammable and may be harmful or fatal if ingested or inhaled.
7.3Preparation of calibration blends—For best results, these components must be added to a stock gasoline or petroleum naphtha, free of oxygenates (Warning—See Note 2). Refer to Test Method D 4307 for preparation of liquid blends. The preparation of several different blends, at different concentration levels covering the scope of the method, is recommended. These will be used to establish the linearity of the component response.
Warning—Extremely flammable. Vapors harmful if inhaled.
7.4Methylene chloride—Used for column preparation. Reagent grade, free of non-volatile residue.
Warning—Harmful if inhaled. High concentrations may cause unconsciousness or death.
8.1TCEP column packing:
8.1.1Any satisfactory method, used in the practice of the art that will produce a column capable of retaining the C
8.1.2Completely dissolve 10 g of TCEP in 100 mL of methylene chloride. Next add 40 g of 80/100 mesh Chromosorb P(AW) to the TCEP solution. Quickly transfer this mixture to a drying dish, in a fume hood, without scraping any of the residual packing from the sides of the container. Constantly, but gently, stir the packing until all of the solvent has evaporated. This column packing can be used immediately to prepare the TCEP column.
9.1Wash a straight 560 mm length of 1.6-mm outside diameter (0.38-mm inside diameter) stainless steel tubing with methanol and dry with compressed nitrogen.
9.2Insert 6 to 12 strands of silvered wire, a small mesh screen or stainless steel frit inside one end of the tube. Slowly add 0.14 to 0.15 g of packing material to the column and gently vibrate to settle the packing inside the column. When strands of wire are used to retain the packing material inside the column, leave 6.0 mm (0.25 in.) of space at the top of the column.
9.3Column conditioning—Both the TCEP and WCOT columns are to be briefly conditioned before use. Connect the columns to the valve (see 11.1) in the chromatographic oven. Adjust the carrier gas flows as in 11.3 and place the valve in the RESET position. After several minutes, increase the column oven temperature to 120 °C and maintain these conditions for 5 to 10 min. Cool the columns below 60 °C before shutting off the carrier flow.
10.1Gasoline samples to be analyzed by this test method shall be sampled in accordance with 40 CFR part 80, appendix D.
11.1Assembly—Connect the WCOT column to the valve system using low volume connectors and narrow bore tubing. It is important to minimize the volume of the chromatographic system that comes in contact with the sample, otherwise peak broadening will occur.
11.2Adjust the operating conditions to those listed in Table 1, but do not turn on the detector circuits. Check the system for leaks before proceeding further.
11.3Flow rate adjustment.
11.3.1Attach a flow measuring device to the column vent with the valve in the RESET position and adjust the pressure to the injection port to give 5.0 mL/min flow (14 psig). Soap bubble flow meters are suitable.
11.3.2Attach a flow measuring device to the split injector vent and adjust flow from the split vent using the A flow controller to give a flow of 70 mL/min. Recheck the column vent flow set in 11.3.1 and adjust if necessary.
11.3.3Switch the valve to the BACK-FLUSH position and adjust the variable restrictor to give the same column vent flow set in 11.3.1. This is necessary to minimize flow changes when the valve is switched.
11.3.4Switch the valve to the inject position RESET and adjust the B flow controller to give a flow of 3.0 to 3.2 mL/min at the detector exit. When required for the particular instrumentation used, add makeup flow or TCD switching flow to give a total of 21 mL/min at the detector exit.
11.4When a thermal conductivity detector is used, turn on the filament current and allow the detector to equilibrate. When a flame ionization detector is used, set the hydrogen and air flows and ignite the flame.
11.5Determine the Time of Backflush—The time to backflush will vary slightly for each column system and must be determined experimentally as follows. The start time of the integrator and valve timer must be synchronized with the injection to accurately reproduce the backflush time.
