AIR PROGRAMS-(Continued)

SUBCHAPTER C—AIR PROGRAMS—(Continued) Pt. 72 PART 72—PERMITS REGULATION Subpart A—Acid Rain Program General Provisions Sec. 72.1 Purpose and scope. 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. 72.11 Computation of time. 72.12 Administrative appeals. 72.13 Incorporation by reference. 72.14 Industrial utility-units exemption. Subpart B—Designated Representative 72.20 Authorization and responsibilities of the designated representative. 72.21 Submissions. 72.22 Alternate designated representative. 72.23 Changing the designated representative, alternate designated representative; changes in the owners and operators. 72.24 Certificate of representation. 72.25 Objections. Subpart C—Acid Rain Permit Applications 72.30 Requirement to apply. 72.31 Information requirements for Acid Rain permit applications. 72.32 Permit application shield and binding effect of permit application. 72.33 Identification of dispatch system. Subpart D—Acid Rain Compliance Plan and Compliance Options 72.40 General. 72.41 Phase I substitution plans. 72.42 Phase I extension plans. 72.43 Phase I reduced utilization plans. 72.44 Phase II repowering extensions. Subpart E—Acid Rain Permit Contents 72.50 General. 72.51 Permit shield. Subpart F—Federal Acid Rain Permit Issuance Procedures 72.60 General. 72.61 Completeness. 72.62 Draft permit. 72.63 Administrative record. 72.64 Statement of basis. 72.65 Public notice of opportunities for public comment. 72.66 Public comments. 72.67 Opportunity for public hearing. 72.68 Response to comments. 72.69 Issuance and effective date of acid rain permits. Subpart G—Acid Rain Phase II Implementation 72.70 Relationship to title V operating permit program. 72.71 Acceptance of State Acid Rain programs—general. 72.72 Criteria for State operating permit program. 72.73 State issuance of Phase II permits. 72.74 Federal issuance of Phase II permits. Subpart H—Permit Revisions 72.80 General. 72.81 Permit modifications. 72.82 Fast-track modifications. 72.83 Administrative permit amendment. 72.84 Automatic permit amendment. 72.85 Permit reopenings. Subpart I—Compliance Certification 72.90 Annual compliance certification report. 72.91 Phase I unit adjusted utilization. 72.92 Phase I unit allowance surrender. 72.93 Units with Phase I extension plans. 72.94 Units with repowering extension plans. 72.95 Allowance deduction formula. 72.96 Administrator's action on compliance certifications. Appendix A to Part 72—Methodology for Annualization of Emissions Limits Appendix B to Part 72—Methodology for Conversion of Emissions Limits Appendix C to Part 72—Actual 1985 Yearly SO 2 Emissions Calculation Appendix D to Part 72—Calculation of Potential Electric Output Capacity Authority:

42 U.S.C. 7601 and 7651 et seq.

Source:

58 FR 3650, Jan. 11, 1993, unless otherwise noted.

Subpart A—Acid Rain Program General Provisions

§ 72.1 Purpose and scope.

(a) Purpose. The purpose of this part is to establish certain general provisions and the operating permit program requirements for affected sources and affected units under the Acid Rain Program, pursuant to title IV of the Clean Air Act, 42 U.S.C. 7401, et seq., as amended by Public Law 101-549 (November 15, 1990).

(b) Scope. The regulations under this part set forth certain generally applicable provisions under the Acid Rain Program. The regulations also set forth requirements for obtaining three types of Acid Rain permits, during Phases I and II, for which an affected source may apply: Acid Rain permits issued by the United States Environmental Protection Agency during Phase I; the Acid Rain portion of an operating permit issued by a State permitting authority during Phase II; and the Acid Rain portion of an operating permit issued by EPA when it is the permitting authority during Phase II. The requirements under this part supplement, and in some cases modify, the requirements under parts 70 and 71 of this chapter and other regulations implementing title V for approving and implementing State operating permit programs and for Federal issuance of operating permits under title V, as such requirements apply to affected sources under the Acid Rain Program.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55475, Oct. 24, 1997]

§ 72.2 Definitions.

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:

Account number means the identification number given by the Administrator to each Allowance Tracking System account pursuant to § 73.31(d) of this chapter.

Acid Rain compliance option means one of the methods of compliance used by an affected unit under the Acid Rain Program as described in a compliance plan submitted and approved in accordance with subpart D of this part, part 74 of this chapter or part 76 of this chapter.

Acid Rain emissions limitation means:

(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.

Acid Rain emissions reduction requirement means a requirement under the Acid Rain Program to reduce the emissions of sulfur dioxide or nitrogen oxides from a unit to a specified level or by a specified percentage.

Acid Rain permit or permit means the legally binding written document or portion of such document, including any permit revisions, that is issued by a permitting authority under this part and specifies the Acid Rain Program requirements applicable to an affected source and to the owners and operators and the designated representative of the affected source or the affected unit.

Acid Rain Program means the national sulfur dioxide and nitrogen oxides air pollution control and emissions reduction program established in accordance with title IV of the Act, this part, and parts 73, 74, 75, 76, 77, and 78 of this chapter.

Act means the Clean Air Act, 42 U.S.C. 7401, et seq. as amended by Public Law No. 101-549 (November 15, 1990).

Actual SO 2 emissions rate means the annual average sulfur dioxide emissions rate for the unit (expressed in lb/mmBtu), for the specified calendar year; provided that, if the unit is listed in the NADB, the “1985 actual SO2 emissions rate” for the unit shall be the rate specified by the Administrator in the NADB under the data field “SO2RTE.”

Add-on control means a pollution reduction control technology that operates independent of the combustion process.

Additional advance auction means the auction of advance allowances that were offered the previous year for sale in an advance sale.

Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator's duly authorized representative.

Advance allowance means an allowance that may be used for purposes of compliance with a unit's Acid Rain sulfur dioxide emissions limitation requirements beginning no earlier than seven years following the year in which the allowance is first offered for sale.

Advance auction means an auction of advance allowances.

Advance sale means a sale of advance allowances.

Affected source means a source that includes one or more affected units.

Affected States means any affected States as defined in part 71 of this chapter.

Affected unit means a unit that is subject to any Acid Rain emissions reduction requirement or Acid Rain emissions limitation under § 72.6 or part 74 of this chapter.

Affiliate shall have the meaning set forth in section 2(a)(11) of the Public Utility Holding Company Act of 1935, 15 U.S.C. 79b(a)(11), as of November 15, 1990.

Allocate or allocation means the initial crediting of an allowance by the Administrator to an Allowance Tracking System unit account or general account.

Allowable SO 2 emissions rate means the most stringent federally enforceable emissions limitation for sulfur dioxide (in lb/mmBtu) applicable to the unit or combustion source for the specified calendar year, or for such subsequent year as determined by the Administrator where such a limitation does not exist for the specified year; provided that, if a Phase I or Phase II unit is listed in the NADB, the “1985 allowable SO2 emissions rate” for the Phase I or Phase II unit shall be the rate specified by the Administrator in the NADB under the data field “1985 annualized boiler SO2 emission limit.”

Allowance means an authorization by the Administrator under the Acid Rain Program to emit up to one ton of sulfur dioxide during or after a specified calendar year.

Allowance deduction, or deduct when referring to allowances, means the permanent withdrawal of allowances by the Administrator from an Allowance Tracking System compliance subaccount, or future year subaccount, to account for the number of tons of SO2 emissions from an affected unit for the calendar year, for tonnage emissions estimates calculated for periods of missing data as provided in part 75 of this chapter, or for any other allowance surrender obligations of the Acid Rain Program.

Allowances held or hold allowances means the allowances recorded by the Administrator, or submitted to the Administrator for recordation in accordance with § 73.50 of this chapter, in an Allowance Tracking System account.

Allowance reserve means any bank of allowances established by the Administrator in the Allowance Tracking System pursuant to sections 404(a)(2) (Phase I extension reserve), 404(g) (energy conservation and renewable energy reserve), or 416(b) (special allowance reserve) of the Act, and implemented in accordance with part 73, subpart B of this chapter.

Allowance Tracking System or ATS means the Acid Rain Program system by which the Administrator allocates, records, deducts, and tracks allowances.

Allowance Tracking System account means an account in the Allowance Tracking System established by the Administrator for purposes of allocating, holding, transferring, and using allowances.

Allowance transfer deadline means midnight of March 1 (or February 29 in any leap year) or, if such day is not a business day, midnight of the first business day thereafter and is the deadline by which allowances may be submitted for recordation in an affected unit's compliance subaccount for the purposes of meeting the unit's Acid Rain emissions limitation requirements for sulfur dioxide for the previous calendar year.

Alternative monitoring system means a system or a component of a system designed to provide direct or indirect data of mass emissions per time period, pollutant concentrations, or volumetric flow, that is demonstrated to the Administrator as having the same precision, reliability, accessibility, and timeliness as the data provided by a certified CEMS or certified CEMS component in accordance with part 75 of this chapter.

As-fired means the taking of a fuel sample just prior to its introduction into the unit for combustion.

Auction subaccount means a subaccount in the Special Allowance Reserve, as specified in section 416(b) of the Act, which contains allowances to be sold at auction in the amount of 150,000 per year from calendar year 1995 through 1999, inclusive, and 200,000 per year for each year begnning in calendar year 2000, subject to the adjustments noted in the regulations in part 73, subpart E of this chapter.

Authorized account representative means a responsible natural person who is authorized, in accordance with part 73 of this chapter, to transfer and otherwise dispose of allowances held in an Allowance Tracking System general account; or, in the case of a unit account, the designated representative of the owners and operators of the affected unit.

Automated data acquisition and handling system means that component of the CEMS, COMS, or other emissions monitoring system approved by the Administrator for use in the Acid Rain Program, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, opacity monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by part 75 of this chapter.

Award means the conditional set-aside by the Administrator, based on the submission of an early ranking application pursuant to subpart D of this part, of an allowance from the Phase I extension reserve, for possible future allocation to a Phase I extension applicant's Allowance Tracking System unit account.

Backup fuel means a fuel for a unit where: (1) For purposes of the requirements of the monitoring exception of appendix E of part 75 of this chapter, the fuel provides less than 10.0 percent of the heat input to a unit during the three calendar years prior to certification testing for the primary fuel and the fuel provides less than 15.0 percent of the heat input to a unit in each of those three calendar years; or the Administrator approves the fuel as a backup fuel; and (2) For all other purposes under the Acid Rain Program, a fuel that is not the primary fuel (expressed in mmBtu) consumed by an affected unit for the applicable calendar year.

Baseline means the annual average quantity of fossil fuel consumed by a unit, measured in millions of British Thermal Units (expressed in mmBtu) for calendar years 1985 through 1987; provided that in the event that a unit is listed in the NADB, the baseline will be calculated for each unit-generator pair that includes the unit, and the unit's baseline will be the sum of such unit-generator baselines. The unit-generator baseline will be as provided in the NADB under the data field “BASE8587”, as adjusted by the outage hours listed in the NADB under the data field “OUTAGEHR” in accordance with the following equation:

Baseline = BASE8587 × {26280 / (26280 − OUTAGEHR)} × {36 / (36 − months not on line)} × 106

“Months not on line” is the number of months during January 1985 through December 1987 prior to the commencement of firing for units that commenced firing in that period, i.e., the number of months, in that period, prior to the on-line month listed under the data field “BLRMNONL” and the on-line year listed in the data field “BLRYRONL” in the NADB.

Basic Phase II allowance allocations means:

(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).

Bias means systematic error, resulting in measurements that will be either consistently low or high relative to the reference value.

Boiler means an enclosed fossil or other fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or any other medium.

Bypass operating quarter means a calendar quarter during which emissions pass through a stack, duct or flue that bypasses add-on emission controls.

By-pass stack means any duct, stack, or conduit through which emissions from an affected unit may or do pass to the atmosphere, which either augments or substitutes for the principal stack exhaust system or ductwork during any portion of the unit's operation.

Calibration error means the difference between:

(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.

Calibration gas means:

(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.

Capacity factor means either: (1) the ratio of a unit's actual annual electric output (expressed in MWe-hr) to the unit's nameplate capacity times 8760 hours, or (2) the ratio of a unit's annual heat input (in million British thermal units or equivalent units of measure) to the unit's maximum design heat input (in million British thermal units per hour or equivalent units of measure) times 8,760 hours.

CEMS precision or precision as applied to the monitoring requirements of part 75 of this chapter, means the closeness of a measurement to the actual measured value expressed as the uncertainty associated with repeated measurements of the same sample or of different samples from the same process (e.g., the random error associated with simultaneous measurements of a process made by more than one instrument). A measurement technique is determined to have increasing “precision” as the variation among the repeated measurements decreases.

Centroidal area means a representational concentric area that is geometrically similar to the stack or duct cross section, and is not greater than 1 percent of the stack or duct cross-sectional area.

Certificate of representation means the completed and signed submission required by § 72.20, for certifying the appointment of a designated representative for an affected source or a group of identified affected sources authorized to represent the owners and operators of such source(s) and of the affected units at such source(s) with regard to matters under the Acid Rain Program.

Certifying official, for purposes of part 73 of this chapter, means:

(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.

Coal means all solid fuels classified as anthracite, bituminous, sub-bi-tum-in-ous, or lignite by the American Society for Testing and Materials Designation ASTM D388-92 “Standard Classification of Coals by Rank” (as incorporated by reference in § 72.13).

Coal-derived fuel means any fuel, whether in a solid, liquid, or gaseous state, produced by the mechanical, thermal, or chemical processing of coal (e.g., pulverized coal, coal refuse, liquified or gasified coal, washed coal, chemically cleaned coal, coal-oil mixtures, and coke).

Coal-fired means the combustion of fuel consisting of coal or any coal-derived fuel (except a coal-derived gaseous fuel that meets the definition of “very low sulfur fuel” in this section), alone or in combination with any other fuel, where:

(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); provided that, if the unit is listed in the NADB, the primary fuel is the fuel listed in the NADB under the data field “PRIMEFUEL”.

Cogeneration unit means a unit that has equipment used to produce electric energy and forms of useful thermal energy (such as heat or steam) for industrial, commercial, heating or cooling purposes, through the sequential use of energy.

Combustion source means a stationary fossil fuel fired boiler, turbine, or internal combustion engine that has submitted or intends to submit an opt-in permit application under § 74.14 of this chapter to enter the Opt-in Program.

Commence commercial operation means to have begun to generate electricity for sale, including the sale of test generation.

Commence construction means that an owner or operator has either undertaken a continuous program of construction or has entered into a contractual obligation to undertake and complete, within a reasonable time, a continuous program of construction.

Commence operation means to have begun any mechanical, chemical, or electronic process, including start-up of an emissions control technology or emissions monitor or of a unit's combustion chamber.

Common stack means the exhaust of emissions from two or more units through a single flue.

Compensating unit means an affected unit that is not otherwise subject to Acid Rain emissions limitation or Acid Rain emissions reduction requirements during Phase I and that is designated as a Phase I unit in a reduced utilization plan under § 72.43; provided that an opt-in source shall not be a compensating unit.

Compliance certification means a submission to the Administrator or permitting authority, as appropriate, that is required by this part, by part 73, 74, 75, 76, 77, or 78 of this chapter, to report an affected source or an affected unit's compliance or non-compliance with a provision of the Acid Rain Program and that is signed and verified by the designated representative in accordance with subparts B and I of this part and the Acid Rain Program regulations generally.

Compliance plan, for the purposes of the Acid Rain Program, means the document submitted for an affected source in accordance with subpart C of this part or subpart E of part 74 of this chapter, or part 76 of this chapter, specifying the method(s) (including one or more Acid Rain compliance options as provided under subpart D of this part or subpart E of part 74 of this chapter, or part 76 of this chapter by which each affected unit at the source will meet the applicable Acid Rain emissions limitation and Acid Rain emissions reduction requirements.

Compliance subaccount means the subaccount in an affected unit's Allowance Tracking System account, established pursuant to § 73.31 (a) or (b) of this chapter, in which are held, from the date that allowances for the current calendar year are recorded under § 73.34(a) until December 31, allowances available for use in the current calendar year and, after December 31 until the date that deductions are made under § 73.35(b), allowances available for use by the unit in the preceding calendar year, for the purpose of meeting the Acid Rain emissions limitation for sulfur dioxide.

Compliance use date means the first calendar year for which an allowance may be used for purposes of meeting a unit's Acid Rain emissions limitation for sulfur dioxide.

Conditionally valid data means data from a continuous monitoring system that are not quality assured, but which may become quality assured if certain conditions are met. Examples of data that may qualify as conditionally valid are: data recorded by an uncertified monitoring system prior to its initial certification; or data recorded by a certified monitoring system following a significant change to the system that may affect its ability to accurately measure and record emissions. A monitoring system must pass a probationary calibration error test, in accordance with section 2.1.1 of appendix B to part 75 of this chapter, to initiate the conditionally valid data status. In order for conditionally valid emission data to become quality assured, one or more quality assurance tests or diagnostic tests must be passed within a specified time period in accordance with § 75.20(b)(3).

Conservation Verification Protocol means a methodology developed by the Administrator for calculating the kilowatt hour savings from energy conservation measures and improved unit efficiency measures for the purposes of title IV of the Act.

Construction means fabrication, erection, or installation of a unit or any portion of a unit.

Consumer Price Index or CPI means, for purposes of the Acid Rain Program, the U.S. Department of Labor, Bureau of Labor Statistics unadjusted Con-sum-er Price Index for All Urban Consumers for the U.S. city average, for All Items on the latest reference base, or if such index is no longer published, such other index as the Administrator in his or her discretion determines meets the requirements of the Clean Air Act Amendments of 1990.

(1) CPI (1990) means the CPI for all urban consumers for the month of August 1989. The “CPI (1990)” is 124.6 (with 1982-1984=100). Beginning in the month for which a new reference base is established, “CPI (1990)” will be the CPI value for August 1989 on the new reference base.

(2) CPI (year) means the CPI for all urban consumers for the month of August of the previous year.

Continuous emission monitoring system or CEMS means the equipment required by part 75 of this chapter used to sample, analyze, measure, and provide, by readings taken at least once every 15 minutes, a permanent record of emissions, expressed in pounds per hour (lb/hr) for sulfur dioxide and in pounds per million British thermal units (lb/mmBtu) for nitrogen oxides. The following systems are component parts included in a continuous emission monitoring system:

(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.

Continuous opacity monitoring system or COMS means the equipment required by part 75 of this chapter to sample, measure, analyze, and provide, with readings taken at least once every 6 minutes, a permanent record of opacity or transmittance. The following systems are component parts included in a continuous opacity monitoring system:

(1) Opacity monitor; and

(2) A data acquisition and handling system.

Control unit means a unit employing a qualifying Phase I technology in accordance with a Phase I extension plan under § 72.42.

Current year subaccount means the subaccount in an Allowance Tracking System general account, established pursuant to § 73.31(c) of this chapter, in which are held allowances that may be transferred to a unit's compliance subaccount for use for the purpose of meeting the Acid Rain sulfur dioxide emissions limitation.

Customer means a purchaser of electricity not for the purposes of retransmission or resale. For generating rural electrical cooperatives, the customers of the distribution cooperatives served by the generating cooperative will be considered customers of the generating cooperative.

Decisional body means any EPA employee who is or may reasonably be expected to act in a decision-making role in a proceeding under part 78 of this chapter, including the Administrator, a member of the Environmental Appeals Board, and a Presiding Officer, and any staff of any such person who are participating in the decisional process.

Demand-side measure means a measure:

(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.

Designated representative means a responsible natural person authorized by the owners and operators of an affected source and of all affected units at the source or by the owners and operators of a combustion source or process source, as evidenced by a certificate of representation submitted in accordance with subpart B of this part, to represent and legally bind each owner and operator, as a matter of Federal law, in matters pertaining to the Acid Rain Program. Whenever the term “responsible official” is used in part 70 of this chapter, in any other regulations implementing title V of the Act, or in a State operating permit program, it shall be deemed to refer to the “designated representative” with regard to all matters under the Acid Rain Program.

Desulfurization refers to various procedures whereby sulfur is removed from petroleum during or apart from the refining process. “Desulfurization” does not include such processes as dilution or blending of low sulfur content diesel fuel with high sulfur content diesel fuel from a diesel refinery not eligible under 40 CFR part 73, subpart G.

Diesel-fired unit means, for the purposes of part 75 of this chapter, an oil-fired unit that combusts diesel fuel as its fuel oil, where the supplementary fuel, if any, shall be limited to natural gas or gaseous fuels containing no more sulfur than natural gas.

Diesel fuel means a low sulfur fuel oil of grades 1-D or 2-D, as defined by the American Society for Testing and Materials standard ASTM D975-91, “Standard Specification for Diesel Fuel Oils,” grades 1-GT or 2-GT, as defined by ASTM D2880-90a, “Standard Specification for Gas Turbine Fuel Oils,” or grades 1 or 2, as defined by ASTM D396-90a, “Standard Specification for Fuel Oils” (incorporated by reference in § 72.13).

Diesel reciprocating engine unit means an internal combustion engine that combusts only diesel fuel and that thereby generates electricity through the operation of pistons, rather than by heating steam or water.

Diluent gas means a major gaseous constituent in a gaseous pollutant mixture, which in the case of emissions from fossil fuel-fired units are carbon dioxide and oxygen.

Diluent gas monitor means that component of the continuous emission monitoring system that measures the diluent gas concentration in a unit's flue gas.

Direct public utility ownership means direct ownership of equipment and facilities by one or more corporations, the principal business of which is sale of electricity to the public at retail. Percentage ownership of such equipment and facilities shall be measured on the basis of book value.

Direct Sale Subaccount means a subaccount in the Special Allowance Reserve, as specified in section 416(b) of the Act, which contains Phase II allowances to be sold in the amount of 25,000 per year, from calendar year 1993 to 1999, inclusive, and of 50,000 per year for each year beginning in calendar year 2000, subject to the adjustments noted in the regulations at part 73, subpart E of this chapter.

Dispatch means the assignment within a dispatch system of generating levels to specific units and generators to effect the reliable and economical supply of electricity, as customer demand rises or falls, and includes:

(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.

Draft Acid Rain permit or draft permit means the version of the Acid Rain permit, or the Acid Rain portion of an operating permit, that a permitting authority offers for public comment.

Dual-fuel reciprocating engine unit means an internal combustion engine that combusts any combination of natural gas and diesel fuel and that thereby generates electricity through the operation of pistons, rather than by heating steam or water.

Eligible Indian tribe means any eligible Indian tribe as defined in part 71 of this chapter.

Emergency fuel means either:

(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.

Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative and as determined by the Administrator, in accordance with the emissions monitoring requirements of part 75 of this chapter.

Environmental Appeals Board means the three-member board established pursuant to § 1.25(e) of this chapter and authorized to hear appeals pursuant to part 78 of this chapter.

EPA means the United States Environmental Protection Agency.

EPA protocol gas means a calibration gas mixture prepared and analyzed according to section 2 of the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, EPA-600/R-97/121 or such revised procedure as approved by the Administrator.

EPA trial staff means an employee of EPA, whether temporary or permanent, who has been designated by the Administrator to investigate, litigate, and present evidence, arguments, and positions of EPA in any evidentiary hearing under part 78 of this chapter. Any EPA or permitting authority employee, consultant, or contractor who is called as a witness in the evidentiary hearing by EPA trial staff shall be deemed to be “EPA trial staff”.

Equivalent diameter means a value, calculated using the equation in paragraph 2.1 of Method 1 in part 60, appendix A of this chapter, and used to determine the upstream and downstream distances for locating CEMS or CEMS components in flues or stacks with rectangular cross sections.

Ex parte communication means any communication, written or oral, relating to the merits of an adjudicatory proceeding under part 78 of this chapter, that was not originally included or stated in the administrative record, in a pleading, or in an evidentiary hearing or oral argument under part 78 of this chapter, between the decisional body and any interested person outside EPA or any EPA trial staff. Ex parte communication shall not include:

(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.

Excepted monitoring system means a monitoring system that follows the procedures and requirements of § 75.19 of this chapter or of appendix D or E to part 75 for approved exceptions to the use of continuous emission monitoring systems.

Excess emissions means:

(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.

Existing unit means a unit (including a unit subject to section 111 of the Act) that commenced commercial operation before November 15, 1990 and that on or after November 15, 1990 served a generator with nameplate capacity of greater than 25 MWe. “Existing unit” does not include simple combustion turbines or any unit that on or after November 15, 1990 served only generators with a nameplate capacity of 25 MWe or less. Any “existing unit” that is modified, reconstructed, or repowered after November 15, 1990 shall continue to be an “existing unit.”

Facility means any institutional, commercial, or industrial structure, installation, plant, source, or building.

File means to send or transmit a document, information, or correspondence to the official custody of the person specified to take possession in accordance with the applicable regulation. Compliance with any “filing” deadline shall be determined by the date that person receives the document, information, or correspondence.

Flow meter accuracy means the closeness of the measurement made by a flow meter to the reference value of the fuel flow being measured, expressed as the difference between the measurement and the reference value.

Flow monitor means a component of the continuous emission monitoring system that measures the volumetric flow of exhaust gas.

Flue means a conduit or duct through which gases or other matter are exhausted to the atmosphere.

Flue gas desulfurization system means a type of add-on emission control used to remove sulfur dioxide from flue gas, commonly referred to as a “scrubber.”

Forced outage means the removal of a unit from service due to an unplanned component failure or other unplanned condition that requires such removal immediately or within 7 days from the onset of the unplanned component failure or condition. For purposes of §§ 72.43, 72.91, and 72.92, “forced outage” also includes a partial reduction in the heat input or electrical output due to an unplanned component failure or other unplanned condition that requires such reduction immediately or within 7 days from the onset of the unplanned component failure or condition.

Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.

Fossil fuel-fired means the combustion of fossil fuel or any derivative of fossil fuel, alone or in combination with any other fuel, independent of the percentage of fossil fuel consumed in any calendar year (expressed in mmBtu).

Fuel flowmeter QA operating quarter means a unit operating quarter in which the unit combusts the fuel measured by the fuel flowmeter for at least 168 unit operating hours (as defined in this section) or more.

Fuel oil means any petroleum-based fuel (including diesel fuel or petroleum derivatives such as oil tar) as defined by the American Society for Testing and Materials in ASTM D396-90a, “Standard Specification for Fuel Oils” (incorporated by reference in § 72.13), and any recycled or blended petroleum products or petroleum by-products used as a fuel whether in a liquid, solid or gaseous state; provided that for purposes of the monitoring requirements of part 75 of this chapter, “fuel oil” shall be limited to the petroleum-based fuels for which applicable ASTM methods are specified in Appendices D, E, or F of part 75 of this chapter.

Fuel supply agreement means a legally binding agreement between a new IPP or a firm associated with a new IPP and a fuel supplier that establishes the terms and conditions under which the fuel supplier commits to provide fuel to be delivered to the new IPP.

Future year subaccount means a subaccount in an Allowance Tracking System account, established by the Administrator pursuant to § 73.31 of this chapter, in which allowances are held for one of the 30 years following the later of 1995 or a current calendar year following 1995.

Gas-fired means:

(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 input is from the combustion of gaseous fuels and the remaining heat input is from the combustion of fuel oil, and a statement that this changed pattern of fuel usage is considered permanent and is projected to continue for the foreseeable future.

(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.

Gas manufacturer's intermediate standard (GMIS) means a compressed gas calibration standard that has been assayed and certified by direct comparison to a standard reference material (SRM), an SRM-equivalent PRM, a NIST/EPA-approved certified reference material (CRM), or a NIST traceable reference material (NTRM), in accordance with section 2.1.2.1 of the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, EPA-600/R-97/121.

Gaseous fuel means a material that is in the gaseous state at standard atmospheric temperature and pressure conditions and that is combusted to produce heat.

General account means an Allowance Tracking System account that is not a unit account.

Generator means a device that produces electricity and was or would have been required to be reported as a generating unit pursuant to the United States Department of Energy Form 860 (1990 edition).

Generator Output capacity means the full-load continuous rating of a generator under specific conditions as designed by the manufacturer.

Hearing clerk means an EPA employee designated by the Administrator to establish a repository for all books, records, documents, and other materials relating to proceedings under part 78 of this chapter.

Heat input means the product (expressed in mmBtu/time) of the gross calorific value of the fuel (expressed in Btu/lb) and the fuel feed rate into the combustion device (expressed in mass of fuel/time) and does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.

Hour before and after means, for purposes of the missing data substitution procedures of part 75 of this chapter, the quality-assured hourly SO2 or CO2 concentration, hourly flow rate, or hourly NOX emission rate recorded by a certified monitor during the unit operating hour immediately before and the unit operating hour immediately after a missing data period.

Hybrid generation facility means a plant that generates electrical energy derived from a combination of qualified renewable energy (wind, solar, biomass, or geothermal) and one or more other energy resources.

Independent auditor means a professional engineer who is not an employee or agent of the source being audited.

Independent Power Production Facility (IPP) means a source that:

(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 Air Act; but only if direct public utility ownership of the equipment comprising the facility does not exceed 50 percent.

Interested person means any person who submitted written comments or testified at a public hearing on the draft permit or other matter subject to notice and comment under the Acid Rain Program or any person who submitted his or her name to the Administrator or the permitting authority, as appropriate, to be placed on a list of persons interested in such matter. The Administrator or the permitting authority may update the list of interested persons from time to time by requesting additional written indication of continued interest from the persons listed and may delete from the list the name of any person failing to respond as requested.

Investor-owned utility means a utility that is organized as a tax-paying for-profit business.

Kilowatthour saved or savings means the net savings in electricity use (expressed in Kwh) that result directly from a utility's energy conservation measures or programs.

Least-cost plan or least-cost planning process means an energy conservation and electric power planning methodology meeting the requirements of § 73.82(a)(4) of this chapter.

Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified generating unit and pays its proportional amount of such unit's total costs, pursuant to a contract:

(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.

Low mass emissions unit means an affected unit that is a gas-fired or oil-fired unit, burns only natural gas or fuel oil and qualifies under § 75.19 of this chapter.

Mail or serve by mail means to submit or serve by means other than personal service.

Maximum potential hourly heat input means an hourly heat input used for reporting purposes when a unit lacks certified monitors to report heat input. If the unit intends to use appendix D of part 75 of this chapter to report heat input, this value should be calculated, in accordance with part 75 of this chapter, using the maximum fuel flow rate and the maximum gross calorific value. If the unit intends to use a flow monitor and a diluent gas monitor, this value should be reported, in accordance with part 75 of this chapter, using the maximum potential flow rate and either the maximum carbon dioxide concentration (in percent CO2) or the minimum oxygen concentration (in percent O2).

Maximum potential NO X emission rate means the emission rate of nitrogen oxides (in lb/mmBtu) calculated in accordance with section 3 of appendix F of part 75 of this chapter, using the maximum potential nitrogen oxides concentration as defined in section 2 of appendix A of part 75 of this chapter, and either the maximum oxygen concentration (in percent O2) or the minimum carbon dioxide concentration (in percent CO2) under all operating conditions of the unit except for unit start-up, shutdown, and upsets.

Maximum rated hourly heat input means a unit-specific maximum hourly heat input (mmBtu) which is the higher of the manufacturer's maximum rated hourly heat input or the highest observed hourly heat input.

Missing data period means the total number of consecutive hours during which any component part of a certified CEMS or approved alternative monitoring system is not providing quality-assured data, regardless of the reason.

Monitor accuracy means the closeness of the measurement made by a CEMS or by one of its component parts to the reference value of the emissions or volumetric flow being measured, expressed as the difference between the measurement and the reference value.

Monitor operating hour means any unit operating hour or portion thereof over which a CEMS, or other monitoring system approved by the Administrator under part 75 of this chapter is operating, regardless of the number of measurements (i.e., data points) collected during the hour or portion of an hour.

Most stringent federally enforceable emissions limitation means the most stringent emissions limitation for a given pollutant applicable to the unit, which has been approved by the Administrator under the Act, whether in a State implementation plan approved pursuant to title I of the Act, a new source performance standard, or otherwise. To determine the most stringent emissions limitation for sulfur dioxide, each limitation shall be converted to lbs/mmBtu, using the appropriate conversion factors in appendix B of this part; provided that for determining the most stringent emissions limitation for sulfur dioxide for 1985, each limitation shall also be annualized, using the appropriate annualization factors in appendix A of this part.

Multi-header generator means a generator served by ductwork from more than one unit.

Multi-header unit means a unit with ductwork serving more than one generator.

Nameplate capacity means the maximum electrical generating output (expressed in MWe) that a generator can sustain over a specified period of time when not restricted by seasonal or other deratings, as listed in the NADB under the data field “NAMECAP” if the generator is listed in the NADB or as measured in accordance with the United States Department of Energy standards if the generator is not listed in the NADB.

National Allowance Data Base or NADB means the data base established by the Administrator under section 402(4)(C) of the Act.

Natural gas means a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) produced in geological formations beneath the Earth's surface that maintains a gaseous state at standard atmospheric temperature and pressure under ordinary conditions. Natural gas contains 1.0 grain or less of hydrogen sulfide per 100 standard cubic feet and the hydrogen sulfide constitutes more than 50% (by weight) of the total sulfur in the gas fuel. Additionally, natural gas must meet either be composed of at least 70% methane by volume or have a gross calorific value between 950 and 1100 Btu per standard cubic foot. Natural gas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value.

NERC region means the North American Electric Reliability Council region or, if any, subregion.

Net income neutrality means, in the case of energy conservation measures undertaken by an investor-owned utility whose rates are regulated by a State utility regulatory authority, rates and charges established by the State utility regulatory authority that ensure that the net income earned by the utility on its State-jurisdictional equity investment will be no lower as a consequence of its expenditures on cost-effective qualified energy conservation measures and any associated lost sales than it would have been had the utility not made such expenditures, or that the State utility regulatory authority has implemented a ratemaking approach designed to meet this objective.

New independent power production facility or new IPP means a unit that:

(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.

New unit means a unit that commences commercial operation on or after November 15, 1990, including any such unit that serves a generator with a nameplate capacity of 25 MWe or less or that is a simple combustion turbine.

Ninetieth (90th) percentile means a value that would divide an ordered set of increasing values so that at least 90 percent are less than or equal to the value and at least 10 percent are greater than or equal to the value.

Ninety-fifth (95th) percentile means a value that would divide an ordered set of increasing values so that at least 95 percent of the set are less than or equal to the value and at least 5 percent are greater than or equal to the value.

NIST/EPA-approved certified reference material or NIST/EPA-approved CRM means a calibration gas mixture that has been approved by EPA and the National Institutes of Standards and Technologies (NIST) as having specific known chemical or physical property values certified by a technically valid procedure as evidenced by a certificate or other documentation issued by a certifying standard-setting body.

NIST traceable reference material (NTRM) means a calibration gas mixture tested by and certified by the National Institutes of Standards and Technologies (NIST) to have a certain specified concentration of gases. NTRMs may have different concentrations from those of standard reference materials.

Offset plan means a plan pursuant to part 77 of this chapter for offsetting excess emissions of sulfur dioxide that have occurred at an affected unit in any calendar year.

Oil-fired means:

(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.

Opacity means the degree to which emissions reduce the transmission of light and obscure the view of an object in the background.

Operating when referring to a combustion or process source seeking entry into the Opt-in Program, means that the source had documented consumption of fuel input for more than 876 hours in the 6 months immediately preceding the submission of a combustion source's opt-in application under § 74.16(a) of this chapter.

Operating permit means a permit issued under part 70 of this chapter and any other regulations implementing title V of the Act.

Opt in or opt into means to elect to become an affected unit under the Acid Rain Program through the issuance of the final effective opt-in permit under § 74.14 of this chapter.

Opt-in permit means the legally binding written document that is contained within the Acid Rain permit and sets forth the requirements under part 74 of this chapter for a combustion source or a process source that opts into the Acid Rain Program.

Opt-in source means a combustion source or process source that has elected to become an affected unit under the Acid Rain Program and whose opt-in permit has been issued and is in effect.

Out-of-control period means any period:

(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.

Oversubscription payment deadline means 30 calendar days prior to the allowance transfer deadline.

Owner means any of the following persons:

(1) Any holder of any portion of the legal or equitable title in an affected unit or in a combustion source or process source; or

(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.

Owner or operator means any person who is an owner or who operates, controls, or supervises an affected unit, affected source, combustion source, or process source and shall include, but not be limited to, any holding company, utility system, or plant manager of an affected unit, affected source, combustion source, or process source.

Ozone nonattainment area means an area designated as a nonattainment area for ozone under subpart C of part 81 of this chapter.

Ozone season means the period of time beginning May 1 of a year and ending on September 30 of the same year, inclusive.

Ozone transport region means the ozone transport region designated under Section 184 of the Act.

Peaking unit means:

(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 meet the criteria in paragraph (1) of this definition initially qualified as a peaking unit under paragraph (2) of this definition, the unit may qualify as a peaking unit for a subsequent year only if the designated representative submits the data specified in paragraph (2)(ii)(A) of this definition.

Permit revision means a permit modification, fast track modification, administrative permit amendment, or automatic permit amendment, as provided in subpart H of this part.

Permitting authority means either:

(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.

Person includes an individual, corporation, partnership, association, State, municipality, political subdivision of a State, any agency, department, or instrumentality of the United States, and any officer, agent, or employee thereof.

Phase I means the Acid Rain Program period beginning January 1, 1995 and ending December 31, 1999.

Phase I unit means any affected unit, except an affected unit under part 74 of this chapter, that is subject to an Acid Rain emissions reduction requirement or Acid Rain emissions limitation beginning in Phase I; or any unit exempt under § 72.8 that, but for such exemption, would be subject to an Acid Rain emissions reduction requirement or Acid Rain emissions limitation beginning in Phase I.

Phase II means the Acid Rain Program period beginning January 1, 2000, and continuing into the future thereafter.

Phase II unit means any affected unit, except an affected unit under part 74 of this chapter, that is subject to an Acid Rain emissions reduction requirement or Acid Rain emissions limitation during Phase II only.

Pipeline natural gas means natural gas, as defined in this section, that is provided by a supplier through a pipeline and that contains 0.3 grains or less of hydrogen sulfide per 100 standard cubic feet and the hydrogen sulfide in content of the gas constitutes at least 50% (by weight) of the total sulfur in the fuel.

Pollutant concentration monitor means that component of the continuous emission monitoring system that measures the concentration of a pollutant in a unit's flue gas.

Potential electrical output capacity means the MWe capacity rating for the units which shall be equal to 33 percent of the maximum design heat input capacity of the steam generating unit, as calculated according to appendix D of part 72.

Power distribution system means the portion of an electricity grid owned or operated by a utility that is dedicated to delivering electric energy to customers.

Power purchase commitment means a commitment or obligation of a utility to purchase electric power from a facility pursuant to:

(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.

Power sales agreement is a legally binding agreement between a QF, IPP, new IPP, or firm associated with such facility and a regulated electric utility that establishes the terms and conditions for the sale of power from the facility to the utility.

Presiding Officer means an Administrative Law Judge appointed under 5 U.S.C. 3105 and designated to preside at a hearing in an appeal under part 78 of this chapter or an EPA lawyer designated to preside at any such hearing under § 78.6(b)(3)(ii) of this chapter.

Primary fuel or primary fuel supply means the main fuel type (expressed in mmBtu) consumed by an affected unit for the applicable calendar year.

Probationary calibration error test means an on-line calibration error test performed in accordance with section 2.1.1 of appendix B to part 75 of this chapter that is used to initiate a conditionally valid data period.

Proposed Acid Rain permit or proposed permit means, in the case of a State operating permit program, the version of an Acid Rain permit that the permitting authority submits to the Administrator after the public comment period, but prior to completion of the EPA permit review period, as provided for in part 70 of this chapter.

Protocol 1 gas means a calibration gas mixture prepared and analyzed according to the “Procedure for NBS-Traceable Certification of Compressed Gas Working Standards Used for Calibration and Audit of Continuous Emission Monitors (“Revised Traceability Protocol No. 1”),” Quality Assurance Handbook for Air Pollution Measurement Systems, Volume III, Stationary Source Specific Methods, Section 3.04, EPA-600/4-77-027b, June 1987 (set forth in appendix H of part 75 of this chapter) or such revised procedure as approved by the Administrator.

QA operating quarter means a calendar quarter in which there are at least 168 unit operating hours (as defined in this section) or, for a common stack or bypass stack, a calendar quarter in which there are at least 168 stack operating hours (as defined in this section).

Qualifying facility (QF) means a “qualifying small power production facility” within the meaning of section 3(17)(C) of the Federal Power Act or a “qualifying cogeneration facility” within the meaning of section 3(18)(B) of the Federal Power Act.

Qualifying Phase I technology means a technological system of continuous emission reduction that is demonstrated to achieve a ninety (90) percent (or greater) reduction in emissions of sulfur dioxide from the emissions that would have resulted from the use of fossil fuels that were not subject to treatment prior to combustion, as provided in § 72.42.

Qualifying power purchase commitment means a power purchase commitment in effect as of November 15, 1990 without regard to changes to that commitment so long as:

(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.

Qualifying repowering technology means:

(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.

Quality-assured monitor operating hour means any unit operating hour or portion thereof over which a certified CEMS, or other monitoring system approved by the Administrator under part 75 of this chapter, is operating:

(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.

Receive or receipt of means the date the Administrator or a permitting authority comes into possession of information or correspondence (whether sent in writing or by authorized electronic transmission), as indicated in an official correspondence log, or by a notation made on the information or correspondence, by the Administrator or the permitting authority in the regular course of business.

Recordation, record, or recorded means, with regard to allowances, the transfer of allowances by the Administrator from one Allowance Tracking System account or subaccount to another.

