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Title 40 – Protection of Environment–Volume 18

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Title 40 – Protection of Environment–Volume 18


Part


chapter i – Environmental Protection Agency (Continued)

72

CHAPTER I – ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)

SUBCHAPTER C – AIR PROGRAMS (CONTINUED)

PART 72 – PERMITS REGULATION


Authority:42 U.S.C. 7401, 7403, 7410, 7411, 7426, 7601, 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 the affected units at a source 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 account for that source 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 SO2 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 source 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.


Air Emission Testing Body (AETB) means a company or other entity that provides to the owner or operator the certification required by section 6.1.2(b) of appendix A to part 75 of this chapter.


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


Allowable SO2 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 account to account for the number of tons of SO2 emissions from the affected units at an affected source 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 source’s compliance account for the purposes of meeting the source’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 compliance account, the designated representative of the owners and operators of the affected source and the affected units at the source.


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, moisture 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)} × 10
6

“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.


Bypass 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 a 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 (or maximum observed hourly gross load (in MWe/hr) if greater than the 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 rated hourly heat input rate (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, subbituminous, 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 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 pipe means an oil or gas supply line through which the same type of fuel is distributed to two or more affected units.


Common pipe operating time means the portion of a clock hour during which fuel flows through a common pipe. The common pipe operating time, in hours, is expressed as a decimal fraction, with valid values ranging from 0.00 to 1.00.


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 account means an Allowance Tracking System account, established by the Administrator under § 73.31(a) or (b) of this chapter or § 74.40(a) of this chapter for an affected source and for each affected unit at the source.


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 use date means the first calendar year for which an allowance may be used for purposes of meeting a source’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 Consumer 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 means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of SO2, NOX, or CO2 emissions or stack gas volumetric flow rate. The following are the principal types of continuous emission monitoring systems required under part 75 of this chapter. Sections 75.10 through 75.18, and § 75.71(a) of this chapter indicate which type(s) of CEMS is required for specific applications:


(1) A sulfur dioxide monitoring system, consisting of an SO2 pollutant concentration monitor and an automated DAHS. An SO2 monitoring system provides a permanent, continuous record of SO2 emissions in units of parts per million (ppm);


(2) A flow monitoring system, consisting of a stack flow rate monitor and an automated DAHS. A flow monitoring system provides a permanent, continuous record of stack gas volumetric flow rate, in units of standard cubic feet per hour (scfh);


(3) A nitrogen oxides (NOX) emission rate (or NOX-diluent) monitoring system, consisting of a NOX pollutant concentration monitor, a diluent gas (CO2 or O2) monitor, and an automated DAHS. A NOX-diluent monitoring system provides a permanent, continuous record of: NOX concentration in units of parts per million (ppm), diluent gas concentration in units of percent O2 or CO2 (% O2 or CO2), and NOX emission rate in units of pounds per million British thermal units (lb/mmBtu);


(4) A nitrogen oxides concentration monitoring system, consisting of a NOX pollutant concentration monitor and an automated DAHS. A NOX concentration monitoring system provides a permanent, continuous record of NOX emissions in units of parts per million (ppm). This type of CEMS is used only in conjunction with a flow monitoring system to determine NOX mass emissions (in lb/hr) under subpart H of part 75 of this chapter;


(5) A carbon dioxide monitoring system, consisting of a CO2 pollutant concentration monitor (or an oxygen monitor plus suitable mathematical equations from which the CO2 concentration is derived) and the automated DAHS. A carbon dioxide monitoring system provides a permanent, continuous record of CO2 emissions in units of percent CO2 (% CO2); and


(6) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter. A moisture monitoring system provides a permanent, continuous record of the stack gas moisture content, in units of percent H2O (% H2O)


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 components are included in a continuous opacity monitoring system:


(1) Opacity monitor; and


(2) An automated 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.


Coverage Factor k means, in general, a value chosen on the basis of the desired level of confidence to be associated with the interval defined by U = kuc. Typically, k is in the range 2 to 3. When the normal distribution applies and uc is a reliable estimate of the standard deviation of y, U = 2 uc (i.e., k = 2) defines an interval having a level of confidence of approximately 95%, and U = 3 uc (i.e., k = 3) defines an interval having a level of confidence greater than 99%.


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 cap value means a default value of percent CO2 or O2 which may be used to calculate the hourly NOX emission rate, when the measured hourly average percent CO2 is below the default value or when the measured hourly average percent O2 is above the default value. The diluent cap values for boilers are 5.0 percent CO2 and 14.0 percent O2. For combustion turbines, the diluent cap values are 1.0 percent CO2 and 19.0 percent O2.


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.


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 a federally-enforceable permit for a plant and 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.


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, as amended August 25, 1999, EPA-600/R-97/121 (incorporated by reference, see § 72.13) or such revised procedure as approved by the Administrator.


EPA Protocol Gas Production Site means a site that produces or blends calibration gas mixtures prepared and analyzed according to section 2 of the “EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards,” September 1997, as amended August 25, 1999, EPA-600/R-97/121 (incorporated by reference, see § 72.13) or such revised procedure as approved by the Administrator.


EPA Protocol Gas Verification Program or PGVP means a calibration gas audit program described in § 75.21(g) of this chapter and implemented by EPA in cooperation with the National Institute of Standards and Technology (NIST).


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 1-1 in section 12.2 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 § 75.15 of this chapter, § 75.19 of this chapter, § 75.81(b) 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 the affected units at an affected source during a calendar year that exceeds the Acid Rain emissions limitation for sulfur dioxide for the source; 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.”


Expanded uncertainty means a measure of uncertainty that defines an interval about the measurement result y within which the value of the measurand Y can be confidently asserted to lie. Although the combined standard uncertainty uc is used to express the uncertainty of many measurement results, for some commercial, industrial, and regulatory applications (e.g., when health and safety are concerned), what is often required is an expanded uncertainty, suggested symbol U, and is obtained by multiplying uc(y) by a coverage factor, suggested symbol k. Thus U = kuc(y) and it is confidently believed that Y is greater than or equal to y − U, and is less than or equal to y + U, which is commonly written as Y = y ± U.


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).


Fuel flowmeter system means an excepted monitoring system (as defined in this section) which provides a continuous record of the flow rate of fuel oil or gaseous fuel, in accordance with appendix D to part 75 of this chapter. A fuel flowmeter system consists of one or more fuel flowmeter components, all necessary auxiliary components (e.g., transmitters, transducers, etc.), and a data acquisition and handling system (DAHS).


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.


Fuel usage time means the portion of a clock hour during which a unit combusts a particular type of fuel. The fuel usage time, in hours, is expressed as a decimal fraction, with valid values ranging from 0.00 to 1.00.


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


Hour before and hour 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, hourly NOX concentration, hourly moisture, hourly O2 concentration, or hourly NOX emission rate (as applicable) recorded by a certified monitor during the unit or stack operating hour immediately before and the unit or stack 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.


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.


Long-term cold storage means the complete shutdown of a unit intended to last for an extended period of time (at least two calendar years) where notice for long-term cold storage is provided under § 75.61(a)(7).


Low mass emissions unit means an affected unit that is “gas-fired” or “oil-fired” (as defined in this section), and that qualifies to use the low mass emissions excepted methodology in § 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 NOX emission rate or MER means the emission rate of nitrogen oxides (in lb/mmBtu) calculated in accordance with section 3 of appendix F to part 75 of this chapter, using the maximum potential nitrogen oxides concentration (MPC), as defined in section 2.1.2.1 of appendix A to 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. The diluent cap value, as defined in this section, may be used in lieu of the maximum O2 or minimum CO2 concentration to calculate the MER. As a second alternative, when the NOX MPC is determined from emission test results or from historical CEM data, as described in section 2.1.2.1 of appendix A to part 75 of this chapter, quality-assured diluent gas (i.e., O2 or CO2) data recorded concurrently with the MPC may be used to calculate the MER. For the purposes of §§ 75.4(f), 75.19(b)(3), and 75.33(c)(7) in part 75 of this chapter and section 2.5 in appendix E to part 75 of this chapter, the MER is specific to the type of fuel combusted in the unit.


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


Missing data period means the total number of consecutive hours during which any 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 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.


Multiple stack configuration refers to an exhaust configuration in which the flue gases from a particular unit discharge to the atmosphere through two or more stacks. The term also refers to a unit for which emissions are monitored in two or more ducts leading to the exhaust stack, in lieu of monitoring at the stack.


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 20.0 grains or less of total sulfur per 100 standard cubic feet. Additionally, natural gas must either be composed of at least 70 percent 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 source 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.


(4) A unit required to comply with the provisions of subpart H of part 75 of this chapter, under a State or Federal NOX mass emissions reduction program, may, pursuant to § 75.74(c)(11) in part 75 of this chapter, qualify as a peaking unit on an ozone season basis rather than an annual basis, if the owner or operator reports NOX mass emissions and heat input data only during the ozone season.


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 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, and which is provided by a supplier through a pipeline. Pipeline natural gas contains 0.5 grains or less of total sulfur per 100 standard cubic feet. Additionally, pipeline natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 950 and 1100 Btu per standard cubic foot.


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.


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).


Qualified individual (QI) means an individual who is identified by an AETB as meeting the requirements described in ASTM D 7036-04 “Standard Practice for Competence of Air Emission Testing Bodies” (incorporated by reference, see § 72.13), as of the date of testing.


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 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 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 or moisture concentration or volumetric flow measured by the pollutant concentration or flow monitor or moisture 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 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, provided that one or more combustion or process sources that have, under § 74.4(c) of this chapter, a different designated representative than the designated representative for one or more affected utility units at a source shall be treated as being included in a separate source from the source that includes such utility units for purposes of parts 72 through 78 of this chapter, but shall be treated as being included in the same source as the source that includes such utility units for purposes of section 502(c) of 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.


Specialty Gas Company means an organization that wholly or partially owns or operates one or more EPA Protocol gas production sites.


Spot allowance means an allowance that may be used for purposes of compliance with a source’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 a clock hour during which flue gases flow through a particular stack or duct (either for the entire hour or for part of the hour) while the associated unit(s) are combusting fuel.


Stack operating time means the portion of a clock hour during which flue gases flow through a particular stack or duct while the associated unit(s) are combusting fuel. The stack operating time, in hours, is expressed as a decimal fraction, with valid values ranging from 0.00 to 1.00.


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


Standard reference material or SRM means a calibration gas mixture issued and certified by NIST as having specific known chemical or physical property values.


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 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 a clock hour during which a unit combusts any fuel, either for part of the hour or for the entire hour.


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


Unit operating time means the portion of a clock hour during which a unit combusts any fuel. The unit operating time, in hours, is expressed as a decimal fraction, with valid values ranging from 0.00 to 1.00.


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]


Editorial Note:For Federal Register citations affecting § 72.2, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 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 or § 72.8 is in effect. Although such a unit is not an affected unit, the unit shall be subject to the requirements of § 72.7 or § 72.8, 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), 1200 Pennsylvania Ave., NW., 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; 66 FR 12978, Mar. 1, 2001]


§ 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 compliance account of the source that includes the unit 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.


(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:




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:


(i) For purposes of applying parts 70 and 71 of this chapter, the unit shall not be treated as an affected unit under the Acid Rain Program and shall continue to be subject to any other applicable requirements under parts 70 and 71 of this chapter.


(ii) The unit shall not be eligible to be an opt-in source under part 74 of 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 for purposes of applying parts 70 and 71 of this chapter, shall be treated as an affected unit under the Acid Rain Program:


(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, as amended at 71 FR 25377, Apr. 28, 2006; 70 FR 25334, May 12, 2005]


§ 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:


(i) For purposes of applying parts 70 and 71 of this chapter, the unit shall not be treated as an affected unit under the Acid Rain Program and shall continue to be subject to any other applicable requirements under parts 70 and 71 of this chapter.


(ii) The unit shall not be eligible to be an opt-in source under part 74 of 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 for purposes of applying parts 70 and 71 of this chapter, shall be treated as an affected unit under the Acid Rain Program:


(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, as amended at 71 FR 25377, Apr. 28, 2006]


§ 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 source or unit, as appropriate, with the Acid Rain emissions limitations and emissions reduction requirements for sulfur dioxide and nitrogen oxides under the Acid Rain Program.


(3) The requirements of part 75 of this chapter shall not affect the responsibility of the owners and operators to monitor emissions of other pollutants or other emissions characteristics at the unit under other applicable requirements of the Act and other provisions of the operating permit for the source.


(c) Sulfur Dioxide Requirements. (1) The owners and operators of each source and each affected unit at the source shall:


(i) Hold allowances, as of the allowance transfer deadline, in the source’s compliance account (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 affected units at the source; 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 or 72.8 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 source 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 source 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 or § 72.8, 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.


(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 or § 72.8 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 source can hold; provided, that the number of allowances held by the source 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; 66 FR 12978, Mar. 1, 2001; 70 FR 25334, May 12, 2005]


§ 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 Public Information Reference Unit of the U.S. EPA, 401 M St., SW., Washington, DC and at the Library (MD-35), U.S. EPA, Research Triangle Park, North Carolina or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.


(a) The following materials are available for purchase from the following address: American Society for Testing and Material (ASTM) International, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, Pennsylvania 19428-2959, phone: 610-832-9585, http://www.astm.org/DIGITAL_LIBRARY/index.shtml.


(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.


(5) ASTM D 7036-04, Standard Practice for Competence of Air Emission Testing Bodies, for § 72.2.


(b) A copy of the following material is available from http://www.epa.gov/ttn/emc/news.html (see postings for Sections 1, 2, 3, 4, Appendices, Spreadsheets, and the “Read before downloading Section 2” revision posted August 27, 1999): EPA-600/R-97/121, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards, September 1997, as amended August 25, 1999, U.S. Environmental Protection Agency, for § 72.2.


[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 26526, May 17, 1995; 62 FR 55478, Oct. 24, 1997; 76 FR 17306, Mar. 28, 2011]


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 representations, 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.


[58 FR 3650, Jan. 11, 1993, as amended at 71 FR 25378, Apr. 28, 2006]


§ 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 source or 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 compliance account.


[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 70 FR 25334, May 12, 2005]


§ 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 representation, action, inaction, or submission 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; 71 FR 25378, Apr. 28, 2006]


§ 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 representations, actions, inactions, and submissions 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 representations, actions, inactions, and submissions 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 an 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 owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions 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 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.


[58 FR 3650, Jan. 11, 1993, as amended at 71 FR 25378, Apr. 28, 2006]


§ 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, including identification and nameplate capacity of each generator served by each such unit.


(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) [Reserved]


(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 representations, actions, inactions, or submissions.”


(7) [Reserved]


(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 a life-of-the-unit, firm power contractual arrangement, 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, except that, 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) [Reserved]


(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; 71 FR 25378, Apr. 28, 2006; 70 FR 25334, May 12, 2005; 72 FR 59205, Oct. 19, 2007]


§ 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 representation, action, inaction, or submission, of the designated representative shall affect any representation, action, inaction, or submission 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; 71 FR 25378, Apr. 28, 2006]


§ 72.26 Delegation by designated representative and alternate designated representative.

(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission (in a format prescribed by the Administrator) to the Administrator provided for or required under this part and parts 73 through 77 of this chapter.


(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission (in a format prescribed by the Administrator) to the Administrator provided for or required under this part and parts 73 through 77 of this chapter.


(c) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:


(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;


(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);


(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and


(4) The following certification statements by such designated representative or alternate designated representative, as appropriate:


(i) “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 72.26(d) shall be deemed to be an electronic submission by me.”


(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 72.26(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 72.26 is terminated.”


(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.


(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.


[71 FR 25378, Apr. 28, 2006]


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;


(c) A complete compliance plan for each unit, in accordance with subpart D of this part;


(d) The standard requirements under § 72.9; and


(e) If the Acid Rain permit application is for Phase II and the unit is a new unit, the date that the unit has commenced or will commence operation and the deadline for monitor certification.


[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 compliance account of the source where the unit is located (after deductions under § 73.34(c) of this chapter) not less than the total annual emissions of sulfur dioxide from the affected units at the source. 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; 70 FR 25334, May 12, 2005]


§ 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 section 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, 1200 Pennsylvania Ave., NW., 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 repowering technology or will be permanently removed from service for replacement by a new unit with such technology; provided that the repowering 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 repowering 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.


(c) Contents. All public notices issued under this section will contain the following information:


(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 public hearing whenever the Administrator finds that such a hearing will contribute to the decision-making process by clarifying one or more significant issues affecting the draft 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 . 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, as amended at 66 FR 12978, Mar. 1, 2001]


§ 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 or affected source under the jurisdiction of the State permitting authority;


(2) Restrictions, inconsistent with the Acid Rain Program, on an affected unit’s or an affected source’s ability to sell or otherwise obligate its allowances;


(3) Requirements that an affected unit or affected source 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 or affected source;


(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.


[58 FR 3650, Jan. 11, 1993, as amended at 60 FR 17113, Apr. 4, 1995; 62 FR 55482, Oct. 24, 1997; 66 FR 12978, Mar. 1, 2001; 70 FR 25334, May 12, 2005]


§ 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, an 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, as amended at 70 FR 25334, May 12, 2005]


§ 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 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; 66 FR 12978, Mar. 1, 2001]


§ 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 during 1995 through 2005 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; 70 FR 25334, May 12, 2005]


§ 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.


(C) “Percentage change in dispatch system sales” is calculated as follows:





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);


(C) The calculation of “dispatch system adjusted utilization” under paragraph (c)(2)(i) of this section;


(D) The calculation of “dispatch system aggregate baseline” under paragraph (c)(2)(ii) of this section;


(E) The calculation of “fraction of generation within dispatch system” under paragraph (c)(2)(v)(A) of this section;


(F) The calculation of “dispatch system emissions rate” under paragraph (c)(2)(v)(B) of this section;


(G) The calculation of “fraction of generation from non-utility generators” under paragraph (c)(2)(v)(C) of this section;


(H) The calculation of “non-utility generator average emissions rate “ under paragraph (c)(2)(v)(F) of this section;


(I) A certification that each designated representative will use these figures, as appropriate, in its annual compliance certification report and will submit upon request the data supporting these calculations; and


(J) The signatures of all the designated representatives.


(c) 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;


(C) Plan reductions under a reduced utilization plan as calculated under § 72.91; and


(D) Foreign generation.


(ii) Allowances are surrendered for deduction for the portion of adjusted utilization that is not accounted for under paragraph (c)(1)(i) of this section.


(2) The designated representative shall surrender for deduction the number of allowances calculated using the following formula:


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:




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


(C) m = all Phase I units in the dispatch system having an adjusted utilization greater than 0 for the calendar year.


(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 =





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 =





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)
WSCC0.8470.466
SPP0.9480.647
SERC0.7491.315
NPCC0.4231.058
MAPP0.7251.171
MAIN0.6821.495
MAAC0.7501.599
ERCOT1.0000.491
ECAR0.5491.564

[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 repower. The designated representative of a unit governed by an approved repowering 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 repowered under an approved repowering 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 source’s compliance account 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 affected units at the source 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; 70 FR 25334, May 12, 2005]


§ 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 source’s compliance account in accordance with part 73 of this chapter based on the information in the compliance certifications and other submissions, as adjusted.


[58 FR 3650, Jan. 11, 1993, as amended at 70 FR 25334, May 12, 2005]


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 unit1.001.00
≤1 day0.930.89
1 week0.970.92
30 days1.000.96
90 days1.001.00
1 year1.001.00
Not specified0.930.89
At all times0.930.89
Coal unit: No Federal limit or limit unknown1.001.00

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/ MMBtu2.02.02.02.0
% sulfur in fuel1.662.222.861.07
Ppm SO20.002870.003840.00167
Ppm sulfur in fuel0.00334
Tons SO2/hour2,000,000/(HEATRATE*SUMNDCAP*capacity factor)
1
Lbs SO2/hour1,000/(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 Coal24 MMBtu/ton.
Subbituminous Coal18 MMBtu/ton.
Lignite Coal14 MMBtu/ton.
Residual Oil6.2 MMBtu/bbl.

Appendix C to Part 72 – Actual 1985 Yearly SO2 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, anthracite39 lbs/ton
Subbituminous35
Lignite30

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.