11.5.1Initially assume a valve BACK-FLUSH time of 0.23 min. With the valve RESET, inject 3 μL of a blend containing at least 0.5% or greater oxygenates (7.3), and simultaneously begin timing the analysis. At 0.23 min., rotate the valve to the BACKFLUSH position and leave it there until the complete elution of benzene is realized. Note this time as the RESET time, which is the time at which the valve is returned to the RESET position. When all of the remaining hydrocarbons are backflushed
11.5.2It is necessary to optimize the valve BACKFLUSH time by analyzing a standard blend containing oxygenates. The correct BACKFLUSH time is determined experimentally by using valve switching times between 0.2 and 0.3 min. When the valve is switched too soon, C
12.1Identification—Determine the retention time of each component by injecting small amounts either separately or in known mixtures or by comparing the relative retention times with those in Table 2.
12.2Standardization—The area under each peak in the chromatogram is considered a quantitative measure of the corresponding compound. Measure the peak area of each oxygenate and of the internal standard by either manual methods or electronic integrator. Calculate the relative volume response factor of each oxygenate, relative to the internal standard, according to Test Method D 4626.
13.1Preparation of sample—Precisely add a quantity of the internal standard to an accurately measured quantity of sample. Concentrations of 1 to 5 volume percent have been used successfully.
13.2Chromatographic analysis—Introduce a representative aliquot of the sample, containing internal standard, into the chromatograph using the same technique as used for the calibration analyses. An injection volume of 3 μL with a 15:1 split ratio has been used successfully.
13.3Interpretation of chromatogram—Compare the results of sample analyses to those of calibration analyses to determine identification of oxygenates present.
14.1After identifying the various oxygenates, measure the area of each oxygenate peak and that of the internal standard. Calculate the volume percent of each oxygenate as follows:
14.2Report the volume of each oxygenate. If the volume percent exceeds 10%, dilute the sample to a concentration lower than 10% and repeat the procedures in sections 13 and 14.
15.1Precision—The precision of this test method as determined by statistical examination of the interlaboratory test results is as follows:
15.1.1 Repeatability—The difference between successive results obtained by the same operator with the same apparatus under constant operating conditions on identical test materials would, in the long run, in the normal and correct operation of the test method exceed the following values only in one case in twenty (see Table 3).
15.1.2 Reproducibility—The difference between two single and independent results obtained by different operators working in different laboratories on identical material would, in the long run, exceed the following values only in one case in twenty (see Table 3).
15.2 Bias—Since there is no accepted reference material suitable for determining bias for the procedure in the test method, bias cannot be determined.
1.1This method covers procedures for obtaining representative samples of diesel fuel for the purpose of testing for compliance with the cetane index and sulfur percentage standards set forth in § 80.29.
2.1It is necessary that the samples be truly representative of the diesel fuel in question. The precautions required to ensure the representative character of the samples are numerous and depend upon the tank, carrier, container or line from which the sample is being obtained, the type and cleanliness of the sample container, and the sampling procedures that are to be used. A summary of the sampling procedures and their application is presented in Table 1. Each procedure is suitable for sampling a material under definite storage, transportation, or container conditions. The basic principle of each procedure is to obtain a sample in such manner and from such locations in the tank or other container that the sample will be truly representative of the diesel fuel.
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
4.1Sample containers may be clear or brown glass bottles, or cans. The clear glass bottle is advantageous because it may be examined visually for cleanliness, and also allows visual inspection of the sample for free water or solid impurities. The brown glass bottle affords some protection from light. Cans with the seams soldered on the exterior surface with a flux of rosin in a suitable solvent are preferred because such a flux is easily removed with diesel fuel, whereas many others are very difficult to remove. If such cans are not available, other cans made with a welded construction that are not affected by, and that do not affect, the diesel fuel being sampled are acceptable.
4.2Container closure. Cork or glass stoppers, or screw caps of plastic or metal may be used for glass bottles; screw caps only shall be used for cans to provide a vapor-tight closure seal. Corks must be of good quality, clean and free from holes and loose bits of cork. Never use rubber stoppers. Contact of the sample with the cork may be prevented by wrapping tin or aluminum foil around the cork before forcing it into the bottle.
Glass stoppers must be a perfect fit. Screw caps must be protected by a cork disk faced with tin or aluminum foil, or other material that will not affect petroleum or petroleum products. In addition, a phenolic cap with a teflon coated liner may be used.