Reduced utilization means a reduction, during any calendar year in Phase I, in the heat input (expressed in mmBtu for the calendar year) at a Phase I unit below the unit's baseline, where such reduction subjects the unit to the requirement to submit a reduced utilization plan under § 72.43; or, in the case of an opt-in source, means a reduction in the average utilization, as specified in § 74.44 of this chapter, of an opt-in source below the opt-in source's baseline.

Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in part 60, appendix A of this chapter.

Reference value or reference signal means the known concentration of a calibration gas, the known value of an electronic calibration signal, or the known value of any other measurement standard approved by the Administrator, assumed to be the true value for the pollutant or diluent concentration or volumetric flow being measured.

Relative accuracy means a statistic designed to provide a measure of the systematic and random errors associated with data from continuous emission monitoring systems, and is expressed as the absolute mean difference between the pollutant concentration or volumetric flow measured by the pollutant concentration or flow monitor and the value determined by the applicable reference method(s) plus the 2.5 percent error confidence coefficient of a series of tests divided by the mean of the reference method tests in accordance with part 75 of this chapter.

Replacement unit means an affected unit replacing the thermal energy provided by an opt-in source, where both the affected unit and the opt-in source are governed by a thermal energy plan.

Research gas material (RGM) means a calibration gas mixture developed by agreement of a requestor and the National Institutes for Standards and Technologies (NIST) that NIST analyzes and certifies as “NIST traceable.” RGMs may have concentrations different from those of standard reference materials.

Research gas mixture (RGM) means a calibration gas mixture developed by agreement of a requestor and NIST that NIST analyzes and certifies as “NIST traceable.” RGMs may have concentrations different from those of standard reference materials.

Schedule of compliance means an enforceable sequence of actions, measures, or operations designed to achieve or maintain compliance, or correct non-compliance, with an applicable requirement of the Acid Rain Program, including any applicable Acid Rain permit requirement.

Secretary of Energy means the Secretary of the United States Department of Energy or the Secretary's duly authorized representative.

Serial number means, when referring to allowances, the unique identification number assigned to each allowance by the Administrator, pursuant to § 73.34(d) of this chapter.

Simple combustion turbine means a unit that is a rotary engine driven by a gas under pressure that is created by the combustion of any fuel. This term includes combined cycle units without auxiliary firing. This term excludes combined cycle units with auxiliary firing, unless the unit did not use the auxiliary firing from 1985 through 1987 and does not use auxiliary firing at any time after November 15, 1990.

Site lease, as used in part 73, subpart E of this chapter, means a legally-binding agreement signed between a new IPP or a firm associated with a new IPP and a site owner that establishes the terms and conditions under which the new IPP or the firm associated with the new IPP has the binding right to utilize a specific site for the purposes of operating or constructing the new IPP.

Small diesel refinery means a domestic motor diesel fuel refinery or portion of a refinery that, as an annual average of calendar years 1988 through 1990 and as reported to the Department of Energy on Form 810, had bona fide crude oil throughput less than 18,250,000 barrels per year, and the refinery or portion of a refinery is owned or controlled by a refiner with a total combined bona fide crude oil throughput of less than 50,187,500 barrels per year.

Solid waste incinerator means a source as defined in section 129(g)(1) of the Act.

Source means any governmental, institutional, commercial, or industrial structure, installation, plant, building, or facility that emits or has the potential to emit any regulated air pollutant under the Act. For purposes of section 502(c) of the Act, a “source”, including a “source” with multiple units, shall be considered a single “facility.”

Span means the highest pollutant or diluent concentration or flow rate that a monitor component is required to be capable of measuring under part 75 of this chapter.

Spot allowance means an allowance that may be used for purposes of compliance with a unit's Acid Rain sulfur dioxide emissions limitation requirements beginning in the year in which the allowance is offered for sale.

Spot auction means an auction of a spot allowance.

Spot sale means a sale of a spot allowance.

Stack means a structure that includes one or more flues and the housing for the flues.

Stack operating hour means any hour (or fraction of an hour) during which flue gases flow through a common stack or bypass stack.

Standard conditions means 68 °F at 1 atm (29.92 in. of mercury).

Standard reference material-equivalent compressed gas primary reference material (SRM-equivalent PRM) means those gas mixtures listed in a declaration of equivalence in accordance with section 2.1.2 of the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, EPA-600/R-97/121.

State means one of the 48 contiguous States and the District of Columbia, any non-federal authorities in or including such States or the District of Columbia (including local agencies, interstate associations, and State-wide agencies), and any eligible Indian tribe in an area in such State or the District of Columbia. The term “State” shall have its conventional meaning where such meaning is clear from the context.

State operating permit program means an operating permit program that the Administrator has approved under part 70 of this chapter.

Stationary gas turbine means a turbine that is not self-propelled and that combusts natural gas, other gaseous fuel with a total sulfur content no greater than the total sulfur content of natural gas, or fuel oil in order to heat inlet combustion air and thereby turn a turbine in addition to or instead of producing steam or heating water.

Steam sales agreement is a legally binding agreement between a QF, IPP, new IPP, or firm associated with such facility and an industrial or commercial establishment requiring steam that establishes the terms and conditions under which the facility will supply steam to the establishment.

Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:

(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.

Substitute data means emissions or volumetric flow data provided to assure 100 percent recording and reporting of emissions when all or part of the continuous emission monitoring system is not functional or is operating outside applicable performance specifications.

Substitution unit means an affected unit, other than a unit under section 410 of the Act, that is designated as a Phase I unit in a substitution plan under § 72.41.

Sulfur-free generation means the generation of electricity by a process that does not have any emissions of sulfur dioxide, including hydroelectric, nuclear, solar, or wind generation. A “sulfur-free generator” is a generator that is located in one of the 48 contiguous States or the District of Columbia and produces “sulfur-free generation.”

Supply-side measure means a measure to improve the efficiency of the generation, transmission, or distribution of electricity, implemented by a utility in connection with its operations or facilities to provide electricity to its customers, and includes the measures set forth in part 73, appendix A, section 2 of this chapter.

Thermal energy means the thermal output produced by a combustion source used directly as part of a manufacturing process but not used to produce electricity.

Ton or tonnage means any “short ton” (i.e., 2,000 pounds). For the purpose of determining compliance with the Acid Rain emissions limitations and reduction requirements, total tons for a year shall be calculated as the sum of all recorded hourly emissions (or the tonnage equivalent of the recorded hourly emissions rates) in accordance with part 75 of this chapter, with any remaining fraction of a ton equal to or greater than 0.50 ton deemed to equal one ton and any fraction of a ton less than 0.50 ton deemed not to equal any ton.

Total planned net output capacity means the planned generator output capacity, excluding that portion of the electrical power which is designed to be used at the power production facility, as specified under one or more qualifying power purchase commitments or contemporaneous documents as of November 15, 1990; “Total installed net output capacity” shall be the generator output capacity, excluding that portion of the electrical power actually used at the power production facility, as installed.

Transfer unit means a Phase I unit that transfers all or part of its Phase I emission reduction obligations to a control unit designated pursuant to a Phase I extension plan under § 72.42.

Underutilization means a reduction, during any calendar year in Phase I, of the heat input (expressed in mmBtu for the calendar year) at a Phase I unit below the unit's baseline.

Unit means a fossil fuel-fired combustion device.

Unit account means an Allowance Tracking System account, established by the Administrator for an affected unit pursuant to § 73.31 (a) or (b) of this chapter.

Unit load means the total (i.e., gross) output of a unit or source in any calendar year (or other specified time period) produced by combusting a given heat input of fuel, expressed in terms of:

(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.

Unit operating day means a calendar day in which a unit combusts any fuel.

Unit operating hour means any hour (or fraction of an hour) during which a unit combusts any fuel.

Unit operating quarter means a calendar quarter in which a unit combusts any fuel.

Utility means any person that sells electricity.

Utility competitive bid solicitation is a public request from a regulated utility for offers to the utility for meeting future generating needs. A qualifying facility, independent power production facility, or new IPP may be regarded as having been “selected” in such solicitation if the utility has named the facility as a project with which the utility intends to negotiate a power sales agreement.

Utility regulatory authority means an authority, board, commission, or other entity (limited to the local-, State-, or federal-level, whenever so specified) responsible for overseeing the business operations of utilities located within its jurisdiction, including, but not limited to, utility rates and charges to customers.

Utility system means all interconnected units and generators operated by the same utility operating company.

Utility unit means a unit owned or operated by a utility:

(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.

Utilization means the heat input (expressed in mmBtu/time) for a unit.

Very low sulfur fuel means either:

(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.

Volumetric flow means the rate of movement of a specified volume of gas past a cross-sectional area (e.g., cubic feet per hour).

Zero air material means either:

(1) A calibration gas certified by the gas vendor not to contain concentrations of SO2, NOX, or total hydrocarbons above 0.1 parts per million (ppm), a concentration of CO above 1 ppm, or a concentration of CO2 above 400 ppm;

(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 SO2, NOX, or total hydrocarbons above 0.1 ppm, a concentration of CO above 1 ppm, or a concentration of CO2 above 400 ppm;

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 15647, Mar. 23, 1993; 58 FR 33770, June 21, 1993; 58 FR 40747, July 30, 1993; 60 FR 17111, Apr. 4, 1995; 60 FR 18468, Apr. 11, 1995; 60 FR 26514, May 17, 1995; 62 FR 55475, Oct. 24, 1997; 63 FR 57498, Oct. 27, 1998; 63 FR 68404, Dec. 11, 1998; 64 FR 25842, May 13, 1999; 64 FR 28586, May 26, 1999]

§ 72.3 Measurements, abbreviations, and acronyms.

Measurements, abbreviations, and acronyms used in this part are defined as follows:

acfh—actual cubic feet per hour. atm—atmosphere. bbl—barrel. Btu—British thermal unit. °C—degree Celsius (centigrade). CEMS—continuous emission monitoring system. cfm—cubic feet per minute. cm—centimeter. dcf—dry cubic feet. DOE—Department of Energy. dscf—dry cubic feet at standard conditions. dscfh—dry cubic feet per hour at standard conditions. EIA—Energy Information Administration. eq—equivalent. °F—degree Fahrenheit. fps—feet per second. gal—gallon. hr—hour. in—inch. °K—degree Kelvin. kacfm—thousands of cubic feet per minute at actual conditions. kscfh—thousands of cubic feet per hour at standard conditions. Kwh—kilowatt hour. lb—pounds. m—meter. mmBtu—million Btu. min—minute. mol. wt.—molecular weight. MWe—megawatt electrical. MWge—gross megawatt electrical. NIST—National Institute of Standards and Technology. ppm—parts per million. psi—pounds per square inch. °R—degree Rankine. RATA—relative accuracy test audit. scf—cubic feet at standard conditions. scfh—cubic feet per hour at standard conditions. sec—second. std—at standard conditions. CO2—carbon dioxide. NOx—nitrogen oxides. O2—oxygen. THC—total hydrocarbon content. SO2—sulfur dioxide. [58 FR 3650, Jan. 11, 1993, as amended at 64 FR 28588, May 26, 1999]

§ 72.4 Federal authority.

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995]

§ 72.5 State authority.

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; provided that such State requirement, if articulated in an operating permit, is in a portion of the operating permit separate from the portion containing the Acid Rain Program requirements.

§ 72.6 Applicability.

(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 than one-third of its potential electrical output capacity and more than 219,000 MWe-hrs electric output, on a gross basis;

(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 annual fuel consumed at such incinerator is other than fossil fuels. For solid waste incinerators which began operation before January 1, 1985, the average annual fuel consumption of non-fossil fuels for calendar years 1985 through 1987 must be greater than 80 percent for such an incinerator to be exempt. For solid waste incinerators which began operation after January 1, 1985, the average annual fuel consumption of non-fossil fuels for the first three years of operation must be greater than 80 percent for such an incinerator to be exempt. If, during any three calendar year period after November 15, 1990, such incinerator consumes 20 percent or more (on a Btu basis) fossil fuel, such incinerator will be an affected source under the Acid Rain Program.

(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) Petition Content. The petition shall be in writing and include identification of the unit and relevant facts about the unit. In the petition, the certifying official shall certify, by his or her signature, the statement set forth at § 72.21(b)(2). Within 10 business days of receipt of any written determination by the Administrator covering the unit, the certifying official shall provide each owner or operator of the unit, facility, or source with a copy of the petition and a copy of the Administrator's response.

(2) Timing. The petition may be submitted to the Administrator at any time but, if possible, should be submitted prior to the issuance (including renewal) of a Phase II Acid Rain permit for the unit.

(3) Submission. All submittals under this section shall be made by the certifying official to the Director, Acid Rain Division, (6204J), 401 M Street, SW., Washington, DC, 20460.

(4) Response. The Administrator will issue a written response based upon the factual submittal meeting the requirements of paragraph (c)(1) of this section.

(5) Administrative appeals. The Administrator's determination of applicability is a decision appealable under 40 CFR part 78 of this chapter.

(6) Effect of determination. The Administrator's determination of applicability shall be binding upon the permitting authority, unless the petition is found to have contained significant errors or omissions.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 15648, Mar. 23, 1993; 62 FR 55475, Oct. 24, 1997; 64 FR 28588, May 26, 1999]

§ 72.7 New units exemption.

(a) Applicability. This section applies to any new utility unit that has not previously lost an exemption under paragraph (f)(4) of this section and that, in each year starting with the first year for which the unit is to be exempt under this section:

(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 under this section, a statement signed by 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 be submitted to 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, which shall be in a format prescribed by the Administrator, shall identify the unit, state 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, and state that the owners and operators of the unit will comply with paragraph (f) of this section.

(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:

ER24OC97.001 where: %Sannual = annual average sulfur content of the fuel burned during the year by the unit, as a percentage by weight; %Sn = sulfur content of the nth sample of the fuel delivered during the year to the unit, as a percentage by weight; Vn = volume of the fuel in a delivery during the year to the unit of which the nth sample is taken, in standard cubic feet; or, for fuel delivered during the year to the unit continuously by pipeline, volume of the fuel delivered starting from when the nth sample of such fuel is taken until the next sample of such fuel is taken, in standard cubic feet; dn = density of the nth sample of the fuel delivered during the year to the unit, in lb per standard cubic foot; and n = each sample taken of the fuel delivered during the year to the unit, taken at least once for each delivery; or, for fuel that is delivered during the year to the unit continuously by pipeline, at least once each quarter during which the fuel is delivered.

(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 (Vn dn), in the equation, the factor, mass (Mn), may be used, where Mn is: mass of the nongaseous fuel in a delivery during the year to the unit of which the nth sample is taken, in lb; or, for fuel delivered during the year to the unit continuously by pipeline, mass of the nongaseous fuel delivered starting from when the nth sample of such fuel is taken until the next sample of such fuel is taken, in lb.

(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) Special Provisions. (1) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under this section shall:

(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.

[62 FR 55476, Oct. 24, 1997]

§ 72.8 Retired units exemption.

(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 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 (b)(1) and (d) of this section.

(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) Special Provisions. (1) A unit exempt under this section shall not emit any sulfur dioxide and nitrogen oxides starting on the date that the exemption takes effect. The owners and operators of the unit will be allocated allowances in accordance with subpart B of part 73 of this chapter. If the unit is a Phase I unit, for each calendar year in Phase I, the designated representative of the unit shall submit a Phase I permit application in accordance with subparts C and D of this part 72 and an annual certification report in accordance with §§ 72.90 through 72.92 and is subject to §§ 72.95 and 72.96.

(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.

[62 FR 55477, Oct. 24, 1997; 62 FR 66279, Dec. 18, 1997]

§ 72.9 Standard requirements.

(a) Permit Requirements. (1) The designated representative of each affected source and each affected unit at the source shall:

(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) Monitoring Requirements. (1) The owners and operators and, to the extent applicable, designated representative of each affected source and each affected unit at the source shall comply with the monitoring requirements as provided in part 75 of this chapter.

(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.

(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) Nitrogen Oxides Requirements. The owners and operators of the source and each affected unit at the source shall comply with the applicable Acid Rain emissions limitation for nitrogen oxides.

(e) Excess Emissions Requirements. (1) The designated representative of an affected unit that has excess emissions in any calendar year shall submit a proposed offset plan, as required under part 77 of this chapter.

(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) Recordkeeping and Reporting Requirements. (1) Unless otherwise provided, the owners and operators of the source and each affected unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time prior to the end of 5 years, in writing by the Administrator or permitting authority.

(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; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation changing the designated representative.

(ii) All emissions monitoring information, in accordance with part 75 of this chapter; provided that to the extent that part 75 provides for a 3-year period for recordkeeping, the 3-year period shall apply.

(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) Liability. (1) Any person who knowingly violates any requirement or prohibition of the Acid Rain Program, a complete Acid Rain permit application, an Acid Rain permit, or an exemption under § 72.7, § 72.8, or § 72.14, including any requirement for the payment of any penalty owed to the United States, shall be subject to enforcement pursuant to section 113(c) of the Act.

(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 (NOX averaging plans), and except with regard to the requirements applicable to units with a common stack under part 75 of this chapter (including §§ 75.16, 75.17 and 75.18 of this chapter), the owners and operators and the designated representative of one affected unit shall not be liable for any violation by any other affected unit of which they are not owners or operators or the designated representative and that is located at a source of which they are not owners or operators or the designated representative.

(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) Effect on Other Authorities. No provision of the Acid Rain Program, an Acid Rain permit application, an Acid Rain permit, or an exemption under § 72.7, § 72.8, or § 72.14 shall be construed as:

(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; provided, that the number of allowances held by the unit shall not affect the source's obligation to comply with any other provisions of the Act.

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 62 FR 55478, Oct. 24, 1997]

§ 72.10 Availability of information.

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.

§ 72.11 Computation of time.

(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.

§ 72.12 Administrative appeals.

The procedures for appeals of decisions of the Administrator under this part are contained in part 78 of this chapter.

§ 72.13 Incorporation by reference.

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 Federal Register. The materials are available for purchase at the corresponding address noted below and are available for inspection at the Office of the Federal Register, 800 North Capitol Street, NW., Suite 700, Washington, DC, at the Public Information Reference Unit of the U.S. EPA, 401 M Street SW, Washington, DC and at the Library (MD-35), U.S. EPA, Research Triangle Park, North Carolina.

(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 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]

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 26526, May 17, 1995; 62 FR 55478, Oct. 24, 1997]

§ 72.14 Industrial utility-units exemption.

(a) Applicability. This section applies to any non-cogeneration, utility unit that has not previously lost an exemption under paragraph (d)(4) of this section and that meets the following criteria:

(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) Petition for exemption. The designated representative (authorized in accordance with subpart B of this part) of a unit under paragraph (a) of this section may submit to the permitting authority otherwise responsible for administering a Phase II Acid Rain permit for the unit a complete petition for an exemption for the unit from the requirements of the Acid Rain Program, except for the provisions of this section, §§ 72.2 through 72.6, and §§ 72.10 through 72.13. If the Administrator is not the permitting authority, a copy of the petition shall be submitted to the Administrator. A complete petition shall include the following elements in a format prescribed by the Administrator:

(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 by each generator served by the unit, and the provisions for expiration or termination of the agreement;

(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) Permitting Authority's Action. (1) (i) For any unit meeting the requirements of paragraphs (a) and (b) of this section, the permitting authority shall issue an exemption from the requirements of the Acid Rain Program, except for the provisions of this section, §§ 72.2 through 72.6 and §§ 72.10 through 72.13.

(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) Special Provisions. (1) 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.

(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 authority. Such records shall include the following information:

(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 electricity that such generator was required to produce for sale under the interconnection agreement or related power purchase agreement under paragraph (a)(2) of this section.

(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.

[62 FR 55478, Oct. 24, 1997]

Subpart B—Designated Representative

§ 72.20 Authorization and responsibilities of the designated representative.

(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.

§ 72.21 Submissions.

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995]

§ 72.22 Alternate designated representative.

(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 NOX averaging plan under § 76.11 of this chapter that covers such units and is approved by the permitting authority, provided that the approved plan remains in effect.

(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).

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997]

§ 72.23 Changing the designated representative, alternate designated representative; changes in the owners and operators.

(a) Changing the designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation. Notwithstanding any such change, all submissions, actions, and inactions by the previous designated representative prior to the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and on the owners and operators of the source represented and the affected units at the source.

(b) Changing the alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation. Notwithstanding any such change, all submissions, actions, and inactions by the previous alternate designated representative prior to the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative and on the owners and operators of the source represented and the affected units at the source.

(c) Changes in the owners and operators. (1) In the event a new owner or operator of an affected source or an affected unit is not included in the list of owners and operators submitted in the certificate of representation, such new owner or operator shall be deemed to be subject to and bound by the certificate of representation, the submissions, actions, and inactions of the designated representative and any alternative designated representative of the source or unit, and the decisions, actions, and inactions of the Administrator and permitting authority, as if the new owner or operator were included in such list.

(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.

§ 72.24 Certificate of representation.

(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 power from an affected unit under life-of-the-unit, firm power contractual arrangements, I certify that:

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997]

§ 72.25 Objections.

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997]

Subpart C—Acid Rain Permit Applications

§ 72.30 Requirement to apply.

(a) Duty to apply. The designated representative of any source with an affected unit shall submit a complete Acid Rain permit application by the applicable deadline in paragraphs (b) and (c) of this section, and the owners and operators of such source and any affected unit at the source shall not operate the source or unit without a permit that states its Acid Rain program requirements.

(b) Deadlines. (1) Phase 1. (i) The designated representative shall submit a complete Acid Rain permit application governing an affected unit during Phase I to the Administrator on or before February 15, 1993 for:

(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 unit in a substitution plan or reduced utilization plan submitted to the Administrator for approval or conditional approval.

(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) Phase II. (i) For any source with an existing unit under § 72.6(a)(2), the designated representative shall submit a complete Acid Rain permit application governing such unit during Phase II to the permitting authority on or before January 1, 1996.

(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) Duty to reapply. The designated representative shall submit a complete Acid Rain permit application for each source with an affected unit at least 6 months prior to the expiration of an existing Acid Rain permit governing the unit during Phase II or an opt-in permit governing an opt-in source or such longer time as may be approved under part 70 of this chapter that ensures that the term of the existing permit will not expire before the effective date of the permit for which the application is submitted.

(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 authority for the State where the affected source is located.

(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, provided that each affected unit is covered by one and only one such application.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 15649, Mar. 23, 1993; 60 FR 17113, Apr. 4, 1995; 62 FR 55480, Oct. 24, 1997]

§ 72.31 Information requirements for Acid Rain permit applications.

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;

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997]

§ 72.32 Permit application shield and binding effect of permit application.

(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); provided that any delay in issuing an Acid Rain permit is not caused by the failure of the designated representative to submit in a complete and timely fashion supplemental information, as required by the permitting authority, necessary to issue a permit.

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55480, Oct. 24, 1997]

§ 72.33 Identification of dispatch system.

(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 submission of an identification of dispatch system after the otherwise applicable deadline for such submission.

(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) Owner's share of the unit's capacity in 1985-1987. Under this method, the baseline of the owner's portion of the unit shall equal the baseline of the unit multiplied by the average of the owner's percentage ownership of the capacity of the unit for each year during 1985-1987. The actual utilization of the owner's portion of the unit for a year in Phase I shall equal the actual utilization of the unit for the year that is attributed to the owner.

(B) Owner's share of the unit's baseline. Under this method, the baseline of the owner's portion of the unit shall equal the average of the unit's annual utilization in 1985-1987 that is attributed to the owner. The actual utilization of the owner's portion of the unit for a year in Phase I shall equal the actual utilization of the unit for the year that is attributed to the owner.

(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 change the election of the apportionment method or the baseline of the owner's portion of the unit.

The same apportionment method must be used for all portions of the unit for all years in Phase I for which any petition under paragraph (f)(1) of this section is approved and in effect.

(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 dispatch systems that include any portion of the unit shall submit all annual compliance certification reports, dispatch system data reports, and other reports required under §§ 72.91 and 72.92 treating, as a separate Phase I unit, each portion of the unit for which a petition is approved under paragraph (f)(3) of this section and the remaining portion of the unit. The reports shall include all required calculations and demonstrations, treating each such portion of the unit as a separate Phase I unit. Upon request, the designated representatives shall demonstrate that the data in all the reports under §§ 72.91 and 72.92 has been properly attributed or apportioned among the portions of the unit and the dispatch systems and that there is no undercounting or double-counting with regard to such data.

(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, under such paragraphs. Approval of a petition under such paragraphs shall not constitute a determination of the percentage ownership in a unit under any other provision of the Acid Rain Program and shall not change the liability of the owners and operators of an affected unit that has excess emissions under § 72.9(e).

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 18468, Apr. 11, 1995; 62 FR 55481, Oct. 24, 1997]

Subpart D—Acid Rain Compliance Plan and Compliance Options

§ 72.40 General.

(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) Multi-unit compliance options. (1) A plan for a compliance option, under § 72.41, 72.42, 72.43, or 72.44 of this part, under § 74.47 of this chapter, or a NOX averaging plan under § 76.11 of this chapter, that includes units at more than one affected source shall be complete only if:

(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) Conditional Approval. In the compliance plan, the designated representative of an affected unit may propose, in accordance with this subpart, any Acid Rain compliance option for conditional approval, except a Phase I extension plan; provided that an Acid Rain compliance option under section 407 of the Act may be conditionally proposed only to the extent provided in part 76 of this chapter.

(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 owners and operators and the designated representative of any unit governed by the conditionally-approved compliance option.

(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) Termination of compliance option. (1) The designated representative for a unit may terminate an Acid Rain compliance option by notifying the permitting authority in writing that an approved compliance option will be terminated beginning January 1 of a specified year. If the compliance option includes a plan described in paragraph (b)(1) of this section, the designated representative for each source governed by the plan shall sign and certify the notification. Such notification shall be subject to the limitations on termination under subpart D of this part and part 76 of this chapter.

(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).

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 62 FR 55481, Oct. 24, 1997; 64 FR 25842, May 13, 1999]

§ 72.41 Phase I substitution plans.

(a) Applicability. This section shall apply during Phase I to the designated representative of:

(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) Contents of a substitution plan. A complete substitution plan shall include the following elements in a format prescribed by the Administrator:

(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 or greater than the total emissions reductions that would have been achieved without the plan, as follows:

(i) For each substitution unit:

(A) The unit's baseline.

(B) Each of the following: the unit's 1985 actual SO2 emissions rate; the unit's 1985 allowable SO2 emissions rate; the unit's 1989 actual SO2 emissions rate; the unit's 1990 actual SO2 emissions rate; and, as of November 15, 1990, the most stringent unit-specific federally enforceable or State enforceable SO2 emissions limitation covering the unit for 1995-1999. For purposes of determining the most stringent emissions limitation, applicable emissions limitations shall be converted to lbs/mmBtu in accordance with appendix B of this part. Where the most stringent emissions limitation is not the same for every year in 1995-1999, the most stringent emissions limitation shall be stated separately for each year.

(C) The lesser of: the unit's 1985 actual SO2 emissions rate; the unit's 1985 allowable SO2 emissions rate; the greater of the unit's 1989 or 1990 actual SO2 emissions rate; or, as of November 15, 1990, the most stringent unit-specific federally enforceable or State enforceable SO2 emissions limitation covering the unit for 1995-99. Where the most stringent emissions limitation is not the same for every year during 1995-1999, the lesser of the emissions rates shall be determined separately for each year using the most stringent emissions limitation for that year.

(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 SO2 emissions limitation is not the same for every year during 1995-1999, the sum in paragraph (c)(3)(ii)(A) of this section shall be calculated separately for each year using the amounts calculated for that year in paragraph (c)(3)(i)(D) of this section. Each separate sum is the total number of allowances available for the respective year under the substitution plan.

(iii) Where, as of November 15, 1990, a non-unit-specific federally enforceable or State enforceable SO2 emissions limitation covers the unit for any year during 1995-1999, the designated representative shall state each such limitation and propose a method for applying the unit-specific and non-unit-specific emissions limitations under paragraph (d) of this section.

(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 designated representative shall submit supporting documentation upon request by the Administrator.

(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 SO2 emissions rate (in lbs/mmBtu), specified in the agreement, for each year during the period that the substitution plan is in effect.

(B) The maximum annual average SO2 emissions rate for the unit under paragraph (a)(2) of this section shall not exceed 70 percent of the lesser of: the unit's 1985 actual SO2 emissions rate; the unit's 1985 allowable SO2 emissions rate; the greater of the unit's 1989 or 1990 actual SO2 emissions rate; the most stringent federally enforceable or State enforceable SO2 emissions limitation, as of November 15, 1990, applicable to the unit in Phase I; or the lesser of the average actual SO2 emissions rate or the most stringent federally enforceable or State enforceable SO2 emissions limitation for the unit for four consecutive quarters that immediately precede the 30-day period ending on the date the substitution plan is submitted to the Administrator. If the unit is covered by a non-unit-specific federally enforceable or State enforceable SO2 emissions limitation in the four consecutive quarters or, as of November 15, 1990, in Phase I, the Administrator will determine, on a case-by-case basis, how to apply the non-unit-specific emissions limitation for purposes of determining whether the maximum annual average SO2 emissions rate meets the requirement of the prior sentence. If a non-unit-specific federally enforceable SO2 emissions limitation is not different from a non-unit-specific federally enforceable SO2 emissions limitation that was effective and applicable to the unit in 1985, the Administrator will apply the non-unit-specific SO2 emissions limitation by using the 1985 allowable SO2 emissions rate.

(C) For each year that the actual SO2 emissions rate of the unit under paragraph (a)(2) of this section exceeds the maximum annual average SO2 emissions rate, the designated representative of the unit under paragraph (a)(1) of this section must surrender allowances for deduction from the Allowance Tracking System account of the unit under paragraph (a)(1) of this section. The designated representative shall surrender allowances authorizing emissions equal to the baseline of the unit under paragraph (a)(2) of this section multiplied by the difference between the actual SO2 emissions rate of the unit under paragraph (a)(2) of this section and the maximum annual average SO2 emissions rate and divided by 2000 lbs/ton. The surrender shall be made by the allowance transfer deadline of the year of the exceedance, and the surrendered allowances shall have the same or an earlier compliance use date as the allowances allocated to the unit under paragraph (a)(2) of this section for that year. The designated representative may identify the serial numbers of the allowances to be deducted. In the absence of such identification, allowances will be deducted on a first-in, first-out basis under § 73.35(c)(2) of this chapter.

(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 SO2 emissions rate for any year and the average actual SO2 emissions rate for any period shall be determined in accordance with part 75 of this chapter.

(6) A demonstration under paragraph (c)(5)(iii) of this section shall include the following supporting documentation:

(i) The calculation of the average actual SO2 emissions rate and the most stringent federally enforceable or State enforceable SO2 emissions limitation for the unit for the four consecutive quarters that immediately preceded the 30-day period ending on the date the substitution plan is submitted to the Administrator. To the extent that the four consecutive quarters include a quarter prior to January 1, 1995, the SO2 emissions rate for the quarter shall be determined applying the methodology for calculating SO2 emissions set forth in appendix C of this part. This methodology shall be applied using data submitted for the quarter to the Secretary of Energy on United States Department of Energy Form 767 or, if such data has not been submitted for the quarter, using the data prepared for such submission for the quarter.

(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 SO2 emissions rate under paragraph (c)(5)(iii) of this section.

(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) Administrator's action. (1) If the Administrator approves a substitution plan, he or she will allocate allowances to the Allowance Tracking System accounts of the units under paragraph (a)(1) of this section and substitution units, as provided in the approved plan, upon issuance of an Acid Rain permit containing the plan, except that if the substitution plan is conditionally approved, the allowances will be allocated upon revision of the permit to activate the plan.

(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 SO2 emissions limitation covers the unit for any year during 1995-1999, the Administrator will specify on a case-by-case basis a method for using unit-specific and non-unit-specific emissions limitations in allocating allowances to the substitution unit. The specified method will not treat a non-unit-specific emissions limitation as a unit-specific emissions limitation and will not result in substitution units retaining allowances allocated under paragraph (d)(1) of this section for emissions reductions necessary to meet a non-unit- specific emissions limitation. Such method may require an end-of-year review and the adjustment of the allowances allocated to the substitution unit and may require the designated representative of the substitution unit to surrender allowances by the allowance transfer deadline of the year that is subject to the review. Any surrendered allowances shall have the same or an earlier compliance use date as the allowances originally allocated for the year, and the designated representative may identify the serial numbers of the allowances to be deducted. In the absence of such identification, such allowances will be deducted on a first-in, first-out basis under § 73.35(c)(2) of this chapter.

(e) Special provisions—(1) Emissions Limitations. (i) Each substitution unit governed by an approved substitution plan shall become a Phase I unit from January 1 of the year for which the plan takes effect until January 1 of the year for which the plan is no longer in effect or is terminated. The designated representative of a substitution unit shall surrender allowances, and the Administrator will deduct allowances, in accordance with paragraph (d)(3) of this section.

(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 SO2 emissions rate under the approved plan and shall include in any such submission a showing that the actions in the changed description will not be implemented during Phase I unless the unit remains a substitution unit. The permit revision will be treated as an administrative amendment, except where the Administrator determines that the change in the description alters the fundamental nature of the actions to be taken and that public notice and comment will contribute to the decision-making process, in which case the permit revision will be treated as a permit modification or, at the option of the designated representative, a fast-track modification.

(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 SO2 emissions rate, provided that, if such deduction of allowance results in excess emissions, the remedies for excess emissions shall be fully applicable.

(2) Liability. The owners and operators of a unit governed by an approved substitution plan shall be liable for any violation of the plan or this section at that unit or any other unit that is the first unit's substitution unit or for which the first unit is a substitution unit under the plan, including liability for fulfilling the obligations specified in part 77 of this chapter and section 411 of the Act.

(3) Termination. (i) A substitution plan shall be in effect only in Phase I for the calendar years specified in the plan or until the calendar year for which a termination of the plan takes effect, provided that no substitution plan shall be terminated, and no unit shall be de-designated as a substitution unit, before the end of Phase I if the substitution unit serves as a control unit under a Phase I extension plan.

(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 number to, and with the same or an earlier compliance use date as, those allocated under paragraph (d)(1) of this section for all calendar years for which the plan is to be terminated. The designated representative may identify the serial numbers of the allowances to be deducted. In the absence of such identification, allowances will be deducted on a first-in, first-out basis under § 73.35(c)(2) of this chapter.

(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)(1) or (2) of this section and the unit received from the Administrator for the year, under the Partial Settlement in Environmental Defense Fund v. Carol M. Browner, No. 93-1203 (D.C. Cir. 1993) (signed May 4, 1993), a total number of allowances equal to the unit's baseline multiplied by the lesser of the unit's 1985 actual SO2 emissions rate or 1985 allowable SO2 emissions rate.

(1) Except as provided in paragraph (e)(3)(iv)(D)(2) of this section, paragraph (e)(3)(iv)(D) of this section shall apply to the first year in Phase I for which the unit is and remains an active substitution unit.

(2) If the unit has a Group 1 boiler under part 76 of this chapter and is and remains an active substitution unit during 1995, paragraph (e)(3)(iv)(D) of this section shall apply to 1995 and to the second year in Phase I for which the unit is and remains an active substitution unit.

(3) If there is a change in the owners, operators, or designated representative of the substitution unit or the Phase I unit during a year under paragraph (e)(3)(iv)(D)(1) or (2) of this section and, with the change, the units do not have a common owner, operator, or designated representative, then the designated representatives for such units 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. If the plan is not terminated in accordance with the prior sentence, 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.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 40747, July 30, 1993; 59 FR 60230, 60238, Nov. 22, 1994; 62 FR 55481, Oct. 24, 1997]

§ 72.42 Phase I extension plans.

(a) Applicability. (1) This section shall apply to any designated representative seeking a 2-year extension of the deadline for meeting Phase I sulfur dioxide emissions reduction requirements at any of the following types of units by applying for allowances from the Phase I extension reserve:

(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 Federal Register, between the hours of 9 a.m. and 5 p.m. Eastern Standard Time at Acid Rain Division, Attn: Early Ranking, U.S. Environmental Protection Agency, 501 3rd Street NW., 4th floor, Washington, DC; or send the application by regular mail, certified mail, or overnight delivery service to Acid Rain Division, Attn: Early Ranking, U.S. Environmental Protection Agency, 6204 J, 401 M Street, SW., Washington, DC 20460.

(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) Contents of early ranking application. A complete early ranking application shall include the following elements in a format prescribed by the Administrator:

(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.1

1 In the case of a transfer unit that shares a common stack with a unit not listed in table 1 of § 73.10(a) of this chapter and whose emissions of sulfur dioxide are not monitored separately or apportioned in accordance with part 75 of this chapter, the projected figures for the transfer unit under paragraph (c)(7) of this section must be for the units combined.

(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 range of fossil fuels (before any treatment prior to combustion) that will be used at the control unit; provided that a vendor certification shall not be a defense against a control unit's failure to achieve 90% control of sulfur dioxide.

(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) Contents of Phase I extension plan. A complete Phase I extension plan shall include the following elements in a format prescribed by the Administrator:

(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; provided that the Phase I extension plan shall not add any new control units or increase the total Phase I extension allowances requested; or

(iii) All elements required for an early ranking application and a statement that no early ranking application for the plan was submitted.

(e) Administrator's action. (1) Early ranking applications. (i) The Administrator may approve in whole or in part or with changes or conditions, as appropriate, or disapprove an early ranking application.

(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; provided that all submissions received by the Administrator prior to the 40th day after publication of this subpart in the Federal Register will be deemed received on the 40th day.

(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) Phase I extension plans. (i) The Administrator will act on each Phase I extension plan in the order that the early ranking application for that plan was received or, if no early ranking application was received, in the order that the Phase I extension plan was received, as determined under paragraph (e)(1)(iii) of this section.

(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) Allowance allocations. In addition to any allowances allocated in accordance with table 1 of § 73.10(a) of this chapter and other approved compliance options, the Administrator will allocate Phase I extension reserve allowances to each eligible unit in a Phase I extension plan in the following order.

(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) Special provisions—(1) Emissions Limitations—(i) Sulfur Dioxide.(A) If a control or transfer unit governed by an approved Phase I extension plan emits in 1997, 1998, or 1999 sulfur dioxide in excess of the projected controlled emissions for the unit specified for the year under paragraph (c)(7) 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 deduct allowances equal to such exceedence from the unit's annual allowance allocation in the following calendar year.2

2 In the case of a transfer unit that shares a common stack with a unit not listed in table 1 of § 73.10(a) of this chapter where the units are not monitored separately or apportioned in accordance with part 75 of this chapter, the combined emissions of both units will be deemed to be the transfer unit's emissions for purposes of applying paragraph (f)(1)(i) of this section.

(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:

Allowances deducted = (1 − (percent reduction achieved•90%)) × Phase I extension reserve allowances received where: “Percent reduction achieved” is the percent reduction determined in accordance with part 75 of this chapter. “Phase I extension reserve allowances received” is the number of Phase I extension reserve allowances allocated for the year under paragraph (e)(2)(ii) of this section.

(ii) Nitrogen Oxides.

(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) Monitoring requirements. Each control unit shall comply with the special monitoring requirements for Phase I extension plans in accordance with part 75 of this chapter.

(3) Reporting requirements. Each control and transfer unit shall comply with the special reporting requirements for Phase I extension plans in accordance with § 72.93.

(4) Liability. The owners and operators of a control or transfer unit governed by an approved Phase I extension plan shall be liable for any violation of the plan or this section at that or any other unit governed by the plan, including liability for fulfilling the obligations specified in part 77 of this chapter and section 411 of the Act.

(5) Termination. A Phase I extension plan shall be in effect only in Phase I, and no Phase I extension plan shall be terminated before the end of Phase I. The designated representative may, however, withdraw a Phase I extension plan at any time prior to issuance of the Phase I Acid Rain permit that includes the Phase I extension plan, as adjusted.

§ 72.43 Phase I reduced utilization plans.

(a) Applicability. This section shall apply to the designated representative of:

(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 SO2 emissions rate or 1985 allowable SO2 emissions rate does not exceed the sum of

(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 SO2 emissions rate; or, as of November 15, 1990, the most stringent federally enforceable or State enforceable SO2 emissions limitation covering the unit for 1995-1999.

(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) Contents of reduced utilization plan. A complete reduced utilization plan shall include the following elements in a format prescribed by the Administrator:

(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 SO2 emissions rate; the unit's 1985 allowable emissions rate; the unit's 1989 actual SO2 emissions rate; the unit's 1990 actual SO2 emissions rate; and, as of November 15, 1990, the most stringent unit-specific federally enforceable or State enforceable SO2 emissions limitation covering the unit for 1995-1999. For purposes of determining the most stringent emissions limitation, applicable emissions limitations shall be converted to lbs/mmBtu in accordance with appendix B of this part. Where the most stringent emissions limitation is not the same for every year in 1995-1999, the most stringent emissions limitation shall be stated separately for each year.

(B) The unit's baseline divided by 2,000 lbs/ton and multiplied by the lesser of the unit's 1985 actual SO2 emissions rate or 1985 allowable SO2 emissions rate.

(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 SO2 emissions rate; or, as of November 15, 1990, the most stringent unit-specific federally enforceable or State enforceable SO2 emissions limitation covering the unit for 1995-1999. Where the most stringent emissions limitation is not the same for every year in 1995-1999, the calculation in the prior sentence shall be made separately for each year.

(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 SO2 emissions limitation is not the same for every year in 1995-1999, the difference shall be calculated separately for each year.

(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 SO2 emissions limitation covers the unit for any year in 1995-1999, the designated representative shall state each such limitation and propose a method for applying unit-specific and non-unit-specific emissions limitations under paragraph (d) of this section.