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:




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 × 10
6 Btu/hr × 1 kw-hr / 3413 Btu × 1 MWe / 1000 kw = 33.2 MWe


[58 FR 15649, Mar. 23, 1993]


PART 73 – SULFUR DIOXIDE ALLOWANCE SYSTEM


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, and Independent 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 compliance account for each source that includes a unit listed in table 1 of this section in the amount listed in column A to be held 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
AlabamaColbert113213357
214907403
314995405
415005405
536202978
E.C. Gaston117624476
218052488
317828482
418773507
5582651575
FloridaBig BendBB0127662748
BB0226387713
BB0326036704
Crist618695505
730846834
GeorgiaBowen1BLR548381482
2BLR533291441
3BLR698621888
4BLR698521888
Hammond18549231
28977243
38676234
436650990
Jack McDonoughMB119386524
MB220058542
Wansley1689081862
2637081722
YatesY1BR7020190
Y2BR6855185
Y3BR6767183
Y4BR8676234
Y5BR9162248
Y6BR24108652
Y7BR20915565
IllinoisBaldwin1460521245
2486951316
3466441261
Coffeen0112925349
02391021057
Grand Tower096479175
Hennepin220182545
Joppa Steam112259331
210487283
311947323
411061299
511119301
610341279
Kincaid134564934
2370631002
Meredosia0515227411
Vermilion29735263
IndianaBailly712256331
817134463
Breed120280548
Cayuga136581989
2374151011
Clifty Creek119620530
219289521
319873537
419552528
518851509
619844536
Elmer W. Stout504253115
605229141
7025883699
F.B. Culley24703127
318603503
Frank E. Ratts1SG19131247
2SG19296251
Gibson1442881197
2449561215
3450331217
4442001195
H.T. Pritchard66325171
Michigan City1225553691
Petersburg118011487
235496959
R. Gallagher17115192
27980216
37159193
48386227
Tanners CreekU427209735
Wabash River14385118
2313585
34111111
54023109
613462364
Warrick429577799
IowaBurlington110428282
Des Moines11225961
George Neal1257169
Milton L. Kapp213437363
Prairie Creek47965215
Riverside93885105
KansasQuindaro24109111
KentuckyColemanC110954296
C212502338
C312015325
Cooper17254196
214917403
E.W. Brown16923187
210623287
325413687
Elmer Smith16348172
214031379
Ghent127662748
Green River57614206
H.L. Spurlock122181599
HMP&L Station 2H112989351
H211986324
Paradise3576131557
Shawnee109902268
MarylandC.P. Crane110058272
28987243
Chalk Point121333577
223690640
Morgantown134332928
2374671013
MichiganJ.H. Campbell118773507
222453607
MinnesotaHigh Bridge64158112
MississippiJack Watson417439471
535734966
MissouriAsbury115764426
James River54722128
LaBadie1390551055
236718992
3392491061
434994946
Montrose17196194
27984216
39824266
New Madrid127497743
231625855
Sibley315170410
Sioux121976594
223067623
Thomas HillMB19980270
MB218880510
New HampshireMerrimack19922268
221421579
New JerseyB.L. England18822238
211412308
New YorkDunkirk312268332
413690370
Greenidge67342198
Milliken110876294
212083327
Northport119289521
223476634
325783697
Port Jefferson310194276
412006324
OhioAshtabula718351496
Avon Lake1112771345
1233413903
Cardinal1375681015
2420081135
Conesville14615125
25360145
36029163
4534631445
Eastlake18551231
29471256
310984297
415906430
5373491009
Edgewater135536150
Gen. J.M. Gavin1866902343
2883122387
Kyger Creek118773507
218072488
317439471
418218492
518247493
Miami Fort5-141711
5-241711
612475337
7422161141
Muskingum River116312441
215533420
315293413
412914349
5443641199
Niles17608206
29975270
Picway95404146
R.E. Burger5337191
6337191
711818319
813626368
W.H. Sammis526496716
6437731183
7473801280
Walter C. Beckjord59811265
625235682
PennsylvaniaArmstrong114031379
215024406
Brunner Island127030730
230282818
3524041416
Cheswick1381391031
Conemaugh1582171573
2647011749
Hatfield’s Ferry136835995
236338982
3392101060
Martins Creek112327333
212483337
Portland15784156
29961269
Shawville110048272
210048272
313846374
413700370
Sunbury38530230
411149301
TennesseeAllen114917403
216329441
315258412
Cumberland1844192281
2923442496
Gallatin117400470
216855455
319493527
420701559
Johnsonville17585205
107351199
27828212
38189221
47780210
58023217
67682208
78744236
88471229
96894186
West VirginiaAlbright311684316
Fort Martin1404961094
2401161084
Harrison1473411279
2449361214
3404081092
Kammer118247493
218948512
316932458
Mitchell1428231157
2443121198
M.T. Storm1425701150
234644936
3413141116
WisconsinEdgewater424099651
Genoa122103597
Nelson Dewey15852158
26504176
North Oak Creek15083137
25005135
35229141
46154166
Pulliam87312198
South Oak Creek59416254
611723317
715754426
815375415

(b) Phase II allowances. (1) The Administrator will allocate allowances to the compliance account for each source that includes a unit listed in table 2 of this section in the amount specified in table 2 column C to be held for the years 2000 through 2009.


(2) The Administrator will allocate allowances to the compliance account for each source that includes a unit listed in table 2 of this section in the amount specified in table 2 column F to be held for the years 2010 and each year thereafter.




















































(3) The owner of each unit listed in the following table shall surrender, for each allowance listed in Column A or B of such table, an allowance of the same or earlier compliance use date and shall return to the Administrator any proceeds received from allowances withheld from the unit, as listed in Column C of such table. The allowances shall be surrendered and the proceeds shall be returned by December 28, 1998.


State
Plant name
Unit
Allowances for 2000 through 2009

column (A)
Allowances for 2010 and thereafter

column (B)
Proceeds
CAEl Centro2285272$2749.48
COValmont11400
FLLauderdalePFL47767817904.74
FLLauderdalePFL57968027904.74
LAR S Nelson130340
LAR S Nelson233320
MDR P Smith9056687.37
NMMaddox**38585687.37
SDMobile**217170
VAChesterfield**8B4094114124.21
WIBlount Street7013343.68
WIBlount Street802943093.16
WIBlount Street903553436.84

[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; 70 FR 25335, May 12, 2005]


§ 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), 1200 Pennsylvania Ave., NW., 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:




(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.




(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.




(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.




(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:




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.




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




(vi) The Administrator will allocate to the ERC unit allowances equal to the lesser of the calculated number of credits in paragraphs (e)(6)(v) (A) or (B) of this section and the following limitation:




(f) 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:



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:



(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:





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 11273
RE Burger 21245
RE Burger 31286
RE Burger 41316
RE Burger 51336
RE Burger 61332
New Castle 11334
New Castle 21485
New Castle 32935
New Castle 42686
New Castle 55481

(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:





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 Allowances 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:



[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:



(3) On or after June 1, 1998, monetary proceeds from the auctions of allowances from the Special Allowance Reserve (under subpart E of this part) for use in calendar years 2000 through 2009 will be distributed to the designated representative of each unit listed in Table 2 according to the following equation:



(4) Monetary proceeds from the auctions of allowances from the Special Allowance Reserve (under subpart E of this part) from years of purchase from 1993 through 1998, remaining in the U.S. Treasury as a result of the surrender of allowances and return of proceeds under § 73.10(b)(3), will be distributed to the designated representative of each unit listed in Table 2 according to the following equation:



(5) Monetary proceeds from the auctions of allowances from the Special Allowance Reserve (under subpart E of this part) for use in calendar years 2010 and thereafter will be distributed to the designated representative of each unit listed in Table 2 according to the following equation:



(c) 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:



(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 compliance account of the source that includes the unit according to the following equation:



(4) [Reserved]


(5) Allowances, for use in calendar years 2010 and thereafter, remaining in the Special Allowance Reserve at the end of each year, following that year’s auction (under subpart E of this part), will be reallocated to the compliance account of the source that includes the unit according to the following equation:



(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; 70 FR 25335, May 12, 2005]


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 compliance accounts for all affected sources 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 source’s compliance account.


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


[58 FR 3687, Jan. 11, 1993; 58 FR 40747, July 30, 1993, as amended at 70 FR 25335, May 12, 2005]


§ 73.31 Establishment of accounts.

(a) Existing affected units. The Administrator will establish a compliance account and allocate allowances for each source that includes a 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 a compliance account for the source that includes the unit, unless the source already has a compliance account.


(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 general 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 representations, actions, inactions, or submissions under 40 CFR part 73. 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, as amended at 71 FR 25378, Apr. 28, 2006; 70 FR 25335, May 12, 2005]


§ 73.32 [Reserved]

§ 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)-(c) [Reserved]


(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 representation, action, inaction, or submission by the alternate authorized account representative when acting in that capacity shall be deemed to be a representation, action, inaction, or submission 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 representations, actions, inactions, or submissions 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 representation, action, inaction, or submission to the Administrator by the authorized account representative shall affect any representation, action, inaction, or submission of 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.


(g) Delegation by authorized account representative and alternate authorized account representative. (1) An authorized account representative may delegate, to one or more natural persons, his or her authority to make an electronic submission (in a format prescribed by the Administrator) to the Administrator provided for or required under this part.


(2) An alternate authorized account representative may delegate, to one or more natural persons, his or her authority to make an electronic submission (in a format prescribed by the Administrator) to the Administrator provided for or required under this part.


(3) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (g)(1) or (2) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:


(i) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;


(ii) The name, address, e-mail address, telephone number, and, facsimile transmission number (if any) of each such natural person (referred to as an “agent”);


(iii) For each such natural person, a list of the type or types of electronic submissions under paragraph (g)(1) or (2) of this section for which authority is delegated to him or her;


(iv) The following certification statements by such authorized account representative or alternate authorized account representative:


(A) “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a authorized account representative or alternate authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 73.33(g)(4) shall be deemed to be an electronic submission by me.”


(B) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 73.33(g)(4), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 73.33(g) is eliminated.”


(4) A notice of delegation submitted under paragraph (g)(3) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.


(5) Any electronic submission covered by the certification in paragraph (g)(3)(iv)(A) of this section and made in accordance with a notice of delegation effective under paragraph (g)(4) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.


[58 FR 3691, Jan. 11, 1993, as amended at 71 FR 25378, Apr. 28, 2006]


§ 73.34 Recordation in accounts.

(a) After a compliance account is established under § 73.31(a) or (b), the Administrator will record in the compliance account any allowance allocated to any affected unit at the source for 30 years starting with the later of 1995 or the year in which the compliance account is established and any allowance allocated for 30 years starting with the later of 1995 or the year in which the compliance account is established and transferred to the source with the transfer submitted in accordance with § 73.50. In 1996 and each year thereafter, after Administrator has completed the deductions pursuant to § 73.35(b), the Administrator will record in the compliance account any allowance allocated to any affected unit at the source for the new 30th year (i.e., the year that is 30 years after the calendar year for which such deductions are made) and any allowance allocated for the new 30th year and transferred to the source with the transfer submitted in accordance with § 73.50.


(b) After a general account is established under § 73.31(c), the Administrator will record in the general account any allowance allocated for 30 years starting with the later of 1995 or the year in which the general account is established and transferred to the general account with the transfer submitted in accordance with § 73.50. In 1996 and each year thereafter, after the Administrator has completed the deductions pursuant to § 73.35(b), the Administrator will record in the general account any allowance allocated for the new 30th year (i.e., the year that is 30 years after the calendar year for which such deductions are made) and transferred to the general account with the transfer submitted in accordance with § 73.50.


(c) Allowances in each compliance account and general account subaccounts will reflect:


(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; 70 FR 25335, May 12, 2005]


§ 73.35 Compliance.

(a) Allowance transfer deadline. No allowance shall be deducted for purposes of compliance with an affected source’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 source’s SO2 emissions occurred; and


(2) The allowance is:


(i) Recorded in the source’s compliance account; or


(ii) Transferred to the source’s compliance account, with the transfer submitted correctly pursuant to subpart D of this part for recordation in the source’s compliance account by not later than the allowance transfer deadline in the calendar year following the year for which compliance is being established; and


(3) The allowance was not previously deducted by the Administrator in accordance with a State SO2 mass emissions reduction program under § 51.124(o) of this chapter or otherwise permanently retired in accordance with § 51.124(p) of this chapter.


(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 account pursuant to paragraph (a) of this section and subpart D of this part, the Administrator will deduct allowances available for deduction under paragraph (a) of this section from each affected source’s compliance account 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 available for deduction under paragraph (a) of this section remain in the compliance account.


(c)(1) Identification of allowances by serial number. The authorized account representative for a source’s compliance account may request that specific allowances, identified by serial number, in the compliance account be deducted for a calendar year in accordance with paragraph (b) or (d) of this section. Such request shall be submitted to the Administrator by the allowance transfer deadline for the year and include, in a format prescribed by the Administrator, the identification of the source and the appropriate serial numbers.


(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 units at the source and recorded in the source’s compliance account. Following the deduction of all originally allocated allowances from the compliance account, the Administrator will deduct those allowances that were transferred and recorded in the source’s compliance account 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 source with excess emissions for the preceding calendar year in an amount equal to the source’s excess emissions tonnage.


[58 FR 3691, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 64 FR 25842, May 13, 1999; 70 FR 25335, May 12, 2005]


§ 73.36 Banking.

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


(b) General accounts. In the case of a general account, any allowances in the general account not transferred pursuant to subpart D to another Allowance Tracking System account will remain in the general account.


[58 FR 3691, Jan. 11, 1993, as amended at 70 FR 25336, May 12, 2005]


§ 73.37 Account error.

The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Tracking System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.


[70 FR 25336, May 12, 2005]


§ 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 close the general account.


(b) Inactive accounts. If a general account shows no activity for a 12-month period or longer and does not contain any allowances, the Administrator may notify the account’s authorized account representative that the account will be closed 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.


[58 FR 3691, Jan. 11, 1993, as amended at 70 FR 25336, May 12, 2005]


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.


(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;


(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 account listed herein, except that I do not waive any 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.”


[58 FR 3694, Jan. 11, 1993, as amended at 63 FR 68404, Dec. 11, 1998; 70 FR 25336, May 12, 2005]


§ 73.51 [Reserved]

§ 73.52 EPA recordation.

(a) General recordation. Except as provided in this paragraph (a), the Administrator will record an allowance transfer by no later than five business days (or longer as necessary to perform a transfer in perpetuity of allowances allocated to a unit) 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 transfer is correctly submitted under § 73.50;


(2) The transferor account includes each allowance identified by serial number in the transfer; and


(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.


(b) To the extent an allowance transfer submitted for recordation after the allowance transfer deadline includes allowances allocated for any year before the year in which the allowance transfer deadline occurs, the transfer of such allowance will not be recorded until after completion of the deductions pursuant to § 73.35(b) for year before the year in which the allowance transfer deadline occurs.


(c) Where an allowance transfer submitted for recordation fails to meet the requirements of paragraph (a) of this section, the Administrator will not record such transfer.


[58 FR 3694, Jan. 11, 1993, as amended at 60 FR 17114, Apr. 4, 1995; 70 FR 25336, May 12, 2005]


§ 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*
199350,000
a
100,000
b
199450,000
a
100,000
b
25,000
c
199550,000
a
100,000
b
25,000
c
1996150,000100,000
b
25,000
c
1997150,000125,000
b
25,000
c
1998150,000125,000
b
1999150,000125,000
b
2000 and after125,000125,000
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.


(f) Transfer of allowances. Allowances will be transferred from the Auction Subaccount and from the Allowance Tracking System account 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 source that includes a 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; 70 FR 25336, May 12, 2005]


§ 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:





(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.


(c) Verification of energy savings methodology. For the purposes of paragraph (a)(11) of this section:


(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:




(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:




(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.


Appendix A to Subpart F of Part 73 – 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.


1.1 Residential

1.1.1 Space 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


1.1.2 Water 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


1.1.3 Lighting

• Lamp replacement


• Dimmers


• Motion detectors and occupancy sensors


• Photovoltaic lighting


• Fixture replacement


• Outdoor lighting controls


1.1.4 Building 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


1.1.5 Other 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


1.2 Commercial

1.2.1 Heating/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


1.2.2 Building 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


1.2.3 Lighting

• 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


1.2.4 Refrigeration

• 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


1.2.5 Water 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


1.2.6 Other 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


1.3 Industial

1.3.1 Motors

• 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


1.3.2 Lighting

• 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


1.3.3 Heating/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


1.3.4 Industrial 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


1.3.5 Building Envelope

• Insulation of ceiling, walls, and ducts


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


• Caulking/weatherstripping


1.3.6 Water 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


1.3.7 Other End-uses and miscellaneous

• Refrigeration system retrofit/replacement


• Energy management control systems and end use metering


• Customer-owned transformer retrofits/replacements and proper sizing


1.4 Agricultural

1.4.1 Space 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


1.4.2 Water 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


1.4.3 Lighting

• Electronic ballast replacements


• Delamping


• Reflectors


• Occupancy sensors


• Daylighting with controls


• Photovoltaic lighting


• Outdoor lighting controls


1.4.4 Pumping/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


1.4.5 Motors

• 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


1.4.6 Other 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


1.5 Government Services Sector

1.5.1 Streetlighting

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


1.5.2 Other

• 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:


2.1 Generation 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


2.2 Transmission 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.


3.1 Biomass 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.


3.2 Solar 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.


3.4 Geothermal resources

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


3.5 Wind 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:





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:



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


PART 74 – SULFUR DIOXIDE OPT-INS


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 or § 72.8 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; 66 FR 12978, Mar. 1, 2001]


§ 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.


[60 FR 17115, Apr. 4, 1995, as amended at 63 FR 18841, Apr. 16, 1998; 71 FR 25379, Apr. 28, 2006]


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.


(c) [Reserved]


(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.


(c) Conditions for withdrawal. In order for an opt-in source to withdraw, the following conditions must be met:


(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.


(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; 70 FR 25336, May 12, 2005]


§ 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:




where,

(i) for a combustion source submitting monthly data,




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,




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:





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) SO2 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 SO2 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,




(2) For a combustion source submitting annual data:





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




[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/mmBtu2.02.02.02.0
% Sulfur in fuel1.662.222.861.07
ppm SO20.002870.003840.00167
ppm Sulfur in fuel0.00334
tons SO2/hour2 × 8760/(annual fuel consumption for specified year
1 × 10
3)
lbs SO2/hour8760/(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 combination1.001.00
Coal Unit with Averaging Time ≤ 1 day0.930.89
Coal Unit with Averaging Time = 1 week0.970.92
Coal Unit with Averaging Time = 30 days1.000.96
Coal Unit with Averaging Time = 90 days1.001.00
Coal Unit with Averaging Time = 1 year1.001.00
Coal Unit with Federal Limit, but Averaging Time Not Specified0.930.89

(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 SO2 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;


(c) Averaging time associated with the allowable emissions rate under paragraph (a) of this section.


§ 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;


(c) Averaging time associated with the emissions limit under paragraph (a) of this section.


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


§ 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:




(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:




(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:




[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



(1) For combustion sources that commenced operations before January 1, 1985,




(2) For combustion sources that commenced operations after January 1, 1985,




(3) Under paragraphs (b) (1) and (2) of this section,


(i) “Remaining calendar quarters” shall be the calendar quarters in the first year for which the opt-in permit will be effective.


(ii) Fuel consumption for remaining calendar quarters =





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 a compliance account under paragraph (b) of this section, the Administrator will establish a compliance account (unless the source that includes the opt-in source already has a compliance account or the opt-in source has, under § 74.4(c), a different designated representative than the designated representative for the source) and allocate allowances in accordance with subpart C of this part for combustion sources or subpart D of this part for process sources.


(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 compliance account (unless the source that includes the opt-in source already has a compliance account or the opt-in source has, under § 74.4(c), a different designated representative than the designated representative for the source)to the Administrator.


[60 FR 17115, Apr. 4, 1995, as amended at 70 FR 25336, May 12, 2005]


§ 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 Limitation on transfers.

(a) With regard to a transfer request submitted for recordation during the period starting January 1 and ending with the allowance transfer deadline in the same year, the Administrator will not record a transfer of an opt-in allowance that is allocated to an opt-in source for the year in which the transfer request is submitted or a subsequent year.


(b) With regard to a transfer request during the period starting with the day after an allowance transfer deadline and ending December 31 in the same year, the Administrator will not record a transfer of an opt-in allowance that is allocated to an opt-in source for a year after the year in which the transfer request is submitted.


[70 FR 25336, May 12, 2005]


§ 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.


(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) In an annual compliance certification report for a year during 1995 through 2005, 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) In an annual compliance certification report for a year during 1995 through 2005, 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;


(5) If a change is required to be reported under paragraph (c)(4) of this section, specify the nature of the change, the reason for the change, when the change occurred, and how the unit’s compliance status was determined subsequent to the change, including what method was used to determine emissions when a change mandated the need for monitoring recertification; and


(6) When applicable, whether the opt-in source was operating in compliance with its thermal energy plan as provided in § 74.47 for combustion sources and § 74.48 for process sources.


[60 FR 17115, Apr. 4, 1995, as amended at 70 FR 25337, May 12, 2005]


§ 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:





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





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,




“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.

(C) Average utilization for the third year after opt-in





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 =




(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 account identification number in the Allowance Tracking System of the source that includes the opt-in source;


(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 compliance account of the source that includes the opt-in source calculated using the following formula:


Allowances credited for the calendar year in which the reduced utilization occurred =




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 compliance account of the source that includes the opt-in source, 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 compliance account of the source that includes the opt-in source 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:





where:

“Allowances held after deduction” shall be the amount of allowances held in the compliance account of the source that includes the opt-in source 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 compliance account of the source that includes the opt-in source the amount of allowances that he or she determines is necessary to offset any increase in excess emissions or will return immediately to the compliance account of the source that includes the opt-in source 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 compliance account of the source that includes the opt-in source shall be calculated as follows:


Adjusted amount of allowances =



where,

“Allowances allocated or acquired” shall be the number of allowances held in the compliance account of the source that includes the opt-in source 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; 70 FR 25337, May 12, 2005]


§ 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) [Reserved]


[60 FR 17115, Apr. 4, 1995, as amended at 70 FR 25337, May 12, 2005]


§ 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 account identification number in the Allowance Tracking System of the source that includes the opt-in source;


(v) The account identification number in the Allowance Tracking System of each source that includes a replacement unit;


(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 compliance account of each source that includes a 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:




(2) Fuel associated with qualifying thermal energy. The fuel associated with the qualifying thermal energy at each replacement unit shall be calculated as follows:





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:





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 compliance account of the source that includes the replacement unit of the replacement unit to any other Allowance Tracking System account.


(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;


(C) The account identification number in the Allowance Tracking System of the source that includes the opt-in source;


(D) The account identification number in the Allowance Tracking System of each source that includes a 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 compliance account for each source that includes the opt-in source or a 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 compliance account of the source that includes 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 compliance account for each source that includes the opt-in source or a 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; 70 FR 25337, May 12, 2005]


§ 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 the compliance account of a source that includes an opt-in source 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]


[60 FR 17115, Apr. 4, 1995, as amended at 70 FR 25337, May 12, 2005]


§ 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 source that includes 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 compliance account of the source that includes the opt-in source 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 compliance account of the source that includes the opt-in source.


(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 the source that includes the 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; 70 FR 25337, May 12, 2005]


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]

PART 75 – CONTINUOUS EMISSION MONITORING


Authority:42 U.S.C. 7601 and 7651K, and 7651K note.


Source:58 FR 3701, Jan. 11, 1993, unless otherwise noted.


Editorial Note:Nomenclature changes to part 75 appear at 67 FR 40476, June 12, 2002.