4.3Cleaning procedure. The method of cleaning all sample containers must be consistent with the residual materials in the container and must produce sample containers that are clean and free of water, dirt, lint, washing compounds, naphtha, or other
New sample containers should be inspected and cleaned if necessary. Dry the container by either passing a current of clean, warm air through the container or by allowing it to air dry in a clean area at room temperature. When dry, stopper or cap the container immediately.
5.1Sampling apparatus is described in detail under each of the specific sampling procedures. Clean, dry, and free all sampling apparatus from any substance that might contaminate the material, using the procedure described in 4.3.
6.1When loading or discharging diesel fuel, take samples from both shipping and receiving tanks, and from the pipeline if required.
6.2Ship or barge tanks. Sample each product after the vessel is loaded or just before unloading.
6.3Tank cars. Sample the product after the car is loaded or just before unloading.
When taking samples from tanks suspected of containing flammable at-mos-pheres, precautions should be taken to guard against ignitions due to static electricity. Metal or conductive objects, such as gage tapes, sample containers, and thermometers, should not be lowered into or suspended in a compartment or tank which is being filled or immediately after cessation of pumping. A waiting period of approximately one minute will generally permit a substantial relaxation of the electrostatic charge; under certain conditions a longer period may be deemed advisable.
7.1Directions for sampling cannot be made explicit enough to cover all cases. Extreme care and good judgment are necessary to ensure samples that represent the general character and average condition of the material. Clean hands are important. Clean gloves may be worn but only when absolutely necessary, such as in cold weather, or when handling materials at high temperature, or for reasons of safety. Select wiping cloths so that lint is not introduced, contaminating samples.
7.2As many petroleum vapors are toxic and flammable, avoid breathing them or igniting them from an open flame or a spark produced by static. Follow all safety precautions specific to the material being sampled.
8.1Container outage. Never completely fill a sample container, but allow adequate room for expansion, taking into consideration the temperature of the liquid at the time of filling and the probable maximum temperature to which the filled container may be subjected.
9.1To prevent loss of liquid during shipment, and to protect against moisture and dust, cover with suitable vapor tight caps. The caps of all containers must be screwed down tightly and checked for leakage. Postal and express office regulations applying to the shipment of flammable liquids must be observed.
10.1Label the container immediately after a sample is obtained. Use waterproof and oilproof ink or a pencil hard enough to dent the tag, since soft pencil and ordinary ink markings are subject to obliteration from moisture, oil smearing and handling. An indelible identification symbol, such as a bar code, may be used in lieu of a manually addressed label. The label shall reference the following information:
10.1.1Date and time (the period elapsed during continuous sampling);
10.1.2Name of the sample;
10.1.3Name or number and owner of the vessel, car, or container;
10.1.4Brand and grade of material; and
10.1.5Reference symbol or identification number.
11.1The standard sampling procedures described in this method are summarized in Table 1. Alternative sampling procedures may be used if a mutually satisfactory agreement has been reached by the party(ies) involved and EPA and such agreement has been put in writing and signed by authorized officials.
11.2Bottle or beaker sampling. The bottle or beaker sampling procedure is applicable for sampling liquids of 16 pounds (1.12 kgf/cm
11.2.1Apparatus. A suitable sampling bottle or beaker as shown in figure 2 of appendix D is required.
11.2.2Procedure.
11.2.2.1All-levels sample. Lower the weighted, stoppered bottle or beaker as near as possible to the draw-off level, pull out the stopper with a sharp jerk of the cord or chain and raise the bottle at a uniform rate so that it is about
11.2.2.2Running sample. Lower the un-stoppered bottles or beaker as near as possible to the level of the bottom of the outlet connection or swing line and then raise the bottle or beaker to the top of the gasoline at a uniform rate of speed such that it is about
11.2.2.3Upper, middle, and lower samples. Lower the weighted, stoppered bottle to the proper depths (Figure 1 of appendix D) as follows:
At the selected level pull out the stopper with a sharp jerk of the cord or chain and allow the bottle or beaker to fill completely, as evidenced by the cessation of air bubbles. When full, raise the bottle or beaker, pour off a small amount, and stopper immediately.
11.2.2.4Top sample. Obtain this sample (Figure 1 of appendix D) in the same manner as specified in 11.2.2.3 but at six inches (150 mm) below the top surface of the tank contents.