(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) Administrator's action. (1) If the Administrator approves the reduced utilization plan, he or she will allocate allowances, as provided in the approved plan, to the Allowance Tracking System account for any designated compensating unit upon issuance of an Acid Rain permit containing the plan, except that, if the plan is conditionally approved, the allowances will be allocated upon revision of the permit to activate the plan.

(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 specify on a case-by-case basis a method for using unit-specific and non-unit specific emissions limitations in approving or disapproving the compensating unit. The specified method will not treat a non-unit-specific emissions limitation as a unit-specific emissions limitation and will not result in compensating units retaining allowances allocated under paragraph (d)(1) of this section for emissions reductions necessary to meet a non-unit-specific emissions limitation. Such method may require an end-of-year review and the disapproval and de-designation, and adjustment of the allowances allocated to, the compensating unit and may require the designated representative of the compensating unit to surrender allowances by the allowance transfer deadline of the year that is subject to the review. Any surrendered allowances shall have the same or an earlier compliance use date as the allowances originally allocated for the year, and the designated representative may identify the serial numbers of the allowances to be deducted. In the absence of such identification, such allowances will be deducted on a first-in, first-out basis under § 73.35(c)(2) of this chapter.

(e) Failure to submit a plan. The designated representative of a Phase I unit will be deemed not to violate, during a Phase I calendar year, the requirement to submit a reduced utilization plan under paragraph (b)(1) or (4) of this section if the designated representative complies with the allowance surrender and other requirements of §§ 72.33, 72.91, and 72.92 of this chapter.

(f) Special provisions—(1) Emissions limitations. (i) Any compensating unit designated under an approved reduced utilization plan shall become a Phase I unit from January 1 of the calendar year in which the plan takes effect until January 1 of the year for which the plan is no longer in effect or is terminated, except that such unit shall not become subject to the Acid Rain emissions limitations for nitrogen oxides in Phase I under part 76 of this chapter.

(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) Reporting requirements. 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 comply with the special reporting requirements under §§ 72.91 and 72.92.

(3) Liability. The owners and operators of a unit governed by an approved reduced utilization plan shall be liable for any violation of the plan or this section at that or any other unit governed by the plan, including liability for fulfilling the obligations specified in part 77 of this chapter and section 411 of the Act.

(4) Termination. (i) A reduced utilization plan shall be in effect only in Phase I for the calendar years specified in the plan or until the calendar year for which a termination of the plan takes effect; provided that no reduced utilization plan that designates a compensating unit that serves as a control unit under a Phase I extension plan shall be terminated, and no such unit shall be de-designated as a compensating unit, before the end of Phase I.

(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 identify the serial numbers of the allowances to be deducted. In the absence of such identification, allowances will be deducted on a first-in, first-out basis under § 73.35(c)(2) of this chapter.

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 59 FR 60230, Nov. 22, 1994; 60 FR 18470, Apr. 11, 1995; 62 FR 55481, Oct. 24, 1997]

§ 72.44 Phase II repowering extensions.

(a) Applicability. (1) This section shall apply to the designated representative of:

(i) Any existing affected unit that is a coal-fired unit and has a 1985 actual SO2 emissions rate equal to or greater than 1.2 lbs/mmBtu.

(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) Contents and Review of Petition for Approval of Repowering Technology. (1) A complete petition for approval of repowering technology shall include the following elements, in a format prescribed by the Administrator, concerning the technology to be used in a plan under paragraph (b) of this section and may follow the repowering technology demonstration protocol issued by the Administrator:

(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; provided that the existence of such guarantee shall not be a defense against the failure to meet the criteria for non-listed technologies.

(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) Contents of repowering extension plan. A complete repowering extension plan shall include the following elements in a format prescribed by the Administrator:

(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 SO2 emissions rate.

(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) Permitting authority's action on repowering extension plan. (1) The permitting authority shall not approve a repowering extension plan until the Administrator makes a conditional determination that the technology is a qualified repowering technology, unless the permitting authority conditionally approves such plan subject to the conditional determination of the Administrator.

(2) Permit issuance. (i) Upon a conditional determination by the Administrator that the technology to be used in the repowering extension plan is a qualified repowering technology and a determination by the permitting authority that such plan meets the requirements of this section, the permitting authority shall issue the Acid Rain portion of the operating permit including:

(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; provided that the re-pow-er-ing extension shall end no later than December 31, 2003.

(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) Allowance allocation. The Administrator will allocate allowances after issuance of an operating permit containing the repowering extension plan (or, if the plan is conditionally approved, after the revision of the Acid Rain permit under § 72.40(c)) and of the Administrator's final determination, under paragraph (d)(4) of this section, that the technology to be used in such plan is a qualifying repowering technology. Allowances will be allocated (including a pro rata allocation for any fraction of a year), as follows:

(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) Failed repowering projects. (1)(i) If, at any time before the end of the repowering extension under paragraph (f)(2)(ii) of this section, the designated representative of a unit governed by an approved repowering extension plan notifies the Administrator in writing that the owners and operators have decided to terminate efforts to properly design, construct, and test the repowering technology specified in the plan before completion of construction or start-up testing and demonstrates, in a requested permit modification, to the Administrator's satisfaction that such efforts were in good faith, the unit shall not be deemed in violation of the Act because of such a termination. If the Administrator is not the permitting authority, a copy of the requested permit modification shall be sumitted to the Administrator. Where the preceding requirements of this paragraph are met, the permitting authority shall revise the operating permit in accordance with this paragraph and paragraph (g)(1)(ii) of this section and § 72.81 (permit modification).

(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) Special provisions. (1) Emissions Limitations. (i) Sulfur Dioxide. Allowances allocated during the repowering extension under paragraphs (f)(3) and (g)(2)(iii) of this section to a unit governed by an approved repowering extension plan shall not be transferred to any Allowance Tracking System account other than the unit accounts of other units at the same source as that unit.

(ii) Nitrogen oxides. Any existing unit governed by an approved repowering extension plan shall be subject to the Acid Rain emissions limitations for nitrogen oxides in accordance with part 76 of this chapter beginning on the date that the unit is removed from operation to install the repowering technology or is permanently removed from service.

(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) Reporting requirements. Each unit governed by an approved repowering extension plan shall comply with the special reporting requirements of § 72.94.

(3) Liability. (i) The owners and operators of a unit governed by an approved repowering plan shall be liable for any violation of the plan or this section at that or any other unit governed by the plan, including liability for fulfilling the obligations specified in part 77 of this chapter and section 411 of the Act.

(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) Terminations. Except as provided in paragraph (g) of this section, a repowering extension plan shall not be terminated after December 31, 1999.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 15649, Mar. 23, 1993; 62 FR 55481, Oct. 24, 1997]

Subpart E—Acid Rain Permit Contents

§ 72.50 General.

(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.

§ 72.51 Permit shield.

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).

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55481, Oct. 24, 1997]

Subpart F—Federal Acid Rain Permit Issuance Procedures

§ 72.60 General.

(a) Scope. This subpart and parts 74, 76, and 78 of this chapter contain the procedures for federal issuance of Acid Rain permits for Phase I of the Acid Rain Program and Phase II for sources for which the Administrator is the permitting authority under § 72.74.

(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) Permit Decision Deadlines. Except as provided in § 72.74(c)(1)(i), the Administrator will issue or deny an Acid Rain permit under § 72.69(a) within 6 months of receipt of a complete Acid Rain permit application submitted for a unit, in accordance with § 72.21, at the U.S. EPA Regional Office for the Region in which the source is located.

(c) Use of Direct Final Procedures. The Administrator may, in his or her discretion, issue, as single document, a draft Acid Rain permit in accordance with § 72.62 and an Acid Rain permit in final form and may provide public notice of the opportunity for public comment on the draft Acid Rain permit in accordance with § 72.65. The Administrator may provide that, if no significant, adverse comment on the draft Acid Rain permit is timely submitted, the Acid Rain permit will be deemed to be issued on a specified date without further notice and, if such significant, adverse comment is timely submitted, an Acid Rain permit or denial of an Acid Rain permit will be issued in accordance with § 72.69. Any notice provided under this paragraph (c) will include a description of the procedure in the prior sentence.

[62 FR 55481, Oct. 24, 1997]

§ 72.61 Completeness.

(a) Determination of Completeness. The Administrator will determine whether the Acid Rain permit application is complete within 60 days of receipt by the U.S. EPA Regional Office for the Region in which the source is located. The permit application shall be deemed to be complete if the Administrator fails to notify the designated representative to the contrary within 60 days of receipt.

(b) Supplemental Information. (1) Regardless of whether the Acid Rain permit application is complete under paragraph (a) of this section, the Administrator may require submission of any additional information that the Administrator determines to be necessary in order to review the Acid Rain permit application and issue an Acid Rain permit.

(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 failure or incorrect submittal, promptly submit such supplementary information or corrected information to the Administrator.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55481, Oct. 24, 1997]

§ 72.62 Draft permit.

(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.

§ 72.63 Administrative record.

(a) Contents of the Administrative Record. The Administrator will prepare an administrative record for an Acid Rain permit or denial of an Acid Rain permit. The administrative record will contain:

(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]

§ 72.64 Statement of basis.

(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.

§ 72.65 Public notice of opportunities for public comment.

(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) Methods. The Administrator will give the public notice required by this section by:

(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 Federal Register and in a newspaper of general circulation in the area where the source covered by the Acid Rain permit application is located or in a State publication designed to give general public notice. Notwithstanding the prior sentence, if a draft permit requires the affected units at a source to comply with § 72.9(c)(1) and to meet any applicable emission limitation for NOX under §§ 76.5, 76.6, 76.7, 76.8, or 76.11 of this chapter and does not include for any unit a compliance option under § 72.44, part 74 of this chapter, or § 76.10 of this chapter, the Administrator may, in his or her discretion, provide notice of the draft permit by Federal Register publication and may omit notice by newspaper or State publication.

(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) Extensions and Reopenings of the Public Comment Period. On the Administrator's own motion or on the request of any person, the Administrator may, at his or her discretion, extend or reopen the public comment period where he or she finds that doing so will contribute to the decision-making process by clarifying one or more significant issues affecting the draft permit or denial of a draft permit. Notice of any such extension or reopening shall be given under paragraph (a)(1)(i) of this section.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55482, Oct. 24, 1997]

§ 72.66 Public comments.

(a) General. During the public comment period, any person may submit written comments on the draft permit or the denial of a draft permit.

(b) Form. (1) Comments shall be submitted in duplicate.

(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) Contents. Timely comments on any aspect of the draft permit or denial or a draft permit will be considered unless they concern:

(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.

§ 72.67 Opportunity for public hearing.

(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.

§ 72.68 Response to comments.

(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.

§ 72.69 Issuance and effective date of acid rain permits.

(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 Federal Register.

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55482, Oct. 24, 1997]

Subpart G—Acid Rain Phase II Implementation

§ 72.70 Relationship to title V operating permit program.

(a) Scope. This subpart sets forth criteria for approval of State operating permit programs and acceptance of State Acid Rain programs, the procedure for including State Acid Rain programs in a title V operating permit program, and the requirements with which State permitting authorities with accepted programs shall comply, and with which the Administrator will comply in the absence of an accepted State program, to issue Phase II Acid Rain permits.

(b) Relationship to operating permit program. Each State permitting authority with an affected source shall act in accordance with this part and parts 70, 74, 76, and 78 of this chapter for the purpose of incorporating Acid Rain Program requirements into each affected source's operating permit or for issuing exemptions under § 72.14. To the extent that this part or part 74, 76, or 78 of this chapter is inconsistent with the requirements of part 70 of this chapter, this part and parts 74, 76, and 78 of this chapter shall take precedence and shall govern the issuance, denial, revision, reopening, renewal, and appeal of the Acid Rain portion of an operating permit.

[62 FR 55482, Oct. 24, 1997]

§ 72.71 Acceptance of State Acid Rain programs—general.

(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 Federal Register, all or a portion of such program to the extent that it meets the requirements of §§ 72.72 and 72.73. At his or her discretion, the Administrator may accept, with conditions and by notice in the Federal Register, all or a portion of such program despite the failure to meet requirements of §§ 72.72 and 72.73. On the later of the date of publication of such notice in the Federal Register or the date on which the State operating permit program is approved under part 70 of this chapter, the State Acid Rain program accepted by the Administrator will become a portion of the approved State operating permit program. Before accepting or rejecting all or a portion of a State Acid Rain Program, the Administrator will provide notice and opportunity for public comment on such acceptance or rejection.

(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.

[62 FR 55482, Oct. 24, 1997]

§ 72.72 Criteria for State operating permit program.

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) Non-Interference with Acid Rain Program. The State operating permit program shall not include or implement any measures that would interfere with the Acid Rain Program. In particular, the State program shall not restrict or interfere with allowance trading and shall not interfere with the Administrator's decision on an offset plan. Aspects and implementation of the State program that would constitute interference with the Acid Rain Program, and are thus prohibited, include but are not limited to:

(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 might affect Acid Rain Program requirements;

(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) Acid Rain Permit Issuance. Issuance or denial of Acid Rain permits shall follow the procedures under this part, part 70 of this chapter, and, for combustion or process sources, part 74, including:

(i) Permit application—(A) Requirement to comply. (1) The owners and operators and the designated representative for each affected source, except for combustion or process sources, under jurisdiction of the State permitting authority shall be required to comply with subparts B, C, and D of this part.

(2) The owners and operators and the designated representative for each combustion or process source under jurisdiction of the State permitting authority shall be required to comply with subpart B of this part and subparts B, C, D, and E of part 74 of this chapter.

(B) Effect of an Acid Rain permit application. A complete Acid Rain permit application, except for a permit application for a combustion or process source, shall be binding on the owners and operators and the designated representative of the affected source, all affected units at the source, and any other unit governed 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 the Acid Rain permit under paragraph (b)(1)(vii) of this section.

(ii) Draft Permit. (A) The State permitting authority shall prepare the draft Acid Rain permit in accordance with subpart E of this part and part 76 of this chapter or, for a combustion or process source, with subpart B of part 74 of this chapter, or deny a draft Acid Rain permit.

(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) Public Notice and Comment Period. Public notice of the issuance or denial of the draft Acid Rain permit and the opportunity to comment and request a public hearing shall be given by publication 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. Notwithstanding the prior sentence, if a draft permit requires the affected units at a source to comply with § 72.9(c)(1) and to meet any applicable emission limitation for NOX under §§ 76.5, 76.6, 76.7, 76.8, or 76.11 of this chapter and does not include for any unit a compliance option under § 72.44, part 74 of this chapter, or § 76.10 of this chapter, the State permitting authority may, in its discretion, provide notice by serving notice on persons entitled to receive a written notice and may omit notice by newspaper or State publication.

(iv) Proposed permit. The State permitting authority shall incorporate all changes necessary and issue a proposed Acid Rain permit in accordance with subpart E of this part and part 76 of this chapter or, for a combustion or process source, with subpart B of part 74 of this chapter, or deny a proposed Acid Rain permit.

(v) Direct proposed procedures. The State permitting authority may, in its discretion, issue, as a single document, a draft Acid Rain permit in accordance with paragraph (b)(1)(ii) of this section and a proposed Acid Rain permit and may provide public notice of the opportunity for public comment on the draft Acid Rain permit in accordance with paragraph (b)(1)(iii) of this section. The State permitting authority may provide that, if no significant, adverse comment on the draft Acid Rain permit is timely submitted, the proposed Acid Rain permit will be deemed to be issued on a specified date without further notice and, if such significant, adverse comment is timely submitted, a proposed Acid Rain permit or denial of a proposed Acid Rain permit will be issued in accordance with paragraph (b)(1)(iv) of this section. Any notice provided under this paragraph (b)(1)(v) shall include a description of the procedure in the prior sentence.

(vi) Acid Rain Permit Issuance. Following the Administrator's review of the proposed Acid Rain permit, the State permitting authority shall or, under part 70 of this chapter, the Administrator will, incorporate any required changes and issue or deny the Acid Rain permit in accordance with subpart E of this part and part 76 of this chapter or, for a combustion or process source, with subpart B of part 74 of this chapter.

(vii) New Owners. An Acid Rain permit shall be binding on any new owner or operator or designated representative of any source or unit governed by the permit.

(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) Permit Revisions. In acting on any Acid Rain permit revision, the State permitting authority shall follow the provisions and procedures set forth at subpart H of this part.

(3) Permit Renewal. The renewal of an Acid Rain permit for an affected source shall be subject to all the requirements of this subpart pertaining to the issuance of permits.

(4) Acid Rain Program Forms. In developing the Acid Rain portion of the operating permit, the permitting authority shall use the applicable forms or other formats prescribed by the Administrator under the Acid Rain Program; provided that the Administrator may waive this requirement in whole or in part.

(5) Acid Rain Appeal Procedures. (i) Appeals of the Acid Rain portion of an operating permit issued by the State permitting authority that do not challenge or involve decisions or actions of the Administrator under this part or part 73, 74, 75, 76, 77, or 78 of this chapter shall be conducted according to procedures established by the State in accordance with part 70 of this chapter. Appeals of the Acid Rain portion of such a permit that challenge or involve such decisions or actions of the Administrator shall follow the procedures under part 78 of this chapter and section 307 of the Act. Such decisions or actions include, but are not limited to, allowance allocations, determinations concerning alternative monitoring systems, and determinations of whether a technology is a qualifying repowering technology.

(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 order in a State administrative or judicial proceeding that interprets, modifies, voids, or otherwise relates to any portion of an Acid Rain permit.

(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) Industrial Utility-Units Exemption. The State permitting authority shall act in accordance with § 72.14 on any petition for exemption from requirements of the Acid Rain Program.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 62 FR 55482, Oct. 24, 1997]

§ 72.73 State issuance of Phase II permits.

(a) State Permit Issuance. (1) A State that is authorized to administer and enforce an operating permit program under part 70 of this chapter and that has a State Acid Rain program accepted by the Administrator under § 72.71 shall be responsible for administering and enforcing Acid Rain permits effective in Phase II for all affected sources:

(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) Permit Issuance Deadline. (1) A State, to the extent that it is responsible under paragraph (a) of this section as of December 31, 1997 (or such later date as the Administrator may establish) for administering and enforcing Acid Rain permits, shall:

(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; provided that the designated representative of the source submitted a timely and complete Acid Rain permit application in accordance with § 72.21.

(ii) On or before January 1, 1999, for each unit subject to an Acid Rain NOX emissions limitation, amend the Acid Rain permit under § 72.83 and add any NOX early election plan that was approved by the Administrator under § 76.8 of this chapter and has not been terminated and reopen the Acid Rain permit and add any other Acid Rain Program nitrogen oxides requirements; provided that the designated representative of the affected source submitted a timely and complete Acid Rain permit application for nitrogen oxides in accordance with § 72.21.

(2) Each Acid Rain permit issued in accordance with this section shall have a term of 5 years commencing on its effective date; provided that, at the discretion of the permitting authority, the first Acid Rain permit for Phase II issued to a source may have a term of less than 5 years where necessary to coordinate the term of such permit with the term of an operating permit to be issued to the source under a State operating permit program. Each Acid Rain permit issued in accordance with paragraph (b)(1) of this section shall take effect by the later of January 1, 2000, or, where the permit governs a unit under § 72.6(a)(3) of this part, the deadline for monitor certification under part 75 of this chapter.

[62 FR 55483, Oct. 24, 1997]

§ 72.74 Federal issuance of Phase II permits.

(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 Federal Register;

(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 Federal Register a notice that he or she will administer and enforce Acid Rain permits effective in Phase II for sources and units subject to the State Acid Rain program or a portion of the program. The effective date of such notice shall be a reasonable period (established by the Administrator in the notice) after the issuance of the notice.

(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 Federal Register that the State operating permit program is currently approved by the Administrator or that the State Acid Rain program or portion of the program is currently accepted by the Administrator, the Administrator will suspend federal administration of Acid Rain permits effective in Phase II for sources and units to the extent that they are subject to the State Acid Rain program or portion of the program, except as provided in paragraph (b)(4) of this section.

(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 Federal Register.

(c) Permit Issuance Deadline. (1)(i) On or before January 1, 1998, the Administrator will issue an Acid Rain permit for Phase II setting forth the Acid Rain Program sulfur dioxide requirements for each affected unit (other than opt-in sources) at a source not under the jurisdiction of a State permitting authority that is responsible, as of January 1, 1997 (or such later date as the Administrator may establish), under § 72.73(a) of this section for administering and enforcing Acid Rain permits with such requirements; provided that the designated representative for the source submitted a timely and complete Acid Rain permit application in accordance with § 72.21. The failure by the Administrator to issue a permit in accordance with this paragraph shall be grounds for the filing of an appeal under part 78 of this chapter.

(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) Nitrogen Oxides. Not later than 6 months following submission by the designated representative of an Acid Rain permit application for nitrogen oxides, the Administrator will amend under § 72.83 the Acid Rain permit and add any NOX early election plan that was approved under § 76.8 of this chapter and has not been terminated and reopen the Acid Rain permit for Phase II and add any other Acid Rain Program nitrogen oxides requirements for each affected source not under the jurisdiction of a State permitting authority that is responsible, as of January 1, 1997 (or such later date as the Administrator may establish), under § 72.73(a) for issuing Acid Rain permits with such requirements; provided that the designated representative for the source submitted a timely and complete Acid Rain permit application for nitrogen oxides in accordance with § 72.21.

(d) Permit Issuance. (1) The Administrator may utilize any or all of the provisions of subparts E and F of this part to administer Acid Rain permits as authorized under this section or may adopt by rulemaking portions of a State Acid Rain program in substitution of or in addition to provisions of subparts E and F of this part to administer such permits. The provisions of Acid Rain permits for Phase I or Phase II issued by the Administrator shall not be applicable requirements under part 70 of this chapter.

(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.

[62 FR 55483, Oct. 24, 1997]

Subpart H—Permit Revisions

§ 72.80 General.

(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 discretion, determine which of these sections is applicable.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55484, Oct. 24, 1997]

§ 72.81 Permit modifications.

(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).

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 62 FR 55485, Oct. 24, 1997]

§ 72.82 Fast-track modifications.

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 or with changes or conditions as appropriate, or disapprove the modification. A fast-track modification shall be subject to the same provisions for review by the Administrator and affected States as are applicable to a permit modification under § 72.81.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55485, Oct. 24, 1997]

§ 72.83 Administrative permit amendment.

(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; provided that all requirements for activation under subpart D of this part are met;

(2) Changes in the designated representative or alternative designated representative; provided that a new certificate of representation is submitted;

(3) Correction of typographical errors;

(4) Changes in names, addresses, or telephone or facsimile numbers;

(5) Changes in the owners or operators; provided that a new certificate of representation is submitted within 30 days;

(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, provided that they are in accordance with § 72.42 of this part;

(9) Changes in the date, specified in a new unit's Acid Rain permit, of commencement of operation or the deadline for monitor certification, provided that they are in accordance with § 72.9 of this part;

(10) The addition of or change in a nitrogen oxides alternative emissions limitation demonstration period, provided that the requirements of part 76 of this chapter are met; and

(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 NOX early election plan that was approved by the Administrator under § 76.8 of this chapter;

(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, provided that the requirements of paragraph (a) of this section are met.

(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 for review by the Administrator and affected States applicable to a permit modification under § 72.81.

[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 62 FR 55485, Oct. 24, 1997]

§ 72.84 Automatic permit amendment.

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.

§ 72.85 Permit reopenings.

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55485, Oct. 24, 1997]

Subpart I—Compliance Certification

§ 72.90 Annual compliance certification report.

(a) Applicability and deadline. For each calendar year in which a unit is subject to the Acid Rain emissions limitations, the designated representative of the source at which the unit is located shall submit to the Administrator, within 60 days after the end of the calendar year, an annual compliance certification report for the unit.

(b) Contents of report. The designated representative shall include in the annual compliance certification report under paragraph (a) of this section the following elements, in a format prescribed by the Administrator, concerning the unit and the calendar year covered by the report:

(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) Annual compliance certification. In the annual compliance certification report under paragraph (a) of this section, the designated representative shall certify, based on reasonable inquiry of those persons with primary responsibility for operating the source and the affected units at the source in compliance with the Acid Rain Program, whether each affected unit for which the compliance certification is submitted was operated during the calendar year covered by the report in compliance with the requirements of the Acid Rain Program applicable to the unit, including:

(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.

[58 FR 3650, Jan. 11, 1993, as amended at 64 FR 28588, May 26, 1999]

§ 72.91 Phase I unit adjusted utilization.

(a) Annual compliance certification report. The designated representative for each Phase I unit shall include in the annual compliance certification report the unit's adjusted utilization for the calendar year in Phase I covered by the report, calculated as follows:

Adjusted utilization = baseline − actual utilization − plan reductions + compensating generation provided to other units where:

(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:

Plan reductions = reduction from energy conservation + reduction from improved unit efficiency improvements + shifts to designated sulfur-free generators + shifts to designated compensating units where:

(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 in heat input (in mmBtu) resulting from those savings. The verified amount of such reduction shall be submitted in accordance with paragraph (b) of this section.

(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:

Shift to sulfur-free generator = actual sulfur-free utilization − [(average 1985-87 sulfur-free annual utilization) (1 + percentage change in dispatch system sales)] where:

(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.

EC01SE92.000

where: S = dispatch system sales (in Kwh) c = calendar year y = 1985, 1986, or 1987

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 sum of each “shift to compensating unit” that is attributed to the unit in the annual compliance certification reports submitted by the Phase I units under such other plans and that is certified under paragraph (a)(3)(iv) of this section.

(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) Confirmation report. (1) If a unit's annual compliance certification report estimates any expected kilowatt hour savings or improvement in heat rate from energy conservation or improved unit efficiency measures under a reduced utilization plan, the designated representative shall submit, by July 1 of the year in which the annual report was submitted, a confirmation report. The Administrator may grant, for good cause shown, an extension of the time to file the confirmation report. The confirmation report shall include the following elements in a format prescribed by the Administrator:

(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 (ii) of this chapter, that such authority verified specified figures related to demand-side measures; 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:

Allowances credited = (verified heat input reduction-estimated heat input reduction) × emissions rate • 2000 lbs/ton where:

(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, provided that if the amount calculated under this paragraph (b)(5)(ii)(C) is equal to or less than zero, then the amount of allowances to be deducted is zero.

(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 any increase in excess emissions of sulfur dioxide that results from the correction and require the owners and operators to pay an excess emission penalty in accordance with part 77 of this chapter.

[58 FR 3650, Jan. 11, 1993, as amended at 58 FR 40747, July 30, 1993; 59 FR 60231, Nov. 22, 1994; 60 FR 18470, Apr. 11, 1995; 62 FR 55485, Oct. 24, 1997]

§ 72.92 Phase I unit allowance surrender.

(a) Annual compliance certification report. If a Phase I unit's adjusted utilization for the calendar year in Phase I under § 72.91(a) is greater than zero, then the designated representative shall include in the annual compliance certification report the number of allowances that shall be surrendered for adjusted utilization using the formula in paragraph (c) of this section and the calculations that were performed to obtain that number.

(b) Other submissions.(1)[Reserved]

(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);

(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) Allowance surrender formula. (1) As provided under the allowance surrender formula in paragraph (c)(2) of this section:

(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;

(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:

Allowances surrendered = [dispatch system adjusted utilization + (dispatch system aggregate baseline × percentage change in dispatch system sales)] × unit's share × emissions rate • 2000 lbs/ton.

If the result of the formula for “allowances surrendered” is less than or equal to zero, then no allowances are surrendered.

(i) Calculating dispatch system adjusted utilization. “Dispatch system adjusted utilization” (in mmBtu) is the sum of the adjusted utilization under § 72.91(a) for all Phase I units in the dispatch system. If “dispatch system adjusted utilization” is less than or equal to zero, then no allowances are surrendered by any unit in that dispatch system.

(ii) Calculating dispatch system aggregate baseline. “Dispatch system aggregate baseline” is the sum of the baselines (as defined in § 72.2 of this chapter) for all Phase I units in the dispatch system.

(iii) Calculating percentage change in dispatch system sales. “Percentage change in dispatch system sales” is the “percentage change in dispatch system sales” under § 72.91 (a)(3)(iii)(C); provided that if result of the formula in § 72.91(a)(3)(iii)(C) is greater than or equal to zero, the value shall be treated as zero only for purposes of paragraph (c)(2) of this section.

(iv) Calculating unit's share. “Unit's share” is the unit's adjusted utilization divided by the sum of the adjusted utilization for all Phase I units within the dispatch system that have adjusted utilization of greater than zero and is calculated as follows:

EC01SE92.001

where:

(A) Uunit = the unit's adjusted utilization for the calendar year;

(B) Ui = the adjusted utilization of a Phase I unit in the dispatch system for the calendar year; and

(v) Calculating emissions rate. “Emissions rate” (in lbs/mmBtu) is the weighted average emissions rate for sulfur dioxide of all units and generators, within and outside the dispatch system, that contributed to the dispatch system's electrical output for the year, calculated as follows:

Emissions rate = [fraction of generation within dispatch system × dispatch system emissions rate] + [fraction of generation from non-utility generators × non-utility generator average emissions rate] + [fraction of generation outside dispatch system × fraction of non-Phase 1 and non-foreign generation in NERC region × NERC region emissions rate] where:

(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 =

ER11AP95.000

where: gi = the difference between a Phase II unit's actual utilization for the calendar year and that Phase II unit's baseline. If that difference is less than or equal to zero, then the difference shall be treated as zero only for purposes of paragraph (c)(2)(v) of this section and that unit will be excluded from the calculation of dispatch system emissions rate. Notwithstanding the prior sentence, if the actual utilization of each Phase II unit for the year is equal to or less than the baseline, then gi shall equal a Phase II unit's actual utilization for the year. Notwithstanding any provision in this paragraph (c)(2)(v)(B) to the contrary, if the actual utilization of each Phase II unit in the dispatch system is zero or there are no Phase II units in the dispatch system, then the dispatch system emissions rate shall equal the fraction of non-Phase I and non-foreign generation in the NERC region multiplied by the NERC region emissions rate. ri = a Phase II unit's emissions rate (in lbs/mmBtu), determined in accordance with part 75 of this chapter, for the calendar year. k = number of Phase II units in the dispatch system.

(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 =

ER11AP95.001

where: Ni = non-utility generation from a non-utility generator; Ri = non-utility generator emissions rate for the calendar year for a non-utility generator, which shall equal the most stringent federally enforceable or State enforceable SO2 emissions limitation applicable for the calendar year to such power production facility, as determined in accordance with paragraphs (c)(2)(v)(F) (1), (2), and (3) of this section; and n = number of non-utility generators from which the dispatch system acquired non-utility generation. If n equals zero, then the non-utility generator average emissions rate shall be treated as zero only for purposes of paragraph (c)(2)(v) of this section.

(1) For purposes of determining the most stringent emissions limitation, applicable emissions limitations shall be converted to lbs/mmBtu in accordance with appendix B of this part. If an applicable emissions limitation cannot be converted to a unit-specific limitation in lbs/mmBtu under appendix B of this part, then the limitation shall not be used in determining the most stringent emissions limitation. Where the power production facility is subject to different emissions limitations depending on the type of fuel it uses during the calendar year, the most stringent emissions limitation shall be determined separately with regard to each type of fuel and the resulting limitation with the highest amount of lbs/mmBtu shall be treated as the facility's most stringent federally enforceable or State enforceable emissions limitation.

(2) If there is no applicable emissions limitation that can be used in determining the most stringent emissions limitation under paragraph (c)(2)(v)(F)(1) of this section, then the power production facility has no non-utility generator emissions rate for purposes of paragraphs (c)(2)(v) (D) and (F) of this section and the generation from the facility shall be treated, for purposes of this paragraph (c)(2)(v) as generation from units and generators within the dispatch system if the facility is within the dispatch system or as generation from units and generators outside the dispatch system if the facility is outside the dispatch system.

(3) Notwithstanding paragraphs (c)(2)(v)(F) (1) and (2) of this section, if the power production facility is authorized under Federal or State law to use only natural gas as fuel, then the most stringent emissions limitation for the facility for the calendar year shall be deemed to be 0.0006 lbs/mmBtu.

(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.

Table 1—NERC Region Generation and Emissions Rate in 1985 NERC region Fraction of non-phase I and non-foreign generation in NERC

region

NERC weighted average emissions rate (lbs/mmBtu) WSCC 0.847 0.466 SPP 0.948 0.647 SERC 0.749 1.315 NPCC 0.423 1.058 MAPP 0.725 1.171 MAIN 0.682 1.495 MAAC 0.750 1.599 ERCOT 1.000 0.491 ECAR 0.549 1.564 [58 FR 3650, Jan. 11, 1993, as amended at 58 FR 40747, July 30, 1993; 60 FR 18470, Apr. 11, 1995]

§ 72.93 Units with Phase I extension plans.

Annual compliance certification report. The designated representative for a control unit governed by a Phase I extension plan shall include in the unit's annual compliance certification report for calendar year 1997, the start-up test results upon which the vendor is released from liability under the vendor certification of guaranteed sulfur dioxide removal efficiency under § 72.42(c)(12).

§ 72.94 Units with repowering extension plans.

(a) Design and engineering and contract requirements. No later than January 1, 2000, the designated representative of a unit governed by an approved repowering plan shall submit to the Administrator and the permitting authority:

(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) Removal from operation to re-pow-er. The designated representative of a unit governed by an approved re-pow-er-ing plan shall notify the Administrator in writing at least 60 days in advance of the date on which the existing unit is to be removed from operation so that the qualified repowering technology can be installed, or is to be replaced by another unit with the qualified repowering technology, in accordance with the plan.

(c) Commencement of operation. Not later than 60 days after the unit re-pow-ered under an approved re-pow-er-ing plan commences operation at full load, the designated representative of the unit shall submit a report comparing the actual hourly emissions and percent removal of each pollutant controlled at the unit to the actual hourly emissions and percent removal at the existing unit under the plan prior to repowering, determined in accordance with part 75 of this chapter.

(d) Decision to terminate. If at any time before the end of the repowering extension the owners and operators decide to terminate good faith efforts to design, construct, and test the qualified repowering technology on the unit to be repowered under an approved repowering plan, then the designated representative shall submit a notice to the Administrator by the earlier of the end of the repowering extension or a date within 30 days of such decision, stating the date on which the decision was made.

§ 72.95 Allowance deduction formula.

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:

Total allowances deducted = Tons emitted + Allowances surrendered for underutilization + Allowances deducted for Phase I extensions + Allowances deducted for substitution or compensating units where:

(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).

[58 FR 3650, Jan. 11, 1993, as amended at 62 FR 55485, Oct. 24, 1997]

§ 72.96 Administrator's action on compliance certifications.

(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.

Pt. 72, App. A Appendix A to Part 72—Methodology for Annualization of Emissions Limits

For the purposes of the Acid Rain Program, 1985 emissions limits must be expressed in pounds of SO2 per million British Thermal Unit of heat input (lb/mmBtu) and expressed on an annual basis.

Annualization factors are used to develop annual equivalent SO2 limits as required by section 402(18) of the CAA. Many emission limits are enforced on a shorter term basis (or averaging period) than annually. Because of the variability of sulfur in coal and, in some cases, scrubber performance, meeting a particular limit with an averaging period of less than a year and at a specified statutory emissions level would require a lower annual average SO2 emission rate (or annual equivalent SO2 limit) than would the shorter term statutory limit. EPA has selected a compliance level of one exceedance per 10 years. For example, an SO2 emission limit of 1.2 lbs/MMBtu, enforced for a scrubbed unit over a 7-day averaging period, would result in an annualized SO2 emission limit of 1.16 lbs/MMBtu. In general, the shorter the averaging period, the lower the annual equivalent would be. Thus, the annualization of limits is established by multiplying each federally enforceable limit by an annualization factor that is determined by the averaging period and whether or not it's a scrubbed unit.

Table A-1—SO2Emission Averaging Periods and Annualization Factors Definition Annualization factor Scrubbed Unscrubbed Unit Unit Oil/gas unit 1.00 1.00 <=1 day 0.93 0.89 1 week 0.97 0.92 30 days 1.00 0.96 90 days 1.00 1.00 1 year 1.00 1.00 Not specified 0.93 0.89 At all times 0.93 0.89 Coal unit: No Federal limit or limit unknown 1.00 1.00 Pt. 72, App. B Appendix B to Part 72—Methodology for Conversion of Emissions Limits

For the purposes of the Acid Rain Program, all emissions limits must be expressed in pounds of SO2 per million British Thermal Unit of heat input (lb/mmBtu).

The factor for converting pounds of sulfur to pounds of SO2 is based on the molecular weights of sulfur (32) and SO2 (64). Limits expressed as percentage of sulfur or parts per million (ppm) depend on the energy content of the fuel and thus may vary, depending on several factors such as fuel heat content and atmospheric conditions. Generic conversions for these limits are based on the assumed average energy contents listed in table A-2. In addition, limits in ppm vary with boiler operation (e.g., load and excess air); generic conversions for these limits assume, conservatively, very low excess air. The remaining factors are based on site-specific heat rates and capacities to develop conversions for Btu per hour. Standard conversion factors for residual oil are 42 gal/bbl and 7.88 lbs/gal.

Table B-1—Conversion Factors [Emission limits converted to lbs SO2/MMBtu by multiplying as below] Unit measurement Plant fuel type Bituminous coal Subbituminous coal Lignite coal Oil Lbs sulfur/ MMBtu 2.0 2.0 2.0 2.0 % sulfur in fuel 1.66 2.22 2.86 1.07 Ppm SO2 0.00287 0.00384 0.00167 Ppm sulfur in fuel 0.00334 Tons SO2/hour 2,000,000/(HEATRATE*SUMNDCAP*capacity factor) 1 Lbs SO2/hour 1,000/(HEATRATE*SUMNDCAP*capacity factor) 1 1 In these cases, if the limit was specified as the “site” limit, the summer net dependable capability for the entire plant is used; otherwise, the summer net dependable capability for the unit is used. For units listed in the NADB, “HEATRATE” shall be that listed in the NADB under that field and “SUMNDCAP” shall be that listed in the NADB under that field. For units not listed in the NADB, “HEATRATE” is the generator net full load heat rate reported on Form EIA-860 and “SUMNDCAP” is the summer net dependable capability of the generator (in MWe) as reported on Form EIA-860. Table B-2—Assumed Average Energy Contents Fuel type Average heat content Bituminous Coal 24 MMBtu/ton. Subbituminous Coal 18 MMBtu/ton. Lignite Coal 14 MMBtu/ton. Residual Oil 6.2 MMBtu/bbl. Pt. 72, App. C Appendix C to Part 72—Actual 1985 Yearly SO 2 Emissions Calculation

The equation used to calculate the yearly SO2 emissions (SO2) is as follows:

SO2 = (coal SO2 emissions) + (oil SO2 emissions) (in tons)

If gas is the only fuel, gas emissions are defaulted to 0.

Each fuel type SO2 emissions is calculated on a yearly basis, using the equation:

fuel SO2 emissions (in tons) = (yrly wtd. av. fuel sulfur %) × (AP-42 fact.) × (1−scrb. effic. %/100) × (units conver. fact.) × (yearly fuel burned)

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 SO2 ton coal, is by coal type:

Coal type AP-42 factor Bituminous, anthracite 39 lbs/ton Subbituminous 35 Lignite 30

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 SO2/thousand gal oil, is by oil type:

Oil type AP-42 factor Distillate (light) 142 lbs/1,000 gal Residual (heavy) 157

For all fuel, the units conversion factor is 1 ton/2000 lbs.

Pt. 72, App. D Appendix D to Part 72—Calculation of Potential Electric Output Capacity

The potential electrical output capacity is calculated from the maximum design heat input from the boiler by the following equation:

EC10NO91.003

For example: (1) Assume a boiler with a maximum design heat input capacity of 340 million Btu/hr. (2) One-third of the maximum design heat input capacity is 113.3 mmBtu/hr. The one-third factor relates to the thermodynamic efficiency of the boiler. (3) To express this in MWe, the standards conversion of 3413 Btu to 1 kw-hr is used: 113.3×106 Btu/hr×1 kw-hr / 3413 Btu×1 MWe / 1000 kw=33.2 MWe [58 FR 15649, Mar. 23, 1993] Pt. 73 PART 73—SULFUR DIOXIDE ALLOWANCE SYSTEM Subpart A—Background and Summary Sec. 73.1 Purpose and scope. 73.2 Applicability. 73.3 General. Subpart B—Allowance Allocations 73.10 Initial allocations for phase I and phase II. 73.11 [Reserved] 73.12 Rounding procedures. 73.13 Procedures for submittals. 73.14-73.17 [Reserved] 73.18 Submittal procedures for units commencing commercial operation during the period from January 1, 1993, through December 31, 1995. 73.19 Certain units with declining SO2 rates. 73.20 Phase II early reduction credits. 73.21 Phase II repowering allowances. 73.22-73.24 [Reserved] 73.25 Phase I extension reserve. 73.26 Conservation and renewable energy reserve. 73.27 Special allowance reserve. Subpart C—Allowance Tracking System 73.30 Allowance tracking system accounts. 73.31 Establishment of accounts. 73.32 Allowance account contents. 73.33 Authorized account representative. 73.34 Recordation in accounts. 73.35 Compliance. 73.36 Banking. 73.37 Account error and dispute resolution. 73.38 Closing of accounts. Subpart D—Allowance Transfers 73.50 Scope and submission of transfers. 73.51 Prohibition. 73.52 EPA recordation. 73.53 Notification. Subpart E—Auctions, Direct Sales, and Independent Power Producers Written Guarantee 73.70 Auctions. 73.71 Bidding. 73.72 Direct sales. 73.73 Delegation of auctions and sales and termination of auctions and sales. Subpart F—Energy Conservation and Renewable Energy Reserve 73.80 Operation of allowance reserve program for conservation and renewable energy. 73.81 Qualified conservation measures and renewable energy generation. 73.82 Application for allowances from reserve program. 73.83 Secretary of Energy's action on net income neutrality applications. 73.84 Administrator's action on applications. 73.85 Administrator review of the reserve program. 73.86 State regulatory autonomy. Appendix A to Subpart F—List of Qualified Energy Conservation Measures, Qualified Renewable Generation, and Measures Applicable for Reduced Utilization Subpart G—Small Diesel Refineries 73.90 Allowance allocations for small diesel refineries. Authority:

42 U.S.C. 7601 and 7651 et seq.

Subpart A—Background and Summary Source:

58 FR 3687, Jan. 11, 1993, unless otherwise noted.

§ 73.1 Purpose and scope.

