[Title 40 CFR 60.49b]
[Code of Federal Regulations (annual edition) - July 1, 2009 Edition]
[Title 40 - PROTECTION OF ENVIRONMENT]
[Chapter I - ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)]
[Subchapter C - AIR PROGRAMS (CONTINUED)]
[Part 60 - STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES--]
[Subpart Db - Standards of Performance for Industrial-Commercial-]
[Sec. 60.49b - Reporting and recordkeeping requirements.]
[From the U.S. Government Printing Office]
40PROTECTION OF ENVIRONMENT62009-07-012009-07-01falseReporting and recordkeeping requirements.60.49bSec. 60.49bPROTECTION OF ENVIRONMENTENVIRONMENTAL PROTECTION AGENCY (CONTINUED)AIR PROGRAMS (CONTINUED)STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES--Standards of Performance for Industrial-Commercial-
Sec. 60.49b Reporting and recordkeeping requirements.
(a) The owner or operator of each affected facility shall submit
notification of the date of initial startup, as provided by Sec. 60.7.
This notification shall include:
(1) The design heat input capacity of the affected facility and
identification of the fuels to be combusted in the affected facility;
(2) If applicable, a copy of any federally enforceable requirement
that limits the annual capacity factor for any fuel or mixture of fuels
under Sec. Sec. 60.42b(d)(1), 60.43b(a)(2), (a)(3)(iii), (c)(2)(ii),
(d)(2)(iii), 60.44b(c), (d), (e), (i), (j), (k), 60.45b(d), (g),
60.46b(h), or 60.48b(i);
(3) The annual capacity factor at which the owner or operator
anticipates operating the facility based on all fuels fired and based on
each individual fuel fired; and
(4) Notification that an emerging technology will be used for
controlling emissions of SO2. The Administrator will examine
the description of the emerging technology and will determine whether
the technology qualifies as an emerging technology. In making this
determination, the Administrator may require the owner or operator of
the affected facility to submit additional information concerning the
control device. The affected facility is subject to the provisions of
Sec. 60.42b(a) unless and until this determination is made by the
Administrator.
(b) The owner or operator of each affected facility subject to the
SO2, PM, and/or NOX emission limits under
Sec. Sec. 60.42b, 60.43b, and 60.44b shall submit to the Administrator
the performance test data from the initial performance test and the
performance evaluation of the CEMS using the applicable performance
specifications in appendix B of this part. The owner or operator of
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each affected facility described in Sec. 60.44b(j) or Sec. 60.44b(k)
shall submit to the Administrator the maximum heat input capacity data
from the demonstration of the maximum heat input capacity of the
affected facility.
(c) The owner or operator of each affected facility subject to the
NOX standard in Sec. 60.44b who seeks to demonstrate
compliance with those standards through the monitoring of steam
generating unit operating conditions in the provisions of Sec.
60.48b(g)(2) shall submit to the Administrator for approval a plan that
identifies the operating conditions to be monitored in Sec.
60.48b(g)(2) and the records to be maintained in Sec. 60.49b(g). This
plan shall be submitted to the Administrator for approval within 360
days of the initial startup of the affected facility. An affected
facility burning coke oven gas alone or in combination with other
gaseous fuels or distillate oil shall submit this plan to the
Administrator for approval within 360 days of the initial startup of the
affected facility or by November 30, 2009, whichever date comes later.
If the plan is approved, the owner or operator shall maintain records of
predicted nitrogen oxide emission rates and the monitored operating
conditions, including steam generating unit load, identified in the
plan. The plan shall:
(1) Identify the specific operating conditions to be monitored and
the relationship between these operating conditions and NOX
emission rates (i.e., ng/J or lbs/MMBtu heat input). Steam generating
unit operating conditions include, but are not limited to, the degree of
staged combustion (i.e., the ratio of primary air to secondary and/or
tertiary air) and the level of excess air (i.e., flue gas O2
level);
(2) Include the data and information that the owner or operator used
to identify the relationship between NOX emission rates and
these operating conditions; and
(3) Identify how these operating conditions, including steam
generating unit load, will be monitored under Sec. 60.48b(g) on an
hourly basis by the owner or operator during the period of operation of
the affected facility; the quality assurance procedures or practices
that will be employed to ensure that the data generated by monitoring
these operating conditions will be representative and accurate; and the
type and format of the records of these operating conditions, including
steam generating unit load, that will be maintained by the owner or
operator under Sec. 60.49b(g).