Subpart A – General

§ 75.1 Purpose and scope.

(a) Purpose. The purpose of this part is to establish requirements for the monitoring, recordkeeping, and reporting of sulfur dioxide (SO2), nitrogen oxides (NOX), and carbon dioxide (CO2) emissions, volumetric flow, and opacity data from affected units under the Acid Rain Program pursuant to sections 412 and 821 of the CAA, 42 U.S.C. 7401-7671q as amended by Public Law 101-549 (November 15, 1990) [the Act]. In addition, this part sets forth provisions for the monitoring, recordkeeping, and reporting of NOX mass emissions with which EPA, individual States, or groups of States may require sources to comply in order to demonstrate compliance with a NOX mass emission reduction program, to the extent these provisions are adopted as requirements under such a program.


(b) Scope. (1) The regulations established under this part include general requirements for the installation, certification, operation, and maintenance of continuous emission or opacity monitoring systems and specific requirements for the monitoring of SO2 emissions, volumetric flow, NOX emissions, opacity, CO2 emissions and SO2 emissions removal by qualifying Phase I technologies. Specifications for the installation and performance of continuous emission monitoring systems, certification tests and procedures, and quality assurance tests and procedures are included in appendices A and B to this part. Criteria for alternative monitoring systems and provisions to account for missing data from certified continuous emission monitoring systems or approved alternative monitoring systems are also included in the regulation.


(2) Statistical estimation procedures for missing data are included in appendix C to this part. Optional protocols for estimating SO2 mass emissions from gas-fired or oil-fired units and NOX emissions from gas-fired peaking or oil-fired peaking units are included in appendices D and E, respectively, to this part. Requirements for recording and recordkeeping of monitoring data and for quarterly electronic reporting also are specified. Procedures for conversion of monitoring data into units of the standard are included in appendix F to this part. Procedures for the monitoring and calculation of CO2 emissions are included in appendix G of this part.


[58 FR 3701, Jan. 11, 1993; 58 FR 34126, June 23, 1993; 58 FR 40747, July 30, 1993; 63 FR 57498, Oct. 27, 1999; 67 FR 40421, June 12, 2002]


§ 75.2 Applicability.

(a) Except as provided in paragraphs (b) and (c) of this section, the provisions of this part apply to each affected unit subject to Acid Rain emission limitations or reduction requirements for SO2 or NOX.


(b) The provisions of this part do not apply to:


(1) A new unit for which a written exemption has been issued under § 72.7 of this chapter (any new unit that serves one or more generators with total nameplate capacity of 25 MWe or less and burns only fuels with a sulfur content of 0.05 percent or less by weight may apply to the Administrator for an exemption); or


(2) Any unit not subject to the requirements of the Acid Rain Program due to operation of any paragraph of § 72.6(b) of this chapter; or


(3) An affected unit for which a written exemption has been issued under § 72.8 of this chapter and an exception granted under § 75.67 of this part.


(c) The provisions of this part apply to sources subject to a State or federal NOX mass emission reduction program, to the extent these provisions are adopted as requirements under such a program.


[58 FR 3701, Jan. 11, 1993, as amended at 58 FR 15716, Mar. 23, 1993; 60 FR 26516, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 70 FR 28678, May 18, 2005; 76 FR 17306, Mar. 28, 2011]


§ 75.3 General Acid Rain Program provisions.

The provisions of part 72, including the following, shall apply to this part:


(a) § 72.2 (Definitions);


(b) § 72.3 (Measurements, Abbreviations, and Acronyms);


(c) § 72.4 (Federal Authority);


(d) § 72.5 (State Authority);


(e) § 72.6 (Applicability);


(f) § 72.7 (New Unit Exemption);


(g) § 72.8 (Retired Units Exemption);


(h) § 72.9 (Standard Requirements);


(i) § 72.10 (Availability of Information); and


(j) § 72.11 (Computation of Time).


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


§ 75.4 Compliance dates.

(a) The provisions of this part apply to each existing Phase I and Phase II unit on February 10, 1993. For substitution or compensating units that are so designated under the Acid Rain permit which governs that unit and contains the approved substitution or reduced utilization plan, pursuant to § 72.41 or § 72.43 of this chapter, the provisions of this part become applicable upon the issuance date of the Acid Rain permit. For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter, the provisions of this part become applicable upon the submission of an opt-in permit application in accordance with § 74.14 of this chapter. The provisions of this part for the monitoring, recording, and reporting of NOX mass emissions become applicable on the deadlines specified in the applicable State or federal NOX mass emission reduction program, to the extent these provisions are adopted as requirements under such a program. In accordance with § 75.20, the owner or operator of each existing affected unit shall ensure that all monitoring systems required by this part for monitoring SO2, NOX, CO2, opacity, moisture and volumetric flow are installed and that all certification tests are completed no later than the following dates (except as provided in paragraphs (d) through (i) of this section):


(1) For a unit listed in table 1 of § 73.10(a) of this chapter, November 15, 1993.


(2) For a substitution or a compensating unit that is designated under an approved substitution plan or reduced utilization plan pursuant to § 72.41 or § 72.43 of this chapter, or for a unit that is designated an early election unit under an approved NOX compliance plan pursuant to part 76 of this chapter, that is not conditionally approved and that is effective for 1995, the earlier of the following dates:


(i) January 1, 1995; or


(ii) 90 days after the issuance date of the Acid Rain permit (or date of approval of permit revision) that governs the unit and contains the approved substitution plan, reduced utilization plan, or NOX compliance plan.


(3) For either a Phase II unit, other than a gas-fired unit or an oil-fired unit, or a substitution or compensating unit that is not a substitution or compensating unit under paragraph (a)(2) of this section: January 1, 1995.


(4) For a gas-fired Phase II unit or an oil-fired Phase II unit, January 1, 1995, except that installation and certification tests for continuous emission monitoring systems for NOX and CO2 or excepted monitoring systems for NOX under appendix E or CO2 estimation under appendix G of this part shall be completed as follows:


(i) For an oil-fired Phase II unit or a gas-fired Phase II unit located in an ozone nonattainment area or the ozone transport region, not later than July 1, 1995; or


(ii) For an oil-fired Phase II unit or a gas-fired Phase II unit not located in an ozone nonattainment area or the ozone transport region, not later than January 1, 1996.


(5) For combustion sources seeking to enter the Opt-in Program in accordance with part 74 of this chapter, the expiration date of a combustion source’s opt-in permit under § 74.14(e) of this chapter.


(b) In accordance with § 75.20, the owner or operator of each new affected unit shall ensure that all monitoring systems required under this part for monitoring of SO2, NOX, CO2, opacity, and volumetric flow are installed and all certification tests are completed on or before the later of the following dates:


(1) January 1, 1995, except that for a gas-fired unit or oil-fired unit located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NOX and CO2 monitoring systems shall be July 1, 1995 and for a gas-fired unit or an oil-fired unit not located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NOX and CO2 monitoring systems shall be January 1, 1996; or


(2) 180 calendar days after the date the unit commences commercial operation, notice of which date shall be provided under subpart G of this part.


(c) In accordance with § 75.20, the owner or operator of any unit affected under any paragraph of § 72.6(a)(3) (ii) through (vii) of this chapter shall ensure that all monitoring systems required under this part for monitoring of SO2, NOX, CO2, opacity, and volumetric flow are installed and all certification tests are completed on or before the later of the following dates:


(1) January 1, 1995, except that for a gas-fired unit or oil-fired unit located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NOX and CO2 monitoring systems shall be July 1, 1995 and for a gas-fired unit or an oil-fired unit not located in an ozone nonattainment area or the ozone transport region, the date for installation and completion of all certification tests for NOX and CO2 monitoring systems shall be January 1, 1996; or


(2) 180 calendar days after the date on which the unit becomes subject to the requirements of the Acid Rain Program, notice of which date shall be provided under subpart G of this part.


(d) This paragraph (d) applies to affected units under the Acid Rain Program and to units subject to a State or Federal pollutant mass emissions reduction program that adopts the emission monitoring and reporting provisions of this part. In accordance with § 75.20, for an affected unit which, on the applicable compliance date, is either in long-term cold storage (as defined in § 72.2 of this chapter) or is shut down as the result of a planned outage or a forced outage, thereby preventing the required continuous monitoring system certification tests from being completed by the compliance date, the owner or operator shall provide notice of such unit storage or outage in accordance with § 75.61(a)(3) or § 75.61(a)(7), as applicable. For the planned and unplanned unit outages described in this paragraph (d), the owner or operator shall ensure that all of the continuous monitoring systems for SO2, NOX, CO2, opacity, and volumetric flow rate required under this part (or under the applicable State or Federal mass emissions reduction program) are installed and that all required certification tests are completed no later than 90 unit operating days or 180 calendar days (whichever occurs first) after the date that the unit recommences commercial operation, notice of which date shall be provided under § 75.61(a)(3) or § 75.61(a)(7), as applicable. The owner or operator shall determine and report SO2 concentration, NOX emission rate, CO2 concentration, and flow rate data (as applicable) for all unit operating hours after the applicable compliance date until all of the required certification tests are successfully completed, using either:


(1) The maximum potential concentration of SO2 (as defined in section 2.1.1.1 of appendix A to this part), the maximum potential NOX emission rate, as defined in § 72.2 of this chapter, the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part, or the maximum potential CO2 concentration, as defined in section 2.1.3.1 of appendix A to this part; or


(2) The conditional data validation provisions of § 75.20(b)(3); or


(3) Reference methods under § 75.22(b); or


(4) Another procedure approved by the Administrator pursuant to a petition under § 75.66.


(e) In accordance with § 75.20, if the owner or operator of an affected unit completes construction of a new stack or flue, or a flue gas desulfurization system or add-on NOX emission controls, after the applicable deadline in paragraph (a), (b), or (c) of this section:


(1) Except as otherwise provided in paragraph (e)(3) of this section, the owner or operator shall ensure that all required certification and/or recertification and/or diagnostic tests of the monitoring systems required under this part (i.e., the SO2, NOX, CO2, O2, opacity, volumetric flow rate, and moisture monitoring systems, as applicable) are completed not later than 90 unit operating days or 180 calendar days (whichever occurs first) after:


(i) For the event of construction of a new stack or flue, the date that emissions first exit to the atmosphere through the new stack or flue, notice of which date shall be provided under subpart G of this part; or


(ii) For the event of installation of a flue gas desulfurization system or add-on NOX emission controls, the date that reagent is first injected into the flue gas desulfurization system or the add-on NOX emission controls, as applicable, notice of which date shall be provided under subpart G of this part.


(2) The owner or operator shall determine and report, as applicable, SO2 concentration, NOX concentration, NOX emission rate, CO2 concentration, O2 concentration, volumetric flow rate, and moisture data for all unit or stack operating hours after emissions first pass through the new stack or flue, or reagent is first injected into the flue gas desulfurization system or add-on NOX emission controls, as applicable, until all required certification and/or recertification and/or diagnostic tests are successfully completed, using:


(i) Quality-assured data recorded by a previously-certified monitoring system for which the event requires no additional testing;


(ii) The applicable missing data substitution procedures under §§ 75.31 through 75.37;


(iii) The conditional data validation procedures of § 75.20(b)(3), except that conditional data validation may, if necessary, be used for the entire window of time provided under paragraph (e)(1) of this section in lieu of the periods specified in § 75.20(b)(3)(iv);


(iv) Reference methods under § 75.22(b);


(v) For the event of installation of a flue gas desulfurization system or add-on NOX emission controls, quality-assured data recorded on the high measurement scale of the monitor that measures the pollutant being removed by the add-on emission controls (i.e., SO2 or NOX, as applicable), if, pursuant to section 2 of appendix A to this part, two spans and ranges are required for that monitor and if the high measurement scale of the monitor has been certified according to § 75.20(c), section 6 of appendix A to this part, and, if applicable, paragraph (e)(4)(i) of this section. Data recorded on the certified high scale that ordinarily would be required to be recorded on the low scale, pursuant to section 2.1.1.4(g) or 2.1.2.4(f) of appendix A to this part, may be reported as quality-assured for a period not to exceed 60 unit or stack operating days after the date and hour that reagent is first injected into the control device, after which one or more of the options provided in paragraphs (e)(2)(ii), (e)(2)(iii), (e)(2)(iv) and (e)(2)(vi) of this section must be used to report SO2 or NOX concentration data (as applicable) for each operating hour in which these low emissions occur, until certification testing of the low scale of the monitor is successfully completed; or


(vi) Another procedure approved by the Administrator pursuant to a petition under § 75.66.


(3) If a particular project involves both the event of new stack or flue construction and the event of installation of a flue gas desulfurization system or add-on NOX emission controls, the owner or operator shall either:


(i) Complete all of the monitoring system certification and/or recertification and/or diagnostic testing requirements of both events within the window of time provided under paragraph (e)(1)(i) of this section; or


(ii) Complete all of the monitoring system certification and/or recertification and/or diagnostic testing requirements of each event within the separate window of time applicable to such event provided under paragraph (e)(1) of this section.


(4) For the project described in paragraph (e)(3) of this section, the emissions data from each CEMS installed on the new stack recorded in the interval of time starting on the date and hour on which emissions first exit to the atmosphere through the new stack and ending on the hour before the date and hour on which reagent is first injected into the control device may be reported as quality assured:


(i) For the CEMS that includes the monitor that measures the pollutant being removed by the add-on emission controls (i.e., SO2 or NOX, as applicable):


(A) Only if the relative accuracy test audit (RATA) of the high measurement scale of the monitor is successfully completed either prior to the date and hour of the first injection of reagent into the emission control device, or after that date and hour during a period when the control device is not operating, but still within the window of time provided under paragraph (e)(1)(i) of this section, and the rest of the certification tests required under § 75.20(c) and section 6 of appendix A to this part for the high measurement scale of the monitor are successfully completed within the window of time provided under paragraph (e)(1)(i) of this section;


(B) Beginning with:


(1) The first unit or stack operating hour after successful completion of all of the certification tests in accordance with paragraph (e)(4)(i)(A) of this section; or


(2) The hour of the probationary calibration error test (see § 75.20(b)(3)(ii)), if conditional data validation is used and all of the certification tests are successfully completed in accordance with paragraph (e)(4)(i)(A) of this section, with no test failures. If any required test is failed or aborted or is otherwise not in accordance with paragraph (e)(4)(i)(A) of this section, data validation shall be done according to § 75.20(b)(3)(vii).


(ii) For a CEMS other than one addressed in paragraph (e)(4)(i) of this section:


(A) Only if the relative accuracy test audit (RATA) of the CEMS is successfully completed either prior to the date and hour of the first injection of reagent into the emission control device, or after that date and hour during a period when the control device is not operating, but still within the window of time provided under paragraph (e)(1)(i) of this section, and the rest of the certification tests required under § 75.20(c) and section 6 of appendix A to this part for the CEMS are successfully completed within the window of time provided under paragraph (e)(1)(i) of this section;


(B) Beginning with:


(1) The first unit or stack operating hour after successful completion of all of the certification tests in accordance with paragraph (e)(4)(ii)(A) of this section; or


(2) The hour of the probationary calibration error test (see § 75.20(b)(3)(ii)), if conditional data validation is used and all of the certification tests are successfully completed in accordance with paragraph (e)(4)(ii)(A) of this section, with no test failures. If any required test is failed or aborted or is otherwise not in accordance with paragraph (e)(4)(ii)(A) of this section, data validation shall be done according to § 75.20(b)(3)(vii).


(f) In accordance with § 75.20, the owner or operator of an affected gas-fired or oil-fired peaking unit, if planning to use appendix E of this part, shall ensure that the required certification tests for excepted monitoring systems under appendix E are completed for backup fuel, as defined in § 72.2 of this chapter, no later than 90 unit operating days or 180 calendar days (whichever occurs first) after the date that the unit first combusts the backup fuel following the certification testing with the primary fuel. If the required testing is completed by this deadline, the appendix E correlation curve derived from the test results may be used for reporting data under this part beginning with the first date and hour that the backup fuel is combusted, provided that the fuel flowmeter for the backup fuel was certified as of that date and hour. If the required appendix E testing has not been successfully completed by the compliance date in this paragraph, then, until the testing is completed, the owner or operator shall report NOX emission rate data for all unit operating hours that the backup fuel is combusted using either:


(1) The fuel-specific maximum potential NOX emission rate, as defined in § 72.2 of this chapter; or


(2) Reference methods under § 75.22(b) of this part; or


(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.


(g) The provisions of this paragraph shall apply unless an owner or operator is exempt from certifying a fuel flowmeter for use during combustion of emergency fuel under section 2.1.4.3 of appendix D to this part, in which circumstance the provisions of section 2.1.4.3 of appendix D shall apply. In accordance with § 75.20, whenever the owner or operator of a gas-fired or oil-fired unit uses an excepted monitoring system under appendix D or E of this part and combusts emergency fuel as defined in § 72.2 of this chapter, then the owner or operator shall ensure that a fuel flowmeter measuring emergency fuel is installed and the required certification tests for excepted monitoring systems are completed by no later than 30 unit operating days after the first date after January 1, 1995 that the unit combusts emergency fuel. For all unit operating hours that the unit combusts emergency fuel after January 1, 1995 until the owner or operator installs a flowmeter for emergency fuel and successfully completes all required certification tests, the owner or operator shall determine and report SO2 mass emission data using either:


(1) The maximum potential fuel flow rate, as described in appendix D of this part, and the maximum sulfur content of the fuel, as described in section 2.1.1.1 of appendix A of this part;


(2) Reference methods under § 75.22(b) of this part; or


(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.


(h) [Reserved]


(i) In accordance with § 75.20, the owner or operator of each affected unit at which SO2 concentration is measured on a dry basis or at which moisture corrections are required to account for CO2 emissions, NOX emission rate in lb/mmBtu, heat input, or NOX mass emissions for units in a NOX mass reduction program, shall ensure that the continuous moisture monitoring system required by this part is installed and that all applicable initial certification tests required under § 75.20(c)(5), (c)(6), or (c)(7) for the continuous moisture monitoring system are completed no later than the following dates:


(1) April 1, 2000, for a unit that is existing and has commenced commercial operation by January 2, 2000;


(2) For a new affected unit which has not commenced commercial operation by January 2, 2000, 90 unit operating days or 180 calendar days (whichever occurs first) after the date the unit commences commercial operation; or


(3) For an existing unit that is shutdown and is not yet operating by April 1, 2000, 90 unit operating days or 180 calendar days (whichever occurs first) after the date that the unit recommences commercial operation.


(j) If the certification tests required under paragraph (b) or (c) of this section have not been completed by the applicable compliance date, the owner or operator shall determine and report SO2 concentration, NOX emission rate, CO2 concentration, and flow rate data for all unit operating hours after the applicable compliance date in this paragraph until all required certification tests are successfully completed using either:


(1) The maximum potential concentration of SO2, as defined in section 2.1.1.1 of appendix A to this part, the maximum potential NOX emission rate, as defined in § 72.2 of this chapter, the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part, or the maximum potential CO2 concentration, as defined in section 2.1.3.1 of appendix A to this part;


(2) Reference methods under § 75.22(b); or


(3) Another procedure approved by the Administrator pursuant to a petition under § 75.66.


[60 FR 17131, Apr. 4, 1995, as amended at 60 FR 26516, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 64 FR 28588, May 26, 1999; 67 FR 40421, June 12, 2002; 73 FR 4340, Jan. 24, 2008; 76 FR 17306, Mar. 28, 2011; 76 FR 50132, Aug. 12, 2011]


§ 75.5 Prohibitions.

(a) A violation of any applicable regulation in this part by the owners or operators or the designated representative of an affected source or an affected unit is a violation of the Act.


(b) No owner or operator of an affected unit shall operate the unit without complying with the requirements of §§ 75.2 through 75.75 and appendices A through G to this part.


(c) No owner or operator of an affected unit shall use any alternative monitoring system, alternative reference method, or any other alternative for the required continuous emission monitoring system without having obtained the Administrator’s prior written approval in accordance with §§ 75.23, 75.48 and 75.66.


(d) No owner or operator of an affected unit shall operate the unit so as to discharge, or allow to be discharged, emissions of SO2, NOX or CO2 to the atmosphere without accounting for all such emissions in accordance with the provisions of §§ 75.10 through 75.19.


(e) No owner or operator of an affected unit shall disrupt the continuous emission monitoring system, any portion thereof, or any other approved emission monitoring method, and thereby avoid monitoring and recording SO2, NOX, or CO2 emissions discharged to the atmosphere, except for periods of recertification, or periods when calibration, quality assurance, or maintenance is performed pursuant to § 75.21 and appendix B of this part.


(f) No owner or operator of an affected unit shall retire or permanently discontinue use of the continuous emission monitoring system, any component thereof, the continuous opacity monitoring system, or any other approved emission monitoring system under this part, except under any one of the following circumstances:


(1) During the period that the unit is covered by an approved retired unit exemption under § 72.8 of this chapter that is in effect; or


(2) The owner or operator is monitoring emissions from the unit with another certified monitoring system or an excepted methodology approved by the Administrator for use at that unit that provides emissions data for the same pollutant or parameter as the retired or discontinued monitoring system; or


(3) The designated representative submits notification of the date of recertification testing of a replacement monitoring system in accordance with §§ 75.20 and 75.61, and the owner or operator recertifies thereafter a replacement monitoring system in accordance with § 75.20.


[58 FR 3701, Jan. 11, 1993, as amended at 58 FR 40747, July 30, 1993; 60 FR 26517, May 17, 1995; 64 FR 28589, May 26, 1999]


§ 75.6 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 Public Information Reference Unit of the U.S. EPA, 401 M St., SW., Washington, DC and at the Library (MD-35), U.S. EPA, Research Triangle Park, North Carolina or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.


(a) The following materials are available for purchase from the following address: American Society for Testing and Material (ASTM) International, 100 Barr Harbor Drive, P.O. Box C700, West Conshohocken, Pennsylvania, 19428-2959, phone: 610-832-9585, http://www.astm.org/DIGITAL_LIBRARY/index.shtml.