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.

[58 FR 3687, Jan. 11, 1993, as amended at 58 FR 15650, Mar. 23, 1993]

§ 73.2 Applicability.

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.

§ 73.3 General.

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.

Subpart B—Allowance Allocations Source:

58 FR 3687, Jan. 11, 1993, unless otherwise noted.

§ 73.10 Initial allocations for phase I and phase II.

(a) Phase I allowances. The Administrator will allocate allowances to the unit account for each unit listed in table 1 of this section in the amount listed in column A to be held in each future year subaccount for the years 1995 through 1999.

Table 1—Phase I Allowance Allocations State name Plant name Boiler Column A final phase 1 allocation Column B auction and sales reserve Alabama Colbert 1 13213 357 2 14907 403 3 14995 405 4 15005 405 5 36202 978 E.C. Gaston 1 17624 476 2 18052 488 3 17828 482 4 18773 507 5 58265 1575 Florida Big Bend BB01 27662 748 BB02 26387 713 BB03 26036 704 Crist 6 18695 505 7 30846 834 Georgia Bowen 1BLR 54838 1482 2BLR 53329 1441 3BLR 69862 1888 4BLR 69852 1888 Hammond 1 8549 231 2 8977 243 3 8676 234 4 36650 990 Jack McDonough MB1 19386 524 MB2 20058 542 Wansley 1 68908 1862 2 63708 1722 Yates Y1BR 7020 190 Y2BR 6855 185 Y3BR 6767 183 Y4BR 8676 234 Y5BR 9162 248 Y6BR 24108 652 Y7BR 20915 565 Illinois Baldwin 1 46052 1245 2 48695 1316 3 46644 1261 Coffeen 01 12925 349 02 39102 1057 Grand Tower 09 6479 175 Hennepin 2 20182 545 Joppa Steam 1 12259 331 2 10487 283 3 11947 323 4 11061 299 5 11119 301 6 10341 279 Kincaid 1 34564 934 2 37063 1002 Meredosia 05 15227 411 Vermilion 2 9735 263 Indiana Bailly 7 12256 331 8 17134 463 Breed 1 20280 548 Cayuga 1 36581 989 2 37415 1011 Clifty Creek 1 19620 530 2 19289 521 3 19873 537 4 19552 528 5 18851 509 6 19844 536 Elmer W. Stout 50 4253 115 60 5229 141 70 25883 699 F.B. Culley 2 4703 127 3 18603 503 Frank E. Ratts 1SG1 9131 247 2SG1 9296 251 Gibson 1 44288 1197 2 44956 1215 3 45033 1217 4 44200 1195 H.T. Pritchard 6 6325 171 Michigan City 12 25553 691 Petersburg 1 18011 487 2 35496 959 R. Gallagher 1 7115 192 2 7980 216 3 7159 193 4 8386 227 Tanners Creek U4 27209 735 Wabash River 1 4385 118 2 3135 85 3 4111 111 5 4023 109 6 13462 364 Warrick 4 29577 799 Iowa Burlington 1 10428 282 Des Moines 11 2259 61 George Neal 1 2571 69 Milton L. Kapp 2 13437 363 Prairie Creek 4 7965 215 Riverside 9 3885 105 Kansas Quindaro 2 4109 111 Kentucky Coleman C1 10954 296 C2 12502 338 C3 12015 325 Cooper 1 7254 196 2 14917 403 E.W. Brown 1 6923 187 2 10623 287 3 25413 687 Elmer Smith 1 6348 172 2 14031 379 Ghent 1 27662 748 Green River 5 7614 206 H.L. Spurlock 1 22181 599 HMP&L Station 2 H1 12989 351 H2 11986 324 Paradise 3 57613 1557 Shawnee 10 9902 268 Maryland C.P. Crane 1 10058 272 2 8987 243 Chalk Point 1 21333 577 2 23690 640 Morgantown 1 34332 928 2 37467 1013 Michigan J.H. Campbell 1 18773 507 2 22453 607 Minnesota High Bridge 6 4158 112 Mississippi Jack Watson 4 17439 471 5 35734 966 Missouri Asbury 1 15764 426 James River 5 4722 128 LaBadie 1 39055 1055 2 36718 992 3 39249 1061 4 34994 946 Montrose 1 7196 194 2 7984 216 3 9824 266 New Madrid 1 27497 743 2 31625 855 Sibley 3 15170 410 Sioux 1 21976 594 2 23067 623 Thomas Hill MB1 9980 270 MB2 18880 510 New Hampshire Merrimack 1 9922 268 2 21421 579 New Jersey B.L. England 1 8822 238 2 11412 308 New York Dunkirk 3 12268 332 4 13690 370 Greenidge 6 7342 198 Milliken 1 10876 294 2 12083 327 Northport 1 19289 521 2 23476 634 3 25783 697 Port Jefferson 3 10194 276 4 12006 324 Ohio Ashtabula 7 18351 496 Avon Lake 11 12771 345 12 33413 903 Cardinal 1 37568 1015 2 42008 1135 Conesville 1 4615 125 2 5360 145 3 6029 163 4 53463 1445 Eastlake 1 8551 231 2 9471 256 3 10984 297 4 15906 430 5 37349 1009 Edgewater 13 5536 150 Gen. J.M. Gavin 1 86690 2343 2 88312 2387 Kyger Creek 1 18773 507 2 18072 488 3 17439 471 4 18218 492 5 18247 493 Miami Fort 5-1 417 11 5-2 417 11 6 12475 337 7 42216 1141 Muskingum River 1 16312 441 2 15533 420 3 15293 413 4 12914 349 5 44364 1199 Niles 1 7608 206 2 9975 270 Picway 9 5404 146 R.E. Burger 5 3371 91 6 3371 91 7 11818 319 8 13626 368 W.H. Sammis 5 26496 716 6 43773 1183 7 47380 1280 Walter C. Beckjord 5 9811 265 6 25235 682 Pennsylvania Armstrong 1 14031 379 2 15024 406 Brunner Island 1 27030 730 2 30282 818 3 52404 1416 Cheswick 1 38139 1031 Conemaugh 1 58217 1573 2 64701 1749 Hatfield's Ferry 1 36835 995 2 36338 982 3 39210 1060 Martins Creek 1 12327 333 2 12483 337 Portland 1 5784 156 2 9961 269 Shawville 1 10048 272 2 10048 272 3 13846 374 4 13700 370 Sunbury 3 8530 230 4 11149 301 Tennessee Allen 1 14917 403 2 16329 441 3 15258 412 Cumberland 1 84419 2281 2 92344 2496 Gallatin 1 17400 470 2 16855 455 3 19493 527 4 20701 559 Johnsonville 1 7585 205 10 7351 199 2 7828 212 3 8189 221 4 7780 210 5 8023 217 6 7682 208 7 8744 236 8 8471 229 9 6894 186 West Virginia Albright 3 11684 316 Fort Martin 1 40496 1094 2 40116 1084 Harrison 1 47341 1279 2 44936 1214 3 40408 1092 Kammer 1 18247 493 2 18948 512 3 16932 458 Mitchell 1 42823 1157 2 44312 1198 M.T. Storm 1 42570 1150 2 34644 936 3 41314 1116 Wisconsin Edgewater 4 24099 651 Genoa 1 22103 597 Nelson Dewey 1 5852 158 2 6504 176 North Oak Creek 1 5083 137 2 5005 135 3 5229 141 4 6154 166 Pulliam 8 7312 198 South Oak Creek 5 9416 254 6 11723 317 7 15754 426 8 15375 415

(b) Phase II allowances. (1) 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 C to be held in the future year subaccounts representing calendar years 2000 through 2009.

(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.

ER28SE98.001 ER28SE98.002 ER28SE98.003 ER28SE98.004 ER28SE98.005 ER28SE98.006 ER28SE98.007 ER28SE98.008 ER28SE98.009 ER28SE98.010 ER28SE98.011 ER28SE98.012 ER28SE98.013 ER28SE98.014 ER28SE98.015 ER28SE98.016 ER28SE98.017 ER28SE98.018 ER28SE98.019 ER28SE98.020 ER28SE98.021 ER28SE98.022 ER28SE98.023 ER28SE98.024 ER28SE98.025 ER28SE98.026 ER28SE98.027 ER28SE98.028 ER28SE98.029 ER28SE98.030 ER28SE98.031 ER28SE98.032 ER28SE98.033 ER28SE98.034 ER28SE98.035 ER28SE98.036 ER28SE98.037 ER28SE98.038 ER28SE98.039 ER28SE98.040 ER28SE98.041 ER28SE98.042 ER28SE98.043 ER28SE98.044 ER28SE98.045 ER28SE98.046 ER28SE98.047 ER28SE98.048 ER28SE98.049 ER28SE98.050

(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.

State Plant name Unit Allowances for 2000 through 2009

column (A)

Allowances for 2010 and thereafter

column (B)

Proceeds CA El Centro 2 285 272 $2749.48 CO Valmont 11 4 0 0 FL Lauderdale PFL4 776 781 7904.74 FL Lauderdale PFL5 796 802 7904.74 LA R S Nelson 1 30 34 0 LA R S Nelson 2 33 32 0 MD R P Smith 9 0 56 687.37 NM Maddox **3 85 85 687.37 SD Mobile **2 17 17 0 VA Chesterfield **8B 409 411 4124.21 WI Blount Street 7 0 13 343.68 WI Blount Street 8 0 294 3093.16 WI Blount Street 9 0 355 3436.84 [58 FR 3687, Jan. 11, 1993, as amended at 58 FR 15650, Mar. 23, 1993; 58 FR 33770, June 21, 1993; 58 FR 40747, July 30, 1993; 62 FR 55486, Oct. 24, 1997; 63 FR 51714, Sept. 28, 1998]

§ 73.11 [Reserved]

§ 73.12 Rounding Procedures.

(a) Calculation rounding. All allowances under this part and part 72 of this chapter shall be allocated as whole allowances. All calculations for such allowances shall be rounded down for decimals less than 0.500 and up for decimals of 0.500 or greater.

(b) [Reserved]

[58 FR 3687, Jan. 11, 1993, as amended at 63 FR 51765, Sept. 28, 1998]

§ 73.13 Procedures for submittals.

(a) Address for submittal. All submittals under this subpart shall be made by the designated representative to the Director, Acid Rain Division, (6204J), 401 M Street, SW., Washington, DC 20460 and shall meet the requirements specified in 40 CFR 72.21.

(b) Appeals procedures. The designated representative may appeal the decision as to eligibility or allocation of allowances under §§ 73.18, 73.19, and 73.20, using the appeals procedures of part 78 of this chapter.

[58 FR 15708, Mar. 23, 1993 as amended at 63 FR 51765, Sept. 28, 1998]

§§ 73.14-73.17 [Reserved]

§ 73.18 Submittal procedures for units commencing commercial operation during the period from January 1, 1993, through December 31, 1995.

(a) Eligibility. To be eligible for allowances under this section, a unit shall commence commercial operation between January 1, 1993, and December 31, 1995, and have commenced construction before December 31, 1990.

(b) Application for allowances. No later than December 31, 1995, the designated representative for a unit expected to be eligible under this provision must submit a photocopy of a signed contract for the construction of the unit.

(c) Commencement of commercial operation. The Administrator will use EIA information submitted by the utility for the boiler on-line date as commencement of commercial operation.

[58 FR 15710, Mar. 23, 1993]

§ 73.19 Certain units with declining SO2 rates.

(a) Eligibility. A unit is eligible for allowance allocations under this section if it meets the following requirements:

(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 SO2 emissions rate was equal to or greater than 1.2 lb/mmBtu;

(4) Its 1990 actual SO2 emissions rate is at least 50 percent less than the lesser of its 1980 actual or allowable SO2 emissions rate;

(5) Its actual SO2 emission rate is less than 1.2 lb/mmBtu in any one calendar year from 1996 through 1999, as reported under part 75 of this chapter;

(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 SO2 emissions rate declined 40 percent or more from 1980 to 1988.

(b)[Reserved]

[58 FR 15710, Mar. 23, 1993, as amended at 63 FR 51765, Sept. 28, 1998]

§ 73.20 Phase II early reduction credits.

(a) Unit eligibility. Units listed in table 2 or 3 of § 73.10 are eligible for allowances under this section if:

(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-fired generation, as a percentage of total system generation, by more than twenty percent between January 1, 1980, and December 31, 1985; and

(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:

EC01SE92.073

(b) Emissions reductions eligibility. Sulfur dioxide emissions reductions eligible for allowance credits at units eligible under paragraph (a) of this section must meet the following requirements:

(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) Initial certification of eligibility. The designated representative of a unit that seeks allowances under this section shall apply for certification of unit eligibility prior to or accompanying a request for allowances under paragraph (d) of this section. A completed application for this certification shall be submitted according to § 73.13 and shall include the following:

(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) Request for allowances. (1) The designated representative of the requesting unit shall submit the request for allowances according to the procedures of § 73.13 and shall include the following information:

(i) The calendar year for which credits for reductions are requested and the actual SO2 emissions and fuel consumption in that year;

(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) Allowance allocation. The Administrator will allocate allowances to the eligible unit upon satisfactory submittal of information under paragraphs (c) and (d) of this section in the amount calculated by the following equations. Such allowances will be allocated to the unit's 2000 future year subaccount.

(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 SO2 emissions reductions.

(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 SO2 emission rate will be equal to the weighted average emission rate of all of the other units at the same source that did operate during 1990.

(5) Early reduction credits will be calculated at the unit level, subject to the restrictions in paragraph (e)(6) of this section.

(6) The number of credits for eligible Phase II units will be calculated as follows:

(i) Comparison of the prior year utilization of ERC units to the 1990 utilization, as a percentage of system utilization. If, as calculated below, system-wide prior year utilization of ERC units exceeds systems-wide 1990 utilization of ERC units on a percentage basis, then paragraphs (e)(6)(ii) and (iii) of this section apply. If not, the ERC units are eligible to receive early reduction credits as calculated in paragraph (e)(6)(v)(A) of this section.

EC01SE92.074

(ii) Comparison of the prior year average emission rate of all ERC units to the prior year average emission rate of all non-ERC units. If, as calculated below, the system-wide average SO2 emission rate of ERC units exceeds that of non-ERC units, then a unit's prior year utilization will be restricted in accordance with paragraph (e)(6)(iv) of this section. If not, then paragraph (iii) of this section applies.

EC01SE92.075

(iii) Comparison of the emission rate of the non-ERC units in the prior year to the emission rate of the non-ERC units in 1990. If, as calculated in paragraph (ii) of this section, the prior year system average non-ERC SO2 emission rate increases above the 1990 system average non-ERC SO2 emission rate, as calculated below, then a unit's prior year utilization will be restricted in accordance with paragraph (e)(6)(iv) of this section. If not, the ERC units are eligible to receive early reduction credits as calculated in paragraph (e)(6)(v)(A) of this section.

EC01SE92.076

(iv) Calculation of the utilization limit for restricted units. The limit on utilization for each unit eligible for early reduction credits subject to paragraphs (e)(6) (ii) and (iii) of this section will be calculated as follows:

EC01SE92.077

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) Calculation of the unit's early reduction credits where the unit's prior year utilization is not restricted.

EC01SE92.078

(B) Calculation of the unit's early reduction credits where the unit's prior year utilization is restricted.

EC01SE92.079

(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:

EC01SE92.080

(f) Allowance loan program. (1) Eligibility. Units eligible for Phase II early reduction credits under paragraph (a) of this section are eligible for allowances under this paragraph (f) if the weighted average emission rate (based on heat input) for the prior year for all of the affected units in the unit's dispatch system was less than the system-wide weighted average emission rate for 1990. The weighted average emission rate shall be calculated as follows:

ER24JN97.000

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) Allowance Calculation. Allowances under this paragraph (f) shall be calculated as follows:

ER24JN97.001

(3) Allowance Loan. (i) The number of allowances calculated under paragraph (f)(2) of this section shall be allocated to the unit's year 2000 subaccount.

(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 2016 subaccount (up to the amount of allowances allocated to the unit for the year 2016) shall be deducted contemporaneously, such that the sum of the allowances deducted from the subaccounts equals the number of allowances required to be deducted under paragraph (f)(3)(ii) of this section.

(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) ERC Units. Any unit to which allowances are allocated under paragraph (f)(3)(i) of this section shall be considered an ERC unit for purposes of applying the restrictions in paragraph (e)(6) of this section.

[58 FR 15711, Mar. 23, 1993, as amended at 62 FR 34150, June 24, 1997]

§ 73.21 Phase II repowering allowances.

(a) Repowering allowances. In addition to allowances allocated under § 73.10(b), the Administrator will allocate, to each existing unit (under § 72.44(b)(1) of this chapter) with an approved repowering extension plan, allowances for use during the repowering extension period approved under § 72.44(f)(2)(ii) of this chapter (including a prorated allocation for any fraction of a year) equal to:

EC01SE92.081

where: 1995 SIP = Most stringent federally enforceable State implementation plan SO2 emissions limitation for 1995. 1995 Actual Rate = 1995 actual SO2 emissions rate Unit's Adjusted Basic Allowances are as listed in the following table Unit Year 2000 adjusted basic allowances RE Burger 1 1273 RE Burger 2 1245 RE Burger 3 1286 RE Burger 4 1316 RE Burger 5 1336 RE Burger 6 1332 New Castle 1 1334 New Castle 2 1485 New Castle 3 2935 New Castle 4 2686 New Castle 5 5481

(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:

EC01SE92.082

where: Forfeiture Period = difference (as a portion of a year) between the end of the approved repowering extension and the end of the repowering extension under § 72.44(g)(1)(ii) 1995 SIP = Most stringent federally enforceable State implementation plan SO2 emissions limitation for 1995. 1995 Actual Rate = 1995 actual SO2 emissions rate Unit's Adjusted Basic Al-low-anc-es are as listed in the table in paragraph (a) of this section.

(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:

ER28SE98.051 [53 FR 15713, Mar. 23, 1993, as amended at 63 FR 51765, Sept. 28, 1998]

§§ 73.22-73.24 [Reserved]

§ 73.25 Phase I extension reserve.

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.

[58 FR 3687, Jan. 11, 1993]

§ 73.26 Conservation and renewable energy 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).

[53 FR 15714, Mar. 23, 1993]

§ 73.27 Special allowance reserve.

(a) Establishment of Reserve. (1) The Administrator will allocate 150,000 allowances annually for calendar years 1995 through 1999 to the Auction Subaccount of the Special Allowance Reserve.

(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) Distribution of proceeds. (1) Monetary proceeds from the auctions and sales of allowances from the Special Allowance Reserve (under subpart E of this part) for use in calendar years 1995 through 1999 will be distributed to the designated representative of the unit according to the following equation:

unit proceeds = (Column B of table 1 of section 73.10/150,000) × total proceeds

(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:

ER28SE98.052

(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:

ER28SE98.053

(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:

ER28SE98.054

(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:

ER28SE98.055

(c) Reallocation of allowances. (1) Allowances remaining in the Special Allowance Reserve following the annual auctions and sales (under subpart E of this part) for use in calendar years 1995 through 1999 will be reallocated to the unit's Allowance Tracking System Account according to the following equation:

unit allowances = (Column B of table 1 of section 73.10/150,000) × Allowances remaining

(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:

ER28SE98.056

(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:

ER28SE98.057

(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:

ER28SE98.058

(d) Calculation rounding. All proceeds under this section shall be distributed as whole dollars. All calculations for such allowances shall be rounded down for decimals less than .5 and up for decimals of .5 or greater.

(e) Achieving exact totals. (1) If the sum of the proceeds to be distributed under paragraph (b) of this section exceeds the total proceeds or the allowances to be reallocated under paragraph (c) of this section exceeds the allowances remaining, then the Administrator will withdraw one dollar or allowance from 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.

(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.

[58 FR 3687, Jan. 11, 1993, as amended at 58 FR 15714, Mar. 23, 1993; 63 FR 51765, Sept. 28, 1998]

Subpart C—Allowance Tracking System Source:

58 FR 3691, Jan. 11, 1993, unless otherwise noted.

§ 73.30 Allowance tracking system accounts.

(a) Nature and function of unit accounts. The Administrator will establish accounts for all affected units pursuant to § 73.31 (a) and (b). All allocations of allowances pursuant to subparts B, E, and F of this part and part 72 of this chapter, transfers of allowances made pursuant to subparts C and D, and deductions of allowances made for purposes of offsetting emissions pursuant to § 73.35 (b) and (d) and parts 72, 75, and 77 of this chapter will be recorded in the unit's Allowance Tracking System account.

(b) Nature and function of general accounts. Transfers of allowances held for any person other than an affected unit, made pursuant to subparts C, D, E, F, and G of this part will be recorded in that person's Allowance Tracking System account established pursuant to § 73.31(c).

[58 FR 3687, Jan. 11, 1993; 58 FR 40747, July 30, 1993]

§ 73.31 Establishment of accounts.

(a) Existing affected units. The Administrator will establish an Allowance Tracking System account and allocate allowances for each unit that is, or will become, an existing affected unit pursuant to sections 404(a) or 405 of the Act and § 72.6 of this chapter.

(b) New units. Upon receipt of a complete certificate of representation for the designated representative for a new unit pursuant to part 72, subpart B of this chapter, the Administrator will establish an Allowance Tracking System account for the unit.

(c) General accounts. (1) Any person may apply to open an Allowance Tracking System account for the purpose of holding and transferring allowances. Such application shall be submitted to the Administrator in a format to be specified by the Administrator by means of the Allowance Account Information Form, or by providing the following information in a similar format:

(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 Administrator has established the new account.

(d) Account identification. The Administrator will assign a unique identifying number to each account established pursuant to this section.

[58 FR 3687, Jan. 11, 1993; 58 FR 40747, July 30, 1993]

§ 73.32 Allowance account contents.

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;

(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.

[58 FR 3687, Jan. 11, 1993; 58 FR 40747, July 30, 1993]

§ 73.33 Authorized account representative.

(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) Authorized account representative identification. The Administrator will assign a unique identifying number to each authorized account representative or alternate authorized account representative identified pursuant to § 73.31(c).

(c) Notification of parties subject to the binding agreement. The authorized account representative for a general account shall notify, in writing, all persons who have an ownership interest with respect to the allowances held in the account of any Acid Rain Program submission required by this part or in a procedure under part 78 of this chapter, by the date of submission. Each person who has an ownership interest with respect to the allowances held in the account may expressly waive his or her right to receive such notification.

(d) General account alternate authorized account representative. Any application for opening a general account may designate one alternate authorized account representative to act on behalf of the certifying authorized account representative, in the event the authorized account representative is absent or otherwise not available to perform actions and duties under this part. The alternate shall be a natural person and shall be authorized, provided that the conditions and procedures specified in § 73.31(c)(1) are met.

(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 action of the authorized account representative, with all the rights, duties, and responsibilities pertaining thereto.

(e) Changes to the general account authorized account representative. An authorized account representative for a general account may be succeeded by any person who submits an application pursuant to § 73.31(c). The actions of an authorized account representative for a general account shall be binding on any successor.

(f) Objections to the authorized account representative. Except for a certification pursuant to paragraph (e) of this section, no objection or other communication submitted to the Administrator concerning any submission to the Administrator by the authorized account representative shall affect the recordation of transfers submitted by the authorized account representative pursuant to subpart D of this part. Neither the United States, the Administrator, nor any permitting authority will adjudicate any dispute between and among persons concerning any submission to the Administrator by the authorized account representative; any actions of the authorized account representative; or any other matter arising directly or indirectly from the certification, actions or representations of the authorized account representative.

§ 73.34 Recordation in accounts.

(a) Recordation in compliance sub-ac-counts. At the beginning of 1995 and, in the case of each year thereafter, after the Administrator has made all deductions from an affected unit's compliance subaccount pursuant to § 73.35(b), the Administrator will record in the compliance subaccount the allowances held in the future year subaccount for the year corresponding to the current calendar year. The future year subaccount for the new 30th year will be established at the same time and include the allowances allocated for the unit for that year pursuant to subpart B of this part.

(b) Recordation in current year subaccounts. At the beginning of 1995 and each year thereafter, the Administrator will record in the current year subaccount the allowances held in the future year subaccount for the year corresponding to the current calendar year.

(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) Serial numbers for allocated allowances. Upon the allocation of allowances to an account, including allowances contained in reserves as provided in subpart B of this part, the Administrator will assign each allowance a unique identification number that will include digits identifying the allowance's compliance use date.

[58 FR 3691, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 63 FR 68404, Dec. 11, 1998]

§ 73.35 Compliance.

(a) Allowance transfer deadline. No allowance shall be deducted for purposes of compliance with an affected unit's sulfur dioxide Acid Rain emissions limitation requirements pursuant to title IV of the Act and paragraph (b) of this section unless:

(1) The compliance use date of the allowance is no later than the year in which the unit's SO2 emissions occurred; and

(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 later than the allowance transfer deadline in the calendar year following the year for which compliance is being established; or

(iii) Held in the compliance subaccount of another affected unit at the same source in accordance with paragraph (b)(3) of this section.

(b) Deductions for compliance. (1) Except as provided in paragraph (d) of this section, following the recordation of transfers submitted correctly for recordation in the compliance subaccount pursuant to paragraph (a) of this section and subpart D of this part, the Administrator will deduct allowances from each affected unit's compliance subaccount in accordance with the allowance deduction formula in § 72.95 of this chapter, or, for opt-in sources, the allowance deduction formula in § 74.49 of this chapter, and any correction made under § 72.96 of this chapter.

(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:

Maximum deduction from other units = 0.95 × Excess emissions if no deduction from other units

Where:

“Maximum deduction from other units” is the maximum number of allowances that may be deducted for the year for which compliance is being established, for the unit otherwise having excess emissions, from the compliance subaccounts of other units at the same source, rounded to the nearest allowance. “Excess emissions if no deduction from other units” is the tons of excess emissions that the unit would otherwise have if no allowances were deducted for the unit from other units under this paragraph (b)(3)(i) or paragraph (b)(3)(ii) of this section.

(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) Identification of allowances by serial number. By no later than sixty days after the end of the calendar year, the authorized account representative for each unit account may identify by serial number the allowances to be deducted from the compliance subaccount for purposes of compliance with the unit's sulfur dioxide emissions limitation requirements. Such identification shall be made pursuant to part 72 of this chapter.

(2) First-in, first-out. In the absence of an identification or in the case of a partial identification of allowances by serial number, as provided for in paragraph (b)(1) or (d) of this section, the Administrator will deduct allowances on a first-in, first-out (FIFO) accounting basis beginning with those allowances with the earliest compliance use date originally allocated for the unit and recorded in its compliance subaccount. Following the deduction of all originally allocated allowances from the compliance subaccount, the Administrator will deduct those allowances that were transferred and recorded in the unit's compliance subaccount pursuant to subpart D of this part, beginning with those with the earliest date of recordation.

(d) Deductions for excess emissions. Pursuant to § 77.4 of this chapter, and following the process of recordation set forth in § 73.34(a) of this part, the Administrator will deduct allowances for each unit with excess emissions for the preceding calendar year in an amount equal to the unit's excess emissions tonnage.

(e) Deductions for units sharing a common emission stack. In the case of units sharing a common emission stack and have emissions that are not individually monitored pursuant to part 75 of this chapter, the authorized account representative may identify the percentage of allowances to be deducted from each unit's compliance subaccount. Such identification shall be made pursuant to part 72, subpart I of this chapter. In the absence of an identification, the Administrator will deduct an equal percentage of allowances from each unit's compliance subaccount.

[58 FR 3691, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 64 FR 25842, May 13, 1999]

§ 73.36 Banking.

(a) Unit accounts. Any allowance in a compliance subaccount not deducted pursuant to § 73.35 will remain in the compliance subaccount.

(b) General accounts. In the case of a general account, any allowances in the current year subaccount at the end of the current calendar year will remain in the current year subaccount.

§ 73.37 Account error and dispute resolution.

(a) Claim of error. The authorized account representative may notify the Administrator of any claim that the Administrator made an error in recording transfer information that was submitted correctly pursuant to subpart D of this part, provided that such claim of error notification is submitted to the Administrator by no later than 15 business days following the date mark of the notification by the Administrator pursuant to actions taken under § 73.37(d) or § 73.53. Such claim of error notification shall be in writing and shall include:

(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.

The Administrator will not act on claim of error notifications received after the stated deadlines (except as provided under paragraph (f) of this section, or that do not contend that the Administrator made an error in recordation.

(b) EPA action. The Administrator, at the Administrator's sole discretion based on documentation provided, will determine what changes, if any, will be made to the accounts subject to the alleged error. Not later than 20 business days after receipt of a claim of error notification pursuant to paragraph (a) of this section, the Administrator will submit to the authorized account representative a written response stating:

(1) The determination made and any action taken by, the Administrator; and

(2) The reasons for such action.

(c) Administrative appeals procedure. Following the Administrator's action pursuant to paragraph (b) of this section, the authorized account representative may appeal the Administrator's action through the administrative appeals procedure pursuant to part 78 of this chapter.

(d) EPA corrections. The Administrator may, without prior notice of a claim of error and in the Administrator's sole discretion, correct any errors in any account on his or her own motion. The Administrator will notify the authorized account representative by no later than 20 business days following any such corrections.

(e) Excess emissions requirements. The filing of a claim of error notification pursuant to paragraph (a) of this section, or the pendency of the Administrator's action pursuant to paragraph (b) of this section, shall not affect a unit's obligations under part 77 of this chapter.

(f) Waiver of deadline. The Administrator may, in his or her discretion, accept claim of error submissions made following the deadlines imposed in this section upon a demonstration by the authorized account representative of good cause for the delay. The finding of whether good cause exists shall be in the sole discretion of the Administrator. Appeals of a decision by the Administrator under this paragraph will be addressed pursuant to the administrative appeals process in part 78 of this chapter.

§ 73.38 Closing of accounts.

(a) General account. The authorized account representative of a general account may instruct the Administrator to close the general account by submitting an allowance transfer, pursuant to § 73.50 and § 73.52, requesting the transfer of all allowances held in the account to one or more other accounts in the Allowance Tracking System, and by submitting in writing, with the signature of the authorized account representative, a request to delete the general account from the Allowance Tracking System.

(b) Inactive accounts. If a general account shows no activity for a period of a year or more and does not contain any allowances in its subaccounts, the Administrator will notify the account's authorized account representative that the account will be closed and eliminated from the Allowance Tracking System following 20 business days from the date the notice is sent. The account will be closed following the 20-day period, unless the Administrator receives and records a request for the transfer of allowances into the account pursuant to § 73.52 before the end of the 20-day period, or the authorized account representative submits, in writing, demonstration of good cause as to why the inactive account should not be closed. The finding of whether good cause exists shall be in the sole discretion of the Administrator.

Subpart D—Allowance Transfers Source:

58 FR 3694, Jan. 11, 1993, unless otherwise noted.

§ 73.50 Scope and submission of transfers.

(a) Scope of transfers. Except as provided in § 73.51 and § 73.52, the Administrator will record transfers of an allowance to and from Allowance Tracking System accounts, including, but not limited to, transfers of an allowance to and from contemporaneous future year sub-ac-counts, and transfers of an allowance to and from compliance sub-ac-counts and current year sub-ac-counts, and transfers of all allowances allocated for a unit for each calendar year, in perpetuity.

(b) Submission of transfers. (1) Authorized account representatives seeking recordation of an allowance transfer shall request such transfer by submitting to the Administrator, in a format to be specified by the Administrator, an Allowance Transfer Form. To be considered correctly submitted the request for transfer shall include:

(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 signed by the authorized account representative and identifying each account into which any transfer of allowances, submitted on or after the date on which the Administrator receives such statement, is authorized. Such authorization shall be binding on any authorized account representative for such account and shall apply to all transfers into the account that are submitted on or after such date of receipt, unless and until the Administrator receives a statement in a format prescribed by the Administrator and signed by the authorized account representative retracting the authorization for the account.

(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).

[58 FR 3694, Jan. 11, 1993, as amended at 63 FR 68404, Dec. 11, 1998]

§ 73.51 Prohibition.

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.

§ 73.52 EPA recordation.

(a) General recordation. Except as provided in § 73.50, § 73.51, and this paragraph (a), the Administrator will record an allowance transfer by no later than five business days following receipt of an allowance transfer request pursuant to § 73.50, by moving each allowance from the transferror account to the transferee account as specified by the request pursuant to § 73.50, provided that:

(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.

[58 FR 3694, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995]

§ 73.53 Notification.

(a) Notification of recordation. The Administrator will notify each party to an allowance transfer within five business days following the recordation of the transfer. Notice will be given in writing or in a format to be specified by the Administrator, to the authorized account representatives of both the transferror and transferee accounts.

(b) Notification of non-recordation. By no later than five business days following receipt of an allowance transfer request by the Administrator, the Administrator will notify, in writing or in a format to be specified by the Administrator, the authorized account representatives of the accounts subject to the allowance transfer request submitted for recordation of:

(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 transfer request for recordation following notification of non-recordation.

Subpart E—Auctions, Direct Sales, and Independent Power Producers Written Guarantee Source:

56 FR 65601, Dec. 17, 1991, unless otherwise noted.

§ 73.70 Auctions.

(a) Allowances to be auctioned. Every year the Administrator will auction allowances from the Auction Subaccount, established pursuant to subpart B of this part, according to the following schedule:

Table I—Allowance Schedule for Auctions Year of purchase Spot auction Advance auction Advance auction* 1993 50,000 a 100,000 b 1994 50,000 a 100,000 b 25,000 c 1995 50,000 a 100,000 b 25,000 c 1996 150,000 100,000 b 25,000 c 1997 150,000 125,000 b 25,000 c 1998 150,000 125,000 b 1999 150,000 125,000 b 2000 and after 125,000 125,000 b a Not usable until 1995. b Not usable until 7 years after purchase. c Not usable until 6 years after purchase. *These are unsold advance allowances from the direct sale program for 1993, 1994, 1995, and 1996 respectively. In addition to the allowances listed above, the Administrator will auction allowances pursuant to paragraph (c) of this section and § 73.72(q) in the amounts and at the times provided for therein.

(b) Timing of the auctions. The spot auction and the advance auction will be held on the same day, selected each year by the Administrator, but no later than March 31 of each year. The Administrator will conduct one spot auction and one advance auction in each calendar year.

(c) Submittal for other allowances for auction. Authorized account representatives may offer allowances for sale at auction, provided that allowances are dated for the year in which they are offered or for any previous year or for seven years following the year in which they are offered. Such authorized account representatives may specify a minimum price for the allowances offered at the auctions. The authorized account representative must notify the Administrator fifteen business days prior to the auctions, using the SO2 Allowance Offer Form published by the Administrator, or by means of electronic communication if the Administrator, following public notice, so requires or permits at some future time. The notification shall include:

(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) Conduct of the auctions. (1) The Administrator will rank all bids in descending order of bid price starting with the highest. Allowances will be sold from the Auction Subaccount in this order at the amounts specified in the bids until there are no allowances in the subaccount. If all allowances are sold from the Auction Subaccount, including unsold allowances transferred from the preceding year's direct sale, and if bids still remain, the Administrator will sell allowances offered by the authorized account representatives, beginning with those offered at the lowest minimum price. Allowances offered at the lowest minimum price will be matched with the highest bid remaining after the Auction Subaccount is exhausted. Sales of offered allowances, including, but not limited to, allowances offered by more than one offeror at the same minimum bid price, will continue in ascending order of minimum price, starting with the lowest, and descending order of remaining bids, starting with the highest, until:

(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) Announcement of results. Following each auction, the Administrator will publish the names of winning bidders and their bids, the amounts of losing bids, and the lowest price at which allowances are sold. The Administrator will announce the results of each auction through the Allowance Tracking System. The results will also be published in the Federal Register and in the Commerce Business Daily.

(f) Transfer of allowances. Allowances will be transferred from the Auction Subaccount and from the subaccount for allowances offered by authorized account representatives to the Allowance Tracking System accounts of successful bidders as soon as payment is collected by the Administrator.

(g) Return of unsuccessful bids. The Administrator will return payment to unsuccessful bidders and to bidders unwilling to purchase fewer allowances than requested following the conclusion of each auction.

(h) Transfer of proceeds. The Administrator will return all proceeds from the auction as follows:

(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) Return of unsold allowances. The Administrator will return all unsold allowances from the auction as follows:

(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.

[56 FR 65601, Dec. 17, 1991, as amended at 61 FR 28763, June 6, 1996; 63 FR 5735, Feb. 4, 1998; 63 FR 51766, Sept. 28, 1998]

§ 73.71 Bidding.

(a) Who may participate in the auctions. Any person may participate in the auctions by submitting a bid or bids pursuant to this section.

(b) Bidding. Sealed bids shall be sent to the Administrator using the Bid Form for SO2 Allowance Auctions, or some method of electronic transfer if the Administrator, following public notice, so requires or permits at some future time. The bid form shall state:

(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) Payment. Each bid must include a certified check or letter of credit for the total bid price, or may specify a method of electronic transfer or other method of payment, if the Administrator, following public notice, so requires or permits at some future time. The certified check should be made payable to the U.S. EPA. To meet the requirements of this paragraph bidders must submit a completed SO2 Allowance Auction Letter of Credit Form. If such Form is used, the Administrator must receive full payment for allowances awarded at the auctions, either by wire transfer or certified check, no later than 2 business days after the results of the auction are announced in the Allowance Tracking System.

(d) Bid amount and number of bids. Bidders may request any number of allowances up to the amount of allowances available for auction. Any person may submit more than one bid in each auction, provided that each bid meets the requirements of this section.

(e) Submission of bids. The Administrator will publish in the Federal Register and in the Commerce Business Daily the address of where to submit bids and payment not later than 60 calendar days before each auction.

(f) Deadline for bids. All bids must be revised by the Administrator no later than 3 business days prior to the date of the auctions.

§ 73.72 Direct sales.

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).

[61 FR 28763, June 6, 1996]

§ 73.73 Delegation of auctions and sales and termination of auctions and sales.

(a) Delegation. The Administrator may, in the Administrator's discretion, by delegation or contract provide for the conduct of sales or auctions under the Administrator's supervision by other departments or agencies of the United States Government or by nongovernmental agencies, groups, or organizations.

(b) Termination of sales. If the Administrator determines that, during any period of 2 consecutive calendar years, fewer than 20 percent of the allowances available in the subaccount for direct sales have been purchased, the Administrator shall terminate the Direct Sale Subaccount and transfer such allowances to the Auction Subaccount.

(c) Termination of auctions. The Administrator may, in the Administrator's discretion, terminate the withholding of allowances and the auctions if the Administrator determines, that, during any period of 3 consecutive years after 2002, fewer than 20 percent of the allowances available in the Auction Subaccount have been purchased.

Subpart F—Energy Conservation and Renewable Energy Reserve Source:

58 FR 3695, Jan. 11, 1993, unless otherwise noted.

§ 73.80 Operation of allowance reserve program for conservation and renewable energy.

(a) General. The Administrator will allocate allowances from the Conservation and Renewable Energy Reserve (the “Reserve”) established under subpart B based on verified kilowatt hours saved through the use of one or more qualified energy conservation measures or based on kilowatt hours generated by qualified renewable energy generation. Allowances will be allocated to applicants that meet the requirements of this subpart according to the formulas specified in § 73.82(d), and in the order in which applications are received, except where provided for in § 73.84 and § 73.85, until a total of 300,000 allowances have been allocated.

(b) Period of applicability. Allowances will be allocated under this subpart for qualified energy conservation measures or renewable energy generation sources that are operational on or after January 1, 1992, and before the date on which any unit owned or operated by the applicant becomes a Phase I unit or a Phase II unit.

(c) Termination of the Reserve. The Administrator will reallocate any allowances remaining in the Reserve after January 2, 2010 to the affected units from whom allowances were withheld by the Administrator, in accordance with section 404(g), for purposes of establishing the Reserve. Each unit's allocation under this paragraph will be calculated as follows:

EC10NO91.004

(Allowances will be rounded to the nearest allowance) [58 FR 3695, Jan. 11, 1993; 58 FR 40747, July 30, 1993]

§ 73.81 Qualified conservation measures and renewable energy generation.

(a) Qualified energy conservation measures. A qualified energy conservation measure is a demand-side measure not operational until the period of applicability, implemented in the residence or facility of a customer to whom the utility sells electricity, that:

(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) Non-qualified energy conservation measures. The following energy conservation measures shall not qualify for Allowance Reserve allocations:

(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) Qualified renewable energy generation. Qualified renewable energy generation is electrical energy generation, not operational until the period of applicability, that:

(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 (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;

(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) Non-qualified renewable energy generation. The following renewable energy generation shall not qualify for Allowance Reserve allocations:

(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.

[58 FR 3695, Jan. 11, 1993; 58 FR 40747, July 30, 1993]

§ 73.82 Application for allowances from reserve program.