(d) Except as provided in paragraph (d)(2) of this section, the
owner or operator of an affected facility shall record and maintain
records as specified in paragraph (d)(1) of this section.
(1) The owner or operator of an affected facility shall record and
maintain records of the amounts of each fuel combusted during each day
and calculate the annual capacity factor individually for coal,
distillate oil, residual oil, natural gas, wood, and municipal-type
solid waste for the reporting period. The annual capacity factor is
determined on a 12-month rolling average basis with a new annual
capacity factor calculated at the end of each calendar month.
(2) As an alternative to meeting the requirements of paragraph
(d)(1) of this section, the owner or operator of an affected facility
that is subject to a federally enforceable permit restricting fuel use
to a single fuel such that the facility is not required to continuously
monitor any emissions (excluding opacity) or parameters indicative of
emissions may elect to record and maintain records of the amount of each
fuel combusted during each calendar month.
(e) For an affected facility that combusts residual oil and meets
the criteria under Sec. Sec. 60.46b(e)(4), 60.44b(j), or (k), the owner
or operator shall maintain records of the nitrogen content of the
residual oil combusted in the affected facility and calculate the
average fuel nitrogen content for the reporting period. The nitrogen
content shall be determined using ASTM Method D4629 (incorporated by
reference, see Sec. 60.17), or fuel suppliers. If residual oil blends
are being combusted, fuel nitrogen specifications may be prorated based
on the ratio of residual oils of different nitrogen content in the fuel
blend.
(f) For an affected facility subject to the opacity standard in
Sec. 60.43b, the owner or operator shall maintain
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records of opacity. In addition, an owner or operator that elects to
monitor emissions according to the requirements in Sec. 60.48b(a) shall
maintain records according to the requirements specified in paragraphs
(f)(1) through (3) of this section, as applicable to the visible
emissions monitoring method used.
(1) For each performance test conducted using Method 9 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (f)(1)(i) through (iii) of this
section.
(i) Dates and time intervals of all opacity observation periods;
(ii) Name, affiliation, and copy of current visible emission reading
certification for each visible emission observer participating in the
performance test; and
(iii) Copies of all visible emission observer opacity field data
sheets;
(2) For each performance test conducted using Method 22 of appendix
A-4 of this part, the owner or operator shall keep the records including
the information specified in paragraphs (f)(2)(i) through (iv) of this
section.
(i) Dates and time intervals of all visible emissions observation
periods;
(ii) Name and affiliation for each visible emission observer
participating in the performance test;
(iii) Copies of all visible emission observer opacity field data
sheets; and
(iv) Documentation of any adjustments made and the time the
adjustments were completed to the affected facility operation by the
owner or operator to demonstrate compliance with the applicable
monitoring requirements.
(3) For each digital opacity compliance system, the owner or
operator shall maintain records and submit reports according to the
requirements specified in the site-specific monitoring plan approved by
the Administrator.
(g) Except as provided under paragraph (p) of this section, the
owner or operator of an affected facility subject to the NOX
standards under Sec. 60.44b shall maintain records of the following
information for each steam generating unit operating day:
(1) Calendar date;
(2) The average hourly NOX emission rates (expressed as
NO2) (ng/J or lb/MMBtu heat input) measured or predicted;
(3) The 30-day average NOX emission rates (ng/J or lb/
MMBtu heat input) calculated at the end of each steam generating unit
operating day from the measured or predicted hourly nitrogen oxide
emission rates for the preceding 30 steam generating unit operating
days;
(4) Identification of the steam generating unit operating days when
the calculated 30-day average NOX emission rates are in
excess of the NOX emissions standards under Sec. 60.44b,
with the reasons for such excess emissions as well as a description of
corrective actions taken;
(5) Identification of the steam generating unit operating days for
which pollutant data have not been obtained, including reasons for not
obtaining sufficient data and a description of corrective actions taken;
(6) Identification of the times when emission data have been
excluded from the calculation of average emission rates and the reasons
for excluding data;
(7) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
(8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
(9) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or 3;
and
(10) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under appendix F, Procedure 1 of this part.
(h) The owner or operator of any affected facility in any category
listed in paragraphs (h)(1) or (2) of this section is required to submit
excess emission reports for any excess emissions that occurred during
the reporting period.