11.2.2.5Handling. Stopper and label bottle samples immediately after taking them, and deliver to the laboratory in the original sampling bottles.
11.3Tap sampling. The tap sampling procedure is applicable for sampling liquids of twenty-six pounds (1.83 kgf/cm
11.3.1Apparatus
11.3.1.1Tank taps. The tank should be equipped with at least three sampling taps placed equidistant throughout the tank height and extending at least three feet (0.9 meter) inside the tank shell. A standard
11.3.1.2Tube. A delivery tube that will not contaminate the product being sampled and long enough to reach to the bottom of the sample container is required to allow submerged filling.
11.3.1.3Sample containers. Use clean, dry glass bottles of convenient size and strength or metal containers to receive the samples.
11.3.2Procedure
11.3.2.1Before a sample is drawn, flush the tap (or gage glass drain cock) and line until they are purged completely. Connect the clean delivery tube to the tap. Draw upper, middle, or lower samples directly from the respective taps after the flushing operation. Stopper and label the sample container immediately after filling, and deliver it to the laboratory.
11.4Continuous sampling. The continuous sampling procedure is applicable for sampling liquids of 16 pounds (1.12 kgf/cm
11.4.1Apparatus
11.4.1.1Sampling probe. The function of the sampling probe is to withdraw from the flow stream a portion that will be representative of the entire stream. The apparatus assembly for continuous sampling is shown in figure 4 of appendix D. Probe designs that are commonly used are as follows:
11.4.1.1.1A tube extending to the center of the line and beveled at a 45 degree angle facing upstream (Figure 4(a) of appendix D).
11.4.1.1.2A long-radius forged elbow or pipe bend extending to the center line of the pipe and facing upstream. The end of the probe should be reamed to give a sharp entrance edge (Figure 4(b) of appendix D).
11.4.1.1.3A closed-end tube with a round orifice spaced near the closed end which should be positioned in such a way that the orifice is in the center of the pipeline and is facing the stream as shown in figure 4(c) of appendix D.
11.4.1.2Probe location. Since the fluid to be sampled may not in all cases be homogeneous, the location, the position and the size of the sampling probe shoud be such as to minimize stratification or dropping out of heavier particles within the tube or the displacement of the product within the tube as a result of variation in gravity of the flowing stream. The sampling probe should be located preferably in a vertical run of pipe and as near as practicable to the point where the product passes to the receiver. The probe should always be in a horizontal position.
11.4.1.2.1The sampling lines should be as short as practicable and should be cleared before any samples are taken.
11.4.1.2.2Where adequate flowing velocity is not available, a suitable device for mixing the fluid flow to ensure a homogeneous mixture at all rates of flow and to eliminate stratification should be installed upstream of the sampling tap. Some effective devices for obtaining a homogeneous mixture are as follows: Reduction in pipe size; a series of baffles; orifice or perforated plate; and a combination of any of these methods.
11.4.1.2.3The design or sizing of these devices is optional with the user, as long as the
11.4.1.3To control the rate at which the sample is withdrawn, the probe or probes should be fitted with valves or plug cocks.
11.4.1.4Automatic sampling devices that meet the standards set out in 11.4.1.5 may be used in obtaining samples of diesel fuel. The quality of sample collected must be of sufficient size for analysis, and its composition should be identical with the composition of the batch flowing in the line while the sample is being taken. An automatic sampler installation necessarily includes not only the automatic sampling device that extracts the samples from the line, but also a suitable probe, connecting lines, auxiliary equipment, and a container in which the sample is collected. Automatic samplers may be classified as follows:
11.4.1.4.1Continuous sampler, time cycle (nonproportional) type. A sampler designed and operated in such a manner that it transfers equal increments of liquid from the pipeline to the sample container at a uniform rate of one or more increments per minute is a continuous sampler.
11.4.1.4.2Continuous sampler, flow-responsive (proportional) type. A sampler that is designed and operated in such a manner that it will automatically adjust the quantity of sample in proportion to the rate of flow is a flow-responsive (proportional) sampler. Adjustment of the quantity of sample may be made either by varying the frequency of transferring equal increments of sample to the sample container, or by varying the volume of the increments while maintaining a constant frequency of transferring the increments to the sample container. The apparatus assembly for continuous sampling is shown in figure 4 of appendix D.