(a) Application Requirements. Each application for Conservation and Renewable Energy Reserve allowances, shall:

(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 meets the requirements of paragraph (a)(4) of this section;

(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) Application to the Secretary of Energy. For purposes of paragraph (a)(9) of this section, the applicant shall fulfill the following requirements:

(1) If a utility applying for allowances from the Reserve has not received certification of net income neutrality from the Secretary of Energy or such certification is no longer applicable, the applicant shall submit to the Secretary of Energy:

(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.

(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) Calculation of allowances to be allocated.

(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:

EC10NO91.005 (Rounded to the nearest ton)

where:

(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 for any calendar year shall be equal to the product of:

EC10NO91.006 (Rounded to the nearest ton)

where:

(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) Certification by Applicant's Certifying Official.

(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) Certification by State Utility Regulatory Authority. Applicants subject to the ratemaking jurisdiction of a State utility regulatory authority shall include in their applications a certification by the State utility regulatory authority's certifying official that it has reviewed the application, including supporting documentation, and finds it to be accurate, complete, and consistent with all applicable requirements of this subpart.

(g) Time period to apply. (1) Beginning no earlier than July 1, 1993, and no earlier than July 1 of each subsequent year, applicants may apply to the Administrator for allowances from the Reserve for emissions avoided in a previous year or years by use of qualified energy conservation measures or qualified renewable energy generation that became operational during the period of applicability; and

(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) Submittal location. Applicants shall submit one copy of the completed Reserve application, not including the net income neutrality application, via registered mail to the Administrator at an address to be specified in later guidance. Applicants shall submit 10 copies of the net income neutrality application via registered mail to the Department of Energy at the following address: Department of Energy, Office of Conservation and Renewable Energy, Mail Stop CE-10, Room 6c-036, 1000 Independence Avenue, SW., Washington, DC 20585, Attn: Net Income Neutrality Certification.

[58 FR 3695, Jan. 11, 1993; 58 FR 40747, July 30, 1993]

§ 73.83 Secretary of Energy's action on net income neutrality applications.

(a) First come, first served. The Secretary of Energy will process and certify net income neutrality applications on a “first-come, first served” basis, according to the order, by date and time, in which they are received from either the applicant or, in the case of an application submitted to the Administrator and then forwarded to the Secretary, from the Administrator.

(b) Deficient applications. If the Secretary of Energy determines that the net income neutrality certification application does not meet the requirements of § 73.82 (a)(9) and (b), the Secretary will notify the applicant and the Administrator in writing of the deficiency. The applicant may then supply additional information or a new revised application as necessary for the Secretary to make a determination that the applicant meets the requirements of § 73.28(a)(9) and (b). Additional information or revised applications will be processed according to the date of receipt of such information or revisions.

(c) Notification of approval. The Secretary of Energy will review the net income neutrality application to determine whether it meets the requirements of § 73.82 (a)(9) and (b) and will certify this finding in writing to the applicant and to the Administrator within 60 calendar days of receipt of the net income neutrality application or a revised application, except that the Secretary may specify a later date for certification.

§ 73.84 Administrator's action on applications.

(a) First come, first served. The Administrator will process and approve Allowance Reserve applications, in whole or in part, on a “first-come, first-served” basis as established by the order of date of receipt, provided that the Administrator shall not allocate more than a total of 30,000 allowances in connection with applications based on any one of the four categories of qualified renewable energy generation enumerated in § 73.81(c)(2)(i) and appendix A(3.1-3.4).

(b) Deficient applications. An application is deficient and will be returned by the Administrator if it fails to meet the requirements set forth in this subpart, including those set forth in § 73.82. A revised application that is submitted after being returned for failure to meet the requirements of this subpart will be processed according to the date of receipt of the revised application.

(c) Notification of approval. Applications that the Administrator determines to be complete and correct will be conditionally approved, subject to notification to EPA of a net income neutrality certification from the Department of Energy, within 120 calendar days of receipt. Allowances from the Reserve will be awarded subject to the Department of Energy certification, or, if a DOE certification has already been issued to the applicant, allocated to applicants from such applications depending on the availability of allowances in the Reserve. In the event the initial application approval is conditioned upon the Secretary of Energy's certification, final approval will be granted upon notification of certification by the Secretary of Energy pursuant to § 73.83. The Administrator will notify applicants of final approval in writing.

(d) Allocation of allowances. Beginning in 1995, the Administrator will allocate allowances from the Reserve for each approved application into the applicant's account or accounts in the Allowance Tracking System. If the applicant does not have an account in the Allowance Tracking System, or wishes to open a new account for the allowances from the Reserve, an application pursuant to § 73.31(c) must accompany the application for Reserve allowances.

(e) Partial fulfillment of requests. (1) In the event that the allowances available in the Reserve are less than the number that could otherwise be allocated to an approved applicant's account under the application as approved, the applicant will receive the allowances remaining in the Reserve.

(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) Oversubscription of the Reserve.(1) In the event that the Reserve becomes oversubscribed by more than one applicant on a single day, the allowances remaining in the Reserve will be distributed on a pro rata basis to applicants meeting the requirements of § 73.82.

(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) Applications for allowances based on the same avoided emissions from the same energy conservation measures or renewable energy generation.(1) The Administrator will not award allowances to more than one applicant for the same avoided emissions from the same energy conservation measure or the same qualified renewable energy generation, and will process and act on such duplicative applications on a “first-come, first-serve” basis as determined by the order of date of receipt.

(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.

§ 73.85 Administrator review of the reserve program.

(a) Administrator review of the Reserve and creation of a subaccount. In the event that an allocation of allowances from the Reserve pursuant to a pending application would bring the total number of allowances allocated to a number greater than 240,000, the Administrator will review the distribution of all allowances allocated as follows:

(1) If at least 60,000 allowances have been allocated from the Reserve for each of

(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) Allocation of allowances from the subaccount. The Administrator will allocate allowances from the subaccount established pursuant to paragraph (a) of this section to approved and DOE certified applicants that fulfill the requirements of this subpart, including § 73.82 and § 73.83, on a “first-come, first-served basis”, pursuant to § 73.84(a), until the subaccount is depleted or closed pursuant to paragraph (c) of this section.

(c) Closure of the subaccount. Unless all allowances in the subaccount have been previously allocated, the Administrator will terminate the subaccount not later than February 1, 1998 and return any allowances remaining in the subaccount to the general account of the Reserve. After all Reserve allocations have been made to applicants with approved and DOE certified applications subject to § 73.84(f)(3), the Administrator will allocate any remaining allowances to any applicants that meet the requirements of this subpart, including § 73.82 and § 73.83, on a “first-come, first-served” basis, pursuant to § 73.84.

§ 73.86 State regulatory autonomy.

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.

Pt. 73, Subpt. F, App. A Appendix A to Subpart F—List of Qualified Energy Conservation Measures, Qualified Renewable Generation, and Measures Applicable for Reduced Utilization 1. Demand-side Measures Applicable for the Conservation and Renewable Energy Reserve Program or Reduced Utilization

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.

1.1Residential 1.1.1Space Conditioning

• 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

1.1.2Water Heating

• 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

1.1.3Lighting

• Lamp replacement

• Dimmers

• Motion detectors and occupancy sensors

• Photovoltaic lighting

• Fixture replacement

• Outdoor lighting controls

1.1.4Building Envelope

• 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

1.1.5Other Appliances

• 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

1.2Commercial 1.2.1Heating/Ventilation/Air Conditioning (HVAC)

• 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

1.2.2Building envelope

• 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

1.2.3Lighting

• 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

1.2.4Refrigeration

• 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

1.2.5Water Heating

• 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

1.2.6Other end-uses and miscellaneous

• 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

1.3Industial 1.3.1Motors

• 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

1.3.2Lighting

• 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

1.3.3Heating/Ventilation/Air Conditioning (HVAC)

• 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

1.3.4Industrial Processes

• 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

1.3.5Building Envelope

• Insulation of ceiling, walls, and ducts

• Window and door replacement/upgrade, including thermal energy barriers

• Caulking/weatherstripping

1.3.6Water Heating

• 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

1.3.7Other End-uses and miscellaneous

• Refrigeration system retrofit/replacement

• Energy management control systems and end use metering

• Customer-owned transformer retrofits/replacements and proper sizing

1.4Agricultural 1.4.1Space Conditioning

• 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

1.4.2Water heating

• 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

1.4.3Lighting

• Electronic ballast replacements

• Delamping

• Reflectors

• Occupancy sensors

• Daylighting with controls

• Photovoltaic lighting

• Outdoor lighting controls

1.4.4Pumping/Irrigation

• 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

1.4.5Motors

• 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

11.4.6Other end uses

• 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

1.5Government Services Sector 1.5.1Streetlighting

• Replace incandescent and mercury vapor lamps with high pressure sodium and metal halide

1.5.2Other

• 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

2. Supply-side Measures Applicable for Reduced Utilization

Supply-side measures that may be approved for purposes of reduced utilization plans under § 72.43 include the following:

2.1Generation efficiency

• 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

2.2Transmission and distribution efficiency

• 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

3. Renewable Energy Generation Measures Applicable for the Conservation and Renewable Energy Reserve Program

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.

3.1Biomass resources

• 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.

3.2Solar resources

• 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.

3.4Geothermal resources

• Hydrothermal or geopressurized resources used for dry steam, flash steam, or binary cycle generation of electricity.

3.5Wind resources

• Grid-connected and non-grid-connected wind farms

• Individual wind-driven electrical generating turbines

Subpart G—Small Diesel Refineries

§ 73.90 Allowance allocations for small diesel refineries.

(a) Initial certification of eligibility. The certifying official of a refinery that seeks allowances under this section shall apply for certification of its facility eligibility prior to or accompanying a request for allowances under paragraph (d) of this section. A completed application for certification, submitted to the address in § 73.13 of this chapter, shall include the following:

(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) Request for allowances. (1) In addition to the application for certification, prior to, or accompanying, the request for allowances, the certifying official for the refinery shall submit an Allowance Tracking System New Account/New Authorized Account Representative Form.

(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 Form 810 for October, November and December 1993;

(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) Allowance allocation. The Administrator will allocate allowances to the eligible refinery upon satisfactory submittal of information under paragraphs (a) and (b) of this section in the amount calculated according to the following equations. Such allowances will be allocated to the refinery's non-unit subaccount for the calendar year in which the application is made.

(1) Allowances allocated under this section to any eligible refinery will be limited to the tons of SO2 attributable to the desulfurization of diesel fuel at the refinery. (2) The refinery will be allocated allowances for a calendar year and, in the case of 1993, for the period October 1 through December 31, calculated according to the following equation, but not to exceed 1500 for any calendar year:

EC01SE92.092

where: a = diesel fuel in barrels for the year (or for October 1 through December 31 for 1993) b = lbs per barrel of diesel c = lbs of sulfur per lbs of diesel d = lbs of SO2 per lbs of sulfur e = lbs per short ton

(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:

ER24OC97.000 [58 FR 15716, Mar. 23, 1993; 58 FR 33770, June 21, 1993; 62 FR 55486, Oct. 24, 1997]

Pt. 74 PART 74—SULFUR DIOXIDE OPT-INS Subpart A—Background and Summary Sec. 74.1 Purpose and scope. 74.2 Applicability. 74.3 Relationship to the Acid Rain program requirements. 74.4 Designated representative. Subpart B—Permitting Procedures 74.10 Roles—EPA and permitting authority. 74.12 Opt-in permit contents. 74.14 Opt-in permit process. 74.16 Application requirements for combustion sources. 74.17 Application requirements for process sources. [Reserved] 74.18 Withdrawal. 74.19 Revision and renewal of opt-in permit. Subpart C—Allowance Calculations for Combustion Sources 74.20 Data for baseline and alternative baseline. 74.22 Actual SO2 emissions rate. 74.23 1985 Allowable SO2 emissions rate. 74.24 Current allowable SO2 emissions rate. 74.25 Current promulgated SO2 emissions limit. 74.26 Allocation formula. 74.28 Allowance allocation for combustion sources becoming opt-in sources on a date other than January 1. Subpart D—Allowance Calculations for Process Sources [Reserved] Subpart E—Allowance Tracking and Transfer and End of Year Compliance 74.40 Establishment of opt-in source allowance accounts. 74.41 Identifying allowances. 74.42 Prohibition on future year transfers. 74.43 Annual compliance certification report. 74.44 Reduced utilization for combustion sources. 74.45 Reduced utilization for process sources. [Reserved] 74.46 Opt-in source permanent shutdown, reconstruction, or change in affected status. 74.47 Transfer of allowances from the replacement of thermal energy—combustion sources. 74.48 Transfer of allowances from the replacement of thermal energy—process sources. [Reserved] 74.49 Calculation for deducting allowances. 74.50 Deducting opt-in source allowances from ATS accounts. Subpart F—Monitoring Emissions: Combustion Sources 74.60 Monitoring requirements. 74.61 Monitoring plan. Subpart G—Monitoring Emissions: Process Sources [Reserved] Authority:

42 U.S.C. 7601 and 7651 et seq.

Source:

60 FR 17115, Apr. 4, 1995, unless otherwise noted.

Subpart A—Background and Summary

§ 74.1 Purpose and scope.

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, et seq., as amended by Public Law 101-549 (November 15, 1990); and

(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.

§ 74.2 Applicability.

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.

[60 FR 17115, Apr. 4, 1995, as amended at 62 FR 55487, Oct. 24, 1997]

§ 74.3 Relationship to the Acid Rain program requirements.

(a) General. (1) For purposes of applying parts 72, 73, 75, 77 and 78, each opt-in source shall be treated as an affected unit.

(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) Permits. The permitting authority shall act in accordance with this part and parts 70, 71, and 72 of this chapter in issuing or denying an opt-in permit and incorporating it into a combustion or process source's operating permit. To the extent that any requirements of this part, part 72, and part 78 of this chapter are inconsistent with the requirements of parts 70 and 71 of this chapter, the requirements of this part, part 72, and part 78 of this chapter shall take precedence and shall govern the issuance, denials, revision, reopening, renewal, and appeal of the opt-in permit.

(c) Appeals. The procedures for appeals of decisions of the Administrator under this part are contained in part 78 of this chapter.

(d) Allowances. A combustion or process source that becomes an affected unit under this part shall be subject to all the requirements of subparts C and D of part 73 of this chapter, consistent with subpart E of this part.

(e) Excess emissions. A combustion or process source that becomes an affected unit under this part shall be subject to the requirements of part 77 of this chapter applicable to excess emissions of sulfur dioxide and shall not be subject to the requirements of part 77 of this chapter applicable to excess emissions of nitrogen oxides.

(f) Monitoring. A combustion or process source that becomes an affected unit under this part shall be subject to all the requirements of part 75, consistent with subparts F and G of this part.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

§ 74.4 Designated representative.

(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 days of that date, a certificate of representation for the designated representative of the combustion or process source shall be submitted consistent with paragraph (b) of this section.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

Subpart B—Permitting Procedures

§ 74.10 Roles—EPA and permitting authority.

(a) Administrator responsibilities. The Administrator shall be responsible for the following activities under the opt-in provisions of the Acid Rain Program:

(1) Calculating the baseline or alternative baseline and allowance allocation, and allocating allowances for combustion or process sources that become affected units under this part;

(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) Permitting authority responsibilities. The permitting authority shall be responsible for the following activities:

(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).

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

§ 74.12 Opt-in permit contents.

(a) The opt-in permit shall be included in the Acid Rain permit.

(b) Scope. The opt-in permit provisions shall apply only to the opt-in source and not to any other affected units.

(c) Contents. Each opt-in permit, including any draft or proposed opt-in permit, shall contain the following elements in a format specified by the Administrator:

(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) Termination. The provision that participation of a combustion or process source in the Acid Rain Program may be terminated only in accordance with § 74.18 (withdrawal), § 74.46 (shutdown, reconstruction, or change in affected status), and § 74.50 (deducting allowances).

(d) Each opt-in permit is deemed to incorporate the definitions of terms under § 72.2 of this chapter.

(e) Permit shield. Each opt-in source operated in accordance with the opt-in permit that governs the opt-in source and that was issued in compliance with title IV of the Act, as provided in this part and parts 72, 73, 75, 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) of this chapter.

(f) Term of opt-in permit. An opt-in permit shall be issued for a period of 5 years and may be renewed in accordance with § 74.19; provided

(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.

§ 74.14 Opt-in permit process.

(a) Submission. The designated representative of a combustion or process source may submit an opt-in permit application and a monitoring plan to the Administrator at any time for any combustion or process source that is operating.

(b) Issuance or denial of opt-in permits. The permitting authority shall issue or deny opt-in permits or revisions of opt-in permits in accordance with the procedures in parts 70 and 71 of this chapter and subparts F and G of part 72 of this chapter, except as provided in this section.

(1) Supplemental information. Regardless of whether the opt-in permit application is complete, the Administrator or the permitting authority may request submission of any additional information that the Administrator or the permitting authority determines to be necessary in order to review the opt-in permit application or to issue an opt-in permit.

(2) Interim review of monitoring plan. The Administrator will determine, on an interim basis, the sufficiency of the monitoring plan, accompanying the opt-in permit application. A monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that all SO2 emissions, NOx emissions, CO2 emissions, and opacity of the combustion or process source are monitored and reported in accordance with part 75 of this chapter. This interim review of sufficiency shall not be construed as the approval or disapproval of the combustion or process source's monitoring system.

(3) Issuance of draft opt-in permit. After the Administrator determines whether the combustion or process source's monitoring plan is sufficient under paragraph (b)(2) of this section, the permitting authority shall serve the draft opt-in permit or the denial of a draft permit or the draft opt-in permit revisions or the denial of draft opt-in permit revisions on the designated representative of the combustion or process source submitting an opt-in permit application. A draft permit or draft opt-in permit revision shall not be served or issued if the monitoring plan is determined not to be sufficient.

(4) Confirmation by source of intention to opt-in. Within 21 calendar days from the date of service of the draft opt-in permit or the denial of the draft opt-in permit, the designated representative of a combustion or process source submitting an opt-in permit application must submit to the Administrator, in writing, a confirmation or recision of the source's intention to become an opt-in source under this part. The Administrator shall treat the failure to make a timely submission as a recision of the source's intention to become an opt-in source and as a withdrawal of the opt-in permit application.

(5) Issuance of draft opt-in permit. If the designated representative confirms the combustion or process source's intention to opt in under paragraph (b)(4) of this section, the permitting authority will give notice of the draft opt-in permit or denial of the draft opt-in permit and an opportunity for public comment, as provided under § 72.65 of this chapter with regard to a draft permit or denial of a draft permit if the Administrator is the permitting authority or as provided in accordance with part 70 of this chapter with regard to a draft permit or the denial of a draft permit if the State is the permitting authority.

(6) Permit decision deadlines. (i) If the Administrator is the permitting authority, an opt-in permit will be issued or denied within 12 months of receipt of a complete opt-in permit application.

(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 such lesser time approved for operating permits under part 70 of this chapter.

(7) Withdrawal of opt-in permit application. A combustion or process source may withdraw its opt-in permit application at any time prior to the issuance of the final opt-in permit. Once a combustion or process source withdraws its application, in order to re-apply, it must submit a new opt-in permit application in accordance with § 74.16 for combustion sources or § 74.17 for process sources.

(d) Entry into Acid Rain Program—(1) Effective date. The effective date of the opt-in permit shall be the January 1, April 1, July 1, or October 1 for a combustion or process source providing monthly data under § 74.20, or January 1 for a combustion or process source providing annual data under § 74.20, following the later of the issuance of the opt-in permit by the permitting authority or the completion of monitoring system certification, as provided in subpart F of this part for combustion sources or subpart G of this part for process sources. The combustion or process source shall become an opt-in source and an affected unit as of the effective date of the opt-in permit.

(2) Allowance allocation. After the opt-in permit becomes effective, the Administrator will allocate allowances to the opt-in source as provided in § 74.40. If the effective date of the opt-in permit is not January 1, allowances for the first year shall be pro-rated as provided in § 74.28.

(e) Expiration of opt-in permit. An opt-in permit that is issued before the completion of monitoring system certification under subpart F of this part for combustion sources or under subpart G of this part for process sources shall expire 180 days after the permitting authority serves the opt-in permit on the designated representative of the combustion or process source governed by the opt-in permit, unless such monitoring system certification is complete. The designated representative may petition the Administrator to extend this time period in which an opt-in permit expires and must explain in the petition why such an extension should be granted. The designated representative of a combustion source governed by an expired opt-in permit and that seeks to become an opt-in source must submit a new opt-in permit application.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

§ 74.16 Application requirements for combustion sources.

(a) Opt-in permit application. Each complete opt-in permit application for a combustion source shall contain the following elements in a format prescribed by the Administrator:

(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 SO2 emissions rate under § 74.22;

(7) The allowable 1985 SO2 emissions rate under § 74.23;

(8) The current allowable SO2 emissions rate under § 74.24;

(9) The current promulgated SO2 emissions rate under § 74.25;

(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 SO2 under § 72.40 of this chapter; and

(14) The following statement signed by the designated representative of the combustion source: “I certify that the data submitted under subpart C of part 74 reflects actual operations of the combustion source and has not been adjusted in any way.”

(b) Accompanying documents. The designated representative of the combustion source shall submit a monitoring plan in accordance with § 74.61.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

§ 74.17 Application requirements for process sources. [Reserved]

§ 74.18 Withdrawal.

(a) Withdrawal through administrative amendment. An opt-in source may request to withdraw from the Acid Rain Program by submitting an administrative amendment under § 72.83 of this chapter; provided that the amendment will be treated as received by the permitting authority upon issuance of the notification of the acceptance of the request to withdraw under paragraph (f)(1) of this section.

(b) Requesting withdrawal. To withdraw from the Acid Rain Program, the designated representative of an opt-in source shall submit to the Administrator and the permitting authority a request to withdraw effective January 1 of the year after the year in which the submission is made. The submission shall be made no later than December 1 of the calendar year preceding the effective date of withdrawal.

(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) Administrator's action on withdrawal. After the opt-in source meets the requirements for withdrawal under paragraphs (b) and (c) of this section, the Administrator will deduct allowances required to be deducted under § 73.35 of this chapter and part 77 of this chapter and allowances equal in number to and with the same or earlier compliance use date as those allocated under § 74.40 for the first year for which the withdrawal is to be effective and all subsequent years. The Administrator will close the opt-in source's unit account and transfer any remaining allowances to a new general account as specified under § 74.46(b)(2).

(e) Opt-in source's prior violations. An opt-in source that withdraws from the Acid Rain Program shall comply with all requirements under the Acid Rain Program concerning all years for which the opt-in source was an affected unit, even if such requirements arise, or must be complied with after the withdrawal takes effect.

(f) Notification. (1) After the requirements for withdrawal under paragraphs (b) and (c) of this section are met and after the Administrator's action on withdrawal under paragraph (d) of this section is complete, the Administrator will issue a notification to the permitting authority and the designated representative of the opt-in source of the acceptance of the opt-in source's request to withdraw.

(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) Permit amendment. (1) After the Administrator issues a notification under paragraph (f)(1) of this section that the requirements for withdrawal have been met (including the deduction of the full amount of allowances as required under paragraph (d) of this section), the permitting authority shall amend, in accordance with §§ 72.80 and 72.83 (administrative amendment) of this chapter, the opt-in source's Acid Rain permit to terminate the opt-in permit, not later than 60 days from the issuance of the notification under paragraph (f) of this section.

(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) Reapplication upon failure to meet conditions of withdrawal. If the Administrator denies the opt-in source's request to withdraw, the designated representative may submit another request to withdraw in accordance with paragraphs (b) and (c) of this section.

(i) Ability to return to the Acid Rain Program. Once a combustion or process source withdraws from the Acid Rain Program and its opt-in permit is terminated, a new opt-in permit application for the combustion or process source may not be submitted prior to the date that is four years after the date on which the opt-in permit became effective.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

§ 74.19 Revision and renewal of opt-in permit.

(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.

Subpart C—Allowance Calculations for Combustion Sources

§ 74.20 Data for baseline and alternative baseline.

(a) Acceptable data. (1) The designated representative of a combustion source shall submit either the data specified in this paragraph or alternative data under paragraph (c) of this section. The designated representative shall also submit the calculations under this section based on such data.

(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 consumed, expressed in British thermal units (Btu) per pound for coal, Btu per barrel for oil, and Btu per standard cubic foot (scf) for natural gas. If other fuels are used, the combustion source must specify units of measure.

(iii) Monthly or annual sulfur content of fuel consumed for each type of fuel consumed, expressed as a percentage by weight.

(3) Calendar Years. (i) For combustion sources that commenced operating prior to January 1, 1985, data under this section shall be submitted for 1985, 1986, and 1987.

(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) Calculation of baseline and alternative baseline.(1) For combustion sources that commenced operation prior to January 1, 1985, the baseline is the average annual quantity of fuel consumed during 1985, 1986, and 1987, expressed in mmBtu. The baseline shall be calculated as follows:

ER04AP95.000

where,

(i) for a combustion source submitting monthly data,

ER04AP95.001

and unit conversion = 2 for coal = 0.001 for oil = 1 for gas For other fuels, the combustion source must specify unit conversion; or

(ii) for a combustion source submitting annual data,

ER04AP95.002

and unit conversion = 2 for coal = 0.001 for oil = 1 for gas For other fuels, the combustion source must specify unit conversion.

(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:

ER04AP95.003

where, “annual fuel consumption” is as defined under paragraph (b)(1)(i) or (ii) of this section.

(c) Alternative data. (1) For combustion sources for which any of the data under paragraph (b) of this section is not available due solely to a natural catastrophe, data as set forth in paragraph (a)(2) of this section for the first three consecutive calendar years for which data is available after December 31, 1985, may be submitted. The alternative baseline for these combustion sources shall be calculated using the equation for alternative baseline in paragraph (b)(2) of this section and the definition of annual fuel consumption in paragraphs (b)(1)(i) or (ii) of this section.

(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) Administrator's action. The Administrator may accept in whole or in part or with changes as appropriate, request additional information, or reject data or alternative data submitted for a combustion source's baseline or alternative baseline.

§ 74.22 Actual SO2 emissions rate.

(a) Data requirements. The designated representative of a combustion source shall submit the calculations under this section based on data submitted under § 74.20 for the following calendar year:

(1) For combustion sources that commenced operation prior to January 1, 1985, the calendar year for calculating the actual SO2 emissions rate shall be 1985.

(2) For combustion sources that commenced operation after January 1, 1985, the calendar year for calculating the actual SO2 emissions rate shall be the first year of the three consecutive calendar years of the alternative baseline under § 74.20(b)(2).

(3) For combustion sources meeting the requirements of § 74.20(c), the calendar year for calculating the actual SO2 emissions rate shall be the first year of the three consecutive calendar years to be used as alternative data under § 74.20(c).

(b) SO 2 emissions factor calculation. The SO2 emissions factor for each type of fuel consumed during the specified year, expressed in pounds per thousand tons for coal, pounds per thousand barrels for oil and pounds per million cubic feet (scf) for gas, shall be calculated as follows:

SO2 Emissions Factor = (average percent of sulfur by weight) × (k), where, average percent of sulfur by weight = annual average, for a combustion source submitting annual data = monthly average, for a combustion source submitting monthly data k = 39,000 for bituminous coal or anthracite = 35,000 for subbituminous coal = 30,000 for lignite = 5,964 for distillate (light) oil = 6,594 for residual (heavy) oil = 0.6 for natural gas For other fuels, the combustion source must specify the SO2 emissions factor.

(c) Annual SO 2 emissions calculation. Annual SO2 Emissions for the specified calendar year, expressed in pounds, shall be calculated as follows:

(1) For a combustion source submitting monthly data,

ER04AP95.004

(2) For a combustion source submitting annual data:

ER04AP95.005

where, “quantity of fuel consumed” is as defined under § 74.20(a)(2)(i); “SO2 emissions factor” is as defined under paragraph (b) of this section; “control system efficiency” is as defined under § 60.48(a) and part 60, appendix A, method 19 of this chapter, if applicable; and “fuel pre-treatment efficiency” is as defined under § 60.48(a) and part 60, appendix A, method 19 of this chapter, if applicable.

(d) Annual fuel consumption calculation. Annual fuel consumption for the specified calendar year, expressed in mmBtu, shall be calculated as defined under § 74.20(b)(1) (i) or (ii).

(e) Actual SO 2 emissions rate calculation. The actual SO2 emissions rate for the specified calendar year, expressed in lbs/mmBtu, shall be calculated as follows:

ER04AP95.006

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

§ 74.23 1985 Allowable SO2 emissions rate.

(a) Data requirements. (1) The designated representative of the combustion source shall submit the following data and the calculations under paragraph (b) of this section based on the submitted data:

(i) Allowable SO2 emissions rate of the combustion source expressed in lbs/mmBtu as defined under § 72.2 of this chapter for the calendar year specified in paragraph (a)(2) of this section. If the allowable SO2 emissions rate is not expressed in lbs/mmBtu, the allowable emissions rate shall be converted to lbs/mmBtu by multiplying the emissions rate by the appropriate factor as specified in Table 1 of this section.

Table 1—Factors to Convert Emission Limits to Pounds of SO2/mmBtu Unit measurement Bituminous coal Subbituminous coal Lignite coal Oil lbs Sulfur/mmBtu 2.0 2.0 2.0 2.0 % Sulfur in fuel 1.66 2.22 2.86 1.07 ppm SO2 0.00287 0.00384 0.00167 ppm Sulfur in fuel 0.00334 tons SO2/hour 2×8760/(annual fuel consumption for specified year 1×10 3) lbs SO2/hour 8760/(annual fuel consumption for specified year 1×10 6) 1 Annual fuel consumption as defined under § 74.20(b)(1) (i) or (ii); specified calendar year as defined under § 74.23(a)(2).

(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:

Table 2—Annualization Factors for SO2 Emission Rates Type of combustion source Annualization factor for scrubbed unit Annualization factor for unscrubbed unit Unit Combusting Oil, Gas, or some combination 1.00 1.00 Coal Unit with Averaging Time <= 1 day 0.93 0.89 Coal Unit with Averaging Time = 1 week 0.97 0.92 Coal Unit with Averaging Time = 30 days 1.00 0.96 Coal Unit with Averaging Time = 90 days 1.00 1.00 Coal Unit with Averaging Time = 1 year 1.00 1.00 Coal Unit with Federal Limit, but Averaging Time Not Specified 0.93 0.89

(2) Calendar year. (i) For combustion sources that commenced operation prior to January 1, 1985, the calendar year for the allowable SO2 emissions rate shall be 1985.

(ii) For combustion sources that commenced operation after January 1, 1985, the calendar year for the allowable SO2 emissions rate shall be the first year of the three consecutive calendar years of the alternative baseline under § 74.20(b)(2).

(iii) For combustion sources meeting the requirements of § 74.20(c), the calendar year for calculating the allowable SO2 emissions rate shall be the first year of the three consecutive calendar years to be used as alternative data under § 74.20(c).

(b) 1985 Allowable SO 2 emissions rate calculation. The allowable SO2 emissions rate for the specified calendar year shall be calculated as follows:

1985 Allowable SO2 Emissions Rate = (Allowable SO2 Emissions Rate) × (Annualization Factor)

§ 74.24 Current allowable SO2 emissions rate.

The designated representative shall submit the following data:

(a) Current allowable SO2 emissions rate of the combustion source, expressed in lbs/mmBtu, which shall be the most stringent federally enforceable emissions limit in effect as of the date of submission of the opt-in application. If the allowable SO2 emissions rate is not expressed in lbs/mmBtu, the allowable emissions rate shall be converted to lbs/mmBtu by multiplying the allowable rate by the appropriate factor as specified in Table 1 in § 74.23(a)(1)(i).

(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;

§ 74.25 Current promulgated SO2 emissions limit.

The designated representative shall submit the following data:

(a) Current promulgated SO2 emissions limit of the combustion source, expressed in lbs/mmBtu, which shall be the most stringent federally enforceable emissions limit that has been promulgated as of the date of submission of the opt-in permit application and that either is in effect on that date or will take effect after that date. If the promulgated SO2 emissions limit is not expressed in lbs/mmBtu, the limit shall be converted to lbs/mmBtu by multiplying the limit by the appropriate factor as specified in Table 1 of § 74.23(a)(1)(i).

(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;

(d) Effective date of the emissions limit under paragraph (a) of this section.

§ 74.26 Allocation formula.

(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 SO2 emissions limit under § 74.25 is greater than or equal to the current allowable SO2 emissions rate under § 74.24, the number of allowances allocated for each year equals:

ER04AP95.007

(2) For combustion sources for which the current promulgated SO2 emissions limit under § 74.25 is less than the current allowable SO2 emissions rate under § 74.24.

(i) The number of allowances for each year ending prior to the effective date of the promulgated SO2 emissions limit equals:

ER04AP95.008

(ii) The number of allowances for the year that includes the effective date of the promulgated SO2 emissions limit and for each year thereafter equals:

ER04AP95.009

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

§ 74.28 Allowance allocation for combustion sources becoming opt-in sources on a date other than January 1.

(a) Dates of entry. (1) If an opt-in source provided monthly data under § 74.20, the opt-in source's opt-in permit may become effective at the beginning of a calendar quarter as of January 1, April 1, July 1, or October 1.

(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) Prorating by Calendar Quarter. Where a combustion source's opt-in permit becomes effective on April 1, July 1, or October 1 of a given year, the Administrator will prorate the allowance allocation for that first year by the calendar quarters remaining in the year as follows:

Allowances for the first year

ER04AP95.010

(1) For combustion sources that commenced operations before January 1, 1985,

ER04AP95.011

(2) For combustion sources that commenced operations after January 1, 1985,

ER04AP95.012

(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 =

ER04AP95.013

where unit conversion = 2 for coal = 0.001 for oil = 1 for gas For other fuels, the combustion source must specify unit conversion; and where starting month = April, if effective date is April 1; = July, if effective date is July 1; and = October, if effective date is October 1.

Subpart D—Allowance Calculations for Process Sources[Reserved] Subpart E—Allowance Tracking and Transfer and End of Year Compliance

§ 74.40 Establishment of opt-in source allowance accounts.

(a) Establishing accounts. Not earlier than the date on which a combustion or process source becomes an affected unit under this part and upon receipt of a request for an opt-in account under paragraph (b) of this section, the Administrator will establish an account and allocate allowances in accordance with subpart C of this part for combustion sources or subpart D of this part for process sources. A separate unit account will be established for each opt-in source.

(b) Request for opt-in account. The designated representative of the opt-in source shall, on or after the effective date of the opt-in permit as specified in § 74.14(d), submit a letter requesting the opening of an allowance account in the Allowance Tracking System to the Administrator.

§ 74.41 Identifying allowances.

(a) Identifying allowances. Allowances allocated to an opt-in source will be assigned a serial number that identifies them as being allocated under an opt-in permit.

(b) Submittal of opt-in allowances for auction. (1) An authorized account representative may offer for sale in the spot auction under § 73.70 of this chapter allowances that are allocated to opt-in sources, if the allowances have a compliance use date earlier than the year in which the spot auction is to be held and if the Administrator has completed the deductions for compliance under § 73.35(b) for the compliance year corresponding to the compliance use date of the offered allowances.

(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.

§ 74.42 Prohibition on future year transfers.

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.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

§ 74.43 Annual compliance certification report.

(a) Applicability and deadline. For each calendar year in which an opt-in source is subject to the Acid Rain emissions limitations, the designated representative of the opt-in source shall submit to the Administrator, no later than 60 days after the end of the calendar year, an annual compliance certification report for the opt-in source in lieu of any annual compliance certification report required under subpart I of part 72 of this chapter.

(b) Contents of report. The designated representative shall include in the annual compliance certification report the following elements, in a format prescribed by the Administrator, concerning the opt-in source and the calendar year covered by the report:

(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) Annual compliance certification. In the annual compliance certification report under paragraph (a) of this section, the designated representative shall certify, based on reasonable inquiry of those persons with primary responsibility for operating the opt-in source in compliance with the Acid Rain Program, whether the opt-in source was operated during the calendar year covered by the report in compliance with the requirements of the Acid Rain Program applicable to the opt-in source, including:

(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;

(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.

§ 74.44 Reduced utilization for combustion sources.

(a) Calculation of utilization—(1) Annual utilization. (i) Except as provided in paragraph (a)(1)(ii) of this section, annual utilization for the calendar year shall be calculated as follows:

Annual Utilization = Actual heat input + Reduction from improved efficiency where,

(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 demand side measures that improve the efficiency of electricity consumption; reduction from demand side measures that improve the efficiency of steam consumption; reduction from improvements in the heat rate at the opt-in source; and reduction from improvement in the efficiency of steam production at the opt-in source. Qualified demand side measures applicable to the calculation of utilization for opt-in sources are listed in appendix A, section 1 of part 73 of this chapter.

(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:

(1) The designated representatives of all such opt-in sources and Phase I units shall submit with their annual compliance certification reports a certification signed by all such designated representatives. The certification shall apportion the total kilowatt hour savings or steam savings among such opt-in sources and Phase I units.

(2) Each designated representative shall include in its annual compliance certification report only its share of kilowatt hour savings or steam savings.

(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:

ER04AP95.014

where “actual heat input” and “reduction from improved efficiency” are defined as set forth in paragraph (a)(1)(i) of this section but are restricted to data or estimates for the “remaining calendar quarters”, which are the calendar quarters that begin on or after the date the opt-in permit becomes effective.

(2) Average utilization. Average utilization for the calendar year shall be defined as the average of the annual utilization calculated as follows:

(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 utilizationyear 1

where “annual utilizationyear 1” is as calculated under paragraph (a)(1)(i) of this section.

(B) Average utilization for the second year

ER04AP95.015

where, “revised annual utilizationyear 1” is as submitted for the year under paragraph (c)(2)(i)(B) of this section and adjusted under paragraph (c)(2)(iii) of this section; “annual utilizationyear 2” is as calculated under paragraph (a)(1)(i) of this section.

(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 -utilizationyear 1

where “annual utilizationyear 1” is as calculated under paragraph (a)(1)(ii) of this section.

(B) Average utilization for the second year after opt-in

where,

ER04AP95.016

“revised annual utilizationyear 1” is as submitted for the year under paragraph (c)(2)(i)(B) of this section and adjusted under paragraph (c)(2)(iii) of this section; and “annual utilizationyear 2” is as calculated under paragraph (a)(1)(ii) of this section.

ER04AP95.017

where, “revised annual utilizationyear 1” is as submitted for the year under paragraph (c)(2)(i)(B) of this section and adjusted under paragraph (c)(2)(iii) of this section; and “revised annual utilizationyear 2” is as submitted for the year under paragraph (c)(2)(i)(B) of this section and adjusted under paragraph (c)(2)(iii) of this section; and “annual utilizationyear 3” is as calculated under paragraph (a)(1)(ii) of this section.

(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) Determination of reduced utilization and calculation of allowances—(1) Determination of reduced utilization. For a year during which its opt-in permit is effective, an opt-in source has reduced utilization if the opt-in source's average utilization for the calendar year, as calculated under paragraph (a) of this section, is less than its baseline.

(2) Calculation of allowances deducted for reduced utilization. If the Administrator determines that an opt-in source has reduced utilization for a calendar year during which the opt-in source's opt-in permit is in effect, the Administrator will deduct allowances, as calculated under paragraph (b)(2)(i) of this section, from the compliance subaccount of the opt-in source's Allowance Tracking System account.

(i) Allowances deducted for reduced utilization =

ER04AP95.018

(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) Compliance—(1) Opt-in Utilization Report. The designated representative for each opt-in source shall submit an opt-in utilization report for the calendar year, as part of its annual compliance certification report under § 74.43, that shall include the following elements in a format prescribed by the Administrator:

(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) Confirmation report. (i) If the annual compliance certification report for an opt-in source includes estimates of any reduction in heat input resulting from improved efficiency as defined under paragraph (a)(1)(i) of this section, the designated representative shall submit, by July 1 of the year in which the annual compliance certification report was submitted, a confirmation report, concerning the calendar year covered by the annual compliance certification report. The Administrator may grant, for good cause shown, an extension of the time to file the confirmation report. The confirmation report shall include the following elements in a format prescribed by the Administrator:

(A) Verified reduction in heat input. Any verified kwh savings or any verified steam savings from demand side measures that improve the efficiency of electricity or steam consumption, any verified reduction in the heat rate at the opt-in source, or any verified improvement in the efficiency of steam production at the opt-in source achieved and the verified corresponding reduction in heat input for the calendar year that resulted.

(B) Revised annual utilization. The opt-in source's annual utilization for the calendar year as provided under paragraph (c)(1)(iii) of this section, recalculated using the verified reduction in heat input for the calendar year under paragraph (c)(2)(i)(A) of this section.

(C) Revised average utilization. The opt-in source's average utilization as provided under paragraph (c)(1)(iv) of this section, recalculated using the verified reduction in heat input for the calendar year under paragraph (c)(2)(i)(A) of this section.

(D) Recalculation of reduced utilization. The difference between the opt-in source's recalculated average utilization and its baseline.

(E) Allowance adjustment. The number of allowances that should be credited or deducted using the formulas in paragraphs (c)(2)(iii)(C) and (D) of this section and the supporting calculations; and the number of adjusted allowances remaining using the formula in paragraph (c)(2)(iii)(E) of this section and the supporting calculations.

(ii) Documentation. (A) For all figures under paragraphs (c)(2)(i)(A) of this section, the opt-in source must provide as part of the confirmation report, documentation (which may follow the EPA Conservation Verification Protocol) verifying the figures to the satisfaction of the Administrator.

(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:

(1) The designated representatives of all such opt-in sources and Phase I 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 steam savings as defined under paragraph (c)(2)(i)(A) of this section for the calendar year among such opt-in sources and Phase I units.

(2) Each designated representative shall include in the opt-in source's confirmation report only its share of the verified reduction in heat input as defined under paragraph (c)(2)(i)(A) of this section for the calendar year under the certification under paragraph (c)(2)(ii)(B)(1) of this section.