(1) ASTM D129-00, Standard Test Method for Sulfur in Petroleum Products (General Bomb Method), for appendices A and D of this part.


(2) D240-00, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, for appendices A, D and F of this part.


(3) ASTM D287-92 (Reapproved 2000), Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), for appendix D of this part.


(4) ASTM D388-99, Standard Classification of Coals by Rank, incorporation by reference for appendix F of this part.


(5) [Reserved]


(6) ASTM D1072-06, Standard Test Method for Total Sulfur in Fuel Gases by Combustion and Barium Chloride Titration, for appendix D of this part.


(7) ASTM D1217-993 (Reapproved 1998), Standard Test Method for Density and Relative Density (Specific Gravity) of Liquids by Bingham Pycnometer, for appendix D of this part.


(8) ASTM D1250-07 , Standard Guide for Use of the Petroleum Measurement Tables, for appendix D of this part.


(9) ASTM D1298-99, Standard Test Method for Density, Relative Density (Specific Gravity) or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method, for appendix D of this part.


(10) ASTM D1480-93 (Reapproved 1997), Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Bingham Pycnometer, for appendix D of this part.


(11) ASTM D1481-93 (Reapproved 1997), Standard Test Method for Density and Relative Density (Specific Gravity) of Viscous Materials by Lipkin Bicapillary Pycnometer, for appendix D of this part.


(12) ASTM D1552-01, Standard Test Method for Sulfur in Petroleum Products (High-Temperature Method), for appendices A and D of the part.


(13) ASTM D1826-94 (Reapproved 1998), Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, for appendices D and F to this part.


(14) ASTM D1945-96 (Reapproved 2001), Standard Test Method for Analysis of Natural Gas by Gas Chromatography, for appendices F and G of this part.


(15) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography, for appendices F and G of this part.


(16) [Reserved]


(17) ASTM D2013-01, Standard Practice for Preparing Coal Samples for Analysis, for appendix F of this part.


(18) [Reserved]


(19) ASTM D2234-00, Standard Practice for Collection of a Gross Sample of Coal, for appendix F of this part.


(20) [Reserved]


(21) ASTM D2502-92 (Reapproved 1996), Standard Test Method for Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum Oils from Viscosity Measurements, for appendix G of this part.


(22) ASTM D2503-92 (Reapproved 1997), Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, for appendix G of this part.


(23) ASTM D2622-98, Standard Test Method for Sulfur in Petroleum Products by Wavelength Dispersive X-ray Fluorescence Spectrometry, for appendices A and D of this part.


(24) ASTM D3174-00, Standard Test Method for Ash in the Analysis Sample of Coal and Coke from Coal, for appendix G of this part.


(25) ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke, for appendices A and F of this part.


(26) ASTM D3177-02 (Reapproved 2007), Standard Test Methods for Total Sulfur in the Analysis Sample of Coal and Coke, for appendix A of this part.


(27) ASTM D5373-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke, for appendix G of this part.


(28) ASTM D3238-95 (Reapproved 2000), Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, for appendix G of this part.


(29) ASTM D3246-96, Standard Test Method for Sulfur in Petroleum Gas by Oxidative Microcoulometry, for appendix D of this part.


(30) [Reserved]


(31) ASTM D3588-98, Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, for appendices D and F to this part.


(32) ASTM D4052-96 (Reapproved 2002), Standard Test Method for Density and Relative Density of Liquids by Digital Density Meter, for appendix D of this part.


(33) ASTM D4057-95 (Reapproved 2000), Standard Practice for Manual Sampling of Petroleum and Petroleum Products, for appendix D of this part.


(34) ASTM D4177-95 (Reapproved 2000), Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, for appendix D of this part.


(35) ASTM D4239-02, Standard Test Methods for Sulfur in the Analysis Sample of Coal and Coke Using High-Temperature Tube Furnace Combustion Methods, for appendix A of this part.


(36) ASTM D4294-98, Standard Test Method for Sulfur in Petroleum and Petroleum Products by Energy-Dispersive X-ray Fluorescence Spectrometry, for appendices A and D of this part.


(37) ASTM D4468-85 (Reapproved 2006), Standard Test Method for Total Sulfur in Gaseous Fuels by Hydrogenolysis and Rateometric Colorimetry, for appendix D of this part.


(38) [Reserved]


(39) ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, for appendices D and F to this part.


(40) ASTM D5291-02, Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, for appendices F and G to this part.


(41) ASTM D5373-02 (Reapproved 2007), “Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal and Coke,” for appendix G to this part.


(42) ASTM D5504-01, Standard Test Method for Determination of Sulfur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence, for appendix D of this part.


(43) [Reserved]


(44) [Reserved]


(45) ASTM D6667-04, Standard Test Method for Determination of Total Volatile Sulfur in Gaseous Hydrocarbons and Liquefied Petroleum Gases by Ultraviolet Fluorescence, for appendix D of this part.


(46) ASTM D4809-00, Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), for appendices D and F of this part.


(47) ASTM D5865-01a, Standard Test Method for Gross Calorific Value of Coal and Coke, for appendices A, D, and F of this part.


(48) ASTM D7036-04, Standard Practice for Competence of Air Emission Testing Bodies, for § 75.21, § 75.59, and appendix A to this part.


(49) ASTM D5453-06, Standard Test Method for Determination of Total Sulfur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence, for appendix D of this part.


(50) ASTM D5865-10 (Approved January 1, 2010), Standard Test Method for Gross Calorific Value of Coal and Coke, for appendices A, D, and F of this part.


(b) The following materials are available for purchase from the American Society of Mechanical Engineers (ASME), 22 Law Drive, P.O. Box 2900, Fairfield, New Jersey 07007-2900:


(1) ASME MFC-3M-2004 (Revision of ASME MFC-3M-1989 (R1995)), Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, for appendix D of this part.


(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters, for appendix D of this part.


(3) ASME-MFC-5M-1985 (Reaffirmed 1994), Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, for appendix D of this part.


(4) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, for appendix D of this part.


(5) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles, for appendix D of this part.


(6) ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid Flow in Closed Conduits by Weighing Method, for appendix D of this part.


(c) The following materials are available for purchase from the American National Standards Institute (ANSI), 25 West 43rd Street, Fourth Floor, New York, New York 10036:


(1) ISO 8316: 1987(E) Measurement of Liquid Flow in closed Conduits-Method by Collection of the Liquid in a Volumetric Tank, for appendices D and E of this part.


(2) [Reserved]


(d) The following materials are available for purchase from the following address: Gas Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74143:


(1) GPA Standard 2172-96, Calculation of Gross Heating Value, Relative Density and Compressibility Factor for Natural Gas Mixtures from Compositional Analysis, for appendices D, E, and F of this part.


(2) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, for appendices D, F, and G of this part.


(e) The following American Gas Association materials are available for purchase from the following address: ILI Infodisk, 610 Winters Avenue, Paramus, New Jersey 07652:


(1) American Gas Association Report No. 3: Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty Guidelines (October 1990 Edition), Part 2: Specification and Installation Requirements (February 1991 Edition) and Part 3: Natural Gas Applications (August 1992 Edition), for appendices D and E of this part.


(2) American Gas Association Transmission Measurement Committee Report No. 7: Measurement of Gas by Turbine Meters (Second Revision, April, 1996), for appendix D to this part.


(f) The following materials are available for purchase from the following address: American Petroleum Institute, Publications Department, 1220 L Street NW, Washington, DC 20005-4070.


(1) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 3 – Tank Gauging, Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second Edition, August 2005; Section 1B – Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second Edition June 2001; Section 2 – Standard Practice for Gauging Petroleum and Petroleum Products in Tank Cars, First Edition, August 1995 (Reaffirmed March 2006); Section 3 – Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank Gauging, First Edition June 1996; Section 4 – Standard Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank Gauging, First Edition April 1995 (Reaffirmed, March 2006); and Section 5 – Standard Practice for Level Measurement of Light Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging, First Edition March 1997 (Reaffirmed, March 2003); for § 75.19.


(2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed August 1987, October 1992), for § 75.19.


(3) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 4 – Proving Systems, Section 2 – Pipe Provers (Provers Accumulating at Least 10,000 Pulses), Second Edition, March 2001, Section 3 – Small Volume Provers, First Edition, July 1988, Reaffirmed Oct 1993, and Section 5 – Master-Meter Provers, Second Edition, May 2000, for appendix D to this part.


(4) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 22 – Testing Protocol, Section 2 – Differential Pressure Flow Measurement Devices (First Edition, August 2005), for appendix D to this part.


(g) A copy of the following material is available from http://www.epa.gov/ttn/emc/news.html (see postings for Sections 1, 2, 3, 4, Appendices, Spreadsheets, and the “Read before downloading Section 2” revision posted August 27, 1999): EPA-600/R-97/121, EPA Traceability Protocol for Assay and Certification of Gaseous Calibration Standards, September 1997, as amended August 25, 1999, U.S. Environmental Protection Agency, for § 75.21, and appendix A to this part.


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26517, May 17, 1995; 61 FR 59157, Nov. 20, 1996; 63 FR 57499, Oct. 27, 1998; 64 FR 28589, May 26, 1999; 67 FR 40422, June 12, 2002; 70 FR 28678, May 18, 2005; 70 FR 51269, Aug. 30, 2005; 73 FR 4341, Jan. 24, 2008; 76 FR 17307, Mar. 28, 2011; 77 FR 2460, Jan. 18, 2012]


Editorial Note:At 70 FR 28678, May 18, 2005, § 75.6 was amended, however, certain amendments could not be incorporated due to inaccurate amendatory instruction.

§§ 75.7-75.8 [Reserved]

Subpart B – Monitoring Provisions

§ 75.10 General operating requirements.

(a) Primary Measurement Requirement. The owner or operator shall measure opacity, and all SO2, NOX, and CO2 emissions for each affected unit as follows:


(1) To determine SO2 emissions, the owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a SO2 continuous emission monitoring system and a flow monitoring system with an automated data acquisition and handling system for measuring and recording SO2 concentration (in ppm), volumetric gas flow (in scfh), and SO2 mass emissions (in lb/hr) discharged to the atmosphere, except as provided in §§ 75.11 and 75.16 and subpart E of this part;


(2) To determine NOX emissions, the owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a NOX-diluent continuous emission monitoring system (consisting of a NOX pollutant concentration monitor and an O2 or CO2 diluent gas monitor) with an automated data acquisition and handling system for measuring and recording NOX concentration (in ppm), O2 or CO2 concentration (in percent O2 or CO2) and NOX emission rate (in lb/mmBtu) discharged to the atmosphere, except as provided in §§ 75.12 and 75.17 and subpart E of this part. The owner or operator shall account for total NOX emissions, both NO and NO2, either by monitoring for both NO and NO2 or by monitoring for NO only and adjusting the emissions data to account for NO2;


(3) The owner or operator shall determine CO2 emissions by using one of the following options, except as provided in § 75.13 and subpart E of this part:


(i) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a CO2 continuous emission monitoring system and a flow monitoring system with an automated data acquisition and handling system for measuring and recording CO2 concentration (in ppm or percent), volumetric gas flow (in scfh), and CO2 mass emissions (in tons/hr) discharged to the atmosphere;


(ii) The owner or operator shall determine CO2 emissions based on the measured carbon content of the fuel and the procedures in appendix G of this part to estimate CO2 emissions (in ton/day) discharged to the atmosphere; or


(iii) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements of this part, a flow monitoring system and a CO2 continuous emission monitoring system that uses an O2 concentration monitor to determine CO2 emissions (according to the procedures in appendix F of this part) with an automated data acquisition and handling system for measuring and recording O2 concentration (in percent), CO2 concentration (in percent), volumetric gas flow (in scfh), and CO2 mass emissions (in tons/hr) discharged to the atmosphere;


(4) The owner or operator shall install, certify, operate, and maintain, in accordance with all the requirements in this part, a continuous opacity monitoring system with the automated data acquisition and handling system for measuring and recording the opacity of emissions (in percent opacity) discharged to the atmosphere, except as provided in §§ 75.14 and 75.18; and


(5) A single certified flow monitoring system may be used to meet the requirements of paragraphs (a)(1) and (a)(3) of this section. A single certified diluent monitor may be used to meet the requirements of paragraphs (a)(2) and (a)(3) of this section. A single automated data acquisition and handling system may be used to meet the requirements of paragraphs (a)(1) through (a)(4) of this section.


(b) Primary Equipment Performance Requirements. The owner or operator shall ensure that each continuous emission monitoring system required by this part meets the equipment, installation, and performance specifications in appendix A to this part; and is maintained according to the quality assurance and quality control procedures in appendix B to this part; and shall record SO2 and NOX emissions in the appropriate units of measurement (i.e., lb/hr for SO2 and lb/mmBtu for NOX).


(c) Heat Input Rate Measurement Requirement. The owner or operator shall determine and record the heat input rate, in units of mmBtu/hr, to each affected unit for every hour or part of an hour any fuel is combusted following the procedures in appendix F to this part.


(d) Primary equipment hourly operating requirements. The owner or operator shall ensure that all continuous emission and opacity monitoring systems required by this part are in operation and monitoring unit emissions or opacity at all times that the affected unit combusts any fuel except as provided in § 75.11(e) and during periods of calibration, quality assurance, or preventive maintenance, performed pursuant to § 75.21 and appendix B of this part, periods of repair, periods of backups of data from the data acquisition and handling system, or recertification performed pursuant to § 75.20. The owner or operator shall also ensure, subject to the exceptions above in this paragraph, that all continuous opacity monitoring systems required by this part are in operation and monitoring opacity during the time following combustion when fans are still operating, unless fan operation is not required to be included under any other applicable Federal, State, or local regulation, or permit. The owner or operator shall ensure that the following requirements are met:


(1) The owner or operator shall ensure that each continuous emission monitoring system is capable of completing a minimum of one cycle of operation (sampling, analyzing, and data recording) for each successive 15-min interval. The owner or operator shall reduce all SO2 concentrations, volumetric flow, SO2 mass emissions, CO2 concentration, O2 concentration, CO2 mass emissions (if applicable), NOX concentration, and NOX emission rate data collected by the monitors to hourly averages. Hourly averages shall be computed using at least one data point in each fifteen minute quadrant of an hour, where the unit combusted fuel during that quadrant of an hour. Notwithstanding this requirement, an hourly average may be computed from at least two data points separated by a minimum of 15 minutes (where the unit operates for more than one quadrant of an hour) if data are unavailable as a result of the performance of calibration, quality assurance, or preventive maintenance activities pursuant to § 75.21 and appendix B of this part, or backups of data from the data acquisition and handling system, or recertification, pursuant to § 75.20. The owner or operator shall use all valid measurements or data points collected during an hour to calculate the hourly averages. All data points collected during an hour shall be, to the extent practicable, evenly spaced over the hour.


(2) The owner or operator shall ensure that each continuous opacity monitoring system is capable of completing a minimum of one cycle of sampling and analyzing for each successive 10-sec period and one cycle of data recording for each successive 6-min period. The owner or operator shall reduce all opacity data to 6-min averages calculated in accordance with the provisions of part 51, appendix M of this chapter, except where the applicable State implementation plan or operating permit requires a different averaging period, in which case the State requirement shall satisfy this Acid Rain Program requirement.


(3) Failure of an SO2, CO2, or O2 emissions concentration monitor, NOX concentration monitor, flow monitor, moisture monitor, or NOX-diluent continuous emission monitoring system to acquire the minimum number of data points for calculation of an hourly average in paragraph (d)(1) of this section shall result in the failure to obtain a valid hour of data and the loss of such component data for the entire hour. For a NOX-diluent monitoring system, an hourly average NOX emission rate in lb/mmBtu is valid only if the minimum number of data points is acquired by both the NOX pollutant concentration monitor and the diluent monitor (O2 or CO2). For a moisture monitoring system consisting of one or more oxygen analyzers capable of measuring O2 on a wet-basis and a dry-basis, an hourly average percent moisture value is valid only if the minimum number of data points is acquired for both the wet-and dry-basis measurements. If a valid hour of data is not obtained, the owner or operator shall estimate and record emissions, moisture, or flow data for the missing hour by means of the automated data acquisition and handling system, in accordance with the applicable procedure for missing data substitution in subpart D of this part.


(e) Optional backup monitor requirements. If the owner or operator chooses to use two or more continuous emission monitoring systems, each of which is capable of monitoring the same stack or duct at a specific affected unit, or group of units using a common stack, then the owner or operator shall designate one monitoring system as the primary monitoring system, and shall record this information in the monitoring plan, as provided for in § 75.53. The owner or operator shall designate the other monitoring system(s) as backup monitoring system(s) in the monitoring plan. The backup monitoring system(s) shall be designated as redundant backup monitoring system(s), non-redundant backup monitoring system(s), or reference method backup system(s), as described in § 75.20(d). When the certified primary monitoring system is operating and not out-of-control as defined in § 75.24, only data from the certified primary monitoring system shall be reported as valid, quality-assured data. Thus, data from the backup monitoring system may be reported as valid, quality-assured data only when the backup is operating and not out-of-control as defined in § 75.24 (or in the applicable reference method in appendix A of part 60 of this chapter) and when the certified primary monitoring system is not operating (or is operating but out-of-control). A particular monitor may be designated both as a certified primary monitor for one unit and as a certified redundant backup monitor for another unit.


(f) Minimum measurement capability requirement. The owner or operator shall ensure that each continuous emission monitoring system is capable of accurately measuring, recording, and reporting data, and shall not incur an exceedance of the full scale range, except as provided in sections 2.1.1.5, 2.1.2.5, and 2.1.4.3 of appendix A to this part.


(g) Minimum recording and recordkeeping requirements. The owner or operator shall record and the designated representative shall report the hourly, daily, quarterly, and annual information collected under the requirements of this part as specified in subparts F and G of this part.


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26519, May 17, 1995; 64 FR 28590, May 26, 1999; 67 FR 40422, June 12, 2002; 70 FR 28678, May 18, 2005; 76 FR 17308, Mar. 28, 2011]


§ 75.11 Specific provisions for monitoring SO2 emissions.

(a) Coal-fired units. The owner or operator shall meet the general operating requirements in § 75.10 for an SO2 continuous emission monitoring system and a flow monitoring system for each affected coal-fired unit while the unit is combusting coal and/or any other fuel, except as provided in paragraph (e) of this section, in § 75.16, and in subpart E of this part. During hours in which only gaseous fuel is combusted in the unit, the owner or operator shall comply with the applicable provisions of paragraph (e)(1), (e)(2), or (e)(3) of this section.


(b) Moisture correction. Where SO2 concentration is measured on a dry basis, the owner or operator shall either:


(1) Report the appropriate fuel-specific default moisture value for each unit operating hour, selected from among the following: 3.0%, for anthracite coal; 6.0% for bituminous coal; 8.0% for sub-bituminous coal; 11.0% for lignite coal; 13.0% for wood and 14.0% for natural gas (boilers, only); or


(2) Install, operate, maintain, and quality assure a continuous moisture monitoring system for measuring and recording the moisture content of the flue gases, in order to correct the measured hourly volumetric flow rates for moisture when calculating SO2 mass emissions (in lb/hr) using the procedures in appendix F to this part. The following continuous moisture monitoring systems are acceptable: a continuous moisture sensor; an oxygen analyzer (or analyzers) capable of measuring O2 both on a wet basis and on a dry basis; or a stack temperature sensor and a moisture look-up table, i.e., a psychrometric chart (for saturated gas streams following wet scrubbers or other demonstrably saturated gas streams, only). The moisture monitoring system shall include as a component the automated data acquisition and handling system (DAHS) for recording and reporting both the raw data (e.g., hourly average wet-and dry-basis O2 values) and the hourly average values of the stack gas moisture content derived from those data. When a moisture look-up table is used, the moisture monitoring system shall be represented as a single component, the certified DAHS, in the monitoring plan for the unit or common stack.


(c) Unit with no location for a flow monitor meeting siting requirements. Where no location exists that satisfies the minimum physical siting criteria in appendix A to this part for installation of a flow monitor in either the stack or the ducts serving an affected unit or installation of a flow monitor in either the stack or ducts is demonstrated to the satisfaction of the Administrator to be technically infeasible, either:


(1) The designated representative shall petition the Administrator for an alternative method for monitoring volumetric flow in accordance with § 75.66; or


(2) The owner or operator shall construct a new stack or modify existing ductwork to accommodate the installation of a flow monitor, and the designated representative shall petition the Administrator for an extension of the required certification date given in § 75.4 and approval of an interim alternative flow monitoring methodology in accordance with § 75.66. The Administrator may grant existing Phase I affected units an extension to January 1, 1995, and existing Phase II affected units an extension to January 1, 1996 for the submission of the certification application for the purpose of constructing a new stack or making substantial modifications to ductwork for installation of a flow monitor; or


(3) The owner or operator shall install a flow monitor in any existing location in the stack or ducts serving the affected unit at which the monitor can achieve the performance specifications of this part.


(d) Gas-fired and oil-fired units. The owner or operator of an affected unit that qualifies as a gas-fired or oil-fired unit, as defined in § 72.2 of this chapter, based on information submitted by the designated representative in the monitoring plan, shall measure and record SO2 emissions:


(1) By meeting the general operating requirements in § 75.10 for an SO2 continuous emission monitoring system and flow monitoring system. If this option is selected, the owner or operator shall comply with the applicable provisions in paragraph (e)(1), (e)(2), or (e)(3) of this section during hours in which the unit combusts only gaseous fuel;


(2) By providing other information satisfactory to the Administrator using the applicable procedures specified in appendix D to this part for estimating hourly SO2 mass emissions; or


(3) By using the low mass emissions excepted methodology in § 75.19(c) for estimating hourly SO2 mass emissions if the affected unit qualifies as a low mass emissions unit under § 75.19(a) and (b). If this option is selected for SO2, the LME methodology must also be used for NOX and CO2 when these parameters are required to be monitored by applicable program(s).