(1) Any affected facility subject to the opacity standards in Sec.
60.43b(f) or to the operating parameter monitoring requirements in Sec.
60.13(i)(1).
(2) Any affected facility that is subject to the NOX
standard of Sec. 60.44b, and that:
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(i) Combusts natural gas, distillate oil, gasified coal, or residual
oil with a nitrogen content of 0.3 weight percent or less; or
(ii) Has a heat input capacity of 73 MW (250 MMBtu/hr) or less and
is required to monitor NOX emissions on a continuous basis
under Sec. 60.48b(g)(1) or steam generating unit operating conditions
under Sec. 60.48b(g)(2).
(3) For the purpose of Sec. 60.43b, excess emissions are defined as
all 6-minute periods during which the average opacity exceeds the
opacity standards under Sec. 60.43b(f).
(4) For purposes of Sec. 60.48b(g)(1), excess emissions are defined
as any calculated 30-day rolling average NOX emission rate,
as determined under Sec. 60.46b(e), that exceeds the applicable
emission limits in Sec. 60.44b.
(i) The owner or operator of any affected facility subject to the
continuous monitoring requirements for NOX under Sec.
60.48(b) shall submit reports containing the information recorded under
paragraph (g) of this section.
(j) The owner or operator of any affected facility subject to the
SO2 standards under Sec. 60.42b shall submit reports.
(k) For each affected facility subject to the compliance and
performance testing requirements of Sec. 60.45b and the reporting
requirement in paragraph (j) of this section, the following information
shall be reported to the Administrator:
(1) Calendar dates covered in the reporting period;
(2) Each 30-day average SO2 emission rate (ng/J or lb/
MMBtu heat input) measured during the reporting period, ending with the
last 30-day period; reasons for noncompliance with the emission
standards; and a description of corrective actions taken; For an
exceedance due to maintenance of the SO2 control system
covered in paragraph 60.45b(a), the report shall identify the days on
which the maintenance was performed and a description of the
maintenance;
(3) Each 30-day average percent reduction in SO2
emissions calculated during the reporting period, ending with the last
30-day period; reasons for noncompliance with the emission standards;
and a description of corrective actions taken;
(4) Identification of the steam generating unit operating days that
coal or oil was combusted and for which SO2 or diluent
(O2 or CO2) data have not been obtained by an
approved method for at least 75 percent of the operating hours in the
steam generating unit operating day; justification for not obtaining
sufficient data; and description of corrective action taken;
(5) Identification of the times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and description of corrective action taken if data
have been excluded for periods other than those during which coal or oil
were not combusted in the steam generating unit;
(6) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
(7) Identification of times when hourly averages have been obtained
based on manual sampling methods;
(8) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
(9) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or 3;
(10) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under appendix F, Procedure 1 of this part; and
(11) The annual capacity factor of each fired as provided under
paragraph (d) of this section.
(l) For each affected facility subject to the compliance and
performance testing requirements of Sec. 60.45b(d) and the reporting
requirements of paragraph (j) of this section, the following information
shall be reported to the Administrator:
(1) Calendar dates when the facility was in operation during the
reporting period;
(2) The 24-hour average SO2 emission rate measured for
each steam generating unit operating day during the reporting period
that coal or oil was combusted, ending in the last 24-hour period in the
quarter; reasons for noncompliance with the emission standards; and a
description of corrective actions taken;
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(3) Identification of the steam generating unit operating days that
coal or oil was combusted for which S02 or diluent
(O2 or CO2) data have not been obtained by an
approved method for at least 75 percent of the operating hours;
justification for not obtaining sufficient data; and description of
corrective action taken;
(4) Identification of the times when emissions data have been
excluded from the calculation of average emission rates; justification
for excluding data; and description of corrective action taken if data
have been excluded for periods other than those during which coal or oil
were not combusted in the steam generating unit;
(5) Identification of ``F'' factor used for calculations, method of
determination, and type of fuel combusted;
(6) Identification of times when hourly averages have been obtained
based on manual sampling methods;
(7) Identification of the times when the pollutant concentration
exceeded full span of the CEMS;
(8) Description of any modifications to the CEMS that could affect
the ability of the CEMS to comply with Performance Specification 2 or 3;
and
(9) Results of daily CEMS drift tests and quarterly accuracy
assessments as required under Procedure 1 of appendix F 1 of this part.