(iii) Determination of reduced utilization based on confirmation report. (A) If an opt-in source must submit a confirmation report as specified under paragraph (c)(2) of this section, the Administrator, upon such submittal, will adjust his or her determination of reduced utilization for the calendar year for the opt-in source. Such adjustment will include the recalculation of both annual utilization and average utilization, using verified reduction in heat input as defined under paragraph (c)(2)(i)(A) of this section for the calendar year instead of the previously estimated values.

(B) Estimates confirmed. If the total, included in the confirmation report, of the amounts of verified reduction in the opt-in source's heat input equals the total estimated in the opt-in source's annual compliance certification report for the calendar year, then the designated representative shall include in the confirmation report a statement indicating that is true.

(C) Underestimate. If the total, included in the confirmation report, of the amounts of verified reduction in the opt-in source's heat input is greater than the total estimated in the opt-in source's annual compliance certification report for the calendar year, then the designated representative shall include in the confirmation report the number of allowances to be credited to the opt-in source's compliance subaccount calculated using the following formula:

Allowances credited for the calendar year in which the reduced utilization occurred =

ER04AP95.019

where, Average Utilizationestimate = the average utilization of the opt-in source as defined under paragraph (a)(2) of this section, calculated using the estimated reduction in the opt-in source's heat input under (a)(1) of this section, and submitted in the annual compliance certification report for the calendar year. Average Utilizationverified = the average utilization of the opt-in source as defined under paragraph (a)(2) of this section, calculated using the verified reduction in the opt-in source's heat input as submitted under paragraph (c)(2)(i)(A) of this section by the designated representative in the confirmation report.

(D) Overestimate. If the total of the amounts of verified reduction in the opt-in source's heat input included in the confirmation report is less than the total estimated in the opt-in source's annual compliance certification report for the calendar year, then the designated representative shall include in the confirmation report the number of allowances to be deducted from the opt-in source's compliance subaccount, which equals the absolute value of the result of the formula for allowances credited under paragraph (c)(2)(iii)(C) of this section.

(E) Adjusted allowances remaining. Unless paragraph (c)(2)(iii)(B) of this section applies, the designated representative shall include in the confirmation report the adjusted amount of allowances that would have been held in the opt-in source's compliance subaccount if the deductions made under § 73.35(b) of this chapter had been based on the verified, rather than the estimated, reduction in the opt-in source's heat input, calculated as follows:

ER04AP95.020

where: “Allowances held after deduction” shall be the amount of allowances held in the opt-in source's compliance subaccount after deduction of allowances was made under § 73.35(b) of this chapter based on the annual compliance certification report. “Excess emissions” shall be the amount (if any) of excess emissions determined under § 73.35(d) for the calendar year based on the annual compliance certification report. “Allowances credited” shall be the amount of allowances calculated under paragraph (c)(2)(iii)(C) of this section. “Allowances deducted” shall be the amount of allowances calculated under paragraph (c)(2)(iii)(D) of this section.

(1) If the result of the formula for “adjusted amount of allowances” is negative, the absolute value of the result constitutes excess emissions of sulfur dioxide. If the result is positive, there are no excess emissions of sulfur dioxide.

(2) If the amount of excess emissions of sulfur dioxide calculated under “adjusted amount of allowances” differs from the amount of excess emissions of sulfur dioxide determined under § 73.35 of this chapter based on the annual compliance certification report, then the designated representative shall include in the confirmation report a demonstration of:

(i) The number of allowances that should be deducted to offset any increase in excess emissions or returned to the account for any decrease in excess emissions; and

(ii) The amount of the excess emissions penalty (excluding interest) that should be paid or returned to the account for the change in excess emissions.

(3) The Administrator will deduct immediately from the opt-in source'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 opt-in source's compliance subaccount the amount of allowances that he or she determines is necessary to account for any decrease in excess emissions.

(4) 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(c)(2) of this chapter and the identification of allowances returned will be at the Administrator's discretion.

(5) If the designated representative of an opt-in source fails to submit on a timely basis a confirmation report, in accordance with paragraph (c)(2) of this section, with regard to the estimate of reductions in heat input as defined under paragraph (c)(2)(i)(A) of this section, then the Administrator will reject such estimate and correct it to equal zero in the opt-in source'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 any increase in excess emissions of sulfur dioxide that results from the correction and will require the owners and operators of the opt-in source to pay an excess emission penalty in accordance with part 77 of this chapter.

(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:

Adjusted amount of allowances = ER16AP98.027 where, “Allowances allocated or acquired” shall be the number of allowances held in the source's compliance subaccount at the allowance transfer deadline plus the number of allowances transferred for the previous calendar year to all replacement units under an approved thermal energy plan in accordance with § 74.47(a)(6). “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. “Allowances transferred to all replacement units” shall be the sum of allowances transferred to all replacement units under an approved thermal energy plan in accordance with § 74.47 and adjusted by the Administrator in accordance with § 74.47(d)(2). “Allowances deducted for reduced utilization” shall be the total number of allowances deducted for reduced utilization as calculated in accordance with this section including any adjustments required under paragraph (c)(iii)(E) of this section. [60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998]

§ 74.45 Reduced utilization for process sources. [Reserved]

§ 74.46 Opt-in source permanent shutdown, reconstruction, or change in affected status.

(a) Notification. (1) When an opt-in source has permanently shutdown during the calendar year, the designated representative shall notify the Administrator of the date of shutdown, within 30 days of such shutdown.

(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) Administrator's action. (1) The Administrator will terminate the opt-in source's opt-in permit and deduct allowances as provided below in the following circumstances:

(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.

§ 74.47 Transfer of allowances from the replacement of thermal energy—combustion sources.

(a) Thermal energy plan—(1) General provisions. The designated representative of an opt-in source that seeks to qualify for the transfer of allowances based on the replacement of thermal energy by a replacement unit shall submit a thermal energy plan subject to the requirements of § 72.40(b) of this chapter for multi-unit compliance options and this section. The effective period of the thermal energy plan shall begin at the start of the calendar quarter (January 1, April 1, July 1, or October 1) for which the plan is approved and end December 31 of the last full calendar year for which the opt-in permit containing the plan is in effect.

(2) Applicability. This section shall apply to any designated representative of an opt-in source and any designated representative of each replacement unit seeking to transfer allowances based on the replacement of thermal energy.

(3) Contents. Each thermal energy plan shall contain the following elements in a format prescribed by the Administrator:

(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 SO2 emissions rate, expressed in lbs/mmBtu, of each replacement unit for the calendar year for which the plan will take effect. When a thermal energy plan is renewed in accordance with paragraph (a)(9) of this section, the allowable SO2 emission rate at each replacement unit will be the most stringent federally enforceable allowable SO2 emissions rate applicable at the time of renewal for the calendar year for which the renewal will take effect. This rate will not be annualized;

(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) Submission. The designated representative of the opt-in source seeking to qualify for the transfer of allowances based on the replacement of thermal energy shall submit a thermal energy plan to the permitting authority by no later than six months prior to the first calendar quarter for which the plan is to be in effect. The thermal energy plan shall be signed and certified by the designated representative of the opt-in source and each replacement unit covered by the plan.

(5) Retirement of opt-in source upon enactment of plan. (i) If the opt-in source will be permanently retired as of the effective date of the thermal energy plan, the opt-in source shall not be required to monitor its emissions upon retirement, consistent with § 75.67 of this chapter, provided that the following requirements are met:

(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) Administrator's action. If the permitting authority approves a thermal energy plan, the Administrator will annually transfer allowances to the Allowance Tracking System account of each replacement unit, as provided in the approved plan.

(7) Incorporation, modification and renewal of a thermal energy plan. (i) An approved thermal energy plan, including any revised or renewed plan that is approved, shall be incorporated into both the opt-in permit for the opt-in source and the Acid Rain permit for each replacement unit governed by the plan. Upon approval, the thermal energy plan shall be incorporated into the Acid Rain permit for each replacement unit pursuant to the requirements for administrative permit amendments under § 72.83 of this chapter.

(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) Termination of plan. (i) A thermal energy plan shall be in effect until the earlier of the expiration of the opt-in permit for the opt-in source or the year for which a termination of the plan takes effect under paragraph (a)(8)(ii) of this section.

(ii) Termination of plan by opt-in source and replacement units. A notification to terminate a thermal energy plan in accordance with § 72.40(d) of this chapter shall be submitted no later than December 1 of the calendar year for which the termination is to take effect.

(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 permit of each replacement unit governed by the thermal energy plan to terminate the plan pursuant to § 72.83 of this chapter, the Administrator will adjust the allowances for the opt-in source and the replacement units to reflect the transfer back to the opt-in source of the allowances transferred from the opt-in source under the plan for the year for which the termination of the plan takes effect.

(9) Renewal of thermal energy plan. The designated representative of an opt-in source may renew the thermal energy plan as part of its opt-in permit renewal in accordance with § 74.19.

(b) Calculation of transferable allowances—(1) Qualifying thermal energy. The amount of thermal energy credited towards the transfer of allowances based on the replacement of thermal energy shall equal the qualifying thermal energy and shall be calculated for each replacement unit as follows:

ER04AP95.022

(2) Fuel associated with qualifying thermal energy. The fuel associated with the qualifying thermal energy at each replacement unit shall be calculated as follows:

ER04AP95.023

where, “Qualifying thermal energy” for the replacement unit is as defined in paragraph (b)(1) of this section; “Efficiency constant” for the replacement unit = 0.85, where the replacement unit is a boiler = 0.80, where the replacement unit is a cogenerator

(3) Allowances transferable from the opt-in source to each replacement unit. The number of allowances transferable from the opt-in source to each replacement unit for the replacement of thermal energy is calculated as follows:

ER04AP95.024

where, “Allowable SO2 emission rate” for the replacement unit is as defined in paragraph (a)(3)(vii) of this section; “Fuel associated with qualifying thermal energy” is as defined in paragraph (b)(2) of this section;

(c) Transfer prohibition. The allowances transferred from the opt-in source to each replacement unit shall not be transferred from the unit account of the replacement unit to any other account in the Allowance Tracking System.

(d) Compliance—(1) Annual compliance certification report. (i) As required for all opt-in sources, the designated representative of the opt-in source covered by a thermal energy plan must submit an opt-in utilization report for the calendar year as part of its annual compliance certification report under § 74.44(c)(1).

(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;

(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) Allowance adjustments by Administrator. (i) 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 changes between the estimated values submitted in the thermal energy plan pursuant to paragraph (a) of this section and the actual values submitted in the thermal energy compliance report pursuant to paragraph (d) of this section. The values to be considered for this adjustment include:

(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) Liability. The owners and operators of an opt-in source or a replacement unit governed by an approved thermal energy plan shall be liable for any violation of the plan or this section at that opt-in source or replacement unit that is governed by the thermal energy plan, including liability for fulfilling the obligations specified in part 77 of this chapter and section 411 of the Act.

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, 18842, Apr. 16, 1998]

§ 74.48 Transfer of allowances from the replacement of thermal energy—process sources. [Reserved]

§ 74.49 Calculation for deducting allowances.

(a) Allowance deduction formula. 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 opt-in source's compliance subaccount as of the allowance transfer deadline applicable to that year:

Total allowances deducted = Tons emitted + Allowances deducted for reduced utilization where:

(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]

§ 74.50 Deducting opt-in source allowances from ATS accounts.

(a)(1) Deduction of allowances. The Administrator may deduct any allowances that were allocated to an opt-in source under § 74.40 by removing, from any Allowance Tracking System accounts in which they are held, the allowances in an amount specified in paragraph (d) of this section, under the following circumstances:

(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)(3), (4), and (5) for the year for which such allowance may first be used.

(b) Method of deduction. The Administrator will deduct allowances beginning with those allowances with the latest recorded date of transfer out of the opt-in source's unit account.

(c) Notification of deduction. When allowances are deducted, the Administrator will send a written notification to the authorized account representative of each Allowance Tracking System account from which allowances were deducted. The notification will state:

(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) Amount of deduction. The Administrator may deduct allowances in accordance with paragraph (a) of this section in an amount required to offset any excess emissions in accordance with part 77 of this chapter and when an opt-in source does not hold allowances equal in number to and with the same or earlier compliance use date for the calendar years specified under § 74.46(b)(1) (i) through (iv) in an amount required to be deducted under § 74.46(b)(1) (i) through (iv).

[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18842, Apr. 16, 1998]

Subpart F—Monitoring Emissions: Combustion Sources

§ 74.60 Monitoring requirements.

(a) Monitoring requirements for combustion sources. The owner or operator of each combustion source shall meet all of the requirements specified in part 75 of this chapter for the owners and operators of an affected unit to install, certify, operate, and maintain a continuous emission monitoring system, an excepted monitoring system, or an approved alternative monitoring system in accordance with part 75 of this chapter.

(b) Monitoring requirements for opt-in sources. The owner or operator of each opt-in source shall install, certify, operate, and maintain a continuous emission monitoring system, an excepted monitoring system, an approved alternative monitoring system in accordance with part 75 of this chapter.

§ 74.61 Monitoring plan.

(a) Monitoring plan. The designated representative of a combustion source shall meet all of the requirements specified under part 75 of this chapter for a designated representative of an affected unit to submit to the Administrator a monitoring plan that includes the information required in a monitoring plan under § 75.53 of this chapter. This monitoring plan shall be submitted as part of the combustion source's opt-in permit application under § 74.14 of this part.

(b) [Reserved]

Subpart G—Monitoring Emissions: Process Sources [Reserved] Pt. 75 PART 75—CONTINUOUS EMISSION MONITORING Subpart A—General Sec. 75.1 Purpose and scope. 75.2 Applicability. 75.3 General Acid Rain Program provisions. 75.4 Compliance dates. 75.5 Prohibitions. 75.6 Incorporation by reference. 75.7-75.8 [Reserved] Subpart B—Monitoring Provisions 75.10 General operating requirements. 75.11 Specific provisions for monitoring SO2 emissions (SO2 and flow monitors). 75.12 Specific provisions for monitoring NOX emission rate (NOX and diluent gas monitors). 75.13 Specific provisions for monitoring CO2 emissions. 75.14 Specific provisions for monitoring opacity. 75.15 Specific provisions for monitoring SO2 emissions removal by qualifying Phase I technology. 75.16 Special provisions for monitoring emissions from common, by-pass, and multiple stacks for SO2 emissions and heat input determinations. 75.17 Specific provisions for monitoring emissions from common, by-pass, and multiple stacks for NOx emission rate. 75.18 Specific provisions for monitoring emissions from common and by-pass stacks for opacity. 75.19 Optional SO2, NOX, and CO2 emissions calculation for low mass emissions units. Subpart C—Operation and Maintenance Requirements 75.20 Initial certification and recertification procedures. 75.21 Quality assurance and quality control requirements. 75.22 Reference test methods. 75.23 Alternatives to standards incorporated by reference. 75.24 Out-of-control periods and adjustment for system bias. Subpart D—Missing Data Substitution Procedures 75.30 General provisions. 75.31 Initial missing data procedures. 75.32 Determination of monitor data availability for standard missing data procedures. 75.33 Standard missing data procedures for SO2, NOX and flow rate. 75.34 Units with add-on emission controls. 75.35 Missing data procedures for CO2 data. 75.36 Missing data procedures for heat input determinations. 75.37 Missing data procedures for moisture. Subpart E—Alternative Monitoring Systems 75.40 General demonstration requirements. 75.41 Precision criteria. 75.42 Reliability criteria. 75.43 Accessibility criteria. 75.44 Timeliness criteria. 75.45 Daily quality assurance criteria. 75.46 Missing data substitution criteria. 75.47 Criteria for a class of affected units. 75.48 Petition for an alternative monitoring system. Subpart F—Recordkeeping Requirements 75.50-75.52 [Reserved] 75.53 Monitoring plan. 75.54 General recordkeeping provisions. 75.55 General recordkeeping provisions for specific situations. 75.56 Certification, quality assurance and quality control record provisions. 75.57 General recordkeeping provisions. 75.58 General recordkeeping provisions for specific situations. 75.59 Certification, quality assurance, and quality control record provisions. Subpart G—Reporting Requirements 75.60 General provisions. 75.61 Notifications. 75.62 Monitoring plan submittals. 75.63 Initial certification or recertification application submittals. 75.64 Quarterly reports. 75.65 Opacity reports. 75.66 Petitions to the Administrator. 75.67 Retired units petitions. Subpart H—NOX Mass Emissions Provisions 75.70 NOX mass emissions provisions. 75.71 Specific provisions for monitoring NOX emission rate and heat input for the purpose of calculating NOX mass emissions. 75.72 Determination of NOX mass emissions. 75.73 Recordkeeping and reporting. 75.74 Annual and ozone season monitoring and reporting requirements. 75.75 Additional ozone season calculation procedures for special circumstances. Appendix A to Part 75—Specifications and Test Procedures Appendix B to Part 75—Quality Assurance and Quality Control Procedures Appendix C to Part 75—Missing Data Estimation Procedures Appendix D to Part 75—Optional SO2 Emissions Data Protocol for Gas-Fired and Oil-Fired Units Appendix E to Part 75—Optional NOx Emissions Estimation Protocol for Gas-Fired Peaking Units and Oil-Fired Peaking Units Appendix F to Part 75—Conversion Procedures Appendix G to Part 75—Determination of CO2 Emissions Appendix H to Part 75—Revised Traceability Protocol No. 1 [Reserved] Appendix I to Part 75—Optional F—factor/Fuel Flow Method [Reserved] Appendix J to Part 75—Compliance Dates for Revised Recordkeeping Requirements and Missing Data Procedures [Reserved] Authority:

42 U.S.C. 7601 and 7651K, and 7651K note.

Source:

58 FR 3701, Jan. 11, 1993, unless otherwise noted.

Pt. 75, App. A Appendix A to Part 75—Specifications and Test Procedures 1. Installation and Measurement Location 1.1Pollutant Concentration and CO2 or O2 Monitors

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 from the affected unit. Select a representative measurement point or path for the monitor probe(s) (or for the path from the transmitter to the receiver) such that the SO2 pollutant concentration monitor or NOx continuous emission monitoring system (NOx pollutant concentration monitor and diluent gas monitor) will pass the relative accuracy test (see section 6 of this appendix).

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).

1.1.1Point Pollutant Concentration and CO 2 or O2 Monitors

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.

1.1.2Path Pollutant Concentration and CO 2 or O2 Gas Monitors

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.

1.2Flow Monitors

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 SO2 emission rate (in lb/hr), and is representative of the pollutant concentration monitor location. Where the moisture content of the flue gas affects volumetric flow measurements, use the procedures in both Reference Methods 1 and 4 of appendix A to part 60 of this chapter to establish a proper location for the flow monitor. The EPA recommends (but does not require) performing a flow profile study following the procedures in 40 CFR part 60, appendix A, method, 1, section 2.5 or 2.4 for each of the three operating or load levels indicated in section 6.5.2 of this appendix to determine the acceptability of the potential flow monitor location and to determine the number and location of flow sampling points required to obtain a representative flow value. The procedure in 40 CFR part 60, appendix A, Test Method 1, section 2.5 may be used even if the flow measurement location is greater than or equal to 2 equivalent stack or duct diameters downstream or greater than or equal to 1/2 duct diameter upstream from a flow disturbance. If a flow profile study shows that cyclonic (or swirling) or stratified flow conditions exist at the potential flow monitor location that are likely to prevent the monitor from meeting the performance specifications of this part, then EPA recommends either (1) selecting another location where there is no cyclonic (or swirling) or stratified flow condition, or (2) eliminating the cyclonic (or swirling) or stratified flow condition by straightening the flow, e.g., by installing straightening vanes. EPA also recommends selecting flow monitor locations to minimize the effects of condensation, coating, erosion, or other conditions that could adversely affect flow monitor performance.

1.2.1Acceptability of Monitor Location

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.

1.2.2Alternative Monitoring Location

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 at two or more alternative flow monitor locations are unacceptable, or where installation of a flow monitor in either the stack or the ducts is demonstrated to be technically infeasible, the owner or operator may petition the Administrator for an alternative method for monitoring flow.

2. Equipment Specifications 2.1Instrument Span and Range

In implementing sections 2.1.1 through 2.1.6 of this appendix, set the measurement range for each parameter (SO2, NOX, CO2, O2, or flow rate) high enough to prevent full-scale exceedances from occurring, yet low enough to ensure good measurement accuracy and to maintain a high signal-to-noise ratio. To meet these objectives, select the range such that the readings obtained during typical unit operation are kept, to the extent practicable, between 20.0 and 80.0 percent of full-scale range of the instrument. These guidelines do not apply to: (1) SO2 readings obtained during the combustion of very low sulfur fuel (as defined in § 72.2 of this chapter); (2) SO2 or NOX readings recorded on the high measurement range, for units with SO2 or NOX emission controls and two span values; or (3) SO2 or NOX readings less than 20.0 percent of full-scale on the low measurement range for a dual span unit with SO2 or NOX emission controls, provided that the readings occur during periods of high control device efficiency.

2.1.1SO2 Pollutant Concentration Monitors

Determine, as indicated in this section 2, the span value(s) and range(s) for an SO2 pollutant concentration monitor so that all potential and expected concentrations can be accurately measured and recorded. Note that if a unit exclusively combusts fuels that are very low sulfur fuels (as defined in § 72.2 of this chapter), the SO2 monitor span requirements in § 75.11(e)(3)(iv) apply in lieu of the requirements of this section.

2.1.1.1Maximum Potential Concentration

(a) Make an initial determination of the maximum potential concentration (MPC) of SO2 by using Equation A-1a or A-1b. Base the MPC calculation on the maximum percent sulfur and the minimum gross calorific value (GCV) for the highest-sulfur fuel to be burned. The maximum sulfur content and minimum GCV shall be determined from all available fuel sampling and analysis data for that fuel from the previous 12 months (minimum), excluding clearly anomalous fuel sampling values. If the designated representative certifies that the highest-sulfur fuel is never burned alone in the unit during normal operation but is always blended or co-fired with other fuel(s), the MPC may be calculated using a best estimate of the highest sulfur content and lowest gross calorific value expected for the blend or fuel mixture and inserting these values into Equation A-1a or A-1b. Derive the best estimate of the highest percent sulfur and lowest GCV for a blend or fuel mixture from weighted-average values based upon the historical composition of the blend or mixture in the previous 12 (or more) months. If insufficient representative fuel sampling data are available to determine the maximum sulfur content and minimum GCV, use values from contract(s) for the fuel(s) that will be combusted by the unit in the MPC calculation.

(b) Alternatively, if a certified SO2 CEMS is already installed, the owner or operator may make the initial MPC determination based upon quality assured historical data recorded by the CEMS. If this option is chosen, the MPC shall be the maximum SO2 concentration observed during the previous 720 (or more) quality assured monitor operating hours when combusting the highest-sulfur fuel (or highest-sulfur blend if fuels are always blended or co-fired) that is to be combusted in the unit or units monitored by the SO2 monitor. For units with SO2 emission controls, the certified SO2 monitor used to determine the MPC must be located at or before the control device inlet. Report the MPC and the method of determination in the monitoring plan required under § 75.53.

(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).

ER26MY99.000 or ER26MY99.001 Where, MPC = Maximum potential concentration (ppm, wet basis). (To convert to dry basis, divide the MPC by 0.9.) MEC = Maximum expected concentration (ppm, wet basis). (To convert to dry basis, divide the MEC by 0.9). %S = Maximum sulfur content of fuel to be fired, wet basis, weight percent, as determined by ASTM D3177-89, ASTM D4239-85, ASTM D4294-90, ASTM D1552-90, ASTM D129-91, or ASTM D2622-92 for solid or liquid fuels (incorporated by reference under § 75.6). %O2w = Minimum oxygen concentration, percent wet basis, under typical operating conditions. %CO2w = Maximum carbon dioxide concentration, percent wet basis, under typical operating conditions. 11.32 × 106 = Oxygen-based conversion factor in Btu/lb (ppm)/%. 66.93 × 106 = Carbon dioxide-based conversion factor in Btu/lb (ppm)/%. Note:

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).

2.1.1.2Maximum Expected Concentration

(a) Make an initial determination of the maximum expected concentration (MEC) of SO2 whenever: (a) SO2 emission controls are used; or (b) both high-sulfur and low-sulfur fuels (e.g., high-sulfur coal and low-sulfur coal or different grades of fuel oil) or high-sulfur and low-sulfur fuel blends are combusted as primary or backup fuels in a unit without SO2 emission controls. For units with SO2 emission controls, use Equation A-2 to make the initial MEC determination. When high-sulfur and low-sulfur fuels or blends are burned as primary or backup fuels in a unit without SO2 controls, use Equation A-1a or A-1b to calculate the initial MEC value for each fuel or blend, except for: (1) the highest-sulfur fuel or blend (for which the MPC was previously calculated in section 2.1.1.1 of this appendix); (2) fuels or blends that are very low sulfur fuels (as defined in § 72.2 of this chapter); or (3) fuels or blends that are used only for unit startup.

(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 SO2 CEMS is already installed, the owner or operator may make the initial MEC determination(s) based upon historical monitoring data. If this option is chosen for a unit with SO2 emission controls, the MEC shall be the maximum SO2 concentration measured downstream of the control device outlet by the CEMS over the previous 720 (or more) quality assured monitor operating hours with the unit and the control device both operating normally. For units that burn high- and low-sulfur fuels or blends as primary and backup fuels and have no SO2 emission controls, the MEC for each fuel shall be the maximum SO2 concentration measured by the CEMS over the previous 720 (or more) quality assured monitor operating hours in which that fuel or blend was the only fuel being burned in the unit.

ER26MY99.002 Where: MEC = Maximum expected concentration (ppm). MPC = Maximum potential concentration (ppm), as determined by Eq. A-1a or A-1b. RE = Expected average design removal efficiency of control equipment (%). 2.1.1.3Span Value(s) and Range(s)

Determine the high span value and the high full-scale range of the SO2 monitor as follows. (Note: For purposes of this part, the high span and range refer, respectively, either to the span and range of a single span unit or to the high span and range of a dual span unit.) The high span value shall be obtained by multiplying the MPC by a factor no less than 1.00 and no greater than 1.25. Round the span value upward to the next highest multiple of 100 ppm. If the SO2 span concentration is ≤500 ppm, the span value may be rounded upward to the next highest multiple of 10 ppm, instead of the nearest 100 ppm. The high span value shall be used to determine concentrations of the calibration gases required for daily calibration error checks and linearity tests. 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 span value. Report the full-scale range setting and calculations of the MPC and span in the monitoring plan for the unit. Note that for certain applications, a second (low) SO2 span and range may be required (see section 2.1.1.4 of this appendix). If an existing state, local, or federal requirement for span of an SO2 pollutant concentration monitor requires a span lower than that required by this section or by section 2.1.1.4 of this appendix, the state, local, or federal span value may be used if a satisfactory explanation is included in the monitoring plan, unless span and/or range adjustments become necessary in accordance with section 2.1.1.5 of this appendix. Span values higher than those required by either this section or section 2.1.1.4 of this appendix must be approved by the Administrator.

2.1.1.4Dual Span and Range Requirements

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 SO2 concentrations (unless span and/or range adjustments become necessary in accordance with section 2.1.1.5 of this appendix). In some instances, however, a second (low) span value based on the MEC may be required to ensure accurate measurement of all possible or expected SO2 concentrations. To determine whether two SO2 span values are required, proceed as follows:

(a) For units with SO2 emission controls, compare the MEC from section 2.1.1.2 of this appendix to the high full-scale range value from section 2.1.1.3 of this appendix. If the MEC is ≥20.0 percent of the high range value, then the high span value and range determined under section 2.1.1.3 of this appendix are sufficient. If the MEC is <20.0 percent of the high range value, then a second (low) span value is required.

(b) For units that combust high- and low-sulfur primary and backup fuels (or blends) and have no SO2 controls, compare the high range value from section 2.1.1.3 of this appendix (for the highest-sulfur fuel or blend) to the MEC value for each of the other fuels or blends, as determined under section 2.1.1.2 of this appendix. If all of the MEC values are ≥20.0 percent of the high range value, the high span and range determined under section 2.1.1.3 of this appendix are sufficient, regardless of which fuel or blend is burned in the unit. If any MEC value is <20.0 percent of the high range value, then a second (low) span value must be used when that fuel or blend is combusted.

(c) When two SO2 spans are required, the owner or operator may either use a single SO2 analyzer with a dual range (i.e., low- and high-scales) or two separate SO2 analyzers connected to a common sample probe and sample interface. For units with SO2 emission controls, the owner or operator may use a low range analyzer and a default high range value, as described in paragraph (f) of this section, in lieu of maintaining and quality assuring a high-scale range. Other monitor configurations are subject to the approval of the Administrator.

(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 SO2 components of a single, primary SO2 monitoring system; or designate the low and high monitor ranges as the SO2 components of two separate, primary SO2 monitoring systems; or designate the normal monitor range as a primary monitoring system and the other monitor range as a non-redundant backup monitoring system; or, when a single, dual-range SO2 analyzer is used, designate the low and high ranges as a single SO2 component of a primary SO2 monitoring system (if this option is selected, use a special dual-range component type code, as specified by the Administrator, to satisfy the requirements of § 75.53(e)(1)(iv)(D)); or, for units with SO2 controls, if the default high range value is used, designate the low range analyzer as the SO2 component of a primary SO2 monitoring system. Do not designate the default high range as a monitoring system or component. Other component and system designations are subject to approval by the Administrator. Note that the component and system designations for redundant backup monitoring systems shall be the same as for primary monitoring systems.

(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 SO2 emission controls, the low range is considered normal). Each monitoring system designated as a non-redundant backup shall meet the applicable quality assurance requirements in § 75.20(d)(2).

(f) For dual span units with SO2 emission controls, the owner or operator may, as an alternative to maintaining and quality assuring a high monitor range, use a default high range value. If this option is chosen, the owner or operator shall report a default SO2 concentration of 200 percent of the MPC for each unit operating hour in which the full-scale of the low range SO2 analyzer is exceeded.

(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 SO2 emission controls, select, as the basis for calculating the appropriate low span value and range, the fuel-specific MEC value closest to 20.0 percent of the high full-scale range value (from paragraph (b) of this section). The low range must be greater than or equal to the low span value, and the required calibration gases must be selected based on the low span value. For units with two SO2 spans, use the low range whenever the SO2 concentrations are expected to be consistently below 20.0 percent of the high full-scale range value, i.e., when the MEC of the fuel or blend being combusted is less than 20.0 percent of the high full-scale range value. When the full-scale of the low range is exceeded, the high range shall be used to measure and record the SO2 concentrations; or, if applicable, the default high range value in paragraph (f) of this section shall be reported for each hour of the full-scale exceedance.

2.1.1.5Adjustment of Span and Range

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 SO2 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) and (b) of this section. Span and range adjustments may be required, for example, as a result of changes in the fuel supply, 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, SO2 data recorded during short-term, non-representative process 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, except that up to 90 days after the end of that quarter may be taken to implement a span adjustment if the calibration gases currently being used for daily calibration error tests and linearity checks are unsuitable for use with the new span value.

(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 SO2 concentration for each hour of the full-scale exceedance and make appropriate adjustments to the MPC, span, and range to prevent future full-scale exceedances.

(2) For units with two SO2 spans and ranges, if the low range is exceeded, no further action is required, provided that the high range is available and is not out-of-control or out-of-service for any reason. However, if the high range is not able to provide quality assured data at the time of the low range exceedance or at any time during the continuation of the exceedance, report the MPC as the SO2 concentration until the readings return to the low range or until the high range is able to provide quality assured data (unless the reason that the high-scale range is not able to provide quality assured data is because the high-scale range has been exceeded; if the high-scale range is exceeded follow the procedures in paragraph (b)(1) of this section).

(c) Whenever changes are made to the MPC, MEC, full-scale range, or span value of the SO2 monitor, as described in paragraphs (a) or (b) of this section, record and report (as applicable) the new full-scale range setting, the new MPC or MEC and calculations of the adjusted span value in an updated monitoring plan. The monitoring plan update shall be made in the quarter in which the changes become effective. In addition, record and report the adjusted span as part of the records for the daily calibration error test and linearity check specified by appendix B to this part. Whenever the span value is adjusted, use calibration gas concentrations that meet the requirements of section 5.1 of this appendix, based on the adjusted span value. When a span adjustment is so significant that the calibration gases currently being used for daily calibration error tests and linearity checks are unsuitable for use with the new span value, then a diagnostic linearity test using the new calibration gases must be performed and passed. Data from the monitor are considered invalid from the hour in which the span is adjusted until the required linearity check is passed in accordance with section 6.2 of this appendix.

2.1.2NOX Pollutant Concentration Monitors

Determine, as indicated in section 2.1.2.1, the span and range value(s) for the NOX pollutant concentration monitor so that all expected NOX concentrations can be determined and recorded accurately.

2.1.2.1Maximum Potential Concentration

(a) The maximum potential concentration (MPC) of NOX for each affected unit shall be based upon whichever fuel or blend combusted in the unit produces the highest level of NOX emissions. Make an initial determination of the MPC using the appropriate option as follows:

Option 1: Use 800 ppm for coal-fired and 400 ppm for oil- or gas-fired units as the maximum potential concentration of NOX (if an MPC of 1600 ppm for coal-fired units or 480 ppm for oil- or gas-fired units was previously selected under this part, that value may still be used, provided that the guidelines of section 2.1 of this appendix are met);

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 NOX emission test results; or

Option 4: Use historical CEM data over the previous 720 (or more) unit operating hours when combusting the fuel or blend with the highest NOX emission rate.

(b) For the purpose of providing substitute data during NOX missing data periods in accordance with §§ 75.31 and 75.33 and as required elsewhere under this part, the owner or operator shall also calculate the maximum potential NOX emission rate (MER), in lb/mmBtu, by substituting the MPC for NOX in conjunction with the minimum expected CO2 or maximum O2 concentration (under all unit operating conditions except for unit startup, shutdown, and upsets) and the appropriate F-factor into the applicable equation in appendix F to this part. The diluent cap value of 5.0 percent CO2 (or 14.0 percent O2) for boilers or 1.0 percent CO2 (or 19.0 percent O2) for combustion turbines may be used in the NOX MER calculation.

(c) Report the method of determining the initial MPC and the calculation of the maximum potential NOX emission rate in the monitoring plan for the unit.

(d) For units with add-on NOX controls (whether or not the unit is equipped with low-NOX burner technology), NOX emission testing may only be used to determine the MPC if testing can be performed either upstream of the add-on controls or during a time or season when the add-on controls are not in operation. If NOX emission testing is performed, use the following guidelines. Use Method 7E from appendix A to part 60 of this chapter to measure total NOX concentration. (Note: Method 20 from appendix A to part 60 may be used for gas turbines, instead of Method 7E.) Operate the unit, or group of units sharing a common stack, at the minimum safe and stable load, the normal load, and the maximum load. If the normal load and maximum load are identical, an intermediate level need not be tested. Operate at the highest excess O2 level expected under normal operating conditions. Make at least three runs of 20 minutes (minimum) duration with three traverse points per run at each operating condition. Select the highest point NOX concentration from all test runs as the MPC for NOX.

(e) If historical CEM data are used to determine the MPC, the data must, for uncontrolled units or units equipped with low-NOX burner technology and no other NOX controls, represent a minimum of 720 quality assured monitor operating hours, obtained under various operating conditions including the minimum safe and stable load, normal load (including periods of high excess air at normal load), and maximum load. For a unit with add-on NOX controls (whether or not the unit is equipped with low-NOX burner technology), historical CEM data may only be used to determine the MPC if the 720 quality assured monitor operating hours of CEM data are collected upstream of the add-on controls or if the 720 hours of data include periods when the add-on controls are not in operation. The highest hourly NOX concentration in ppm shall be the MPC.

Table 2-1.—Maximum Potential Concentration for NO X—Coal-Fired Units Unit type Maximum potential concentration for NOX (ppm) Tangentially-fired dry bottom and fluidized bed 460 Wall-fired dry bottom, turbo-fired dry bottom, stokers 675 Roof-fired (vertically-fired) dry bottom, cell burners, arch-fired 975 Cyclone, wall-fired wet bottom, wet bottom turbo-fired 1200 Others (1) 1 As approved by the Administrator. Table 2-2.—Maximum Potential Concentration for NO X—Gas-and Oil-Fired Units Unit type Maximum potential concentration for NOX (ppm) Tangentially-fired dry bottom 380 Wall-fired dry bottom 600 Roof-fired (vertically-fired) dry bottom, arch-fired 550 Existing combustion turbine or combined cycle turbine 200 New stationary gas turbine/combustion turbine 50 Others (1) 1 As approved by the Administrator 2.1.2.2Maximum Expected Concentration

(a) Make an initial determination of the maximum expected concentration (MEC) of NOX during normal operation for affected units with add-on NOX controls of any kind (e.g., steam injection, water injection, SCR, or SNCR). Determine a separate MEC value for each type of fuel (or blend) combusted in the unit, except for fuels that are only used for unit startup and/or flame stabilization. Calculate the MEC of NOX using Equation A-2, if applicable, inserting the maximum potential concentration, as determined using the procedures in section 2.1.2.1 of this appendix. Where Equation A-2 is not applicable, set the MEC either by: (1) measuring the NOX concentration using the testing procedures in this section; or (2) using historical CEM data over the previous 720 (or more) quality assured monitor operating hours. Include in the monitoring plan for the unit each MEC value and the method by which the MEC was determined.

(b) If NOX emission testing is used to determine the MEC value(s), the MEC for each type of fuel (or blend) shall be based upon testing at minimum load, normal load, and maximum load. At least three tests of 20 minutes (minimum) duration, using at least three traverse points, shall be performed at each load, using Method 7E from appendix A to part 60 of this chapter (Note: Method 20 from appendix A to part 60 may be used for gas turbines instead of Method 7E). The test must be performed at a time when all NOX control devices and methods used to reduce NOX emissions are operating properly. The testing shall be conducted downstream of all NOX controls. The highest point NOX concentration (e.g., the highest one-minute average) recorded during any of the test runs shall be the MEC.

(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 NOX control device malfunctions or outages. All NOX control devices and methods used to reduce NOX emissions must be operating properly during each hour. The CEM data shall be collected downstream of all NOX controls. For each type of fuel, the highest of the 720 (or more) quality assured hourly average NOX concentrations recorded by the CEMS shall be the MEC.

2.1.2.3Span Value(s) and Range(s)

(a) Determine the high span value of the NOX monitor as follows. The high span value shall be obtained by multiplying the MPC by a factor no less than 1.00 and no greater than 1.25. Round the span value upward to the next highest multiple of 100 ppm. If the NOX span concentration is ≤ 500 ppm, the span value may be rounded upward to the next highest multiple of 10 ppm, rather than 100 ppm. The high span value shall be used to determine the concentrations of the calibration gases required for daily calibration error checks and linearity tests. Note that for certain applications, a second (low) NOX span and range may be required (see section 2.1.2.4 of this appendix).

(b) If an existing State, local, or federal requirement for span of a NOX pollutant concentration monitor requires a span lower than that required by this section or by section 2.1.2.4 of this appendix, the State, local, or federal span value may be used, where a satisfactory explanation is included in the monitoring plan, unless span and/or range adjustments become necessary in accordance with section 2.1.2.5 of this appendix. Span values higher than required by this section or by section 2.1.2.4 of this appendix must be approved by the Administrator.

(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.

2.1.2.4Dual Span and Range Requirements

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 NOX concentrations (unless span and/or range adjustments must be made in accordance with section 2.1.2.5 of this appendix). In some instances, however, a second (low) span value based on the MEC may be required to ensure accurate measurement of all expected and potential NOX concentrations. To determine whether two NOX spans are required, proceed as follows:

(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 NOX spans are required, the owner or operator may either use a single NOX analyzer with a dual range (low-and high-scales) or two separate NOX analyzers connected to a common sample probe and sample interface. For units with add-on NOX emission controls (i.e., steam injection, water injection, SCR, or SNCR), the owner or operator may use a low range analyzer and a “default high range value,” as described in paragraph 2.1.2.4(e) of this section, in lieu of maintaining and quality assuring a high-scale range. Other monitor configurations are subject to the approval of the Administrator.

(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 NOX components of a single, primary NOX monitoring system; or designate the low and high ranges as the NOX components of two separate, primary NOX monitoring systems; or designate the normal range as a primary monitoring system and the other range as a non-redundant backup monitoring system; or, when a single, dual-range NOX analyzer is used, designate the low and high ranges as a single NOX component of a primary NOX monitoring system (if this option is selected, use a special dual-range component type code, as specified by the Administrator, to satisfy the requirements of § 75.53(e)(1)(iv)(D)); or, for units with add-on NOX controls, if the default high range value is used, designate the low range analyzer as the NOX component of the primary NOX monitoring system. Do not designate the default high range as a monitoring system or component. Other component and system designations are subject to approval by the Administrator. Note that the component and system designations for redundant backup monitoring systems shall be the same as for primary monitoring systems.

(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 NOX emission controls, the low range is considered normal). Each monitoring system designated as non-redundant backup shall meet the applicable quality assurance requirements in § 75.20(d)(2).

(e) For dual span units with add-on NOX emission controls (e.g., steam injection, water injection, SCR, or SNCR), the owner or operator may, as an alternative to maintaining and quality assuring a high monitor range, use a default high range value. If this option is chosen, the owner or operator shall report a default value of 200.0 percent of the MPC for each unit operating hour in which the full-scale of the low range NOX analyzer is exceeded.

(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 NOX spans, use the low range whenever NOX concentrations are expected to be consistently <20.0 percent of the high range value, i.e., when the MEC of the fuel being combusted is <20.0 percent of the high range value. When the full-scale of the low range is exceeded, the high range shall be used to measure and record the NOX concentrations; or, if applicable, the default high range value in paragraph (e) of this section shall be reported for each hour of the full-scale exceedance.