(e) Special considerations during the combustion of gaseous fuels. The owner or operator of an affected unit that uses a certified flow monitor and a certified diluent gas (O2 or CO2) monitor to measure the unit heat input rate shall, during any hours in which the unit combusts only gaseous fuel, determine SO2 emissions in accordance with paragraph (e)(1) or (e)(3) of this section, as applicable.


(1) If the gaseous fuel qualifies for a default SO2 emission rate under Section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix D to this part, the owner or operator may determine SO2 emissions by using Equation F-23 in appendix F to this part. Substitute into Equation F-23 the hourly heat input, calculated using the certified flow monitoring system and the certified diluent monitor (according to the applicable equation in section 5.2 of appendix F to this part), in conjunction with the appropriate default SO2 emission rate from section 2.3.1.1, 2.3.2.1.1, or 2.3.6(b) of appendix D to this part. When this option is chosen, the owner or operator shall perform the necessary data acquisition and handling system tests under § 75.20(c), and shall meet all quality control and quality assurance requirements in appendix B to this part for the flow monitor and the diluent monitor; or


(2) [Reserved]


(3) The owner or operator may determine SO2 mass emissions by using a certified SO2 continuous monitoring system, in conjunction with the certified flow rate monitoring system. However, if the gaseous fuel is very low sulfur fuel (as defined in § 72.2 of this chapter), the SO2 monitoring system shall meet the following quality assurance provisions when the very low sulfur fuel is combusted:


(i) When conducting the daily calibration error tests of the SO2 monitoring system, as required by section 2.1.1 in appendix B of this part, the zero-level calibration gas shall have an SO2 concentration of 0.0 percent of span. This restriction does not apply if gaseous fuel is burned in the affected unit only during unit startup.


(ii) EPA recommends that the calibration response of the SO2 monitoring system be adjusted, either automatically or manually, in accordance with the procedures for routine calibration adjustments in section 2.1.3 of appendix B to this part, whenever the zero-level calibration response during a required daily calibration error test exceeds the applicable performance specification of the instrument in section 3.1 of appendix A to this part (i.e., ±2.5 percent of the span value or ±5 ppm, whichever is less restrictive).


(iii) Any bias-adjusted hourly average SO2 concentration of less than 2.0 ppm recorded by the SO2 monitoring system shall be adjusted to a default value of 2.0 ppm, for reporting purposes. Such adjusted hourly averages shall be considered to be quality-assured data, provided that the monitoring system is operating and is not out-of-control with respect to any of the quality assurance tests required by appendix B of this part (i.e., daily calibration error, linearity and relative accuracy test audit).


(iv) In accordance with the requirements of section 2.1.1.2 of appendix A to this part, for units that sometimes burn gaseous fuel that is very low sulfur fuel (as defined in § 72.2 of this chapter) and at other times burn higher sulfur fuel(s) such as coal or oil, a second low-scale SO2 measurement range is not required when the very low sulfur gaseous fuel is combusted. For units that burn only gaseous fuel that is very low sulfur fuel and burn no other type(s) of fuel(s), the owner or operator shall set the span of the SO2 monitoring system to a value no greater than 200 ppm.


(4) The provisions in paragraph (e)(1) of this section, may also be used for the combustion of a solid or liquid fuel that meets the definition of very low sulfur fuel in § 72.2 of this chapter, mixtures of such fuels, or combinations of such fuels with gaseous fuel, if the owner or operator submits a petition under § 75.66 for a default SO2 emission rate for each fuel, mixture or combination, and if the Administrator approves the petition.


(f) Other units. The owner or operator of an affected unit that combusts wood, refuse, or other material in addition to oil or gas shall comply with the monitoring provisions for coal-fired units specified in paragraph (a) of this section, except where the owner or operator has an approved petition to use the provisions of paragraph (e)(1) of this section.


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26520, 26566, May 17, 1995; 61 FR 59157, Nov. 20, 1996; 63 FR 57499, Oct. 27, 1998; 64 FR 28590, May 26, 1999; 67 FR 40423, June 12, 2002; 73 FR 4342, Jan. 24, 2008]


§ 75.12 Specific provisions for monitoring NOX emission rate.

(a) Coal-fired units, gas-fired nonpeaking units or oil-fired nonpeaking units. The owner or operator shall meet the general operating requirements in § 75.10 of this part for a NOX continuous emission monitoring system (CEMS) for each affected coal-fired unit, gas-fired nonpeaking unit, or oil-fired nonpeaking unit, except as provided in paragraph (d) of this section, § 75.17, and subpart E of this part. The diluent gas monitor in the NOX-diluent CEMS may measure either O2 or CO2 concentration in the flue gases.


(b) Moisture correction. If a correction for the stack gas moisture content is needed to properly calculate the NOX emission rate in lb/mmBtu, e.g., if the NOX pollutant concentration monitor measures on a different moisture basis from the diluent monitor, the owner or operator shall either report a fuel-specific default moisture value for each unit operating hour, as provided in § 75.11(b)(1), or shall install, operate, maintain, and quality assure a continuous moisture monitoring system, as defined in § 75.11(b)(2). Notwithstanding this requirement, if Equation 19-3, 19-4 or 19-8 in Method 19 in appendix A to part 60 of this chapter is used to measure NOX emission rate, the following fuel-specific default moisture percentages shall be used in lieu of the default values specified in § 75.11(b)(1): 5.0%, for anthracite coal; 8.0% for bituminous coal; 12.0% for sub-bituminous coal; 13.0% for lignite coal; 15.0% for wood and 18.0% for natural gas (boilers, only).


(c) Determination of NOX emission rate. The owner or operator shall calculate hourly, quarterly, and annual NOX emission rates (in lb/mmBtu) by combining the NOX concentration (in ppm), diluent concentration (in percent O2 or CO2), and percent moisture (if applicable) measurements according to the procedures in appendix F to this part.


(d) Gas-fired peaking units or oil-fired peaking units. The owner or operator of an affected unit that qualifies as a gas-fired peaking unit or oil-fired peaking unit, as defined in § 72.2 of this chapter, based on information submitted by the designated representative in the monitoring plan shall comply with one of the following:


(1) Meet the general operating requirements in § 75.10 for a NOX continuous emission monitoring system; or


(2) Provide information satisfactory to the Administrator using the procedure specified in appendix E of this part for estimating hourly NOX emission rate. However, if in the years after certification of an excepted monitoring system under appendix E of this part, a unit’s operations exceed a capacity factor of 20 percent in any calendar year or exceed a capacity factor of 10.0 percent averaged over three years, the owner or operator shall install, certify, and operate a NOX-diluent continuous emission monitoring system no later than December 31 of the following calendar year. If the required CEMS has not been installed and certified by that date, the owner or operator shall report the maximum potential NOX emission rate (MER) (as defined in § 72.2 of this chapter) for each unit operating hour, starting with the first unit operating hour after the deadline and continuing until the CEMS has been provisionally certified.


(e) Low mass emissions units. Notwithstanding the requirements of paragraphs (a) and (d) of this section, the owner or operator of an affected unit that qualifies as a low mass emissions unit under § 75.19(a) and (b) shall comply with one of the following:


(1) Meet the general operating requirements in § 75.10 for a NOX continuous emission monitoring system;


(2) Meet the requirements specified in paragraph (d)(2) of this section for using the excepted monitoring procedures in appendix E to this part, if applicable; or


(3) Use the low mass emissions excepted methodology in § 75.19(c) for estimating hourly NOX emission rate and hourly NOX mass emissions, if applicable under § 75.19(a) and (b). If this option is selected for NOX, the LME methodology must also be used for SO2 and CO2 when these parameters are required to be monitored by applicable program(s).


(f) Other units. The owner or operator of an affected unit that combusts wood, refuse, or other material in addition to oil or gas shall comply with the monitoring provisions specified in paragraph (a) of this section.


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26520, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 64 FR 28591, May 26, 1999; 67 FR 40423, June 12, 2002; 73 FR 4342, Jan. 24, 2008]


§ 75.13 Specific provisions for monitoring CO2 emissions.

(a) CO2 continuous emission monitoring system. If the owner or operator chooses to use the continuous emission monitoring method, then the owner or operator shall meet the general operating requirements in § 75.10 for a CO2 continuous emission monitoring system and flow monitoring system for each affected unit. The owner or operator shall comply with the applicable provisions specified in §§ 75.11(a) through (e) or § 75.16, except that the phrase “CO2 continuous emission monitoring system” shall apply rather than “SO2 continuous emission monitoring system,” the phrase “CO2 concentration” shall apply rather than “SO2 concentration,” the term “maximum potential concentration of CO2” shall apply rather than “maximum potential concentration of SO2,” and the phrase “CO2 mass emissions” shall apply rather than “SO2 mass emissions.”


(b) Determination of CO2 emissions using appendix G to this part. If the owner or operator chooses to use the appendix G method, then the owner or operator shall follow the procedures in appendix G to this part for estimating daily CO2 mass emissions based on the measured carbon content of the fuel and the amount of fuel combusted. For units with wet flue gas desulfurization systems or other add-on emissions controls generating CO2, the owner or operator shall use the procedures in appendix G to this part to estimate both combustion-related emissions based on the measured carbon content of the fuel and the amount of fuel combusted and sorbent-related emissions based on the amount of sorbent injected. The owner or operator shall calculate daily, quarterly, and annual CO2 mass emissions (in tons) in accordance with the procedures in appendix G to this part.


(c) Determination of CO2 mass emissions using an O2 monitor according to appendix F to this part. If the owner or operator chooses to use the appendix F method, then the owner or operator shall determine hourly CO2 concentration and mass emissions with a flow monitoring system; a continuous O2 concentration monitor; fuel F and Fc factors; and, where O2 concentration is measured on a dry basis (or where Equation F-14b in appendix F to this part is used to determine CO2 concentration), either, a continuous moisture monitoring system, as specified in § 75.11(b)(2), or a fuel-specific default moisture percentage (if applicable), as defined in § 75.11(b)(1); and by using the methods and procedures specified in appendix F to this part. For units using a common stack, multiple stack, or bypass stack, the owner or operator may use the provisions of § 75.16, except that the phrase “CO2 continuous emission monitoring system” shall apply rather than “SO2 continuous emission monitoring system,” the term “maximum potential concentration of CO2” shall apply rather than “maximum potential concentration of SO2,” and the phrase “CO2 mass emissions” shall apply rather than “SO2 mass emissions.”


(d) Determination of CO2 mass emissions from low mass emissions units. The owner or operator of a unit that qualifies as a low mass emissions unit under § 75.19(a) and (b) shall comply with one of the following:


(1) Meet the general operating requirements in § 75.10 for a CO2 continuous emission monitoring system and flow monitoring system;


(2) Meet the requirements specified in paragraph (b) or (c) of this section for use of the methods in appendix G or F to this part, respectively; or


(3) Use the low mass emissions excepted methodology in § 75.19(c) for estimating hourly CO2 mass emissions, if applicable under § 75.19(a) and (b). If this option is selected for CO2, the LME methodology must also be used for NOX and SO2 when these parameters are required to be monitored by applicable program(s).


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26521, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 64 FR 28591, May 26, 1999; 67 FR 40423, June 12, 2002; 73 FR 4343, Jan. 24, 2008]


§ 75.14 Specific provisions for monitoring opacity.

(a) Coal-fired units and oil-fired units. The owner or operator shall meet the general operating provisions in § 75.10 of this part for a continuous opacity monitoring system for each affected coal-fired or oil-fired unit, except as provided in paragraphs (b), (c), and (d) of this section and in § 75.18. Each continuous opacity monitoring system shall meet the design, installation, equipment, and performance specifications in Performance Specification 1 in appendix B to part 60 of this chapter. Any continuous opacity monitoring system previously certified to meet Performance Specification 1 shall be deemed certified for the purposes of this part.


(b) Unit with wet flue gas pollution control system. If the owner or operator can demonstrate that condensed water is present in the exhaust flue gas stream and would impede the accuracy of opacity measurements, then the owner or operator of an affected unit equipped with a wet flue gas pollution control system for SO2 emissions or particulates is exempt from the opacity monitoring requirements of this part.


(c) Gas-fired units. The owner or operator of an affected unit that qualifies as gas-fired, as defined in § 72.2 of this chapter, based on information submitted by the designated representative in the monitoring plan is exempt from the opacity monitoring requirements of this part. Whenever a unit previously categorized as a gas-fired unit is recategorized as another type of unit by changing its fuel mix, the owner or operator shall install, operate, and certify a continuous opacity monitoring system as required by paragraph (a) of this section by December 31 of the following calendar year.


(d) Diesel-fired units and dual-fuel reciprocating engine units. The owner or operator of an affected diesel-fired unit or a dual-fuel reciprocating engine unit is exempt from the opacity monitoring requirements of this part.


(e) Unit with a certified particulate matter (PM) monitoring system. If, for a particular affected unit, the owner or operator installs, certifies, operates, maintains, and quality-assures a continuous particulate matter (PM) monitoring system in accordance with Procedure 2 in appendix F to part 60 of this chapter, the unit shall be exempt from the opacity monitoring requirement of this part.


[58 FR 3701, Jan. 11, 1993, as amended at 61 FR 25581, May 22, 1996; 73 FR 4343, Jan. 24, 2008]


§ 75.15 [Reserved]

§ 75.16 Special provisions for monitoring emissions from common, bypass, and multiple stacks for SO2 emissions and heat input determinations.

(a) [Reserved]


(b) Common stack procedures. The following procedures shall be used when more than one unit uses a common stack:


(1) Unit utilizing common stack with other affected unit(s). When a Phase I or Phase II affected unit utilizes a common stack with one or more other Phase I or Phase II affected units, but no nonaffected units, the owner or operator shall either:


(i) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the duct to the common stack from each affected unit; or


(ii) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the common stack and combine emissions for the affected units for recordkeeping and compliance purposes.


(2) Unit utilizing common stack with nonaffected unit(s). When one or more Phase I or Phase II affected units utilizes a common stack with one or more nonaffected units, the owner or operator shall either:


(i) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the duct to the common stack from each Phase I and Phase II unit; or


(ii) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the common stack; and


(A) Designate the nonaffected units as opt-in units in accordance with part 74 of this chapter and combine emissions for recordkeeping and compliance purposes; or


(B) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in the duct from each nonaffected unit; determine SO2 mass emissions from the affected units as the difference between SO2 mass emissions measured in the common stack and SO2 mass emissions measured in the ducts of the nonaffected units, not to be reported as an hourly average value less than zero; combine emissions for the Phase I and Phase II affected units for recordkeeping and compliance purposes; and calculate and report SO2 mass emissions from the Phase I and Phase II affected units, pursuant to an approach approved by the Administrator, such that these emissions are not underestimated; or


(C) Record the combined emissions from all units as the combined SO2 mass emissions for the Phase I and Phase II affected units for recordkeeping and compliance purposes; or


(D) Petition through the designated representative and provide information satisfactory to the Administrator on methods for apportioning SO2 mass emissions measured in the common stack to each of the units using the common stack and on reporting the SO2 mass emissions. The Administrator may approve such demonstrated substitute methods for apportioning and reporting SO2 mass emissions measured in a common stack whenever the demonstration ensures that there is a complete and accurate accounting of all emissions regulated under this part and, in particular, that the emissions from any affected unit are not underestimated.


(c) Unit with bypass stack. Whenever any portion of the flue gases from an affected unit can be routed through a bypass stack so as to avoid the installed SO2 continuous emission monitoring system and flow monitoring system, the owner or operator shall either:


(1) Install, certify, operate, and maintain separate SO2 continuous emission monitoring systems and flow monitoring systems on the main stack and the bypass stack and calculate SO2 mass emissions for the unit as the sum of the SO2 mass emissions measured at the two stacks; or


(2) Monitor SO2 mass emissions at the main stack using SO2 and flow rate monitoring systems and measure SO2 mass emissions at the bypass stack using the reference methods in § 75.22(b) for SO2 and flow rate and calculate SO2 mass emissions for the unit as the sum of the emissions recorded by the installed monitoring systems on the main stack and the emissions measured by the reference method monitoring systems; or


(3) Install, certify, operate, and maintain SO2 and flow rate monitoring systems only on the main stack. If this option is chosen, report the following values for each hour during which emissions pass through the bypass stack: the maximum potential concentration of SO2 as determined under section 2.1.1.1 of appendix A to this part (or, if available, the SO2 concentration measured by a certified monitor located at the control device inlet may be reported instead), and the hourly volumetric flow rate value that would be substituted for the flow monitor installed on the main stack or flue under the missing data procedures in subpart D of this part if data from the flow monitor installed on the main stack or flue were missing for the hour. The maximum potential SO2 concentration may be specific to the type of fuel combusted in the unit during the bypass (see § 75.33(b)(5)). The option in this paragraph, (c)(3), may only be used if use of the bypass stack is limited to unit startup, emergency situations (e.g., malfunction of a flue gas desulfurization system), and periods of routine maintenance of the flue gas desulfurization system or maintenance on the main stack. If this option is chosen, it is not necessary to designate the exhaust configuration as a multiple stack configuration in the monitoring plan required under § 75.53, with respect to SO2 or any other parameter that is monitored only at the main stack. Calculate SO2 mass emissions for the unit as the sum of the emissions calculated with the substitute values and the emissions recorded by the SO2 and flow monitoring systems installed on the main stack.


(d) Unit with multiple stacks or ducts. When the flue gases from an affected unit utilize two or more ducts feeding into two or more stacks (that may include flue gases from other affected or nonaffected units), or when the flue gases utilize two or more ducts feeding into a single stack and the owner or operator chooses to monitor in the ducts rather than the stack, the owner or operator shall either:


(1) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in each duct feeding into the stack or stacks and determine SO2 mass emissions from each affected unit as the sum of the SO2 mass emissions recorded for each duct; or


(2) Install, certify, operate, and maintain an SO2 continuous emission monitoring system and flow monitoring system in each stack. Determine SO2 mass emissions from each affected unit as the sum of the SO2 mass emissions recorded for each stack. Notwithstanding the prior sentence, if another unit also exhausts flue gases to one or more of the stacks, the owner or operator shall also comply with the applicable common stack requirements of this section to determine and record SO2 mass emissions from the units using that stack and shall calculate and report SO2 mass emissions from the affected units and stacks, pursuant to an approach approved by the Administrator, such that these emissions are not underestimated.


(e) Heat input rate. The owner or operator of an affected unit using a common stack, bypass stack, or multiple stacks shall account for heat input rate according to the following:


(1) The owner or operator of an affected unit using a common stack, bypass stack, or multiple stack with a diluent monitor and a flow monitor on each stack may use the flow rate and diluent monitors to determine the heat input rate for the affected unit, using the procedures specified in paragraphs (b) through (d) of this section, except that the term “heat input rate” shall apply rather than “SO2 mass emissions” or “emissions” and the phrase “a diluent monitor and a flow monitor” shall apply rather than “SO2 continuous emission monitoring system and flow monitoring system.” The applicable equation in appendix F to this part shall be used to calculate the heat input rate from the hourly flow rate, diluent monitor measurements, and (if the equation in appendix F requires a correction for the stack gas moisture content) hourly moisture measurements. Notwithstanding the options for combining heat input rate in paragraph (b)(1)(ii) and (b)(2)(ii) of this section, the owner or operator of an affected unit with a diluent monitor and a flow monitor installed on a common stack to determine the combined heat input rate at the common stack shall also determine and report heat input rate to each individual unit, according to paragraph (e)(3) of this section.


(2) In the event that an owner or operator of a unit with a bypass stack does not install and certify a diluent monitor and flow monitoring system in a bypass stack, the owner or operator shall determine total heat input rate to the unit for each unit operating hour during which the bypass stack is used according to the missing data provisions for heat input rate under § 75.36 or the procedures for calculating heat input rate from fuel sampling and analysis in section 5.5 of appendix F to this part.


(3) The owner or operator of an affected unit with a diluent monitor and a flow monitor installed on a common stack to determine heat input rate at the common stack may choose to apportion the heat input rate from the common stack to each affected unit utilizing the common stack by using either of the following two methods, provided that all of the units utilizing the common stack are combusting fuel with the same F-factor found in section 3 of appendix F of this part. The heat input rate may be apportioned either by using the ratio of load (in MWe) for each individual unit to the total load for all units utilizing the common stack or by using the ratio of steam load (in 1000 lb/hr or mmBtu/hr thermal output) for each individual unit to the total steam load for all units utilizing the common stack, in conjunction with the appropriate unit and stack operating times. If using either of these apportionment methods, the owner or operator shall apportion according to section 5.6 of appendix F to this part.


(4) Notwithstanding paragraph (e)(1) of this section, any affected unit that is using the procedures in this part to meet the monitoring and reporting requirements of a State or federal NOX mass emission reduction program must also meet the requirements for monitoring heat input rate in §§ 75.71, 75.72 and 75.75.


[60 FR 26522, May 17, 1995, as amended at 61 FR 25582, May 22, 1996; 61 FR 59158, Nov. 20, 1996; 64 FR 28591, May 26, 1999; 67 FR 40423, June 12, 2002; 67 FR 53504, Aug. 16, 2002; 73 FR 4343, Jan. 24, 2008]


§ 75.17 Specific provisions for monitoring emissions from common, bypass, and multiple stacks for NOX emission rate.

Notwithstanding the provisions of paragraphs (a), (b), (c), and (d) of this section, the owner or operator of an affected unit that is using the procedures in this part to meet the monitoring and reporting requirements of a State or federal NOX mass emission reduction program must also meet the provisions for monitoring NOX emission rate in §§ 75.71 and 75.72.


(a) Unit utilizing common stack with other affected unit(s). When an affected unit utilizes a common stack with one or more affected units, but no nonaffected units, the owner or operator shall either:


(1) Install, certify, operate, and maintain a NOX continuous emission monitoring system in the duct to the common stack from each affected unit; or


(2) Install, certify, operate, and maintain a NOX continuous emission monitoring system in the common stack and follow the appropriate procedure in paragraphs (a)(2) (i) through (iii) of this section, depending on whether or not the units are required to comply with a NOX emission limitation (in lb/mmBtu, annual average basis) pursuant to section 407(b) of the Act (referred to hereafter as “NOX emission limitation”).