If the owner or operator elects to implement the alternative data
assessment procedures described in Sec. Sec. 60.47b(e)(4)(i) through
(e)(4)(iii), each data assessment report shall include a summary of the
results of all of the RATAs, linearity checks, CGAs, and calibration
error or drift assessments required by Sec. Sec. 60.47b(e)(4)(i)
through (e)(4)(iii).
(m) For each affected facility subject to the SO2
standards in Sec. 60.42(b) for which the minimum amount of data
required in Sec. 60.47b(c) were not obtained during the reporting
period, the following information is reported to the Administrator in
addition to that required under paragraph (k) of this section:
(1) The number of hourly averages available for outlet emission
rates and inlet emission rates;
(2) The standard deviation of hourly averages for outlet emission
rates and inlet emission rates, as determined in Method 19 of appendix A
of this part, section 7;
(3) The lower confidence limit for the mean outlet emission rate and
the upper confidence limit for the mean inlet emission rate, as
calculated in Method 19 of appendix A of this part, section 7; and
(4) The ratio of the lower confidence limit for the mean outlet
emission rate and the allowable emission rate, as determined in Method
19 of appendix A of this part, section 7.
(n) If a percent removal efficiency by fuel pretreatment (i.e.,
%Rf) is used to determine the overall percent reduction
(i.e., %Ro) under Sec. 60.45b, the owner or operator of the
affected facility shall submit a signed statement with the report.
(1) Indicating what removal efficiency by fuel pretreatment (i.e.,
%Rf) was credited during the reporting period;
(2) Listing the quantity, heat content, and date each pre-treated
fuel shipment was received during the reporting period, the name and
location of the fuel pretreatment facility; and the total quantity and
total heat content of all fuels received at the affected facility during
the reporting period;
(3) Documenting the transport of the fuel from the fuel pretreatment
facility to the steam generating unit; and
(4) Including a signed statement from the owner or operator of the
fuel pretreatment facility certifying that the percent removal
efficiency achieved by fuel pretreatment was determined in accordance
with the provisions of Method 19 of appendix A of this part and listing
the heat content and sulfur content of each fuel before and after fuel
pretreatment.
(o) All records required under this section shall be maintained by
the owner or operator of the affected facility for a period of 2 years
following the date of such record.
(p) The owner or operator of an affected facility described in Sec.
60.44b(j) or (k) shall maintain records of the following information for
each steam generating unit operating day:
(1) Calendar date;
(2) The number of hours of operation; and
(3) A record of the hourly steam load.
[[Page 215]]
(q) The owner or operator of an affected facility described in Sec.
60.44b(j) or Sec. 60.44b(k) shall submit to the Administrator a report
containing:
(1) The annual capacity factor over the previous 12 months;
(2) The average fuel nitrogen content during the reporting period,
if residual oil was fired; and
(3) If the affected facility meets the criteria described in Sec.
60.44b(j), the results of any NOX emission tests required
during the reporting period, the hours of operation during the reporting
period, and the hours of operation since the last NOX
emission test.
(r) The owner or operator of an affected facility who elects to use
the fuel based compliance alternatives in Sec. 60.42b or Sec. 60.43b
shall either:
(1) The owner or operator of an affected facility who elects to
demonstrate that the affected facility combusts only very low sulfur
oil, natural gas, wood, a mixture of these fuels, or any of these fuels
(or a mixture of these fuels) in combination with other fuels that are
known to contain an insignificant amount of sulfur in Sec. 60.42b(j) or
Sec. 60.42b(k) shall obtain and maintain at the affected facility fuel
receipts from the fuel supplier that certify that the oil meets the
definition of distillate oil and gaseous fuel meets the definition of
natural gas as defined in Sec. 60.41b and the applicable sulfur limit.
For the purposes of this section, the distillate oil need not meet the
fuel nitrogen content specification in the definition of distillate oil.
Reports shall be submitted to the Administrator certifying that only
very low sulfur oil meeting this definition, natural gas, wood, and/or
other fuels that are known to contain insignificant amounts of sulfur
were combusted in the affected facility during the reporting period; or
(2) The owner or operator of an affected facility who elects to
demonstrate compliance based on fuel analysis in Sec. 60.42b or Sec.