2.1.2.5Adjustment of Span and Range

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 NOX 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) and (b) of this section. Span and range adjustments may be required, for example, as a result of changes in the fuel supply, 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, note that NOX 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, except that up to 90 days after the end of that quarter may be taken to implement a span adjustment if the calibration gases currently being used for daily calibration error tests and linearity checks are unsuitable for use with the new span value.

(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 NOX pollutant concentration span(s) and (if necessary) monitor range(s) 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 or stack may affect the concentration of emissions being emitted from the unit 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. An example of a change that may require a span and range adjustment is the installation of low-NOX burner technology on a previously uncontrolled unit. Determine the adjusted span(s) using the procedures in section 2.1.2.3 or 2.1.2.4 of this appendix (as applicable). Select the full-scale range(s) of the instrument to be greater than or equal to the adjusted 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 NOX concentration for each hour of the full-scale exceedance and make appropriate adjustments to the MPC, span, and range to prevent future full-scale exceedances.

(2) For units with two NOX spans and ranges, if the low range is exceeded, no further action is required, provided that the high range is available and is not out-of-control or out-of-service for any reason. However, if the high range is not able to provide quality assured data at the time of the low range exceedance or at any time during the continuation of the exceedance, report the MPC as the NOX concentration until the readings return to the low range or until the high range is able to provide quality assured data (unless the reason that the high-scale range is not able to provide quality assured data is because the high-scale range has been exceeded; if the high-scale range is exceeded, follow the procedures in paragraph (b)(1) of this section).

(c) Whenever changes are made to the MPC, MEC, full-scale range, or span value of the NOX monitor as described in paragraphs (a) and (b) of this section, record and report (as applicable) the new full-scale range setting, the new MPC or MEC, maximum potential NOX emission rate, and the adjusted span value in an updated monitoring plan for the unit. The monitoring plan update shall be made in the quarter in which the changes become effective. In addition, record and report the adjusted span as part of the records for the daily calibration error test and linearity check required by appendix B to this part. Whenever the span value is adjusted, use calibration gas concentrations that meet the requirements of section 5.1 of this appendix, based on the adjusted span value. When a span adjustment is significant enough that the calibration gases currently being used for daily calibration error tests and linearity checks are unsuitable for use with the new span value, a linearity test using the new calibration gases must be performed and passed. Data from the monitor are considered invalid from the hour in which the span is adjusted until the required linearity check is passed in accordance with section 6.2 of this appendix.

2.1.3CO2 and O2 Monitors

For an O2 monitor (including O2 monitors used to measure CO2 emissions or percentage moisture), select a span value between 15.0 and 25.0 percent O2. For a CO2 monitor installed on a boiler, select a span value between 14.0 and 20.0 percent CO2. For a CO2 monitor installed on a combustion turbine, an alternative span value between 6.0 and 14.0 percent CO2 may be used. An alternative O2 span value below 15.0 percent O2 may be used if an appropriate technical justification is included in the monitoring plan (e.g., O2 concentrations above a certain level create an unsafe operating condition). 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 span value. Select the calibration gas concentrations for the daily calibration error tests and linearity checks in accordance with section 5.1 of this appendix, as percentages of the span value. For O2 monitors with span values ≥21.0 percent O2, purified instrument air containing 20.9 percent O2 may be used as the high-level calibration material.

2.1.3.1Maximum Potential Concentration of CO2

For CO2 pollutant concentration monitors, the maximum potential concentration shall be 14.0 percent CO2 for boilers and 6.0 percent CO2 for combustion turbines. Alternatively, the owner or operator may determine the MPC based on a minimum of 720 hours of quality assured historical CEM data representing the full operating load range of the unit(s). Note that the MPC for CO2 monitors shall only be used for the purpose of providing substitute data under this part. The CO2 monitor span and range shall be determined according to section 2.1.3 of this appendix.

2.1.3.2Minimum Potential Concentration of O2

The owner or operator of a unit that uses a flow monitor and an O2 diluent monitor to determine heat input in accordance with Equation F-17 or F-18 in appendix F to this part shall, for the purposes of providing substitute data under § 75.36, determine the minimum potential O2 concentration. The minimum potential O2 concentration shall be based upon 720 hours or more of quality-assured CEM data, representing the full operating load range of the unit(s). The minimum potential O2 concentration shall be the lowest quality-assured hourly average O2 concentration recorded in the 720 (or more) hours of data used for the determination.

2.1.3.3Adjustment of Span and Range

Adjust the span value and range of a CO2 or O2 monitor in accordance with section 2.1.1.5 of this appendix (insofar as those provisions are applicable), with the term “CO2 or O2” applying instead of the term “SO2”. Set the new span and range in accordance with section 2.1.3 of this appendix and report the new span value in the monitoring plan.

2.1.4Flow Monitors

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.

2.1.4.1Maximum Potential Velocity and Flow Rate

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 ft2) at the flow monitor location.

ER26MY99.003 or ER26MY99.004 Where: MPV = maximum potential velocity (fpm, standard wet basis). Fd = dry-basis F factor (dscf/mmBtu) from Table 1, Appendix F to this part. Fc = carbon-based F factor (scf CO2/mmBtu) from Table 1, Appendix F to this part. Hf = maximum heat input (mmBtu/minute) for all units, combined, exhausting to the stack or duct where the flow monitor is located. A = inside cross sectional area (ft2) of the flue at the flow monitor location. %O2d = maximum oxygen concentration, percent dry basis, under normal operating conditions. %CO2d = minimum carbon dioxide concentration, percent dry basis, under normal operating conditions. %H2O = maximum percent flue gas moisture content under normal operating conditions. 2.1.4.2Span Values and Range

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).

2.1.4.3Adjustment of Span and Range

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 span, and range to prevent future full-scale exceedances. Calculate the new calibration span value by converting the new flow rate span value from units of scfh to units of daily calibration. A calibration error test must be performed and passed to validate data on the new range.

(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).

2.1.5Minimum Potential Moisture Percentage

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 H2O as the minimum potential moisture percentage. Alternatively, the minimum potential moisture percentage may be based upon 720 hours or more of quality-assured CEM data, representing the full operating load range of the unit(s). If this option is chosen, the minimum potential moisture percentage shall be the lowest quality-assured hourly average H2O concentration recorded in the 720 (or more) hours of data used for the determination.

2.1.6Maximum Potential Moisture Percentage

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 NOX emission rate, the owner or operator of a unit that uses a continuous moisture monitoring system shall, for the purpose of providing substitute data under § 75.37, determine the maximum potential moisture percentage. The maximum potential moisture percentage shall be based upon 720 hours or more of quality-assured CEM data, representing the full operating load range of the unit(s). The maximum potential moisture percentage shall be the highest quality-assured hourly average H2O concentration recorded in the 720 (or more) hours of data used for the determination.

2.2Design for Quality Control Testing [Reserved] 3. Performance Specifications 3.1Calibration Error

(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 SO2 and NOX pollutant concentration monitors shall not deviate from the reference value of either the zero or upscale calibration gas by more than 2.5 percent of the span of the instrument, as calculated using Equation A-5 of this appendix. Alternatively, where the span value is less than 200 ppm, calibration error test results are also acceptable if the absolute value of the difference between the monitor response value and the reference value, |R−A| in Equation A-5 of this appendix, is ≤5 ppm. The calibration error of CO2 or O2 monitors (including O2 monitors used to measure CO2 emissions or percent moisture) shall not deviate from the reference value of the zero or upscale calibration gas by >0.5 percent O2 or CO2, as calculated using the term|R−A|in the numerator of Equation A-5 of this appendix. The calibration error of flow monitors shall not exceed 3.0 percent of the calibration span value of the instrument, as calculated using Equation A-6 of this appendix. For differential pressure-type flow monitors, the calibration error test results are also acceptable if |R−A|, the absolute value of the difference between the monitor response and the reference value in Equation A-6, does not exceed 0.01 inches of water.

3.2Linearity Check

For SO2 and NOx pollutant concentration monitors, 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). Linearity check results are also acceptable if the absolute value of the difference between the average of the monitor response values and the average of the reference values, | R-A | in equation A-4 of this appendix, is less than or equal to 5 ppm. For CO2 or O2 monitors (including O2 monitors used to measure CO2 emissions or percent moisture):

(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, | R-A| in equation A-4 of this appendix, shall be less than or equal to 0.5 percent CO2 or O2, whichever is less restrictive.

3.3Relative Accuracy 3.3.1Relative Accuracy for SO 2

The relative accuracy for SO2 pollutant concentration monitors and for SO2-diluent continuous emission monitoring systems used by units with a qualifying Phase I technology for the period during which the units are required to monitor SO2 emission removal efficiency, from January 1, 1997 through December 31, 1999, shall not exceed 10.0 percent except as provided below in this section.

For affected units where the average of the monitor measurements of SO2 concentration during the relative accuracy test audit is less than or equal to 250.0 ppm (or for SO2-diluent monitors, less than or equal to 0.5 lb/mmBTU), the mean value of the monitor measurements shall not exceed ±15.0 ppm of the reference method mean value (or, for SO2-diluent monitors, not to exceed ±0.03 lb/mmBTU for the period during which the units are required to monitor SO2 emission removal efficiency, from January 1, 1997 through December 31, 1999) wherever the relative accuracy specification of 10.0 percent is not achieved.

3.3.2Relative Accuracy for NOX-Diluent Continuous Emission Monitoring Systems

(a) The relative accuracy for NOX-diluent continuous emission monitoring systems shall not exceed 10.0 percent.

(b) For affected units where the average of the monitoring system measurements of NOX emission rate during the relative accuracy test audit is less than or equal to 0.200 lb/mmBtu, the mean value of the continuous emission monitoring system measurements shall not exceed ±0.020 lb/mmBtu of the reference method mean value whenever the relative accuracy specification of 10.0 percent is not achieved.

3.3.3Relative Accuracy for CO 2 and O2 Pollutant Concentration Monitors

The relative accuracy for CO2 and O2 monitors shall not exceed 10.0 percent. The relative accuracy test results are also acceptable if the mean difference of the CO2 or O2 monitor measurements and the corresponding reference method measurement, calculated using equation A-7 of this appendix, is within 1.0 percent CO2 or O2.

3.3.4Relative Accuracy for Flow

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 ±2.0 fps of the reference method mean value in fps wherever the relative accuracy specification above is not achieved.

3.3.5Combined SO 2/Flow Monitoring System [Reserved] 3.3.6Relative Accuracy for Moisture Monitoring Systems

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 H2O) and the corresponding moisture monitoring system measurements (in percent H2O), calculated using Equation A-7 of this appendix, are within ±1.5 percent H2O.

3.3.7Relative Accuracy for NOX Concentration Monitoring Systems

(a) The following requirement applies only to NOX concentration monitoring systems (i.e., NOX pollutant concentration monitors) that are used to determine NOX mass emissions, where the owner or operator elects to monitor and report NOX mass emissions using a NOX concentration monitoring system and a flow monitoring system.

(b) The relative accuracy for NOX concentration monitoring systems shall not exceed 10.0 percent. Alternatively, for affected units where the average of the monitoring system measurements of NOX concentration during the relative accuracy test audit is less than or equal to 250.0 ppm, the mean value of the continuous emission monitoring system measurements shall not exceed ±15.0 ppm of the reference method mean value.

3.4Bias 3.4.1SO2 Pollutant Concentration Monitors, NOX Concentration Monitoring Systems and NOX-Diluent Continuous Emission Monitoring Systems

SO2 pollutant concentration monitors, NOX-diluent continuous emission monitoring systems and NOX concentration monitoring systems used to determine NOX mass emissions, as defined in § 75.71(a)(2), shall not be biased low as determined by the test procedure in section 7.6 of this appendix. The bias specification applies to all SO2 pollutant concentration monitors and to all NOX concentration monitoring systems, including those measuring an average SO2 or NOX concentration of 250.0 ppm or less, and to all NOX-diluent continuous emission monitoring systems, including those measuring an average NOX emission rate of 0.200 lb/mmBtu or less.

3.4.2Flow Monitors

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.

3.5Cycle Time

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.

4. Data Acquisition and Handling Systems

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 NOx emission rate data; and all missing data procedure statistics specified in subpart D of this part.

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 SO2, lb/mmBtu of NOX);

(4) Predict and record NOX emission rate using the heat input rate and the NOX/heat input correlation developed under appendix E of this part;

(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.

5. Calibration Gas 5.1Reference Gases

For the purposes of part 75, calibration gases include the following:

5.1.1Standard Reference Materials (SRM)

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.

5.1.2SRM-Equivalent Compressed Gas Primary Reference Material (PRM)

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.

5.1.3NIST Traceable Reference Materials

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.

5.1.4EPA Protocol 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.

5.1.5Research Gas Mixtures

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.

5.1.6Zero Air Material

Zero air material is defined in § 72.2 of this chapter.

5.1.7NIST/EPA-Approved Certified Reference Materials

Existing certified reference materials (CRMs) that are still within their certification period may be used as calibration gas.

5.1.8Gas Manufacturer's Intermediate Standards

Gas manufacturer's intermediate standards is defined in § 72.2 of this chapter.

5.2Concentrations

Four concentration levels are required as follows.

5.2.1Zero-level Concentration

0.0 to 20.0 percent of span, including span for high-scale or both low- and high-scale for SO2, NOX, CO2, and O2 monitors, as appropriate.

5.2.2Low-level Concentration

20.0 to 30.0 percent of span, including span for high-scale or both low- and high-scale for SO2, NOX, CO2, and O2 monitors, as appropriate.

5.2.3Mid-level Concentration

50.0 to 60.0 percent of span, including span for high-scale or both low- and high-scale for SO2, NOX, CO2, and O2 monitors, as appropriate.

5.2.4High-level Concentration

80.0 to 100.0 percent of span, including span for high-scale or both low-and high-scale for SO2, NOX, CO2, and O2 monitors, as appropriate.

6. Certification Tests and Procedures 6.1Pretest Preparation

Install the components of the continuous emission monitoring system (i.e., pollutant concentration monitors, CO2 or O2 monitor, and flow monitor) as specified in sections 1, 2, and 3 of this appendix, and prepare each system component and the combined system for operation in accordance with the manufacturer's written instructions. Operate the unit(s) during each period when measurements are made. Units may be tested on non-consecutive days. To the extent practicable, test the DAHS software prior to testing the monitoring hardware.

6.2Linearity Check (General Procedures)

Check the linearity of each SO2, NOX, CO2, and O2 monitor while the unit, or group of units for a common stack, is combusting fuel at conditions of typical stack temperature and pressure; it is not necessary for the unit to be generating electricity during this test. Notwithstanding these requirements, if the SO2 or NOX span value for a particular monitor range is ≤30 ppm, that range is exempted from the linearity test requirements of this part. For units using emission controls and other units using both a high and a low span, perform a linearity check on both the low- and high-scales for initial certification. For on-going quality assurance of the CEMS, perform linearity checks, using the procedures in this section, on the range(s) and at the frequency specified in section 2.2.1 of appendix B to this part. Challenge each monitor with calibration gas, as defined in section 5.1 of this appendix, at the low-, mid-, and high-range concentrations specified in section 5.2 of this appendix. Introduce the calibration gas at the gas injection port, as specified in section 2.2.1 of this appendix. Operate each monitor at its normal operating temperature and conditions. For extractive and dilution type monitors, pass the calibration gas through all filters, scrubbers, conditioners, and other monitor components used during normal sampling and through as much of the sampling probe as is practical. For in-situ type monitors, perform calibration checking all active electronic and optical components, including the transmitter, receiver, and analyzer. Challenge the monitor three times with each reference gas (see example data sheet in Figure 1). Do not use the same gas twice in succession. To the extent practicable, the duration of each linearity test, from the hour of the first injection to the hour of the last injection, shall not exceed 24 unit operating hours. Record the monitor response from the data acquisition and handling system. For each concentration, use the average of the responses to determine the error in linearity using Equation A-4 in this appendix. Linearity checks are acceptable for monitor or monitoring system certification, recertification, or quality assurance if none of the test results exceed the applicable performance specifications in section 3.2 of this appendix. The status of emission data from a CEMS prior to and during a linearity test period shall be determined as follows:

(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.

6.37-Day Calibration Error Test 6.3.1Gas Monitor 7-day Calibration Error Test

Measure the calibration error of each SO2 monitor, each NOX monitor and each CO2 or O2 monitor while the unit is combusting fuel (but not necessarily generating electricity) once each day for 7 consecutive operating days according to the following procedures. (In the event that extended unit outages occur after the commencement of the test, the 7 consecutive unit operating days need not be 7 consecutive calendar days.) Units using dual span monitors must perform the calibration error test on both high- and low-scales of the pollutant concentration monitor. The calibration error test procedures in this section and in section 6.3.2 of this appendix shall also be used to perform the daily assessments and additional calibration error tests required under sections 2.1.1 and 2.1.3 of appendix B to this part. Do not make manual or automatic adjustments to the monitor settings until after taking measurements at both zero and high concentration levels for that day during the 7-day test. If automatic adjustments are made following both injections, conduct the calibration error test such that the magnitude of the adjustments can be determined and recorded. Record and report test results for each day using the unadjusted concentration measured in the calibration error test prior to making any manual or automatic adjustments (i.e., resetting the calibration). The calibration error tests should be approximately 24 hours apart, (unless the 7-day test is performed over non-consecutive days). Perform calibration error tests at both the zero-level concentration and high-level concentration, as specified in section 5.2 of this appendix. Alternatively, a mid-level concentration gas (50.0 to 60.0 percent of the span value) may be used in lieu of the high-level gas, provided that the mid-level gas is more representative of the actual stack gas concentrations. In addition, repeat the procedure for SO2 and NOX pollutant concentration monitors using the low-scale for units equipped with emission controls or other units with dual span monitors. Use only calibration gas, as specified in section 5.1 of this appendix. Introduce the calibration gas at the gas injection port, as specified in section 2.2.1 of this appendix. Operate each monitor in its normal sampling mode. For extractive and dilution type monitors, pass the calibration gas through all filters, scrubbers, conditioners, and other monitor components used during normal sampling and through as much of the sampling probe as is practical. For in-situ type monitors, perform calibration, checking all active electronic and optical components, including the transmitter, receiver, and analyzer. Challenge the pollutant concentration monitors and CO2 or O2 monitors once with each calibration gas. Record the monitor response from the data acquisition and handling system. Using Equation A-5 of this appendix, determine the calibration error at each concentration once each day (at approximately 24-hour intervals) for 7 consecutive days according to the procedures given in this section. The results of a 7-day calibration error test are acceptable for monitor or monitoring system certification, recertification or diagnostic testing if none of these daily calibration error test results exceed the applicable performance specifications in section 3.1 of this appendix.The status of emission data from a gas 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).

6.3.2Flow Monitor 7-day Calibration Error Test

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:

(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).

6.4Cycle Time Test

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 5 at the end of this appendix.) For the NOx-diluent continuous emission monitoring system test and SO2-diluent continuous emission monitoring system test, record and report the longer cycle time of the two component analyzers as the system cycle time. For time-shared systems, this procedure must be done at all probe locations that will be polled within the same 15-minute period during monitoring system operations. To determine the cycle time for time-shared systems, add together the longest cycle time obtained at each of the probe locations. Report the sum of the longest cycle time at each of the probe locations plus the sum of the time required for all purge cycles (as determined by the continuous emission monitoring system manufacturer) at each of the probe locations as the cycle time for each of the time-shared systems. For monitors with dual ranges, report the test results from on the range giving the longer cycle time. Cycle time test results are acceptable for monitor or monitoring system certification, recertification or diagnostic testing if none of the cycle times exceed 15 minutes. The status of emissions data from a monitor prior to and during a cycle time test period shall be determined as follows:

(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).

6.5Relative Accuracy and Bias Tests (General Procedures)

Perform the required relative accuracy test audits (RATAs) as follows for each CO2 pollutant concentration monitor (including O2 monitors used to determine CO2 pollutant concentration), each SO2 pollutant concentration monitor, each NOX concentration monitoring system used to determine NOX mass emissions, each flow monitor, each NOX-diluent continuous emission monitoring system, each O2 or CO2 diluent monitor used to calculate heat input, each moisture monitoring system and each SO2-diluent continuous emission monitoring system. For NOX concentration monitoring systems used to determine NOX mass emissions, as defined in § 75.71(a)(2), use the same general RATA procedures as for SO2 pollutant concentration monitors; however, use the reference methods for NOX concentration specified in section 6.5.10 of this appendix:

(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 SO2 or NOx controls or for units that need a dual range to record high concentration “spikes” during startup conditions, the low range is considered normal. However, for some dual span units (e.g., for units that use fuel switching or for which the emission controls are operated seasonally), either of the two measurement ranges may be considered normal; in such cases, perform the RATA on the range that is in use at the time of the scheduled test.

(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 specified in § 75.20(b)(3)(iv) for the individual tests.

(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 SO2 or CO2 pollutant concentration monitor, each flow monitor, each CO2 or O2 diluent monitor used to determine heat input, each NOX concentration monitoring system used to determine NOX mass emissions, as defined in § 75.71(a)(2), each moisture monitoring system and each NOX-diluent continuous emission monitoring system, calculate the relative accuracy, in accordance with section 7.3 or 7.4 of this appendix, as applicable. In addition (except for CO2, O2, SO2-diluent or moisture monitors), test for bias and determine the appropriate bias adjustment factor, in accordance with sections 7.6.4 and 7.6.5 of this appendix, using the data from the relative accuracy test audits.

6.5.1Gas Monitoring System RATAs (Special Considerations)

(a) Perform the required relative accuracy test audits for each SO2 or CO2 pollutant concentration monitor, each CO2 or O2 diluent monitor used to determine heat input, each NOX-diluent continuous emission monitoring system, each NOX concentration monitoring system used to determine NOX mass emissions, as defined in § 75.71(a)(2), and each SO2-diluent continuous emission monitoring system, at the normal load level for the unit (or combined units, if common stack), as defined in section 6.5.2.1 of this appendix. If two load levels have been designated as normal, the RATAs may be done at either load level.

(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.

6.5.2Flow Monitor RATAs (Special Considerations)

(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.

6.5.2.1Range of Operation and Normal Load Level(s)

(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 quarters of representative historical operating data. For common stacks, the maximum sustainable load is the sum of all of the maximum sustainable loads of the individual units discharging through the stack, unless this load is unattainable in practice, in which case use the highest sustainable combined load for the units that discharge through the stack, based on at least four quarters of representative historical operating data. The load values for the unit(s) shall be expressed either in units of megawatts or thousands of lb/hr of steam load.

(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..

6.5.2.2Multi-Load Flow RATA Results

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.

6.5.3CO 2 Pollutant Concentration Monitors

Perform relative accuracy test audits for each CO2 monitor (measuring in percent CO2) at a normal operating level for the unit (or combined units, if common stack).

6.5.4Calculations

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.

6.5.5Reference Method Measurement Location

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 SO2 and NOX continuous emission monitoring systems, Performance Specification 3 in appendix B of part 60 of this chapter for CO2 or O2 monitors, or method 1 (or 1A) in appendix A of part 60 of this chapter for volumetric flow, except as otherwise indicated in this section or as approved by the Administrator.

6.5.6Reference Method Traverse Point Selection

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 SO2, NOX, and moisture monitoring system RATAs), Performance Specification 3 in appendix B to part 60 of this chapter (for O2 and CO2 monitor RATAs), Method 1 (or 1A) (for volumetric flow rate monitor RATAs), Method 3 (for molecular weight), and Method 4 (for moisture determination) in appendix A to part 60 of this chapter. Unless otherwise specified, use only codified versions of PS No. 2 revised as of July 1, 1995, July 1, 1996 or July 1, 1997. The following alternative reference method traverse point locations are permitted for moisture and gas monitor RATAs:

(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).

6.5.6.1Stratification Test

(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 (±3.0 percent) during the traverse and if the reference method analyzers have passed all of the required quality assurance checks, proceed with the data analysis.

(e) Calculate the average NOX, SO2, and CO2 (or O2) concentrations at each of the individual traverse points. Then, calculate the arithmetic average NOX, SO2, and CO2 (or O2) concentrations for all traverse points.

6.5.6.2Alternative (Abbreviated) Stratification Test

(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 (SO2 or NOX) and diluent (CO2 or O2) concentrations at three points. The points shall be located according to the specifications for the long measurement line in section 3.2 of PS No. 2 (i.e., locate the points 16.7 percent, 50.0 percent, and 83.3 percent of the way across the stack). Alternatively, the concentration measurements may be made at six traverse points along a diameter. The six points shall be located in accordance with Method 1 in appendix A to part 60 of this chapter.

(c) Measure for a minimum of 2 minutes at each traverse point. To the extent practicable, complete the traverse within a 1-hour period.

6.5.6.3Stratification Test Results and Acceptance Criteria

(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 ±10.0 percent from the arithmetic average concentration for all traverse points. The results are also acceptable if the concentration at each individual traverse point differs by no more than ± 5ppm or ±0.5 percent CO2 (or O2) from the arithmetic average concentration for all traverse points.

(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 ±5.0 percent from the arithmetic average concentration for all traverse points. The results are also acceptable if the concentration at each individual traverse point differs by no more than ±3 ppm or ±0.3 percent CO2 (or O2) from the arithmetic average concentration for all traverse points.

(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.

6.5.7Sampling Strategy

(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, CO2 or O2 monitor, flow monitor, and SO2 or NOX continuous emission monitoring system measurements. The minimum acceptable time for a gas monitoring system RATA run or for a moisture monitoring system RATA run is 21 minutes. For each run of a gas monitoring system RATA, all necessary pollutant concentration measurements, diluent concentration measurements, and moisture measurements (if applicable) must, to the extent practicable, be made within a 60-minute period. For NOX-diluent or SO2-diluent monitoring system RATAs, the pollutant and diluent concentration measurements must be made simultaneously. For flow monitor RATAs, the minimum time per run shall be 5 minutes. Flow rate reference method measurements may be made either sequentially from port to port or simultaneously at two or more sample ports. The velocity measurement probe may be moved from traverse point to traverse point either manually or automatically. If, during a flow RATA, significant pulsations in the reference method readings are observed, be sure to allow enough measurement time at each traverse point to obtain an accurate average reading when a manual readout method is used (e.g., a “sight-weighted” average from a manometer). A minimum of one set of auxiliary measurements for stack gas molecular weight determination (i.e., diluent gas data and moisture data) is required for every clock hour of a flow RATA or for every three test runs (whichever is less restrictive). Successive flow RATA runs may be performed without waiting in-between runs. If an O2-diluent monitor is used as a CO2 continuous emission monitoring system, perform a CO2 system RATA (i.e., measure CO2, rather than O2, with the reference method). For moisture monitoring systems, an appropriate coefficient, “K” factor or other suitable mathematical algorithm may be developed prior to the RATA, to adjust the monitoring system readings with respect to the reference method. If such a coefficient, K-factor or algorithm is developed, it shall be applied to the CEMS readings during the RATA and (if the RATA is passed), to the subsequent CEMS data, by means of the automated data acquisition and handling system. The owner or operator shall keep records of the current coefficient, K factor or algorithm, as specified in §§ 75.56(a)(5)(ix) and 75.59(a)(5)(vii). Whenever the coefficient, K factor or algorithm is changed, a RATA of the moisture monitoring system is required.

(b) To properly correlate individual SO2 or NOX continuous emission monitoring system data (in lb/mmBtu) and volumetric flow rate data with the reference method data, annotate the beginning and end of each reference method test run (including the exact time of day) on the individual chart recorder(s) or other permanent recording device(s).

6.5.8Correlation of Reference Method and Continuous Emission Monitoring System

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 CO2, lb/mmBtu, or other units) against the corresponding reference method values. Tabulate the paired data in a table such as the one shown in Figure 2.

6.5.9Number of Reference Method Tests

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.

Note:

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.

6.5.10Reference Methods

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 O2 or CO2; Method 4 for moisture; Methods 6, 6A, or 6C for SO2; Methods 7, 7A, 7C, 7D or 7E for NOX, excluding the exception in section 5.1.2 of Method 7E. When using Method 7E for measuring NOX concentration, total NOX, both NO and NO2, must be measured.

7. Calculations 7.1Linearity Check

Analyze the linearity data for pollutant concentration and CO2 or O2 monitors as follows. Calculate the percentage error in linearity based upon the reference value at the low-level, mid-level, and high-level concentrations specified in section 6.2 of this appendix. Perform this calculation once during the certification test. Use the following equation to calculate the error in linearity for each reference value.

EC01SE92.114

(Eq. A-4) where, LE = Percentage Linearity error, based upon the reference value. R = Reference value of Low-, mid-, or high-level calibration gas introduced into the monitoring system. A = Average of the monitoring system responses. 7.2Calibration Error 7.2.1Pollutant Concentration and Diluent Monitors

For each reference value, calculate the percentage calibration error based upon instrument span for daily calibration error tests using the following equation:

EC01SE92.115

(Eq. A-5) where, CE = Calibration error as a percentage of the span of the instrument. R = Reference value of zero or upscale (high-level or mid-level, as applicable) calibration gas introduced into the monitoring system. A = Actual monitoring system response to the calibration gas. S = Span of the instrument, as specified in section 2 of this appendix. 7.2.2Flow Monitor Calibration Error

For each reference value, calculate the percentage calibration error based upon span using the following equation:

ER17MY95.007

where: CE = Calibration error as a percentage of span. R = Low or high level reference value specified in section 2.2.2.1 of this appendix. A = Actual flow monitor response to the reference value. S = Flow monitor calibration span value as determined under section 2.1.4.2 of this appendix. 7.3Relative Accuracy for SO2 and CO2 Pollutant Concentration Monitors, SO2-Diluent Continuous Emission Monitoring Systems, and Flow Monitors

Analyze the relative accuracy test audit data from the reference method tests for SO2 and CO2 pollutant concentration monitors, SO2-diluent continuous emission monitoring systems (lb/mmBtu) used by units with a qualifying Phase I technology for the period during which the units are required to monitor SO2 emission removal efficiency, from January 1, 1997 through December 31, 1999, and flow monitors using the following procedures. Summarize the results on a data sheet. An example is shown in Figure 2. Calculate the mean of the monitor or monitoring system measurement values. Calculate the mean of the reference method values. Using data from the automated data acquisition and handling system, calculate the arithmetic differences between the reference method and monitor measurement data sets. Then calculate the arithmetic mean of the difference, the standard deviation, the confidence coefficient, and the monitor or monitoring system relative accuracy using the following procedures and equations.

7.3.1Arithmetic Mean

Calculate the arithmetic mean of the differences, d, of a data set as follows.

EC01SE92.116

(Eq. A-7) where, n = Number of data points. n Σdi = Algebraic sum of the i=1individual differences di. di = The difference between a reference method value and the corresponding continuous emission monitoring system value (RMi-CEMi) at a given point in time i.

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.

7.3.2Standard Deviation

Calculate the standard deviation, Sd, of a data set as follows:

EC01SE92.117

(Eq. A-8) 7.3.3Confidence Coefficient

Calculate the confidence coefficient (one-tailed), cc, of a data set as follows.

EC01SE92.118

(eq. A-9) where, t0.025 = t value (see table 7-1). Table 7-1—t-Values n-1 t0.025 n-1 t0.025 n-1 t0.025 1 12.706 12 2.179 23 2.069 2 4.303 13 2.160 24 2.064 3 3.182 14 2.145 25 2.060 4 2.776 15 2.131 26 2.056 5 2.571 16 2.120 27 2.052 6 2.447 17 2.110 28 2.048 7 2.365 18 2.101 29 2.045 8 2.306 19 2.093 30 2.042 9 2.262 20 2.086 40 2.021 10 2.228 21 2.080 60 2.000 11 2.201 22 2.074 >60 1.960 7.3.4Relative Accuracy

Calculate the relative accuracy of a data set using the following equation.

EC01SE92.119

(Eq. A-10) where, RM = Arithmetic mean of the reference method values. |d | = The absolute value of the mean difference between the reference method values and the corresponding continuous emission monitoring system values. |cc| = The absolute value of the confidence coefficient. 7.4Relative Accuracy for NOx Continuous Emission Monitoring Systems

Analyze the relative accuracy test audit data from the reference method tests for NOx continuous emissions monitoring system as follows.

7.4.1 Data Preparation

If CNOx, the NOx concentration, is in ppm, multiply it by 1.194 × 10−7 (lb/dscf)/ppm to convert it to units of lb/dscf. If CNOx is in mg/dscm, multiply it by 6.24 × 10−8 (lb/dscf)/(mg/dscm) to convert it to lb/dscf. Then, use the diluent (O2 or CO2) reference method results for the run and the appropriate F or Fc factor from table 1 in appendix F of this part to convert CNOx from lb/dscf to lb/mmBtu units. Use the equations and procedure in section 3 of appendix F to this part, as appropriate.

7.4.2NO x Emission Rate (Monitoring System)

For each test run in a data set, calculate the average NOx emission rate (in lb/mmBtu), by means of the data acquisition and handling system, during the time period of the test run. Tabulate the results as shown in example Figure 4.

7.4.3Relative Accuracy

Use the equations and procedures in section 7.3 above to calculate the relative accuracy for the NOx continuous emission monitoring system. In using equation A-7, “d” is, for each run, the difference between the NOx emission rate values (in lb/mmBtu) obtained from the reference method data and the NOx continuous emission monitoring system.

7.5Relative Accuracy for Combined SO2/Flow [Reserved] 7.6Bias Test and Adjustment Factor

Test the following relative accuracy test audit data sets for bias: SO2 pollutant concentration monitors; flow monitors; NOX concentration monitoring systems used to determine NOX mass emissions, as defined in § 75.71(a)(2); and NOX-diluent continuous emission monitoring systems, using the procedures outlined in section 7.6.1 through 7.6.5 of this appendix. For multiple-load flow RATAs, perform a bias test at each load level designated as normal under section 6.5.2.1 of this appendix.

7.6.1Arithmetic Mean

Calculate the arithmetic mean of the difference, d, of the data set using equation A-7 of this appendix. To calculate bias for an SO2 pollutant concentration monitor, “d” is, for each paired data point, the difference between the SO2 concentration value (in ppm) obtained from the reference method and the monitor. To calculate bias for a flow monitor, “d” is, for each paired data point, the difference between the flow rate values (in scfh) obtained from the reference method and the monitor. To calculate bias for a NOX continuous emission monitoring system, “d” is, for each paired data point, the difference between the NOX emission rate values (in lb/mmBtu) obtained from the reference method and the monitoring system.

7.6.2Standard Deviation

Calculate the standard deviation, Sd, of the data set using equation A-8.

7.6.3Confidence Coefficient

Calculate the confidence coefficient, cc, of the data set using equation A-9.

7.6.4Bias Test

If, for the relative accuracy test audit data set being tested, the mean difference, d, is less than or equal to the absolute value of the confidence coefficient, √ cc √, the monitor or monitoring system has passed the bias test. If the mean difference, d, is greater than the absolute value of the confidence coefficient, √ cc √, the monitor or monitoring system has failed to meet the bias test requirement.

7.6.5Bias Adjustment

(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:

ER26MY99.005 Where: CEMi Monitor = Data (measurement) provided by the monitor at time i. CEMi Adjusted = Data value, adjusted for bias, at time i. BAF = Bias adjustment factor, defined by: ER26MY99.006 Where: BAF = Bias adjustment factor, calculated to the nearest thousandth. d = Arithmetic mean of the difference obtained during the failed bias test using Equation A-7. CEMavg = Mean of the data values provided by the monitor during the failed bias test.

(b) For single-load RATAs of SO2 pollutant concentration monitors, NOX concentration monitoring systems, and NOX-diluent monitoring systems and for the single-load flow RATAs required or allowed under section 6.5.2 of this appendix and sections 2.3.1.3(b) and 2.3.1.3(c) of appendix B to this part, the appropriate BAF is determined directly from the RATA results at normal load, using Equation A-12. Notwithstanding, when a NOX concentration CEMS or an SO2 CEMS or a NOX-diluent CEMS installed on a low-emitting affected unit (i.e., average SO2 or NOX concentration during the RATA ≤ 250 ppm or average NOX emission rate ≤ 0.200 lb/mmBtu) meets the normal 10.0 percent relative accuracy specification (as calculated using Equation A-10) or the alternate relative accuracy specification in section 3.3 of this appendix for low-emitters, but fails the bias test, the BAF may either be determined using Equation A-12, or a default BAF of 1.111 may be used.

(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 SO2, the flow rate, the average NOX emission rate, the unit heat input, and the calculated mass emissions of SO2 and CO2 during the quarter and calendar year, as specified in subpart G of this part. In addition, when using a NOX concentration monitoring system and a flow monitor to calculate NOX mass emissions under subpart H of this part, use bias-adjusted values for NOX concentration and flow rate in the mass emission calculations and use bias-adjusted NOX concentrations to compute the appropriate substitution values for NOX concentration in the missing data routines under subpart D of this part.

7.7Reference Flow-to-Load Ratio or Gross Heat Rate

(a) Except as provided in section 7.8 of this appendix, the owner or operator shall determine Rref, the reference value of the ratio of flow rate to unit load, each time that a passing flow RATA is performed at a load level designated as normal in section 6.5.2.1 of this appendix. The owner or operator shall report the current value of Rref in the electronic quarterly report required under § 75.64 and shall also report the completion date of the associated RATA. If two load levels have been designated as normal under section 6.5.2.1 of this appendix, the owner or operator shall determine a separate Rref value for each of the normal load levels. The requirements of this section shall become effective as of April 1, 2000. The reference flow-to-load ratio shall be calculated as follows:

ER26MY99.007 Where: Rref = Reference value of the flow-to-load ratio, from the most recent normal-load flow RATA, scfh/megawatts or scfh/1000 lb/hr of steam. Qref = Average stack gas volumetric flow rate measured by the reference method during the normal-load RATA, scfh. Lavg = Average unit load during the normal-load flow RATA, megawatts or 1000 lb/hr of steam.

(b) In Equation A-13, for a common stack, Lavg shall be the sum of the operating loads of all units that discharge through the stack. For a unit that discharges its emissions through multiple stacks (except for a discharge configuration consisting of a main stack and a bypass stack), Qref will be the sum of the total volumetric flow rates that discharge through all of the stacks. For a unit with a multiple stack discharge configuration consisting of a main stack and a bypass stack (e.g., a unit with a wet SO2 scrubber), determine Qref separately for each stack at the time of the normal load flow RATA. Round off the value of Rref to two decimal places.

(c) In addition to determining Rref or as an alternative to determining Rref, a reference value of the gross heat rate (GHR) may be determined. In order to use this option, quality assured diluent gas (CO2 or O2) must be available for each hour of the most recent normal-load flow RATA. The reference value of the GHR shall be determined as follows:

ER26MY99.008 Where: (GHR)ref = Reference value of the gross heat rate at the time of the most recent normal-load flow RATA, Btu/kwh or Btu/lb steam load. (Heat Input)avg = Average hourly heat input during the normal-load flow RATA, as determined using the applicable equation in appendix F to this part, mmBtu/hr. Lavg = Average unit load during the normal-load flow RATA, megawatts or 1000 lb/hr of steam.

(d) In the calculation of (Heat Input)avg, use Qref, the average volumetric flow rate measured by the reference method during the RATA, and use the average diluent gas concentration measured during the flow RATA.

7.8Flow-to-Load Test Exemptions

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.

Figure 1 To Appendix A—Linearity Error Determination Day Date and time Reference value Monitor value Difference Percent of reference value Low-level: Mid-level: High-level: Figure 2 to Appendix A—Relative Accuracy Determination (Pollutant Concentration Monitors) Run No. Date and time SO2 (ppmc) RMa Mb Diff Date and time CO2 (Pollutant) (ppmc) RMa Mb Diff 1 2 3 4 5 6 7 8 9 10 11 12 Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative Accuracy (Eq. A-10). a RM means “reference method data.” b M means “monitor data.” c Make sure the RM and M data are on a consistent basis, either wet or dry. Figure 3 to Appendix A—Relative Accuracy Determination (Flow Monitors) Run No. Date and time Flow rate (Low) (scf/hr)* RM M Diff Date and time Flow rate (Normal) (scf/hr)* RM M Diff Date and time Flow rate (High) (scf/hr)* RM M Diff 1 2 3 4 5 6 7 8 9 10 11 12 Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative Accuracy (Eq. A-10). * Make sure the RM and M data are on a consistent basis, either wet or dry. Figure 4 to Appendix A—Relative Accuracy Determination (NOX/Diluent Combined System) Run No. Date and time Reference method data NOX()a O2/CO2% NOX system (lb/mmBtu) RM M Difference 1 2 3 4 5 6 7 8 9 10 11 12 Arithmetic Mean Difference (Eq. A-7). Confidence Coefficient (Eq. A-9). Relative Accuracy (Eq. A-10). a Specify units: ppm, lb/dscf, mg/dscm. Figure 5—Cycle Time Date of test Component/system ID#: Analyzer type Serial Number High level gas concentration: ___ ppm/% (circle one) Zero level gas concentration: ___ ppm/% (circle one) Analyzer span setting: ___ ppm/% (circle one) Upscale: Stable starting monitor value: ___ ppm/% (circle one) Stable ending monitor reading: ___ ppm/% (circle one) Elapsed time: ___ seconds Downscale: Stable starting monitor value: ___ ppm/% (circle one) Stable ending monitor value: ___ ppm/% (circle one) Elapsed time: ___ seconds Component cycle time= ___ seconds System cycle time= ___ seconds ER20NO96.000

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 flue gas emissions until the response stabilizes.