(i) When each of the affected units has a NOX emission limitation, the designated representative shall submit a compliance plan to the Administrator that indicates:


(A) Each unit will comply with the most stringent NOX emission limitation of any unit utilizing the common stack; or


(B) Each unit will comply with the applicable NOX emission limitation by averaging its emissions with the other unit(s) utilizing the common stack, pursuant to the emissions averaging plan submitted under part 76 of this chapter; or


(C) Each unit’s compliance with the applicable NOX emission limit will be determined by a method satisfactory to the Administrator for apportioning to each of the units the combined NOX emission rate (in lb/mmBtu) measured in the common stack and for reporting the NOX emission rate, as provided in a petition submitted by the designated representative. The Administrator may approve such demonstrated substitute methods for apportioning and reporting NOX emission rate measured in a common stack whenever the demonstration ensures that there is a complete and accurate estimation of all emissions regulated under this part and, in particular, that the emissions from any unit with a NOX emission limitation are not underestimated.


(ii) When none of the affected units has a NOX emission limitation, the owner or operator and the designated representative have no additional obligations pursuant to section 407 of the Act and may record and report a combined NOX emission rate (in lb/mmBtu) for the affected units utilizing the common stack.


(iii) When at least one of the affected units has a NOX emission limitation and at least one of the affected units does not have a NOX emission limitation, the owner or operator shall either:


(A) Install, certify, operate, and maintain NOX and diluent monitors in the ducts from the affected units; or


(B) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NOX emission rate (in lb/mmBtu) measured in the common stack on each of the units. The Administrator may approve such demonstrated substitute methods for apportioning the combined NOX emission rate measured in a common stack whenever the demonstration ensures complete and accurate estimation of all emissions regulated under this part.


(b) Unit utilizing common stack with nonaffected unit(s). When one or more affected units utilizes a common stack with one or more nonaffected units, the owner or operator shall either:


(1) Install, certify, operate, and maintain a NOX-diluent continuous emission monitoring system in the duct from each affected unit; or


(2) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined NOX emission rate (in lb/mmBtu) measured in the common stack for each of the units. The Administrator may approve such demonstrated substitute methods for apportioning the combined NOX emission rate measured in a common stack whenever the demonstration ensures complete and accurate estimation of all emissions regulated under this part.


(c) Unit with multiple stacks or ducts. When the flue gases from an affected unit discharge to the atmosphere through two or more stacks or when flue gases from an affected unit utilize two or more ducts feeding into a single stack and the owner or operator chooses to monitor in the ducts rather than the stack, the owner or operator shall monitor the NOX emission rate in a way that is representative of each affected unit. Where another unit also exhausts flue gases to one or more of the stacks where monitoring systems are installed, the owner or operator shall also comply with the applicable common stack monitoring requirements of this section. The owner or operator shall either:


(1) Install, certify, operate, and maintain a NOX-diluent continuous emission monitoring system and a flow monitoring system in each stack or duct and determine the NOX emission rate for the unit as the Btu-weighted average of the NOX emission rates measured in the stacks or ducts using the heat input estimation procedures in appendix F to this part. Alternatively, for units that are eligible to use the procedures of appendix D to this part, the owner or operator may monitor heat input and NOX emission rate at the unit level, in lieu of installing flow monitors on each stack or duct. If this alternative unit-level monitoring is performed, report, for each unit operating hour, the highest emission rate measured by any of the NOX-diluent monitoring systems installed on the individual stacks or ducts as the hourly NOX emission rate for the unit, and report the hourly unit heat input as determined under appendix D to this part. Also, when this alternative unit-level monitoring is performed, the applicable NOX missing data procedures in §§ 75.31 or 75.33 shall be used for each unit operating hour in which a quality-assured NOX emission rate is not obtained for one or more of the individual stacks or ducts; or


(2) Provided that the products of combustion are well-mixed, install, certify, operate, and maintain a NOX continuous emission monitoring system in one stack or duct from the affected unit and record the monitored value as the NOX emission rate for the unit. The owner or operator shall account for NOX emissions from the unit during all times when the unit combusts fuel. Therefore, this option shall not be used if the monitored stack or duct can be bypassed (e.g., by using dampers). Follow the procedure in § 75.17(d) for units with bypass stacks. Further, this option shall not be used unless the monitored NOX emission rate truly represents the NOX emissions discharged to the atmosphere (e.g., the option is disallowed if there are any additional NOX emission controls downstream of the monitored location).


(d) Unit with a main stack and bypass stack configuration. For an affected unit with a discharge configuration consisting of a main stack and a bypass stack, the owner or operator shall either:


(1) Follow the procedures in paragraph (c)(1) of this section; or


(2) Install, certify, operate, and maintain a NOX-diluent CEMS only on the main stack. If this option is chosen, it is not necessary to designate the exhaust configuration as a multiple stack configuration in the monitoring plan required under § 75.53, with respect to NOX or any other parameter that is monitored only at the main stack. For each unit operating hour in which the bypass stack is used and the emissions are either uncontrolled (or the add-on controls are not documented to be operating properly), report the maximum potential NOX emission rate (as defined in § 72.2 of this chapter). The maximum potential NOX emission rate may be specific to the type of fuel combusted in the unit during the bypass (see § 75.33(c)(8)). Alternatively, for a unit with NOX add-on emission controls, for each unit operating hour in which the bypass stack is used and the add-on NOX emission controls are not bypassed, the owner or operator may report the maximum controlled NOX emission rate (MCR) instead of the maximum potential NOX emission rate provided that the add-on controls are documented to be operating properly, as described in the quality assurance/quality control program for the unit, required by section 1 in appendix B of this part. To provide the necessary documentation, the owner or operator shall record parametric data to verify the proper operation of the NOX add-on emission controls as described in § 75.34(d). Furthermore, the owner or operator shall calculate the MCR using the procedure described in section 2.1.2.1(b) of appendix A to this part where the words “maximum potential NOX emission rate (MER)” shall apply instead of the words “maximum controlled NOX emission rate (MCR)” and by using the NOX MEC in the calculations instead of the NOX MPC.


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26523, May 17, 1995; 63 FR 57499, Oct. 27, 1998; 64 FR 28592, May 26, 1999; 67 FR 40424, June 12, 2002; 73 FR 4343, Jan. 24, 2008]


§ 75.18 Specific provisions for monitoring emissions from common and by-pass stacks for opacity.

(a) Unit using common stack. When an affected unit utilizes a common stack with other affected units or nonaffected units, the owner or operator shall comply with the applicable monitoring provision in this paragraph, as determined by existing Federal, State, or local opacity regulations.


(1) Where another regulation requires the installation of a continuous opacity monitoring system upon each affected unit, the owner or operator shall install, certify, operate, and maintain a continuous opacity monitoring system meeting Performance Specification 1 in appendix B to part 60 of this chapter (referred to hereafter as a “certified continuous opacity monitoring system”) upon each unit.


(2) Where another regulation does not require the installation of a continuous opacity monitoring system upon each affected unit, and where the affected source is not subject to any existing Federal, State, or local opacity regulations, the owner or operator shall install, certify, operate, and maintain a certified continuous opacity monitoring system upon each common stack for the combined effluent.


(b) Unit using bypass stack. Where any portion of the flue gases from an affected unit can be routed so as to bypass the installed continuous opacity monitoring system, the owner or operator shall install, certify, operate, and maintain a certified continuous opacity monitoring system on each bypass stack flue, duct, or stack gas stream unless either:


(1) An applicable Federal, State, or local opacity regulation or permit exempts the unit from a requirement to install a continuous opacity monitoring system in the bypass stack; or


(2) A continuous opacity monitoring system is already installed and certified at the inlet of the add-on emissions controls.


(3) The owner or operator monitors opacity using method 9 of appendix A of part 60 of this chapter whenever emissions pass through the bypass stack. Method 9 shall be used in accordance with the applicable State regulations.


[58 FR 3701, Jan. 11, 1993, as amended at 60 FR 26524, May 17, 1995; 60 FR 40296, Aug. 8, 1995; 61 FR 59158, Nov. 20, 1996]


§ 75.19 Optional SO2, NOX, and CO2 emissions calculation for low mass emissions (LME) units.

(a) Applicability and qualification. (1) For units that meet the requirements of this paragraph (a)(1) and paragraphs (a)(2) and (b) of this section, the low mass emissions (LME) excepted methodology in paragraph (c) of this section may be used in lieu of continuous emission monitoring systems or, if applicable, in lieu of methods under appendices D, E, and G to this part, for the purpose of determining unit heat input, NOX, SO2, and CO2 mass emissions, and NOX emission rate under this part. If the owner or operator of a qualifying unit elects to use the LME methodology, it must be used for all parameters that are required to be monitored by the applicable program(s). For example, for an Acid Rain Program LME unit, the methodology must be used to estimate SO2, NOX, and CO2 mass emissions, NOX emission rate, and unit heat input.


(i) A low mass emissions unit is an affected unit that is gas-fired, or oil-fired (as defined in § 72.2 of this chapter), and for which:


(A) An initial demonstration is provided, in accordance with paragraph (a)(2) of this section, which shows that the unit emits:


(1) No more than 25 tons of SO2 annually and less than 100 tons of NOX annually, for Acid Rain Program affected units. If the unit is also subject to the provisions of subpart H of this part, no more than 50 of the allowable annual tons of NOX may be emitted during the ozone season; or


(2) Less than 100 tons of NOX annually and no more than 50 tons of NOX during the ozone season, for non-Acid Rain Program units subject to the provisions of subpart H of this part, for which the owner or operator reports emissions data on a year-round basis, in accordance with § 75.74(a) or § 75.74(b); or


(3) No more than 50 tons of NOX per ozone season, for non-Acid Rain Program units subject to the provisions of subpart H of this part, for which the owner or operator reports emissions data only during the ozone season, in accordance with § 75.74(b); and


(B) An annual demonstration is provided thereafter, using one of the allowable methodologies in paragraph (c) of this section, showing that the low mass emissions unit continues to emit no more than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section.


(C) This paragraph, (a)(1)(i)(C), applies only to a unit that is subject to an SO2 emission limitation under the Acid Rain Program, and that combusts a gaseous fuel other than pipeline natural gas or natural gas (as defined in § 72.2 of this chapter). The owner or operator of such a unit must quantify the sulfur content and variability of the gaseous fuel by performing the demonstration described in section 2.3.6 of appendix D to this part, in order for the unit to qualify for LME unit status. If the results of that demonstration show that the gaseous fuel qualifies under paragraph (b) of section 2.3.6 to use a default SO2 emission rate to report SO2 mass emissions under this part, the unit is eligible for LME unit status.


(ii) Each qualifying LME unit must start using the low mass emissions excepted methodology as follows:


(A) For a unit that reports emission data on a year-round basis, begin using the methodology in the first unit operating hour in the calendar year designated in the certification application as the first year that the methodology will be used; or


(B) For a unit that is subject to Subpart H of this part and that reports only during the ozone season according to § 75.74(c), begin using the methodology in the first unit operating hour in the ozone season designated in the certification application as the first ozone season that the methodology will be used.


(C) For a new or newly-affected unit, see paragraph (b)(4) of this section for additional guidance.


(2) A unit may initially qualify as a low mass emissions unit if the designated representative submits a certification application to use the LME methodology (as described in § 75.63(a)(1)(ii) and in this paragraph, (a)(2)) and the Administrator (or permitting authority, as applicable) certifies the use of such methodology. The certification application shall be submitted no later than 45 days prior to the date on which use of the low mass emissions methodology is expected to commence, and the application must contain:


(i) A statement identifying the projected date on which the LME methodology will first be used. The projected commencement date shall be consistent with paragraphs (a)(1)(ii) and (b)(4) of this section, as applicable; and


(ii) Either:


(A) Actual SO2 and/or NOX mass emissions data (as applicable) for each of the three calendar years (or ozone seasons) prior to the calendar year in which the certification application is submitted demonstrating to the satisfaction of the Administrator or (if applicable) the permitting authority, that the unit emitted less than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section. For the purposes of this paragraph, (a)(2)(ii)(A), the required actual SO2 or NOX mass emissions for each qualifying year or ozone season shall be determined using the SO2, NOX and heat input data reported to the Administrator in the electronic quarterly reports required under § 75.64 or under the Ozone Transport Commission (OTC) NOX Budget Trading Program. Notwithstanding this requirement, in the absence of such electronic reports, an estimate of the actual emissions for each of the previous three years (or ozone seasons) shall be provided, using either the maximum rated heat input methodology described in paragraph (c)(3)(i) of this section or procedures consistent with the long term fuel flow heat input methodology described in paragraph (c)(3)(ii) of this section, in conjunction with the appropriate SO2 or NOX emission rate from paragraph (c)(1)(i) of this section for SO2, and paragraph (c)(1)(ii) or (c)(1)(iv) of this section for NOX. Alternatively, the initial estimate of the NOX emission rate may be based on historical emission test data that is representative of operation at normal load or historical data from a CEMS certified under part 60 of this chapter or under a state CEM program; or


(B) When the three full years (or ozone seasons) of actual SO2 and NOX mass emissions data (or reliable estimates thereof) described under paragraph (a)(2)(ii)(A) of this section do not exist, the designated representative may submit an application to use the low mass emissions excepted methodology based upon a combination of actual historical SO2 and NOX mass emissions data and projected SO2 and NOX mass emissions, totaling three years (or ozone seasons). Except as provided in paragraph (a)(3) of this section, actual data must be used for any years (or ozone seasons) in which such data exists and projected data should be used for any remaining future years (or ozone seasons) needed to provide emissions data for three consecutive calendar years (or ozone seasons). For example, if a unit commenced operation two years ago, the designated representative may submit actual, historical data for the previous two years and one year of projected emissions for the current calendar year or, for a new unit, the designated representative may submit three years of projected emissions, beginning with the current calendar year. Any actual or projected annual emissions must demonstrate to the satisfaction of the Administrator that the unit will emit less than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section. Projected emissions shall be calculated using either the appropriate default emission rates from paragraphs (c)(1)(i) and (c)(1)(ii) of this section (or, alternatively for NOX, a conservative estimate of the NOX emission rate, as described in paragraph (a)(4) of this section), in conjunction with projections of unit operating hours or fuel type and fuel usage, according to one of the allowable calculation methodologies in paragraph (c) of this section; and


(iii) A description of the methodology from paragraph (c) of this section that will be used to demonstrate on-going compliance under paragraph (b) of this section; and


(iv) Appropriate documentation demonstrating that the unit is eligible to use projected emissions to qualify for LME status under paragraph (a)(3) of this section (if applicable).


(3) In the following circumstances, projected emissions for a future year (or years) may be used in lieu of the actual emissions data from one (or more) of the three years (or ozone seasons) preceding the year of the certification application:


(i) If the owner or operator takes an enforceable permit restriction on the number of annual or ozone season unit operating hours for the future year (or years), such that the unit will emit no more than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section; or


(ii) If the actual emissions for one (or more) of the three years (or ozone seasons) prior to the year of the certification application is not representative of the present and expected future emissions from the unit, because the owner or operator has recently installed emission controls on the unit.


(4) When the owner or operator elects to demonstrate initial LME qualification and on-going compliance using a fuel-and-unit-specific NOX emission rate in accordance with paragraph (c)(1)(iv) of this section, there will be instances (e.g., for a new or newly-affected unit) where it is not possible to determine that NOX emission rate prior to submitting the certification application. In such cases, if the generic default NOX emission rates in Table LM-2 of this section are inappropriately high for the unit, the owner or operator may use a more representative, but conservatively high estimate of the expected NOX emission rate, for the purposes of the initial monitoring plan submittal and to calculate the unit’s projected annual or ozone season emissions under paragraph (a)(2)(ii)(B) of this section. For example, the NOX emission rate could, as described in paragraph (a)(2)(ii)(A) of this section, be estimated using historical CEM data or historical emission test data that is representative of operation at normal load. The NOX emission limit specified in the operating permit for the unit could also be used to estimate the NOX emission rate (except for units equipped with SCR or SNCR), or, consistent with paragraph (c)(1)(iv)(C)(4) of this section, for a unit that uses SCR or SNCR to control NOX emissions, an estimated default NOX emission rate of 0.15 lb/mmBtu could be used. However, these estimated NOX emission rates may not be used for reporting purposes in the time period extending from the first hour in which the LME methodology is used to the date and hour on which the fuel-and-unit-specific NOX emission rate testing is completed. Rather, in that interval, the owner or operator shall either report the appropriate default NOX emission rate from Table LM-2, or shall report the maximum potential NOX emission rate, calculated in accordance with § 72.2 of this chapter and section 2.1.2.1 of appendix A to this part. Then, beginning with the first unit operating hour after completion of the tests, the appropriate default NOX emission rate(s) obtained from the fuel-and-unit-specific testing shall be used for emissions reporting.


(b) On-going qualification and disqualification. (1) Once a low mass emissions unit has qualified for and has started using the low mass emissions excepted methodology, an annual demonstration is required, showing that the unit continues to emit no more than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section. The calculation methodology used for the annual demonstration shall be the methodology described in the certification application under paragraph (a)(2)(iii) of this section.


(2) If any low mass emissions unit fails to provide the required annual demonstration under paragraph (b)(1) of this section, such that the calculated cumulative emissions for the unit exceed the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section at the end of any calendar year or ozone season, then:


(i) The low mass emissions unit shall be disqualified from using the low mass emissions excepted methodology; and


(ii) The owner or operator of the low mass emissions unit shall install and certify monitoring systems that meet the requirements of §§ 75.11, 75.12, and 75.13, and shall report SO2 (Acid Rain Program units, only), NOX, and CO2 (Acid Rain Program units, only) emissions data and heat input data from such monitoring systems by December 31 of the calendar year following the year in which the unit exceeded the number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section; and


(iii) If the required monitoring systems have not been installed and certified by the applicable deadline in paragraph (b)(2)(ii) of this section, the owner or operator shall report the following values for each unit operating hour, beginning with the first operating hour after the deadline and continuing until the monitoring systems have been provisionally certified: the maximum potential hourly heat input for the unit, as defined in § 72.2 of this chapter; the SO2 emissions, in lb/hr, calculated using the applicable default SO2 emission rate from paragraph (c)(1)(i) of this section and the maximum potential hourly unit heat input; the CO2 emissions, in tons/hr, calculated using the applicable default CO2 emission rate from paragraph (c)(1)(iii) of this section and the maximum potential hourly unit heat input; and the maximum potential NOX emission rate, as defined in § 72.2 of this chapter.


(3) If a low mass emissions unit that initially qualifies to use the low mass emissions excepted methodology under this section changes fuels, such that a fuel other than those allowed for use in the low mass emissions methodology is combusted in the unit, the unit shall be disqualified from using the low mass emissions excepted methodology as of the first hour that the new fuel is combusted in the unit. The owner or operator shall install and certify SO2 (Acid Rain Program units, only), NOX, and CO2 (Acid Rain Program units, only) and flow (if necessary) monitoring systems that meet the requirements of §§ 75.11, 75.12, and 75.13 prior to a change to such fuel, and shall report emissions data from such monitoring systems beginning with the date and hour on which the new fuel is first combusted in the unit. If the required monitoring systems are not installed and certified prior to the fuel switch, the owner or operator shall report (as applicable) the maximum potential concentration of SO2, CO2 and NOX, the maximum potential NOX emission rate, the maximum potential flowrate, the maximum potential hourly heat input and the maximum (or minimum, if appropriate) potential moisture percentage, from the date and hour of the fuel switch until the monitoring systems are certified or until probationary calibration error tests of the monitors are passed and the conditional data validation procedures in § 75.20(b)(3) begin to be used. All maximum and minimum potential values shall be specific to the new fuel and shall be determined in a manner consistent with section 2 of appendix A to this part and § 72.2 of this chapter. The owner or operator must notify the Administrator (or the permitting authority) in the case where a unit switches fuels without previously having installed and certified a SO2, NOX and CO2 monitoring system meeting the requirements of §§ 75.11, 75.12, and 75.13.


(4) If a new of newly-affected unit initially qualifies to use the low mass emissions excepted methodology under this section and the owner or operator wants to use the low mass emissions methodology for the unit, he or she must:


(i) Keep the records specified in paragraph (c)(2) of this section, beginning with the date and hour of commencement of commercial operation, for a new unit subject to an Acid Rain emission limitation, and beginning with the date and hour of the commencement of operation, for a new unit subject to a NOX mass reduction program under subpart H of this part. For newly-affected units, the records in paragraph (c)(2) of this section shall be kept as follows:


(A) For Acid Rain Program units, begin keeping the records as of the first hour of commercial operation of the unit following the date on which the unit becomes affected; or


(B) For units subject to a NOX mass reduction program under subpart H of this part, begin keeping the records as of the first hour of unit operation following the date on which the unit becomes an affected unit;


(ii) Use these records to determine the cumulative heat input and SO2, CO2, and/or NOX mass emissions in order to continue to qualify as a low mass emissions unit; and


(iii) Determine the cumulative SO2 and/or NOX mass emissions according to paragraph (c) of this section using the same procedures used after the certification deadline for the unit, for purposes of demonstrating eligibility to use the excepted methodology set forth in this section. For example, use the default emission rates in Tables LM-1, LM-2, and LM-3 of this section or use the fuel-and-unit-specific NOX emission rate determined according to paragraph (c)(1)(iv) of this section. For Acid Rain Program LME units, the Administrator will not count SO2 mass emissions calculated for the period between commencement of commercial operation and the certification deadline for the unit under § 75.4 against SO2 allowances to be held in the unit account.


(5) A low mass emissions unit that has been disqualified from using the low mass emissions excepted methodology may subsequently submit an application to qualify again to use the low mass emissions methodology under paragraph (a)(2) of this section only if, following the non-compliant year (or ozone season), at least three full years (or ozone seasons) of actual, monitored emissions data is obtained showing that the unit emitted no more than the applicable number of tons of SO2 and/or NOX specified in paragraph (a)(1)(i)(A) of this section. Further, the designated representative or authorized account representative must certify in the application that the unit operation for the years or ozone seasons for which the emissions were monitored are representative of the projected future operation of the unit.