60.43b shall develop and submit a site-specific fuel analysis plan to
the Administrator for review and approval no later than 60 days before
the date you intend to demonstrate compliance. Each fuel analysis plan
shall include a minimum initial requirement of weekly testing and each
analysis report shall contain, at a minimum, the following information:
(i) The potential sulfur emissions rate of the representative fuel
mixture in ng/J heat input;
(ii) The method used to determine the potential sulfur emissions
rate of each constituent of the mixture. For distillate oil and natural
gas a fuel receipt or tariff sheet is acceptable;
(iii) The ratio of different fuels in the mixture; and
(iv) The owner or operator can petition the Administrator to approve
monthly or quarterly sampling in place of weekly sampling.
(s) Facility specific NOX standard for Cytec Industries
Fortier Plant's C.AOG incinerator located in Westwego, Louisiana:
(1) Definitions.
Oxidation zone is defined as the portion of the C.AOG incinerator
that extends from the inlet of the oxidizing zone combustion air to the
outlet gas stack.
Reducing zone is defined as the portion of the C.AOG incinerator
that extends from the burner section to the inlet of the oxidizing zone
combustion air.
Total inlet air is defined as the total amount of air introduced
into the C.AOG incinerator for combustion of natural gas and chemical
by-product waste and is equal to the sum of the air flow into the
reducing zone and the air flow into the oxidation zone.
(2) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When natural gas and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 289 ng/J
(0.67 lb/MMBtu) and a maximum of 81 percent of the total inlet air
provided for combustion shall be provided to the reducing zone of the
C.AOG incinerator.
(3) Emission monitoring. (i) The percent of total inlet air provided
to the reducing zone shall be determined at least every 15 minutes by
measuring the air flow of all the air entering the reducing zone and the
air flow of all the air entering the oxidation zone, and compliance with
the percentage of
[[Page 216]]
total inlet air that is provided to the reducing zone shall be
determined on a 3-hour average basis.
(ii) The NOX emission limit shall be determined by the
compliance and performance test methods and procedures for
NOX in Sec. 60.46b(i).
(iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec. 60.48b.
(4) Reporting and recordkeeping requirements. (i) The owner or
operator of the C.AOG incinerator shall submit a report on any
excursions from the limits required by paragraph (a)(2) of this section
to the Administrator with the quarterly report required by paragraph (i)
of this section.
(ii) The owner or operator of the C.AOG incinerator shall keep
records of the monitoring required by paragraph (a)(3) of this section
for a period of 2 years following the date of such record.
(iii) The owner of operator of the C.AOG incinerator shall perform
all the applicable reporting and recordkeeping requirements of this
section.
(t) Facility-specific NOX standard for Rohm and Haas
Kentucky Incorporated's Boiler No. 100 located in Louisville, Kentucky:
(1) Definitions.
Air ratio control damper is defined as the part of the low
NOX burner that is adjusted to control the split of total
combustion air delivered to the reducing and oxidation portions of the
combustion flame.
Flue gas recirculation line is defined as the part of Boiler No. 100
that recirculates a portion of the boiler flue gas back into the
combustion air.
(2) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When fossil fuel and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 473 ng/J
(1.1 lb/MMBtu), and the air ratio control damper tee handle shall be at
a minimum of 5 inches (12.7 centimeters) out of the boiler, and the flue
gas recirculation line shall be operated at a minimum of 10 percent open
as indicated by its valve opening position indicator.
(3) Emission monitoring for nitrogen oxides. (i) The air ratio
control damper tee handle setting and the flue gas recirculation line
valve opening position indicator setting shall be recorded during each
8-hour operating shift.
(ii) The NOX emission limit shall be determined by the
compliance and performance test methods and procedures for
NOX in Sec. 60.46b.
(iii) The monitoring of the NOX emission limit shall be
performed in accordance with Sec. 60.48b.
(4) Reporting and recordkeeping requirements. (i) The owner or
operator of Boiler No. 100 shall submit a report on any excursions from
the limits required by paragraph (b)(2) of this section to the
Administrator with the quarterly report required by Sec. 60.49b(i).
(ii) The owner or operator of Boiler No. 100 shall keep records of
the monitoring required by paragraph (b)(3) of this section for a period
of 2 years following the date of such record.
(iii) The owner of operator of Boiler No. 100 shall perform all the
applicable reporting and recordkeeping requirements of Sec. 60.49b.