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.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26541-26546, 26569-26570, May 17, 1995; 61 FR 25582, May 22, 1996; 61 FR 59162, Nov. 20, 1996; 63 FR 57512, Oct. 27, 1998; 64 FR 28631-28643, May 26, 1999; 64 FR 37582, July 12, 1999] Pt. 75, App. B Appendix B to Part 75—Quality Assurance and Quality Control Procedures 1. Quality Assurance/Quality Control Program

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.

1.1Requirements for All Monitoring Systems 1.1.1Preventive Maintenance

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.

1.1.2Recordkeeping and Reporting

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.

1.1.3Maintenance Records

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.

1.2Specific Requirements for Continuous Emissions Monitoring Systems 1.2.1 Calibration Error Test and Linearity Check Procedures

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.

1.2.2Calibration and Linearity Adjustments

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.

1.2.3Relative Accuracy Test Audit Procedures

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.

1.2.4Parametric Monitoring for Units With Add-on Emission Controls

The owner or operator shall keep a written (or electronic) record including a list of operating parameters for the add-on SO2 or NOX emission controls, including parameters in § 75.55(b) or § 75.58(b), as applicable, and the range of each operating parameter that indicates the add-on emission controls are operating properly. The owner or operator shall keep a written (or electronic) record of the parametric monitoring data during each SO2 or NOX missing data period.

1.3Specific Requirements for Excepted Systems Approved Under Appendices D and E 1.3.1Fuel Flowmeter Accuracy Test Procedures

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).

1.3.2Transducer or Transmitter Accuracy Test Procedures

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.

1.3.3Fuel Flowmeter, Transducer, or Transmitter Calibration and Maintenance Records

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.

1.3.4Primary Element Inspection Procedures

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.

1.3.5Fuel Sampling Method and Sample Retention

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).

1.3.6Appendix E Monitoring System Quality Assurance Information

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 NOX emission rate testing. Keep a copy of all data and results from the initial and from the most recent NOX emission rate testing, including the values of quality assurance parameters specified in section 2.3 of appendix E to this part.

1.4Requirements for Alternative Systems Approved Under Subpart E 1.4.1Daily Quality Assurance Tests

Explain how the daily assessment procedures specific to the alternative monitoring system are to be performed.

1.4.2Daily Quality Assurance Test Adjustments

Explain how each component of the alternative monitoring system will be adjusted in response to the results of the daily assessments.

1.4.3Relative Accuracy Test Audit Procedures

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.

2. Frequency of Testing

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.

2.1Daily Assessments

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.

2.1.1Calibration Error Test

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 O2 analyzers) according to the procedures in section 6.3.1 of appendix A to this part, and perform the daily calibration error test of each flow monitoring system according to the procedure in section 6.3.2 of appendix A to this part.

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.

2.1.1.1 On-line Daily Calibration Error Tests. Except as provided in section 2.1.1.2 of this appendix, all daily calibration error tests must be performed while the unit is in operation at normal, stable conditions (i.e. “on-line”).

2.1.1.2 Off-line Daily Calibration Error Tests. Daily calibrations may be performed while the unit is not operating (i.e., “off-line”) and may be used to validate data for a monitoring system that meets the following conditions:

(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.

2.1.2Daily Flow Interference Check

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.

2.1.3Additional Calibration Error Tests and Calibration Adjustments

(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 record emissions data; or after making certain calibration adjustments, as described in this section. Except in the case of the routine calibration adjustments described in this section, data from the monitor are considered invalid until the required additional calibration error test has been successfully completed.

(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, CO2 or O2 monitor, or flow monitor.

(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.

2.1.4Data Validation

(a) An out-of-control period occurs when the calibration error of an SO2 or NOX pollutant concentration monitor exceeds 5.0 percent of the span value (or exceeds 10 ppm, for span values <200 ppm), when the calibration error of a CO2 or O2 monitor (including O2 monitors used to measure CO2 emissions or percent moisture) exceeds 1.0 percent O2 or CO2, or when the calibration error of a flow monitor or a moisture sensor exceeds 6.0 percent of the span value, which is twice the applicable specification of appendix A to this part. Notwithstanding, a differential pressure-type flow monitor for which the calibration error exceeds 6.0 percent of the span value shall not be considered out-of-control if uR−Au, the absolute value of the difference between the monitor response and the reference value in Equation A-6, is ≤0.02 inches of water. The out-of-control period begins upon failure of the calibration error test and ends upon completion of a successful calibration error test. Note, that if a failed calibration, corrective action, and successful calibration error test occur within the same hour, emission data for that hour recorded by the monitor after the successful calibration error test may be used for reporting purposes, provided that two or more valid readings are obtained as required by § 75.10. A NOX-diluent continuous emission monitoring system is considered out-of-control if the calibration error of either component monitor exceeds twice the applicable performance specification in appendix A to this part. Emission data shall not be reported from an out-of-control monitor.

(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.

2.1.5Quality Assurance of Data With Respect to Daily Assessments

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.

2.1.5.1 Data Invalidation with Respect to Daily Assessments. The following specific rules apply to the invalidation of data with respect to daily assessments:

(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 validation, then data from that monitoring system are invalid, beginning with the 27th unit operating hour following that off-line calibration error test.

2.1.5.2 Daily Assessment Start-Up Grace Period. For the purpose of quality assuring data with respect to a daily assessment (i.e. a daily calibration error test or a flow interference check), a start-up grace period may apply when a unit begins to operate after a period of non-operation. The start-up grace period for a daily calibration error test is independent of the start-up grace period for a daily flow interference check. To qualify for a start-up grace period for a daily assessment, there are two requirements:

(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.

2.1.6Data Recording

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.

2.2Quarterly Assessments

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.

2.2.1Linearity Check

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 SO2 and NOX pollutant concentration monitor and each primary and redundant backup CO2 or O2 monitor (including O2 monitors used to measure CO2 emissions or to continuously monitor moisture) at least once during each QA operating quarter, as defined in § 72.2 of this chapter. For units using both a low and high span value, a linearity check is required only on the range(s) used to record and report emission data during the QA operating quarter. Conduct the linearity checks no less than 30 days apart, to the extent practicable. The data validation procedures in section 2.2.3(e) of this appendix shall be followed.

2.2.2Leak Check

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.

2.2.3Data Validation

(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-linearization or reprogramming of the monitor. Trial gas injection 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 linearity check, as necessary, to optimize the performance of the monitor. The trial gas injections need not be reported, provided that they meet the specification for trial gas injections in § 75.20(b)(3)(vii)(E)(1). However, if, for any trial injection, the specification in § 75.20(b)(3)(vii)(E)(1) is not met, the trial injection shall be counted as an aborted linearity check.

(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 NOX-diluent or SO2-diluent continuous emission monitoring system, the system is considered out-of-control if either of the component monitors exceeds the applicable specification in section 3.2 of appendix A to this part or if the linearity test of either component is aborted due to a problem with the monitor. The out-of-control period begins with the hour of the failed or aborted linearity check and ends with the hour of completion of a satisfactory linearity check following corrective action and/or monitor repair, 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 (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 monitor shall not be considered out-of-control when a linearity test is aborted for a reason unrelated to the monitor's performance (e.g., a forced unit outage).

(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.

2.2.4Linearity and Leak Check Grace Period

(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 system, four successive calendar quarters have elapsed after the quarter in which a linearity check of a monitor or monitoring system (or range) was last performed without a subsequent linearity test having been done, the owner or operator has a grace period of 168 consecutive unit operating hours, as defined in § 72.2 of this chapter (or, for monitors installed on common stacks or bypass stacks, 168 consecutive stack operating hours, as defined in § 72.2 of this chapter) in which to perform a linearity test or leak check of that monitor or monitoring system (or range). The grace period begins with the first unit or stack operating hour following the calendar quarter in which the linearity test was due. Data validation during a linearity or leak check grace period shall be done in accordance with the applicable provisions in section 2.2.3 of this appendix.

(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.

2.2.5Flow-to-Load Ratio or Gross Heat Rate Evaluation

(a) Applicability and methodology. The provisions of this section apply beginning on April 1, 2000. Unless exempted by an approved petition in accordance with section 7.8 of appendix A to this part, the owner or operator shall, for each flow rate monitoring system installed on each unit, common stack or multiple stack, evaluate the flow-to-load ratio quarterly, i.e., for each QA operating quarter (as defined in § 72.2 of this chapter). At the end of each QA operating quarter, the owner or operator shall use Equation B-1 to calculate the flow-to-load ratio for every hour during the quarter in which: the unit (or combination of units, for a common stack) operated within ±10.0 percent of Lavg, the average load during the most recent normal-load flow RATA; and a quality assured hourly average flow rate was obtained with a certified flow rate monitor.

ER26MY99.009 Where: Rh = Hourly value of the flow-to-load ratio, scfh/megawatts or scfh/1000 lb/hr of steam load. Qh = Hourly stack gas volumetric flow rate, as measured by the flow rate monitor, scfh. Lh = Hourly unit load, megawatts or 1000 lb/hr of steam; must be within ±10.0 percent of Lavg during the most recent normal-load flow RATA.

(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, Lh shall be the sum of the hourly operating loads of all units that discharge through the stack. For a unit that discharges its emissions through multiple stacks (except when one of the stacks is a bypass stack) or that monitors its emissions in multiple breechings, Qh will be the combined hourly volumetric flow rate for all of the stacks or ducts. For a unit with a multiple stack discharge configuration consisting of a main stack and a bypass stack, each of which has a certified flow monitor (e.g., a unit with a wet SO2 scrubber), calculate the hourly flow-to-load ratios separately for each stack. Round off each value of Rh to two decimal places.

(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 (CO2 or O2) concentration data are both available from a certified monitor or monitoring system or reference method. If this option is selected, calculate each hourly GHR value as follows:

ER26MY99.010 where: (GHR)h = Hourly value of the gross heat rate, Btu/kwh or Btu/lb steam load. (Heat Input)h = Hourly heat input, as determined from the quality assured flow rate and diluent data, using the applicable equation in appendix F to this part, mmBtu/hr. Lh = Hourly unit load, megawatts or 1000 lb/hr of steam; must be within ± 10.0 percent of Lavg during the most recent normal-load flow RATA.

(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)h, provided that all of the heat input values are determined in the same manner.

(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 Eh, the absolute percentage difference between each hourly Rh value and Rref, the reference value of the flow-to-load ratio, as determined in accordance with section 7.7 of appendix A to this part. Note that Rref shall always be based upon the most recent normal-load RATA, even if that RATA was performed in the calendar quarter being evaluated.

ER26MY99.011 where: Eh = Absolute percentage difference between the hourly average flow-to-load ratio and the reference value of the flow-to-load ratio at normal load. Rh = The hourly average flow-to-load ratio, for each flow rate recorded at a load level within # 10.0 percent of Lavg. Rref = The reference value of the flow-to-load ratio from the most recent normal-load flow RATA, determined in accordance with section 7.7 of appendix A to this part.

(6) Equation B-2 shall be used in a consistent manner. That is, use Rref and Rh if the flow-to-load ratio is being evaluated, and use (GHR)ref and (GHR)h if the gross heat rate is being evaluated. Finally, calculate Ef, the arithmetic average of all of the hourly Eh values. The owner or operator shall report the results of each quarterly flow-to-load (or gross heat rate) evaluation, as determined from Equation B-2, in the electronic quarterly report required under § 75.64.

(b) Acceptable results. The results of a quarterly flow-to-load (or gross heat rate) evaluation are acceptable, and no further action is required, if the calculated value of Ef is less than or equal to: (1) 15.0 percent, if Lavg for the most recent normal-load flow RATA is ≥60 megawatts (or ≥500 klb/hr of steam) and if unadjusted flow rates were used in the calculations; or (2) 10.0 percent, if Lavg for the most recent normal-load flow RATA is ≥60 megawatts (or ≥500 klb/hr of steam) and if bias-adjusted flow rates were used in the calculations; or (3) 20.0 percent, if Lavg for the most recent normal-load flow RATA is <60 megawatts (or <500 klb/hr of steam) and if unadjusted flow rates were used in the calculations; or (4) 15.0 percent, if Lavg for the most recent normal-load flow RATA is <60 megawatts (or <500 klb/hr of steam) and if bias-adjusted flow rates were used in the calculations. If Ef is above these limits, the owner or operator shall either: implement Option 1 in section 2.2.5.1 of this appendix; or perform a RATA in accordance with Option 2 in section 2.2.5.2 of this appendix; or re-examine the hourly data used for the flow-to-load or GHR analysis and recalculate Ef, after excluding all non-representative hourly flow rates.

(c) Recalculation of E f. If the owner or operator chooses to recalculate Ef, the flow rates for the following hours are considered non-representative and may be excluded from the data analysis:

(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 SO2 scrubber and which always discharges its flue gases to the atmosphere through a single stack, any hour in which the SO2 scrubber was bypassed;

(3) Any hour in which “ramping” occurred, i.e., the hourly load differed by more than ±15.0 percent from the load during the preceding hour or the subsequent hour;

(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, Ef meets the applicable limit in paragraph (b)(1), (b)(2), (b)(3), or (b)(4) of this section, no further action is required. If, however, Ef is still above the applicable limit, the monitor shall be declared out-of-control, beginning with the first hour of the quarter following the quarter in which Ef exceeded the applicable limit. The owner or operator shall then either implement Option 1 in section 2.2.5.1 of this appendix or Option 2 in section 2.2.5.2 of this appendix.

2.2.5.1Option 1

Within two weeks of the end of the calendar quarter for which the Ef value is above the applicable limit, investigate and troubleshoot the applicable flow monitor(s). Evaluate the results of each investigation as follows:

(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.

2.2.5.2Option 2

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 Ef is outside of the applicable limit. Data from the monitor remain invalid until the required RATA has been passed.

2.2.5.3Abbreviated Flow-to-Load Test

(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 exact conditions at the time of the most recent normal-load flow RATA. To achieve this, it is recommended that the load be held constant to within ±5.0 percent of the average load during the RATA and that the diluent gas (CO2 or O2) concentration be maintained within ±0.5 percent CO2 or O2 of the average diluent concentration during the RATA. For common stacks, to the extent practicable, use the same combination of units and load levels that were used during the RATA. When the process parameters have been set, record a minimum of six and a maximum of 12 consecutive hourly average flow rates, using the flow monitor(s) for which Ef was outside the applicable limit. For peaking units, a minimum of three and a maximum of 12 consecutive hourly average flow rates are required. Also record the corresponding hourly load values and, if applicable, the hourly diluent gas concentrations. Calculate the flow-to-load ratio (or GHR) for each hour in the test hour period, using Equation B-1 or B-1a. Determine Eh for each hourly flow-to-load ratio (or GHR), using Equation B-2 of this appendix and then calculate Ef, the arithmetic average of the Eh values.

(c) The results of the abbreviated flow-to-load test shall be considered acceptable, and no further action is required if the value of Ef does not exceed the applicable limit specified in section 2.2.5 of this appendix. All conditionally valid data recorded by the flow monitor shall be considered quality assured, beginning with the hour of the probationary calibration error test that preceded the abbreviated flow-to-load test. However, if Ef is outside the applicable limit, all conditionally valid data recorded by the flow monitor shall be considered invalid back to the hour of the probationary calibration error test that preceded the abbreviated flow-to-load test, and a single-load RATA is required in accordance with section 2.2.5.2 of this appendix. If the flow monitor must be re-linearized, however, a 3-load RATA is required.

2.3Semiannual and Annual Assessments

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.

2.3.1Relative Accuracy Test Audit (RATA) 2.3.1.1Standard RATA Frequencies

(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 SO2 pollutant concentration monitor, flow monitor, CO2 pollutant concentration monitor (including O2 monitors used to determine CO2 emissions), CO2 or O2 diluent monitor used to determine heat input, moisture monitoring system, NOX concentration monitoring system, NOX-diluent continuous emission monitoring system, or SO2-diluent continuous emission monitoring system. A calendar quarter that does not qualify as a QA operating quarter shall be excluded in determining the deadline for the next RATA. No more than eight successive calendar quarters shall elapse after the quarter in which a RATA was last performed without a subsequent RATA having been conducted. If a RATA has not been completed by the end of the eighth calendar quarter since the quarter of the last RATA, then the RATA must be completed within a 720 unit (or stack) operating hour grace period (as provided in section 2.3.3 of this appendix) following the end of the eighth successive elapsed calendar quarter, or data from the CEMS will become invalid.

(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.

2.3.1.2Reduced RATA Frequencies

Relative accuracy test audits of primary and redundant backup SO2 pollutant concentration monitors, CO2 pollutant concentration monitors (including O2 monitors used to determine CO2 emissions), CO2 or O2 diluent monitors used to determine heat input, moisture monitoring systems, NOX concentration monitoring systems, flow monitors, NOX-diluent monitoring systems or SO2-diluent monitoring systems may be performed annually (i.e., once every four successive QA operating quarters, rather than once every two successive QA operating quarters) if any of the following conditions are met for the specific monitoring system involved:

(a) The relative accuracy during the audit of an SO2 or CO2 pollutant concentration monitor (including an O2 pollutant monitor used to measure CO2 using the procedures in appendix F to this part), or of a CO2 or O2 diluent monitor used to determine heat input, or of a NOX concentration monitoring system, or of a NOX-diluent monitoring system, or of an SO2-diluent continuous emissions monitoring system is ≤ 7.5 percent;

(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 ± 1.5 fps of the reference method mean value, converted to an equivalent velocity in fps;

(e) For low SO2 or NOX emitting units (average SO2 or NOX concentrations ≤ 250 ppm, when an SO2 pollutant concentration monitor or NOX concentration monitoring system fails to achieve a relative accuracy ≤ 7.5 percent during the audit, but the monitor mean value from the RATA is within ± 12 ppm of the reference method mean value;

(f) For units with low NOX emission rates (average NOX emission rate ≤ 0.200 lb/mmBtu), when a NOX-diluent continuous emission monitoring system fails to achieve a relative accuracy ≤ 7.5 percent, but the monitoring system mean value from the RATA, calculated using Equation A-7 in appendix A to this part, is within ± 0.015 lb/mmBtu of the reference method mean value;

(g) For units with low SO2 emission rates (average SO2 emission rate ≤ 0.500 lb/mmBtu), when an SO2-diluent continuous emission monitoring system fails to achieve a relative accuracy ≤ 7.5 percent, but the monitoring system mean value from the RATA, calculated using Equation A-7 in appendix A to this part, is within ± 0.025 lb/mmBtu of the reference method mean value;

(h) For a CO2 or O2 monitor, when the mean difference between the reference method values from the RATA and the corresponding monitor values is within ± 0.7 percent CO2 or O2; and

(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 ± 1.0 percent H2O.

2.3.1.3RATA Load Levels and Additional RATA Requirements

(a) For SO2 pollutant concentration monitors, CO2 pollutant concentration monitors (including O2 monitors used to determine CO2 emissions), CO2 or O2 diluent monitors used to determine heat input, NOX concentration monitoring systems, moisture monitoring systems, SO2-diluent monitoring systems and NOX-diluent monitoring systems, the required semiannual or annual RATA tests shall be done at the load level designated as normal under section 6.5.2.1 of appendix A to this part. If two load levels are designated as normal, the required RATA(s) may be done at either load level.

(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.

(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.

2.3.1.4Number of RATA Attempts

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.

2.3.2Data Validation

(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)(2). However, if, for any trial run, the specification in § 75.20(b)(3)(vii)(E)(2) is not met, the trial run shall be counted as an aborted RATA attempt.

(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 CO2 pollutant concentration monitor (or an O2 monitor used to measure CO2 emissions) which also serves as the diluent component in a NOX-diluent (or SO2-diluent) monitoring system, if the CO2 (or O2) RATA is failed, then both the CO2 (or O2) monitor and the associated NOX-diluent (or SO2-diluent) system are considered out-of-control, beginning with the hour of completion of the failed CO2 (or O2) monitor RATA, and continuing until the hour of completion of subsequent hands-off RATAs which demonstrate that both systems have met the applicable relative accuracy specifications in sections 3.3.2 and 3.3.3 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).

(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 SO2 pollutant concentration monitor, a NOX-diluent monitoring system, a NOX concentration monitoring system or a flow monitor is passed, perform a bias test in accordance with section 7.6.4 of appendix A to this part. Apply the appropriate bias adjustment factor to the reported SO2, NOX, or flow rate data, in accordance with section 7.6.5 of appendix A to this part.

(j) Failure of the bias test does not result in the monitoring system being out-of-control.

2.3.3 RATA Grace Period

(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 SO2 RATA requirements of this part, an SO2 RATA has not been completed by the end of the calendar quarter in which the annual usage of fuel(s) with a sulfur content higher than very low sulfur fuel(as defined in § 72.2 of this chapter) exceeds 480 hours; or eight successive calendar quarters have elapsed, following the quarter in which a RATA was last performed, without a subsequent RATA having been done, due either to infrequent operation of the unit(s) or frequent combustion of very low sulfur fuel, as defined in § 72.2 of this chapter (SO2 monitors, only), or a combination of these factors.

(b) Except for SO2 monitoring system RATAs, the grace period shall begin with the first unit (or stack) operating hour following the calendar quarter in which the required RATA was due. For SO2 monitor RATAs, the grace period shall begin with the first unit (or stack) operating hour in which fuel with a total sulfur content higher than that of very low sulfur fuel (as defined in § 72.2 of this chapter) is burned in the unit(s), following the quarter in which the required RATA is due. Data validation during a RATA grace period shall be done in accordance with the applicable provisions in section 2.3.2 of this appendix.

(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 .

2.3.4Bias Adjustment Factor

Except as otherwise specified in section 7.6.5 of appendix A to this part, if an SO2 pollutant concentration monitor, flow monitor, NOX continuous emission monitoring system, or NOX concentration monitoring system used to calculate NOX mass emissions fails the bias test specified in section 7.6 of appendix A to this part, use the bias adjustment factor given in Equations A-11 and A-12 of appendix A to this part to adjust the monitored data.

2.4Recertification, Quality Assurance, RATA Frequency and Bias Adjustment Factors (Special Considerations)

(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.

2.5Other Audits

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.

Figure 1 to Appendix B of Part 75—Quality Assurance Test Requirements. Test QA test frequency requirements Daily* Quarterly* Semiannual* Calibration Error (2 pt.) ✔ Interference (flow) ✔ Flow-to-Load Ratio ✔ Leak Check (DP flow monitors) ✔ Linearity (3 pt.) ✔ RATA (SO2, NOX, CO2, H2O)1 ✔ RATA (flow)1,2 ✔ *For monitors on bypass stack/duct, “daily” means bypass operating days, only. “Quarterly” means once every QA operating quarter. “Semiannual” means once every two QA operating quarters. 1 Conduct RATA annually (i.e., once every four QA operating quarters), if monitor meets accuracy requirements to qualify for less frequent testing. 2 For flow monitors installed on peaking units and bypass stacks, conduct all RATAs at a single, normal load. For other flow monitors, conduct annual RATAs at the two load levels used most frequently since the last annual RATA. Alternating single-load and 2-load RATAs may be done if a monitor is on a semiannual frequency. A single-load RATA may be done in lieu of a 2-load RATA if, since the last annual flow RATA, the unit has operated at one load level for "85.0 percent of the time. A 3-load RATA is required at least once in every period of five consecutive calendar years and whenever a flow monitor is re-linearized. Figure 2 to Appendix B of Part 75—Relative Accuracy Test Frequency Incentive System. RATA Semiannual 1 (percent) Annual 1 SO2 or NOX 3 7.5% <RA ≤ 10.0% or ± 15.0 ppm2 RA ≤ 7.5% or ± 12.0 ppm2 SO2-diluent 7.5% < RA ≤ 10.0% or ± 0.030 RA ≤ 7.5% or ± 0.025. lb/mmBtu 2 lb/mmBtu 2 NOX-diluent 7.5% < RA ≤ 10.0% or ± 0.020 RA ≤ 7.5% or ± 0.015. lb/mmBtu 2 lb/mmBtu 2. Flow (Phase I) 10.0% < RA ≤ 15.0% or ± 1.5 fps 2 RA ≤ 10.0%. Flow (Phase II) 7.5% < RA ≤ 10.0% or ± 1.5 fps 2 RA ≤ 7.5%. CO2 or O2 7.5% < RA ≤ 10.0% or ± 1.0% CO2/O2 2 RA ≤ 7.5% or ± 0.7% CO2/O2 2. Moisture 7.5% < RA ≤ 10.0% or ± 1.5% H2O2 RA ≤ 7.5% or ± 1.0% H2O2. 1 The deadline for the next RATA is the end of the second (if semiannual) or fourth (if annual) successive QA operating quarter following the quarter in which the CEMS was last tested. Exclude calendar quarters with fewer than 168 unit operating hours (or, for common stacks and bypass stacks, exclude quarters with fewer than 168 stack operating hours) in determining the RATA deadline. For SO2 monitors, QA operating quarters in which only very low sulfur fuel as defined in § 72.2, is combusted may also be excluded. However, the exclusion of calendar quarters is limited as follows: the deadline for the next RATA shall be no more than 8 calendar quarters after the quarter in which a RATA was last performed. 2 The difference between monitor and reference method mean values applies to moisture monitors, CO2, and O2 monitors, low emitters, or low flow, only. 3 A NOX concentration monitoring system used to determine NOX mass emissions under § 75.71. [58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26546, 26571, May 17, 1995; 61 FR 59165, Nov. 20, 1996; 64 FR 28644, May 26, 1999; 64 FR 37582, July 12, 1999] Pt. 75, App. C Appendix C to Part 75—Missing Data Estimation Procedures 1. Parametric Monitoring Procedure for Missing SO 2 Concentration or NOX Emission Rate Data 1.1Applicability

The owner or operator of any affected unit equipped with post-combustion SO2 or NOx emission controls and SO2 pollutant concentration monitors and/or NOx continuous emission monitoring systems at the inlet and outlet of the emission control system may apply to the Administrator for approval and certification of a parametric, empirical, or process simulation method or model for calculating substitute data for missing data periods. Such methods may be used to parametrically estimate the removal efficiency of the SO2 of postcombustion NOx emission controls which, with the monitored inlet concentration or emission rate data, may be used to estimate the average concentration of SO2 emissions or average emission rate of NOx discharged to the atmosphere. After approval by the Administrator, such method or model may be used for filling in missing SO2 concentration or NOx emission rate data when data from the outlet SO2 pollutant concentration monitor or outlet NOx continuous emission monitoring system have been reported with an annual monitor data availability of 90.0 percent or more.

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.

1.2Petition Requirements

Continuously monitor, determine, and record hourly averages of the estimated SO2 or NOX removal efficiency and of the parameters specified below, at a minimum. The affected facility shall supply additional parametric information where appropriate. Measure the SO2 concentration or NOX emission rate, removal efficiency of the add-on emission controls, and the parameters for at least 2160 unit operating hours. Provide information for all expected operating conditions and removal efficiencies. At least 4 evenly spaced data points are required for a valid hourly average, except during periods of calibration, maintenance, or quality assurance activities, during which 2 data points per hour are sufficient. The Administrator will review all applications on a case-by-case basis.

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 SO2 concentration as determined by the monitor or missing data substitution procedures.

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 SO2 concentration as determined by the monitor or missing data substitution procedures.

1.2.2.7Any other parameters necessary to verify scrubber removal efficiency, if the Administrator determines the parameters above are not sufficient.

1.2.3Parameters for Other Flue Gas Desulfurization Systems

If SO2 control technologies other than wet or dry lime or limestone scrubbing are selected for flue gas desulfurization, a corresponding empirical correlation or process simulation parametric method using appropriate parameters may be developed by the owner or operator of the affected unit, and then reviewed and approved or modified by the Administrator on a case-by-case basis.

1.2.4Parameters for Post-Combustion NO x Emission Controls

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 NOx emission rate as determined by the NOx continuous emission monitoring system or missing data substitution procedures.

1.2.4.6Any other parameters specific to the emission reduction process necessary to verify the NOx control removal efficiency, (e.g., reagent feedrate in gal/mi).

1.3Correlation of Emissions With Parameters

Establish a method for correlating hourly averages of the parameters identified above with the percent removal efficiency of the SO2 or post-combustion NOX emission controls under varying unit operating loads. Equations 1-7 in § 75.15 may be used to estimate the percent removal efficiency of the SO2 emission controls on an hourly basis.

Each parametric data substitution procedure should develop a data correlation procedure to verify the performance of the SO2 emission controls or post-combustion NOx emission controls, along with the SO2 pollutant concentration monitor and NOx continuous emission monitoring system values for varying unit load ranges.

For NOx emission rate data, and wherever the performance of the emission controls varies with the load, use the load range procedure provided in section 2.2 of this appendix.

1.4Calculations

1.4.1Use the following equation to calculate substitute data for filling in missing (outlet) SO2 pollutant concentration monitor data.

Mo = Ic (1-E) (Eq. C-1) where, Mo = Substitute data for outlet SO2 concentration, ppm. Ic = Recorded inlet SO2 concentration, ppm. E = Removal efficiency of SO2 emission controls as determined by the correlation procedure described in section 1.3 of this appendix.

1.4.2Use the following equation to calculate substitute data for filling in missing (outlet) NOx emission rate data.

Mo = Ic (1-E) (Eq. C-2) where, Mo = Substitute data for outlet NOx emission rate, lb/mmBtu. Ic = Recorded inlet NOx emission rate, lb/mmBtu. E = Removal efficiency of post-combustion NOx emission controls determined by the correlation procedure described in section 1.3 of this appendix. 1.5Missing Data

1.5.1If both the inlet and the outlet SO2 pollutant concentration monitors are unavailable simultaneously, use the maximum inlet SO2 concentration recorded by the inlet SO2 pollutant concentration monitor during the previous 720 quality assured monitor operating hours to substitute for the inlet SO2 concentration in equation C-1 of this appendix.

1.5.2If both the inlet and outlet NOx continuous emission monitoring systems are unavailable simultaneously, use the maximum inlet NOx emission rate for the corresponding unit load recorded by the NOx continuous emission monitoring system at the inlet during the previous 2160 quality assured monitor operating hours to substitute for the inlet NOx emission rate in equation C-2 of this appendix.

1.6Application

Apply to the Administrator for approval and certification of the parametric substitution procedure for filling in missing SO2 concentration or NOx emission rate data using the established criteria and information identified above. DO not use this procedure until approved by the Administrator.

2. Load-Based Procedure for Missing Flow Rate and NOX Emission Rate Data 2.1Applicability

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), NOX emission rate (in lb/mmBtu) from NOX-diluent continuous emission monitoring systems, and NOX concentration data (in ppm) from NOx concentration monitoring systems used to determine NOX mass emissions.

2.2Procedure

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 NOX) may be broken down into 20 operating load ranges in increments of 5.0 percent of the combined maximum hourly average gross load of all units utilizing the common stack. If this option is selected, the twentieth (uppermost) operating load range shall include all values greater than 95.0 percent of the maximum hourly average gross load. For a cogenerating unit or other unit at which some portion of the heat input is not used to produce electricity or for a unit for which hourly average gross load in MWge is not recorded separately, use the hourly gross steam load of the unit, in pounds of steam per hour at the measured temperature (°F) and pressure (psia) instead of MWge. Indicate a change in the number of load ranges or the units of loads to be used in the precertification section of the monitoring plan.

Table C-1.—Definition of Operating Load Ranges for Load-based Substitution Data Procedures Operating load range Percent of maximum hourly gross load or maximum hourly gross steam load (percent) 1 0-10 2 ≤10-20 3 ≤20-30 4 ≤30-40 5 ≤40-50 6 ≤50-60 7 ≤60-70 8 ≤70-80 9 ≤80-90 10 ≤90

2.2.2Beginning with the first hour of unit operation after installation and certification of the flow monitor or the NOX-diluent continuous emission monitoring system (or a NOX concentration monitoring system used to determine NOX mass emissions, as defined in § 75.71(a)(2)), for each hour of unit operation record a number, 1 through 10, (or 1 through 20 for flow at common stacks) that identifies the operating load range corresponding to the integrated hourly gross load of the unit(s) recorded for each unit operating hour.

2.2.3Beginning with the first hour of unit operation after installation and certification of the flow monitor or the NOX-diluent continuous emission monitoring system (or a NOX concentration monitoring system used to determine NOX mass emissions, as defined in § 75.71(a)(2)) and continuing thereafter, the data acquisition and handling system must be capable of calculating and recording the following information for each unit operating hour of missing flow or NOX data within each identified load range during the shorter of: (a) the previous 2,160 quality assured monitor operating hours (on a rolling basis), or (b) all previous quality assured monitor operating hours.

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 NOX emission rate, in lb/mmBtu, reported by a NOX continuous emission monitoring system.

2.2.3.6The 90th percentile value of hourly NOX emission rates, in lb/mmBtu.

2.2.3.7The 95th percentile value of hourly NOX emission rates, in lb/mmBtu.

2.2.3.8The maximum value of hourly NOX emission rates, in lb/mmBtu.

2.2.3.9Average of the hourly NOX pollutant concentrations, in ppm, reported by a NOX concentration monitoring system used to determine NOX mass emissions, as defined in § 75.71(a)(2).

2.2.3.10The 90th percentile value of hourly NOX pollutant concentration, in ppm.

2.2.3.11The 95th percentile value of hourly NOX pollutant concentration, in ppm.

2.2.3.12The maximum value of hourly NOX pollutant concentration, in ppm.

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 NOX-diluent continuous emission monitoring system (and/or the NOX concentration monitoring system used to determine NOX mass emissions, as defined in § 75.71(a)(2)), apply the adjustment factor to all monitor or continuous emission monitoring system data values placed in the load ranges.

2.2.6Use the calculated monitor or monitoring system data averages, maximum values, and percentile values to substitute for missing flow rate and NOX emission rate data (and where applicable, NOX concentration data) according to the procedures in subpart D of this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26547, 26548, May 17, 1995; 63 FR 57313, Oct. 27, 1998; 64 FR 28652, May 26, 1999] Pt. 75, App. D Appendix D to Part 75—Optional SO2 Emissions Data Protocol for Gas-Fired and Oil-Fired Units 1. Applicability

1.1This protocol may be used in lieu of continuous SO2 pollutant concentration and flow monitors for the purpose of determining hourly SO2 mass emissions and heat input from: gas-fired units, as defined in § 72.2 of this chapter, or oil-fired units, as defined in § 72.2 of this chapter. Section 2.1 of this appendix provides procedures for measuring oil or gaseous fuel flow using a fuel flowmeter, section 2.2 of this appendix provides procedures for conducting oil sampling and analysis to determine sulfur content and gross calorific value (GCV) of fuel oil, and section 2.3 of this appendix provides procedures for determining the sulfur content and GCV of gaseous fuels.

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 SO2 continuous emission monitoring system. Complete all testing requirements no later than the applicable deadline specified in § 75.4. Apply to the Administrator for initial certification to use this protocol no later than 45 days after the completion of all certification tests. Whenever the monitoring method is to be changed, reapply to the Administrator for recertification of the new monitoring method.

2. Procedure 2.1Fuel Flowmeter Measurements

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 NOX mass emissions under a state or federal NOX mass emission reduction program. For all other units, if the fuel flowmeter is installed in a common pipe header, do one of the following:

2.1.2.1Measure the fuel flow rate in the common pipe, and combine SO2 mass emissions for the affected units for recordkeeping and compliance purposes; or

2.1.2.2Provide information satisfactory to the Administrator on methods for apportioning SO2 mass emissions and heat input to each of the affected units demonstrating that the method ensures complete and accurate accounting of the actual emissions from each of the affected units included in the apportionment and all emissions regulated under this part. The information shall be provided to the Administrator through a petition submitted by the designated representative under § 75.66. Satisfactory information includes: the proposed apportionment, using fuel flow measurements; the ratio of hourly integrated gross load (in MWe-hr) in each unit to the total load for all units receiving fuel from the common pipe header, or the ratio of hourly steam flow (in 1000 lb) at each unit to the total steam flow for all units receiving fuel from the common pipe header (see section 3.4.3 of this appendix); and documentation that shows the provisions of sections 2.1.5 and 2.1.6 of this appendix have been met for the fuel flowmeter used in the apportionment.

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.

2.1.4Situations in Which Certified Flowmeter is Not Required 2.1.4.1Start-up or Ignition Fuel

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.

2.1.4.2Gas or Oil Flowmeter Used for Commercial Billing

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.

2.1.4.3 Emergency Fuel

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.

2.1.5Initial Certification Requirement for all Fuel Flowmeters

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 this appendix by measurement against a NIST traceable reference method.

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

(b) Calculate the flowmeter accuracy at each of the three flow levels using the following equation:

ER26MY99.012 Where: ACC=Flowmeter accuracy at a particular load level, as a percentage of the upper range value. R=Average of the three flow measurements of the reference flowmeter. A=Average of the three measurements of the flowmeter being tested. URV=Upper range value of fuel flowmeter being tested (i.e. maximum measurable flow).

(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 ±1.0 percent of each other at all levels tested. This exception to calibration and flowmeter accuracy testing requirements for the reference flowmeter shall apply for periods of no longer than five consecutive years (i.e., 20 consecutive calendar quarters).

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 2.1.5.2 of this appendix or flow rate from a procedure performed according to a standard incorporated by reference under section 2.1.5.1 of this appendix), report the results of flowmeter accuracy tests using the following Table D-1.

Table D-1.—Table of Flowmeter Accuracy Results Test number:XXXX Test completion date 1:XXXXXXXXXX Test completion time 1:XXXXXX Reinstallation date 2 (for testing under 2.1.5.1 only):XXXXXXXXXX Reinstallation time 2:XXXXXX Unit or pipe ID:Component/System ID: Flowmeter serial number:Upper range value: Units of measure for flowmeter and reference flow readings: Measurement level (percent of URV) Run No. Time of run (HHMM) Candidate flowmeter reading Reference flow reading Percent

accuracy

(percent of URV)

Low (Minimum) level 1 XX percent 3 of URV 2 3 Average Mid-level 1 XX percent 3 of URV 2 3 Average High (Maximum) level 1 XX percent 3 of URV 2 3 Average 1 Report the date, hour, and minute that all test runs were completed. 2 For laboratory tests not performed inline, report the date and hour that the fuel flowmeter was reinstalled following the test. 3 It is required to test at least at three different levels: (1) normal full unit operating load, (2) normal minimum unit operating load, and (3) a load point approximately equally spaced between the full and minimum unit operating loads. 2.1.6 Quality Assurance

(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.

2.1.6.1Transmitter or Transducer Accuracy Test for Orifice-, Nozzle-, and Venturi-Type Flowmeters

(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:

ER26MY99.013 Where: ACC = Accuracy of the transmitter or transducer as a percentage of full-scale. R = Reading of the NIST traceable reference value (in milliamperes, inches of water, psi, or degrees). T = Reading of the transmitter or transducer being tested (in milliamperes, inches of water, psi, or degrees, consistent with the units of measure of the NIST traceable reference value). FS = Full-scale range of the transmitter or transducer being tested (in milliamperes, inches of water, psi, or degrees, consistent with the units of measure of the NIST traceable reference value).

(c) If each transmitter or transducer meets an accuracy of ± 1.0 percent of its full-scale range at each level tested, the fuel flowmeter accuracy of 2.0 percent is considered to be met at all levels. If, however, one or more of the transmitters or transducers does not meet an accuracy of ± 1.0 percent of full-scale at a particular level, then the owner or operator may demonstrate that the fuel flowmeter meets the total accuracy specification of 2.0 percent at that level by using one of the following alternative methods. If, at a particular level, the sum of the individual accuracies of the three transducers is less than or equal to 4.0 percent, the fuel flowmeter accuracy specification of 2.0 percent is considered to be met for that level. Or, if at a particular level, the total fuel flowmeter accuracy is 2.0 percent or less, when calculated in accordance with Part 1 of American Gas Association Report No. 3, General Equations and Uncertainty Guidelines, the flowmeter accuracy requirement is considered to be met for that level.

2.1.6.2 Recordkeeping and Reporting of Transmitter or Transducer Accuracy Results

(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.

Table D-2.—Table of Flowmeter Transmitter or Transducer Accuracy Results Test number:XXXX Test completion date: XXXXXXXXXX Unit or pipe ID: XXXXXX Flowmeter serial number:Component/System ID: Full-scale value:Units of measure: 3 Transducer/Transmitter Type (check one): XX Differential Pressure XX Static Pressure XX Temperature Measurement level (percent of full-scale) Run number (if multiple runs) 2 Run time (HHMM) Transmitter/transducer input (pre-calibration) Expected transmitter/transducer output (reference) Actual transmitter/transducer output 3 Percent accuracy (percent of full-scale) Low (Minimum) level XX percent 1 of full-scale Mid-level XX percent1 of full-scale (If tested at more than 3 levels) 2nd Mid-level XX percent 1 of full-scale (If tested at more than 3 levels) 3rd Mid-level XX percent 1 of full-scale High (Maximum) level XX percent 1 of full-scale 1 At a minimum, it is required to test at zero-level and at least two other levels across the range of the transmitter or transducer readings corresponding to normal unit operation. 2 It is required to test at least once at each level. 3 Use the same units of measure for all readings (e.g., use degrees (°), inches of water (in H2O), pounds per square inch (psi), or milliamperes (ma) for both transmitter or transducer readings and reference readings).

(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.

2.1.6.3Failure of Transducer(s) or Transmitter(s)

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.

2.1.6.4Primary Element Inspection

(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, 2.1.6.1, or 2.1.6.4 of this appendix when conducting periodic quality assurance testing of a certified fuel flowmeter. Note, however, that these procedures may not be used unless the 168-hour baseline data requirement of section 2.1.7.1 of this appendix has been met. If, following a flowmeter accuracy test or flowmeter transmitter test and primary element inspection, where applicable, the procedures of this section are performed during each subsequent fuel flowmeter QA