(c) Low mass emissions excepted methodology, calculations, and values – (1) Determination of SO2, NOX, and CO2 emission rates.


(i) If the unit combusts only natural gas and/or fuel oil, use Table LM-1 of this section to determine the appropriate SO2 emission rate for use in calculating hourly SO2 mass emissions under this section. Alternatively, for fuel oil combustion, a lower, fuel-specific SO2 emission factor may be used in lieu of the applicable emission factor from Table LM-1, if a federally enforceable permit condition is in place that limits the sulfur content of the oil. If this alternative is chosen, the fuel-specific SO2 emission rate in lb/mmBtu shall be calculated by multiplying the fuel sulfur content limit (weight percent sulfur) by 1.01. In addition, the owner or operator shall periodically determine the sulfur content of the oil combusted in the unit, using one of the oil sampling and analysis options described in section 2.2 of appendix D to this part, and shall keep records of these fuel sampling results in a format suitable for inspection and auditing. Alternatively, the required oil sampling and associated recordkeeping may be performed using a consensus standard (e.g., ASTM, API, etc.) that is prescribed in the unit’s Federally-enforceable operating permit, in an applicable State regulation, or in another applicable Federal regulation. If the unit combusts gaseous fuel(s) other than natural gas, the owner or operator shall use the procedures in section 2.3.6 of appendix D to this part to document the total sulfur content of each such fuel and to determine the appropriate default SO2 emission rate for each such fuel.


(ii) If the unit combusts only natural gas and/or fuel oil, use either the appropriate NOX emission factor from Table LM-2 of this section, or a fuel-and-unit-specific NOX emission rate determined according to paragraph (c)(1)(iv) of this section, to calculate hourly NOX mass emissions under this section. If the unit combusts a gaseous fuel other than pipeline natural gas or natural gas, the owner or operator shall determine a fuel-and-unit-specific NOX emission rate according to paragraph (c)(1)(iv) of this section.


(iii) If the unit combusts only natural gas and/or fuel oil, use Table LM-3 of this section to determine the appropriate CO2 emission rate for use in calculating hourly CO2 mass emissions under this section (Acid Rain Program units, only). If the unit combusts a gaseous fuel other than pipeline natural gas or natural gas, the owner or operator shall determine a fuel-and-unit-specific CO2 emission rate for the fuel, as follows:


(A) Derive a carbon-based F-factor for the fuel, using fuel sampling and analysis, as described in section 3.3.6 of appendix F to this part; and


(B) Use Equation G-4 in appendix G to this part to derive the default CO2 emission rate. Rearrange the equation, solving it for the ratio of WCO2/H (this ratio will yield an emission rate, in units of tons/mmBtu). Then, substitute the carbon-based F-factor determined in paragraph (c)(1)(iii)(A) of this section into the rearranged equation to determine the default CO2 emission rate for the unit.


(iv) In lieu of using the default NOX emission rate from Table LM-2 of this section, the owner or operator may, for each fuel combusted by a low mass emissions unit, determine a fuel-and-unit-specific NOX emission rate for the purpose of calculating NOX mass emissions under this section. This option may be used by any unit which qualifies to use the low mass emission excepted methodology under paragraph (a) of this section, and also by groups of units which combust fuel from a common source of supply and which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section to determine heat input. The testing must be completed in a timely manner, such that the test results are reported electronically no later than the end of the calendar year or ozone season in which the LME methodology is first used. If this option is chosen, the following procedures shall be used.


(A) Except as otherwise provided in paragraphs (c)(1)(iv)(F), (c)(1)(iv)(G), and (c)(1)(iv)(I) of this section, determine a fuel-and-unit-specific NOX emission rate by conducting a four load NOX emission rate test procedure as specified in section 2.1 of appendix E to this part, for each type of fuel combusted in the unit. For a group of units sharing a common fuel supply, the appendix E testing must be performed on each individual unit in the group, unless some or all of the units in the group belong to an identical group of units, as defined in paragraph (c)(1)(iv)(B) of this section, in which case, representative testing may be conducted on units in the identical group of units, as described in paragraph (c)(1)(iv)(B) of this section. For the purposes of this section, make the following modifications to the appendix E test procedures:


(1) Do not measure the heat input as required under 2.1.3 of appendix E to this part.


(2) Do not plot the test results as specified under 2.1.6 of appendix E to this part.


(3) Do not correct the NOX concentration to 15% O2.


(4) If the testing is performed on an uncontrolled diffusion flame turbine, a correction to the observed average NOX concentration from each run of the test must be applied using the following Equation LM-1a.





Where:

NOXcorr = Corrected NOX concentration (ppm).

NOXobs = Average measured NOX concentration for each run of the test (ppm).

Pr = Average annual atmospheric pressure (or average ozone season atmospheric pressure for a Subpart H unit that reports data only during the ozone season) at the nearest weather station (e.g., a standardized NOAA weather station located at the airport) for the year (or ozone season) prior to the year of the test (mm Hg).

Po = Observed atmospheric pressure during the test run (mm Hg).

Hr = Average annual atmospheric humidity ratio (or average ozone season humidity ratio for a Subpart H unit that reports data only during the ozone season) at the nearest weather station, for the year (or ozone season) prior to the year of the test (g H2O/g air).

Ho = Observed humidity ratio during the test run (g H2O/g air).

Tr = Average annual atmospheric temperature (or average ozone season atmospheric temperature for a Subpart H unit that reports data only during the ozone season) at the nearest weather station, for the year (or ozone season) prior to the year of the test (° K).

Ta = Observed atmospheric temperature during the test run (° K).

(B) Representative appendix E testing may be done on low mass emission units in a group of identical units. All of the units in a group of identical units must combust the same fuel type but do not have to share a common fuel supply.


(1) To be considered identical, all low mass emission units must be of the same size (based on maximum rated hourly heat input), manufacturer and model, and must have the same history of modifications (e.g., have the same controls installed, the same types of burners and have undergone major overhauls at the same frequency (based on hours of operation)). Also, under similar operating conditions, the stack or turbine outlet temperature of each unit must be within ±50 degrees Fahrenheit of the average stack or turbine outlet temperature for all of the units.


(2) If all of the low mass emission units in the group qualify as identical, then representative testing of the units in the group may be performed according to Table LM-4 of this section.


(3) [Reserved]


(4) If the acceptance criteria in paragraph (c)(1)(iv)(B)(1) of this section are not met then the group of low mass emission units is not considered an identical group of units and individual appendix E testing of each unit is required.


(5) Fuel and unit specific NOX emission rates determined according to paragraphs (c)(1)(iv)(F) and (c)(1)(iv)(G) of this section may be used in lieu of appendix E testing for one or more low mass emission units in a group of identical units.


(C) Based on the results of the part 75 appendix E testing, determine the fuel-and-unit-specific NOX emission rate as follows:


(1) Except for LME units that use selective catalytic reduction (SCR) or selective non-catalytic reduction (SNCR) to control NOX emissions, the highest three-run average NOX emission rate obtained at any load in the appendix E test for a particular type of fuel shall be the fuel-and-unit-specific NOX emission rate, for that type of fuel.


(2) [Reserved]


(3) For a group of identical low mass emissions units (except for units that use SCR or SNCR to control NOX emissions), the fuel-and-unit-specific NOX emission rate for all units in the group, for a particular type of fuel, shall be the highest three-run average NOX emission rate obtained at any tested load from any unit tested in the group, for that type of fuel.


(4) Except as provided in paragraphs (c)(1)(iv)(C)(7) and (c)(1)(iv)(C)(8) of this section, for an individual low mass emissions unit which uses SCR or SNCR to control NOX emissions, the fuel-and-unit-specific NOX emission rate for each type of fuel combusted in the unit shall be the higher of:


(i) The highest three-run average emission rate from any load of the appendix E test for that type of fuel; or


(ii) 0.15 lb/mmBtu.


(5) [Reserved]


(6) Except as provided in paragraphs (c)(1)(iv)(C)(7) and (c)(1)(iv)(C)(8) of this section, for a group of identical low mass emissions units that are all equipped with SCR or SNCR to control NOX emissions, the fuel-and-unit-specific NOX emission rate for each unit in the group of units, for a particular type of fuel, shall be the higher of:


(i) The highest three-run average NOX emission rate at any load from all appendix E tests of all tested units in the group, for that type of fuel; or


(ii) 0.15 lb/mmBtu.


(7) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)(4) and (c)(1)(iv)(C)(6) of this section, for a unit (or group of identical units) equipped with SCR (or SNCR) and water (or steam) injection to control NOX emissions:


(i) If the appendix E testing is performed when the water (or steam) injection is in use and either upstream of the SCR or SNCR or during a time period when the SCR or SNCR is out of service; then


(ii) The highest three-run average emission rate from the appendix E testing may be used as the fuel-and-unit-specific NOX emission rate for the unit (or, if applicable, for each unit in the group), for each unit operating hour in which the water-to-fuel ratio is within the acceptable range established during the appendix E testing.


(8) Notwithstanding the requirements of paragraphs (c)(1)(iv)(C)(4) and (c)(1)(iv)(C)(6) of this section, for a unit (or group of identical units) equipped with SCR (or SNCR) and uses dry low-NOX technology to control NOX emissions:


(i) If the appendix E testing is performed during a time period when the dry low-NOX controls are in use, but the SCR or SNCR is out of service; then


(ii) The highest three-run average emission rate from the appendix E testing may be used as the fuel-and-unit-specific NOX emission rate for the unit (or, if applicable, for each unit in the group), for each unit operating hour in which the parametric data described in paragraph (c)(1)(iv)(H)(2) of this section demonstrate that the dry low-NOX controls are operating in the premixed or low-NOX mode.


(9) For an individual combustion turbine (or a group of identical turbines) that operate principally at base load (or at a set point temperature), but are capable of operating at a higher peak load (or higher internal operating temperature), the fuel-and-unit-specific NOX emission rate for the unit (or for each unit in the group) shall be as follows:


(i) If the testing is done only at base load, use the three-run average NOX emission rate for base load operating hours and 1.15 times that emission rate for peak load operating hours; or


(ii) If the testing is done at both base load and peak load, use the three-run average NOX emission rate from the base load testing for base load operating hours and the three-run average NOX emission rate from the peak load testing for peak load operating hours.


(D) For each low mass emissions unit, or group of identical units for which the provisions of paragraph (c)(1)(iv) of this section are used to account for NOX emission rate, the owner or operator shall determine a new fuel-and-unit-specific NOX emission rate every five years (20 calendar quarters), unless changes in the fuel supply, physical changes to the unit, changes in the manner of unit operation, or changes to the emission controls occur which may cause a significant increase in the unit’s actual NOX emission rate. If such changes occur, the fuel-and-unit-specific NOX emission rate(s) shall be re-determined according to paragraph (c)(1)(iv) of this section. Testing shall be done at the number of loads specified in paragraph (c)(1)(iv)(A) or (c)(1)(iv)(I) of this section, as applicable. If a low mass emissions unit belongs to a group of identical units and it is required to retest to determine a new fuel-and-unit-specific NOX emission rate because of changes in the fuel supply, physical changes to the unit, changes in the manner of unit operation or changes to the emission controls occur which may cause a significant increase in the unit’s actual NOX emission rate, any other unit in that group of identical units is not required to re-determine the fuel-and-unit-specific NOX emission rate unless such unit also undergoes changes in the fuel supply, physical changes to the unit, changes in the manner of unit operation or changes to the emission controls occur which may cause a significant increase in the unit’s actual NOX emission rates.


(E) Each low mass emissions unit or each low mass emissions unit in a group of identical units for which a fuel-and-unit-specific NOX emission rate(s) are determined shall meet the quality assurance and quality control provisions of paragraph (e) of this section.


(F) Low mass emission units may use the results of appendix E testing, if such test results are available from a test conducted no more than five years prior to the time of initial certification, to determine the appropriate fuel-and-unit-specific NOX emission rate(s). However, fuel-and-unit-specific NOX emission rates from historical testing may not be used longer than five years after the appendix E testing was conducted.


(G) Low mass emissions units for which at least 3 years of quality-assured NOX emission rate data from a NOX-diluent CEMS that meets the quality assurance requirements of either: this part, or appendix F to part 60 of this chapter, or a comparable State CEM program, and corresponding fuel usage data are available may determine fuel-and-unit-specific NOX emission rates from the actual data using the following procedure. Separate the actual NOX emission rate data into groups, according to the type of fuel combusted. Discard data from periods when multiple fuels were combusted. Each fuel-specific data set must contain at least 168 hours of data and must represent all normal operating ranges of the unit when combusting the fuel. Sort the data in each fuel-specific data set in ascending order according to NOX emission rate. Determine the 95th percentile NOX emission rate for each data set as defined in § 72.2 of this chapter. Use the 95th percentile value for each data set as the fuel-and-unit-specific NOX emission rate, except that for a unit that uses SCR or SNCR for NOX emission control, if the 95th percentile value is less than 0.15 lb/mmBtu, a value of 0.15 lb/mmBtu shall be used as the fuel-and-unit-specific NOX emission rate.


(H) For low mass emission units with add-on NOX emission controls, and for units that use dry low-NOX technology, the owner or operator shall, during every hour of unit operation during the test period, monitor and record parameters, as required under paragraph (e)(5) of this section, which indicate that the NOX emission controls are operating properly. After the test period, these same parameters shall be monitored and recorded and kept for all operating hours in order to determine whether the NOX controls are operating properly and to allow the determination of the correct NOX emission rate as required under paragraph (c)(1)(iv) of this section.


(1) For low mass emission units with steam or water injection, the steam-to-fuel or water-to-fuel ratio used during the testing must be documented. The water-to-fuel or steam-to-fuel ratio must be maintained during unit operations for a unit to use the fuel and unit specific NOX emission rate determined during the test. Owners or operators must include in the monitoring plan the acceptable range of the water-to-fuel or steam-to-fuel ratio, which will be used to indicate hourly, proper operation of the NOX controls for each unit. The water-to-fuel or steam-to-fuel ratio shall be monitored and recorded during each hour of unit operation. If the water-to-fuel or steam-to-fuel ratio is not within the acceptable range in a given hour the fuel and unit specific NOX emission rate may not be used for that hour, and the appropriate default NOX emission rate from Table LM-2 shall be reported instead.


(2) For a low mass emissions unit that uses dry low-NOX premix technology to control NOX emissions, proper operation of the emission controls means that the unit is in the low-NOX or premixed combustion mode, and fired with natural gas. Evidence of operation in the low-NOX or premixed mode shall be provided by monitoring the appropriate turbine operating parameters. These parameters may include percentage of full load, turbine exhaust temperature, combustion reference temperature, compressor discharge pressure, fuel and air valve positions, dynamic pressure pulsations, internal guide vane (IGV) position, and flame detection or flame scanner condition. The acceptable values and ranges for all parameters monitored shall be specified in the monitoring plan for the unit, and the parameters shall be monitored during each subsequent operating hour. If one or more of these parameters is not within the acceptable range or at an acceptable value in a given operating hour, the fuel-and-unit-specific NOX emission rate may not be used for that hour, and the appropriate default NOX emission rate from Table LM-2 shall be reported instead. When the unit is fired with oil the appropriate default value from Table LM-2 shall be reported.


(3) For low mass emission units with other types of add-on NOX controls, appropriate parameters and the acceptable range of the parameters which indicate hourly proper operation of the NOX controls must be specified in the monitoring plan. These parameters shall be monitored during each subsequent operating hour. If any of these parameters are not within the acceptable range in a given operating hour, the fuel and unit specific NOX emission rates may not be used in that hour, and the appropriate default NOX emission rate from Table LM-2 shall be reported instead.


(I) Notwithstanding the requirements in paragraph (c)(1)(iv)(A) of this section, the appendix E testing to determine (or re-determine) the fuel-specific, unit-specific NOX emission rate for a unit (or for each unit in a group of identical units) may be performed at fewer than four loads, under the following circumstances:


(1) Testing may be done at one load level if the data analysis described in paragraph (c)(1)(iv)(J) of this section is performed and the results show that the unit has operated (or all units in the group of identical units have operated) at a single load level for at least 85.0 percent of all operating hours in the previous three years (12 calendar quarters) prior to the calendar quarter of the appendix E testing. For combustion turbines that are operated to produce approximately constant output (in MW) but which use internal operating and exhaust temperatures and not the actual output in MW to control the operation of the turbine, the internal operating temperature set point may be used as a surrogate for load in demonstrating that the unit qualifies for single-load testing. If the data analysis shows that the unit does not qualify for single-load testing, testing may be done at two (or three) load levels if the unit has operated (or if all units in the group of identical units have operated) cumulatively at two (or three) load levels for at least 85.0 percent of all operating hours in the previous three years; or


(2) If a multiple-load appendix E test was initially performed for a unit (or group of identical units) to determine the fuel-and-unit specific NOX emission rate, then the periodic retests required under paragraph (c)(1)(iv)(D) of this section may be single-load tests, performed at the load level for which the highest average NOX emission rate was obtained in the initial test.


(3) The initial appendix E testing may be performed at a single load, between 75 and 100 percent of the maximum sustainable load defined in the monitoring plan for the unit, if the average annual capacity factor of the LME unit, when calculated according to the definition of “capacity factor” in § 72.2 of this chapter, is 2.5 percent or less for the three calendar years immediately preceding the year of the testing, and that the annual capacity factor does not exceed 4.0 percent in any of those three years. Similarly, for a LME unit that reports emissions data on an ozone season-only basis, the initial appendix E testing may be performed at a single load between 75 and 100 percent of the maximum sustainable load if the 2.5 and 4.0 percent capacity factor requirements are met for the three ozone seasons immediately preceding the date of the emission testing (see § 75.74(c)(11)). For a group of identical LME units, any unit(s) in the group that meet the 2.5 and 4.0 percent capacity factor requirements may perform the initial appendix E testing at a single load between 75 and 100 percent of the maximum sustainable load.


(4) The retest of any LME unit may be performed at a single load between 75 and 100 percent of the maximum sustainable load if, for the three calendar years immediately preceding the year of the retest (or, if applicable, the three ozone seasons immediately preceding the date of the retest), the applicable capacity factor requirements described in paragraph (c)(1)(iv)(I)(3) of this section are met.


(5) Alternatively, for combustion turbines, the single-load testing described in paragraphs (c)(1)(iv)(I)(3) and (c)(1)(iv)(I)(4) of this section may be performed at the highest attainable load level corresponding to the season of the year in which the testing is conducted.


(6) In all cases where the alternative single-load testing option described in paragraphs (c)(1)(iv)(I)(3) through (c)(1)(iv)(I)(5) of this section is used, the owner or operator shall keep records documenting that the required capacity factor requirements were met.


(J) To determine whether a unit qualifies for testing at fewer than four loads under paragraph (c)(1)(iv)(I) of this section, follow the procedures in paragraph (c)(1)(iv)(J)(1) or (c)(1)(iv)(J)(2) of this section, as applicable.


(1) Determine the range of operation of the unit, according to section 6.5.2.1 of appendix A to this part. Divide the range of operation into four equal load bands. For example, if the range of operation extends from 20 MW to 100 MW, the four equal load bands would be: band #1: from 20 MW to 40 MW; band #2: from 41 MW to 60 MW; band #3: from 61 MW to 80 MW; and band #4: from 81 to 100 MW. Then, perform a historical load analysis for all unit operating hours in the 12 calendar quarters preceding the quarter of the test. Alternatively, for sources that report emissions data only during the ozone season, the historical load analysis may be based on unit operation in the previous three ozone seasons, rather than unit operation in the previous 12 calendar quarters. Determine the percentage of the data that fall into each load band. For a unit that is not part of a group of identical units, if 85.0% or more of the data fall into one load band, single-load testing may be performed at any point within that load band. For a group of identical units, if each unit in the group meets the 85.0% criterion, then representative single-load testing within the load band may be performed. If the 85.0% criterion cannot be met to qualify for single-load testing but this criterion can be met cumulatively for two (or three) load levels, then testing may be performed at two (or three) loads instead of four.


(2) For a combustion turbine that uses exhaust temperature and not the actual output in megawatts to control the operation of the turbine (or for a group of identical units of this type), the owner or operator must document that the unit (or each unit in the group) has operated within ±10% of the set point temperature for 85.0% of the operating hours in the previous 12 calendar quarters to qualify for single-load testing. Alternatively, for sources that report emissions data only during the ozone season, the historical set point temperature analysis may be based on unit operation in the previous three ozone seasons, rather than unit operation in the previous 12 calendar quarters. When the set point temperature is used rather than unit load to justify single-load testing, the designated representative shall certify in the monitoring plan for the unit that this is the normal manner of unit operation and shall document the setpoint temperature.


(2) Records of operating time, fuel usage, unit output and NOX emission control operating status. The owner or operator shall keep the following records on-site, for three years, in a form suitable for inspection, except that for unmanned facilities, the records may be kept at a central location, rather than on-site:


(i) For each low mass emissions unit, the owner or operator shall keep hourly records which indicate whether or not the unit operated during each clock hour of each calendar year. The owner or operator may report partial operating hours or may assume that for each hour the unit operated the operating time is a whole hour. Units using partial operating hours and the maximum rated hourly heat input to calculate heat input for each hour must report partial operating hours.


(ii) For each low mass emissions unit, the owner or operator shall keep hourly records indicating the type(s) of fuel(s) combusted in the unit during each hour of unit operation.


(iii) For each low mass emissions unit using the long term fuel flow methodology under paragraph (c)(3)(ii) of this section to determine hourly heat input, the owner or operator shall keep hourly records of unit load (in megawatts or thousands of pounds of steam per hour), for the purpose of apportioning heat input to the individual unit operating hours.


(iv) For each low mass emissions unit with add-on NOX emission controls of any kind and each unit that uses dry low-NOX technology, the owner or operator shall keep hourly records of the hourly value of the parameter(s) specified in (c)(1)(iv)(H) of this section used to indicate proper operation of the unit’s NOX controls.