11.4.1.4.3Intermittent sampler. A sampler that is designed and operated in such a manner that it transfers equal increments of liquid from a pipeline to the sample container at a uniform rate of less than one increment per minute is an intermittent sampler.
11.4.1.5Standards of installation. Automatic sampler installations should meet all safety requirements in the plant or area where used, and should comply with American National Standard Code for Pressure Piping, and other applicable codes (ANSI B31.1). The sampler should be so installed as to provide ample access space for inspection and maintenance.
11.4.1.5.1Small lines connecting various elements of the installation should be so arranged that complete purging of the automatic sampler and of all lines can be accomplished effectively. All fluid remaining in the sampler and the lines from the preceding sampling cycle should be purged immediately before the start of any given sampling operation.
11.4.1.5.2In those cases where the sampler design is such that complete purging of the sampling lines and the sampler is not possible, a small pump should be installed in order to circulate a continuous stream from the sampling tube past or through the sampler and back into the line. The automatic sampler should then withdraw the sample from the sidestream through the shortest possible connection.
11.4.1.5.3Under certain conditions, there may be a tendency for water and heavy particles to drop out in the discharge line from the sampling device and appear in the sample container during some subsequent sampling period. To circumvent this possibility, the discharge pipe from the sampling device should be free of pockets or enlarged pipe areas, and preferably should be pitched downward to the sample container.
11.4.1.5To ensure clean, free-flowing lines, piping should be designed for periodic cleaning.
11.4.1.6Field calibration. Composite samples obtained from the automatic sampler installation should be verified for quantity performance in a manner that meets with the approval of all parties concerned (including EPA), at least once a month and more often if conditions warrant. In the case of time-cycle samplers, deviations in quantity of the sample taken should not exceed
11.4.1.6.1The batch pumped during the test interval should be diverted into a clean tank and a sample taken within one hour after cessation of pumping.
11.4.1.6.2If the sampling of the delivery tank is to be delayed beyond one hour, then the tank selected must be equipped with an adequate mixing means. For valid comparison, the sampling of the delivery tank must be completed within eight hours after cessation of pumping, even though the tank is equipped with a motor-driven mixer.
11.4.1.6.3When making a normal full-tank delivery from a tank, a properly secured sample may be used to check the results of the sampler if the parties (including EPA) mutually agree to this procedure.
11.4.1.7Receiver. The receiver must be a clean, dry container of convenient size to receive the sample. All connections from the sample probe to the sample container must be free of leaks. Two types of container may
11.4.1.7.1Atmospheric container. The atmospheric container shall be constructed in such a way that it retards evaporation loss and protects the sample from extraneous material such as rain, snow, dust, and trash. The construction should allow cleaning, interior inspection, and complete mixing of the sample prior to removal. The container should be provided with a suitable vent.
11.4.1.7.2Closed container. The closed container shall be constructed in such a manner that it prevents evaporation loss. The construction must allow cleaning, interior inspection and complete mixing of the sample prior to removal. The container should be equipped with a pressure-relief valve.
11.4.2Procedure.
11.4.2.1Nonautomatic sample. Adjust the valve or plug cock from the sampling probe so that a steady stream is drawn from the probe. Whenever possible, the rate of sample withdrawal should be such that the velocity of liquid flowing through the probe is approximately equal to the average linear velocity of the stream flowing through the pipeline. Measure and record the rate of sample withdrawal as gallons per hour. Divert the sample stream to the sampling container continuously or intermittently to provide a quantity of sample that will be of sufficient size for analysis.
11.4.2.2Automatic sampling. Purge the sampler and the sampling lines immediately before the start of a sampling operation. If the sample design is such that complete purging is not possible, circulate a continuous stream from the probe past or through the sampler and back into the line. Withdraw the sample from the side stream through the automatic sampler using the shortest possible connections. Adjust the sampler to deliver not less than one and not more than 40 gallons (151 liters) of sample during the desired sampling period. For time-cycle samplers, record the rate at which sample increments were taken per minute. For flow-responsive samplers, record the proportion of sample to total stream. Label the samples and deliver them to the laboratory in the containers in which they were collected.