(u) Site-specific standard for Merck & Co., Inc.'s Stonewall Plant
in Elkton, Virginia. (1) This paragraph (u) applies only to the
pharmaceutical manufacturing facility, commonly referred to as the
Stonewall Plant, located at Route 340 South, in Elkton, Virginia
(``site'') and only to the natural gas-fired boilers installed as part
of the powerhouse conversion required pursuant to 40 CFR 52.2454(g). The
requirements of this paragraph shall apply, and the requirements of
Sec. Sec. 60.40b through 60.49b(t) shall not apply, to the natural gas-
fired boilers installed pursuant to 40 CFR 52.2454(g).
(i) The site shall equip the natural gas-fired boilers with low
NOX technology.
(ii) The site shall install, calibrate, maintain, and operate a
continuous monitoring and recording system for measuring NOX
emissions discharged to the atmosphere and opacity using a continuous
emissions monitoring system or a predictive emissions monitoring system.
(iii) Within 180 days of the completion of the powerhouse
conversion, as required by 40 CFR 52.2454, the site
[[Page 217]]
shall perform a performance test to quantify criteria pollutant
emissions.
(2) [Reserved]
(v) The owner or operator of an affected facility may submit
electronic quarterly reports for SO2 and/or NOX
and/or opacity in lieu of submitting the written reports required under
paragraphs (h), (i), (j), (k) or (l) of this section. The format of each
quarterly electronic report shall be coordinated with the permitting
authority. The electronic report(s) shall be submitted no later than 30
days after the end of the calendar quarter and shall be accompanied by a
certification statement from the owner or operator, indicating whether
compliance with the applicable emission standards and minimum data
requirements of this subpart was achieved during the reporting period.
Before submitting reports in the electronic format, the owner or
operator shall coordinate with the permitting authority to obtain their
agreement to submit reports in this alternative format.
(w) The reporting period for the reports required under this subpart
is each 6 month period. All reports shall be submitted to the
Administrator and shall be postmarked by the 30th day following the end
of the reporting period.
(x) Facility-specific NOX standard for Weyerhaeuser
Company's No. 2 Power Boiler located in New Bern, North Carolina:
(1) Standard for nitrogen oxides. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When fossil fuel and chemical by-product waste are
simultaneously combusted, the NOX emission limit is 215 ng/J
(0.5 lb/MMBtu).
(2) Emission monitoring for nitrogen oxides. (i) The NOX
emissions shall be determined by the compliance and performance test
methods and procedures for NOX in Sec. 60.46b.
(ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec. 60.48b.
(3) Reporting and recordkeeping requirements. (i) The owner or
operator of the No. 2 Power Boiler shall submit a report on any
excursions from the limits required by paragraph (x)(2) of this section
to the Administrator with the quarterly report required by Sec.
60.49b(i).
(ii) The owner or operator of the No. 2 Power Boiler shall keep
records of the monitoring required by paragraph (x)(3) of this section
for a period of 2 years following the date of such record.
(iii) The owner or operator of the No. 2 Power Boiler shall perform
all the applicable reporting and recordkeeping requirements of Sec.
60.49b.
(y) Facility-specific NOX standard for INEOS USA's AOGI
located in Lima, Ohio:
(1) Standard for NOX. (i) When fossil fuel alone is
combusted, the NOX emission limit for fossil fuel in Sec.
60.44b(a) applies.
(ii) When fossil fuel and chemical byproduct/waste are
simultaneously combusted, the NOX emission limit is 645 ng/J
(1.5 lb/MMBtu).
(2) Emission monitoring for NOX. (i) The NOX
emissions shall be determined by the compliance and performance test
methods and procedures for NOX in Sec. 60.46b.
(ii) The monitoring of the NOX emissions shall be
performed in accordance with Sec. 60.48b.
(3) Reporting and recordkeeping requirements. (i) The owner or
operator of the AOGI shall submit a report on any excursions from the
limits required by paragraph (y)(2) of this section to the Administrator
with the quarterly report required by paragraph (i) of this section.
(ii) The owner or operator of the AOGI shall keep records of the
monitoring required by paragraph (y)(3) of this section for a period of
2 years following the date of such record.
(iii) The owner or operator of the AOGI shall perform all the
applicable reporting and recordkeeping requirements of this section.
[72 FR 32742, June 13, 2007, as amended at 74 FR 5089, Jan. 28, 2009]