11.5Nozzle sampling. The nozzle sampling procedure is applicable for sampling diesel fuel from a retail outlet or wholesale purchaser-consumer facility storage tank.
11.5.1Apparatus. Sample containers conforming with 4.1 should be used. A spacer, if appropriate (Figure 6 of appendix D), and a nozzle extension device similar to that shown in figures 7 or 7a of appendix D shall be used when nozzle sampling. The nozzle extension device does not need to be identical to that shown in figure 7 or 7a of appendix D but it should be a device that will bottom fill the container.
11.5.2Procedure. Immediately after diesel fuel has been delivered from the pump and the pump has been reset, deliver a small amount of product into the sample container. Rinse sample container and dump product into waste container. Insert nozzle extension (Figure 7 or 7a of appendix D) into sample container and insert pump nozzle into extension with slot over air bleed hole. Fill slowly through nozzle extension to 70-80 percent full (Figure 8 of appendix D). Remove nozzle extension. Cap sample container at once. Check for leaks.
12.1Precautions. Official samples should be taken by, or under the immediate supervision of, a person of judgment, skill, and sampling experience. Never prepare composite samples for this test. Make certain that containers which are to be shipped by common carrier conform to applicable Interstate Commerce Commission, State, and local regulations. When flushing or purging lines or containers, observe the pertinent regulations and precautions against fire, explosion, and other hazards.
12.2Sample containers. Use containers of not less than one quart (0.9 liter) nor more than two gallons (7.6 liters) capacity, of sufficient strength to withstand the pressure to which they may be subjected. Open-type containers have a single opening which permits sampling by immersion. Closed-type containers have two openings, one in each end (or the equivalent thereof), fitted with valves suitable for sampling by water displacement or by purging.
12.3Transfer connections. The transfer connection for the open-type container consists of an air tube and a liquid delivery tube assembled in a cap or stopper. The air tube extends to the bottom of the container. One end of the liquid delivery tube is long enough to reach the bottom of the diesel fuel chamber while the sample is being transferred to the chamber. The transfer connection for the closed-type container consists of a single tube with a connection suitable for attaching it to one of the openings of the sample container. The tube is long enough to reach the bottom of the diesel chamber while the sample is being transferred.
12.4Sampling open tanks. Use clean containers of the open type when sampling open tanks and tank cars. An all-level sample obtained by the bottle procedure described in 11.2 is recommended. Before taking the sample, flush the container by immersing it in the product to be sampled. Then obtain the sample immediately. Pour off enough so that the container will be 70-80 percent full and close it promptly. Label the container and deliver it to the laboratory.
12.5Sampling closed tanks. Containers of either the open or closed type may be used to obtain samples from closed or pressure
12.6Water displacement procedure. Completely fill the closed-type container with water and close the valves. While permitting a small amount of product to flow through the fittings, connect the top or inlet valve of the container to the tank sampling tap or valve. Then open all valves on the inlet side of the container. Open the bottom or outlet valve slightly to allow the water to be displaced slowly by the sample entering the container. Regulate the flow so that there is no appreciable change in pressure within the container. Close the outlet valve as soon as diesel fuel discharges from the outlet; then in succession close the inlet valve and the sampling valve on the tank. Disconnect the container and withdraw enough of the contents so that it will be 70-80 percent full. If the vapor pressure of the product is not high enough to force liquid from the container, open both the upper and lower valves slightly to remove the excess. Promptly seal and label the container, and deliver it to the laboratory.
12.7Purging procedure. Connect the inlet valve of the closed-type container to the tank sampling tap or valve. Throttle the outlet valve of the container so that the pressure in it will be approximately equal to that in the container being sampled. Allow a volume of product equal to at least twice that of the container to flow through the sampling system. Then close all valves, the outlet valve first, the inlet valve of the container second, and the tank sampling valve last, and disconnect the container immediately. Withdraw enough of the contents so that the sample container will be 70-80 percent full. If the vapor pressure of the product is not high enough to force liquid from the container, open both the upper and lower valves slightly to remove the excess. Promptly seal and label the container, and deliver it to the laboratory.