(3) Heat input. Hourly, quarterly and annual heat input for a low mass emissions unit shall be determined using either the maximum rated hourly heat input method under paragraph (c)(3)(i) of this section or the long term fuel flow method under paragraph (c)(3)(ii) of this section.


(i) Maximum rated hourly heat input method. (A) For the purposes of the mass emission calculation methodology of paragraph (c)(3) of this section, HIhr, the hourly heat input (mmBtu) to a low mass emissions unit shall be deemed to equal the maximum rated hourly heat input, as defined in § 72.2 of this chapter, multiplied by the operating time of the unit for each hour. The owner or operator may choose to record and report partial operating hours or may assume that a unit operated for a whole hour for each hour the unit operated. However, the owner or operator of a unit may petition the Administrator under § 75.66 for a lower value for maximum rated hourly heat input than that defined in § 72.2 of this chapter. The Administrator may approve such lower value if the owner or operator demonstrates that either the maximum hourly heat input specified by the manufacturer or the highest observed hourly heat input, or both, are not representative, and such a lower value is representative, of the unit’s current capabilities because modifications have been made to the unit, limiting its capacity permanently.


(B) The quarterly heat input, HIqtr, in mmBtu, shall be determined using Equation LM-1:





Where:

n = Number of unit operating hours in the quarter.

HIhr = Hourly heat input under paragraph (c)(3)(i)(A) of this section (mmBtu).

(C) The year-to-date cumulative heat input (mmBtu) shall be the sum of the quarterly heat input values for all of the calendar quarters in the year to date.


(D) For a unit subject to the provisions of subpart H of this part, which is not required to report emission data on a year-round basis and elects to report only during the ozone season, the quarterly heat input for the second calendar quarter of the year shall, for compliance purposes, include only the heat input for the months of May and June, and the cumulative ozone season heat input shall be the sum of the heat input values for May, June and the third calendar quarter of the year.


(ii) Long term fuel flow heat input method. The owner or operator may, for the purpose of demonstrating that a low mass emissions unit or group of low mass emission units sharing a common fuel supply meets the requirements of this section, use records of long-term fuel flow, to calculate hourly heat input to a low mass emissions unit.


(A) This option may be used for a group of low mass emission units only if:


(1) The low mass emission units combust fuel from a common source of supply; and


(2) Records are kept of the total amount of fuel combusted by the group of low mass emission units and the hourly output (in megawatts or pounds of steam) from each unit in the group; and


(3) All of the units in the group are low mass emission units.


(B) For each fuel used during the quarter, the volume in standard cubic feet (for gas) or gallons (for oil) may be determined using any of the following methods;


(1) Fuel billing records (for low mass emission units, or groups of low mass emission units, which purchase fuel from non-affiliated sources);


(2) American Petroleum Institute (API) Manual of Petroleum Measurement Standards, Chapter 3-Tank Gauging, Section 1A, Standard Practice for the Manual Gauging of Petroleum and Petroleum Products, Second Edition, August 2005; Section 1B-Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second Edition June 2001; Section 2-Standard Practice for Gauging Petroleum and Petroleum Products in Tank Cars, First Edition, August 1995 (Reaffirmed March 2006); Section 3-Standard Practice for Level Measurement of Liquid Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank Gauging, First Edition June 1996 (Reaffirmed, March 2001); Section 4-Standard Practice for Level Measurement of Liquid Hydrocarbons on Marine Vessels by Automatic Tank Gauging, First Edition April 1995 (Reaffirmed, September 2000); and Section 5-Standard Practice for Level Measurement of Light Hydrocarbon Liquids Onboard Marine Vessels by Automatic Tank Gauging, First Edition March 1997 (Reaffirmed, March 2003); for § 75.19; Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, December 1961 (Reaffirmed August 1987, October 1992) (all incorporated by reference under § 75.6 of this part); or


(3) A fuel flow meter certified and maintained according to appendix D to this part.


(C) Except as provided in paragraph (c)(3)(ii)(C)(3) of this section, for each fuel combusted during a quarter, the gross calorific value of the fuel shall be determined by either:


(1) Using the applicable procedures for gas and oil analysis in sections 2.2 and 2.3 of appendix D to this part. If this option is chosen the highest gross calorific value recorded during the previous calendar year shall be used (or, for a new or newly-affected unit, if there are no sample results from the previous year, use the highest GCV from the samples taken in the current year); or


(2) Using the appropriate default gross calorific value listed in Table LM-5 of this section.


(3) For gaseous fuels other than pipeline natural gas or natural gas, the GCV sampling frequency shall be daily unless the results of a demonstration under section 2.3.5 of appendix D to this part show that the fuel has a low GCV variability and qualifies for monthly sampling. If daily GCV sampling is required, use the highest GCV obtained in the calendar quarter as GCVmax in Equation LM-3, of this section.


(D) If Eq. LM-2 is used for heat input determination, the specific gravity of each type of fuel oil combusted during the quarter shall be determined either by:


(1) Using the procedures in section 2.2.6 of appendix D to this part. If this option is chosen, use the highest specific gravity value recorded during the previous calendar year (or, for a new or newly-affected unit, if there are no sample results from the previous year, use the highest specific gravity from the samples taken in the current year); or


(2) Using the appropriate default specific gravity value in Table LM-6 of this section.


(E) The quarterly heat input from each type of fuel combusted during the quarter by a low mass emissions unit or group of low mass emissions units sharing a common fuel supply shall be determined using either Equation LM-2 or Equation LM-3 for oil (as applicable to the method used to quantify oil usage) and Equation LM-3 for gaseous fuels. For a unit subject to the provisions of subpart H of this part, which is not required to report emission data on a year-round basis and elects to report only during the ozone season, the quarterly heat input for the second calendar quarter of the year shall include only the heat input for the months of May and June.





Where:

HIfuel-qtr = Quarterly total heat input from oil (mmBtu).

Mqtr = Mass of oil consumed during the quarter, determined as the product of the volume of oil under paragraph (c)(3)(ii)(B) of this section and the specific gravity under paragraph (c)(3)(ii)(D) of this section (lb).

GCVmax = Gross calorific value of oil, as determined under paragraph (c)(3)(ii)(C) of this section (Btu/lb)

10
6 = Conversion of Btu to mmBtu.



Where:

HIfuel-qtr = Quarterly heat input from gaseous fuel or fuel oil (mmBtu).

Qqtr = Volume of gaseous fuel or fuel oil combusted during the quarter, as determined under paragraph (c)(3)(ii)(B) of this section standard cubic feet (scf) or (gal), as applicable.

GCVmax = Gross calorific value of the gaseous fuel or fuel oil combusted during the quarter, as determined under paragraph (c)(3)(ii)(C) of this section (Btu/scf) or (Btu/gal), as applicable.

10
6 = Conversion of Btu to mmBtu.

(F) Use Eq. LM-4 to calculate HIqtr-total, the quarterly heat input (mmBtu) for all fuels. HIqtr-total shall be the sum of the HIfuel-qtr values determined using Equations LM-2 and LM-3.




(G) The year-to-date cumulative heat input (mmBtu) for all fuels shall be the sum of all quarterly total heat input (HIqtr-total) values for all calendar quarters in the year to date. For a unit subject to the provisions of subpart H of this part, which is not required to report emission data on a year-round basis and elects to report only during the ozone season, the cumulative ozone season heat input shall be the sum of the quarterly heat input values for the second and third calendar quarters of the year.


(H) For each low mass emissions unit or each low mass emissions unit in a group of identical units, the owner or operator shall determine the cumulative quarterly unit load in megawatt hours or thousands of pounds of steam. The quarterly cumulative unit load shall be the sum of the hourly unit load values recorded under paragraph (c)(2) of this section and shall be determined using Equations LM-5 or LM-6. For a unit subject to the provisions of subpart H of this part, which is not required to report emission data on a year-round basis and elects to report only during the ozone season, the quarterly cumulative load for the second calendar quarter of the year shall include only the unit loads for the months of May and June.







Where:

MWqtr = Sum of all unit operating loads recorded during the quarter by the unit (MWh).

STfuel-qtr = Sum of all hourly steam loads recorded during the quarter by the unit (klb of steam/hr).

MW = Unit operating load for a particular unit operating hour (MWh).

ST = Unit steam load for a particular unit operating hour (klb of steam).

(I) For a low mass emissions unit that is not included in a group of low mass emission units sharing a common fuel supply, apportion the total heat input for the quarter, HIqtr-total to each hour of unit operation using either Equation LM-7 or LM-8:



(Eq LM-7 for MW output)


(Eq LM-8 for steam output)


Where:

HIhr = Hourly heat input to the unit (mmBtu).

MWhr = Hourly operating load for the unit (MW).

SThr = Hourly steam load for the unit (klb of steam/hr).

(J) For each low mass emissions unit that is included in a group of units sharing a common fuel supply, apportion the total heat input for the quarter, HIqtr-total to each hour of operation using either Equation LM-7a or LM-8a:



(Eq LM-7a for MW output)


(Eq LM-8a for steam output)


Where:

HIhr = Hourly heat input to the individual unit (mmBtu).

MWhr = Hourly operating load for the individual unit (MW).

SThr = Hourly steam load for the individual unit (klb of steam/hr).

ΣMWqtr = Sum of the quarterly operating

all-units loads (from Eq. LM-5) for all units in the group (MW).


ΣSTqtr = Sum of the quarterly steam

all-units loads (from Eq. LM-6) for all units in the group (klb of steam/hr)


(4) Calculation of SO2, NOX and CO2 mass emissions. The owner or operator shall, for the purpose of demonstrating that a low mass emissions unit meets the requirements of this section, calculate SO2, NOX and CO2 mass emissions in accordance with the following.


(i) SO2 mass emissions. (A) The hourly SO2 mass emissions (lbs) for a low mass emissions unit (Acid Rain Program units, only) shall be determined using Equation LM-9 and the appropriate fuel-based SO2 emission factor for the fuels combusted in that hour. If more than one fuel is combusted in the hour, use the highest emission factor for all of the fuels combusted in the hour. If records are missing as to which fuel was combusted in the hour, use the highest emission factor for all of the fuels capable of being combusted in the unit.


WSO2 = EFSO2 × HIhr (Eq. LM-9)


Where:

WSO2 = Hourly SO2 mass emissions (lbs.)

EFSO2 = Either the SO2 emission factor from Table LM-1 of this section or the fuel-and-unit-specific SO2 emission rate from paragraph (c)(1)(i) of this section (lb/mmBtu).

HIhr = Either the maximum rated hourly heat input under paragraph (c)(3)(i)(A) of this section or the hourly heat input under paragraph (c)(3)(ii) of this section (mmBtu).

(B) The quarterly SO2 mass emissions (tons) for the low mass emissions unit shall be the sum of all the hourly SO2 mass emissions in the quarter, as determined under paragraph (c)(4)(i)(A) of this section, divided by 2000 lb/ton.


(C) The year-to-date cumulative SO2 mass emissions (tons) for the low mass emissions unit shall be the sum of the quarterly SO2 mass emissions, as determined under paragraph (c)(4)(i)(B) of this section, for all of the calendar quarters in the year to date.


(ii)(A) The hourly NOX mass emissions for the low mass emissions unit (lbs) shall be determined using Equation LM-10. If more than one fuel is combusted in the hour, use the highest emission rate for all of the fuels combusted in the hour. If records are missing as to which fuel was combusted in the hour, use the highest emission factor for all of the fuels capable of being combusted in the unit. For low mass emission units with NOX emission controls of any kind and for which a fuel-and-unit-specific NOX emission rate is determined under paragraph (c)(1)(iv) of this section, for any hour in which the parameters under paragraph (c)(1)(iv)(A) of this section do not show that the NOX emission controls are operating properly, use the NOX emission rate from Table LM-2 of this section for the fuel combusted during the hour with the highest NOX emission rate.


WNOX = EFNOX × HIhr (Eq. LM-10)


Where:

WNOX = Hourly NOX mass emissions (lbs).

EFNOX = Either the NOX emission factor from Table LM-2 of this section or the fuel- and unit-specific NOX emission rate determined under paragraph (c)(1)(iv) of this section (lb/mmBtu).

HIhr = Either the maximum rated hourly heat input from paragraph (c)(3)(i)(A) of this section or the hourly heat input as determined under paragraph (c)(3)(ii) of this section (mmBtu).

(B) The quarterly NOX mass emissions (tons) for the low mass emissions unit shall be the sum of all of the hourly NOX mass emissions in the quarter, as determined under paragraph (c)(4)(ii)(A) of this section, divided by 2000 lb/ton.


(C) The year-to-date cumulative NOX mass emissions (tons) for the low mass emissions unit shall be the sum of the quarterly NOX mass emissions, as determined under paragraph (c)(4)(ii)(B) of this section, for all of the calendar quarters in the year to date. For a unit subject to the provisions of subpart H of this part, which is not required to report emission data on a year-round basis and elects to report only during the ozone season, the ozone season NOX mass emissions for the unit shall be the sum of the quarterly NOX mass emissions, as determined under paragraph (c)(4)(ii)(B) of this section, for the second and third calendar quarters of the year, and the second quarter report shall include emissions data only for May and June.


(D) The quarterly and cumulative NOX emission rate in lb/mmBtu (if required by the applicable program(s)) shall be determined as follows. Calculate the quarterly NOX emission rate by taking the arithmetic average of all of the hourly EFNOX values. Calculate the cumulative (year-to-date) NOX emission rate by taking the arithmetic average of the quarterly NOX emission rates.


(iii) CO2 Mass Emissions. (A) The hourly CO2 mass emissions (tons) for the affected low mass emissions unit (Acid Rain Program units, only) shall be determined using Equation LM-11 and the appropriate fuel-based CO2 emission factor from Table LM-3 of this section for the fuel being combusted in that hour. If more than one fuel is combusted in the hour, use the highest emission factor for all of the fuels combusted in the hour. If records are missing as to which fuel was combusted in the hour, use the highest emission factor for all of the fuels capable of being combusted in the unit.


WCO2 = EFCO2 × HIhr (Eq. LM-11)


Where:

WCO2 = Hourly CO2 mass emissions (tons).

EFCO2 = Either the fuel-based CO2 emission factor from Table LM-3 of this section or the fuel-and-unit-specific CO2 emission rate from paragraph (c)(1)(iii) of this section (tons/mmBtu).

HIhr = Either the maximum rated hourly heat input from paragraph (c)(3)(i)(A) of this section or the hourly heat input as determined under paragraph (c)(3)(ii) of this section (mmBtu).

(B) The quarterly CO2 mass emissions (tons) for the low mass emissions unit shall be the sum of all of the hourly CO2 mass emissions in the quarter, as determined under paragraph (c)(4)(iii)(A)of this section.


(C) The year-to-date cumulative CO2 mass emissions (tons) for the low mass emissions unit shall be the sum of all of the quarterly CO2 mass emissions, as determined under paragraph (c)(4)(iii)(B) of this section, for all of the calendar quarters in the year to date.


(d) Each unit that qualifies under this section to use the low mass emissions methodology must follow the recordkeeping and reporting requirements pertaining to low mass emissions units in subparts F and G of this part.


(e) The quality control and quality assurance requirements in § 75.21 are not applicable to a low mass emissions unit for which the low mass emissions excepted methodology under paragraph (c) of this section is being used in lieu of a continuous emission monitoring system or an excepted monitoring system under appendix D or E to this part, except for fuel flowmeters used to meet the provisions in paragraph (c)(3)(ii) of this section. However, the owner or operator of a low mass emissions unit shall implement the following quality assurance and quality control provisions:


(1) For low mass emission units or groups of units which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section and which use fuel billing records to determine fuel usage, the owner or operator shall keep, at the facility, for three years, the records of the fuel billing statements used for long term fuel flow determinations.


(2) For low mass emissions units or groups of units which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section and which use one of the methods specified in paragraph (c)(3)(ii)(B)(2) of this section to determine fuel usage, the owner or operator shall keep, at the facility, a copy of the standard used and shall keep records, for three years, of all measurements obtained for each quarter using the methodology.


(3) For low mass emission units or groups of units which use the long term fuel flow methodology under paragraph (c)(3)(ii) of this section and which use a certified fuel flow meter to determine fuel usage, the owner or operator shall comply with the quality control quality assurance requirements for a fuel flow meter under section 2.1.6 of appendix D of this part.


(4) For each low mass emissions unit for which fuel-and-unit-specific NOX emission rates are determined in accordance with paragraph (c)(1)(iv) of this section, the owner or operator shall keep, at the facility, records which document the results of all NOX emission rate tests conducted according to appendix E to this part. If CEMS data are used to determine the fuel-and-unit-specific NOX emission rates under paragraph (c)(1)(iv)(G) of this section, the owner or operator shall keep, at the facility, records of the CEMS data and the data analysis performed to determine a fuel-and-unit-specific NOX emission rate. The appendix E test records and historical CEMS data records shall be kept until the fuel and unit specific NOX emission rates are re-determined.


(5) For each low mass emissions unit for which fuel-and-unit-specific NOX emission rates are determined in accordance with paragraph (c)(1)(iv) of this section and which has add-on NOX emission controls of any kind or uses dry low-NOX technology, the owner or operator shall develop and keep on-site a quality assurance plan which explains the procedures used to document proper operation of the NOX emission controls. The plan shall include the parameters monitored (e.g., water-to-fuel ratio) and the acceptable ranges for each parameter used to determine proper operation of the unit’s NOX controls.


(6) For unmanned facilities, the records required by paragraphs (e)(1), (e)(2) and (e)(4) of this section may be kept at a central location, rather than at the facility.


Table LM-1 – SO2 Emission Factors (lb/mmBtu) for Various Fuel Types

Fuel type
SO2 emission factors
Pipeline Natural Gas0.0006 lb/mmBtu.
Other Natural Gas0.06 lb/mmBtu.
Residual Oil2.1 lb/mmBtu.
Diesel Fuel0.5 lb/mmBtu.

Table LM-2 – NOX Emission Rates (lb/mmBtu) for Various Boiler/Fuel Types

Unit type
Fuel type
NOX emission rate
TurbineGas0.7
TurbineOil1.2
BoilerGas1.5
BoilerOil2

Table LM-3 – CO2 Emission Factors (ton/mmBtu) for Gas and Oil

Fuel type
CO2 emission factors
Pipeline (or other) Natural Gas0.059 ton/mmBtu.
Oil0.081 ton/mmBtu.

Table LM-4 – Identical Unit Testing Requirements

Number of identical units in the group
Number of appendix E tests required
21
3 to 62
73
>7n tests; where n = number of units divided by 3 and rounded to nearest integer.

Table LM-5 – Default Gross Calorific Values (GCVs) for Various Fuels

Fuel
GCV for use in equation LM-2 or LM-3
Pipeline Natural Gas1050 Btu/scf.
Other Natural Gas1100 Btu/scf.
Residual Oil19,700 Btu/lb or 167,500 Btu/gallon.
Diesel Fuel20,500 Btu/lb or 151,700 Btu/gallon.

Table LM-6 – Default Specific Gravity Values for Fuel Oil

Fuel
Specific gravity (lb/gal)
Residual Oil8.5
Diesel Fuel7.4

[63 FR 57500, Oct. 27, 1998, as amended at 64 FR 28592, May 26, 1999; 64 FR 37582, July 12, 1999; 67 FR 40424, 40425, June 12, 2002; 67 FR 53504, Aug. 16, 2002; 73 FR 4344, Jan. 24, 2008]


Subpart C – Operation and Maintenance Requirements

§ 75.20 Initial certification and recertification procedures.

(a) Initial certification approval process. The owner or operator shall ensure that each continuous emission or opacity monitoring system required by this part meets the initial certification requirements of this section and shall ensure that all applicable initial certification tests under paragraph (c) of this section are completed by the deadlines specified in § 75.4 and prior to use in the Acid Rain Program. In addition, whenever the owner or operator installs a continuous emission or opacity monitoring system in order to meet the requirements of §§ 75.11 through 75.18, where no continuous emission or opacity monitoring system was previously installed, initial certification is required.


(1) Notification of initial certification test dates. The owner or operator or designated representative shall submit a written notice of the dates of initial certification testing at the unit as specified in § 75.61(a)(1).


(2) Certification application. The owner or operator shall apply for certification of each continuous emission or opacity monitoring system used under the Acid Rain Program. The owner or operator shall submit the certification application in accordance with § 75.60 and each complete certification application shall include the information specified in § 75.63.


(3) Provisional approval of certification (or recertification) applications. Upon the successful completion of the required certification (or recertification) procedures of this section, each continuous emission or opacity monitoring system shall be deemed provisionally certified (or recertified) for use under the Acid Rain Program for a period not to exceed 120 days following receipt by the Administrator of the complete certification (or recertification) application under paragraph (a)(4) of this section. Notwithstanding this paragraph, no continuous emission or opacity monitor systems for a combustion source seeking to enter the Opt-in Program in accordance with part 74 of this chapter shall be deemed provisionally certified (or recertified) for use under the Acid Rain Program. Data measured and recorded by a provisionally certified (or recertified) continuous emission or opacity monitoring system , operated in accordance with the requirements of appendix B to this part, will be considered valid quality-assured data (retroactive to the date and time of provisional certification or recertification), provided that the Administrator does not invalidate the provisional certification (or recertification) by issuing a notice of disapproval within 120 days of receipt by the Administrator of the complete certification (or recertification) application. Note that when the conditional data validation procedures of paragraph (b)(3) of this section are used for the initial certification (or recertification) of a continuous emissions monitoring system, the date and time of provisional certification (or recertification) of the CEMS may be earlier than the date and time of completion of the required certification (or recertification) tests.


(4) Certification (or recertification) application formal approval process. The Administrator will issue a notice of approval or disapproval of the certification (or recertification) application to the owner or operator within 120 days of receipt of the complete certification (or recertification) application. In the event the Administrator does not issue such a notice within 120 days of receipt, each continuous emission or opacity monitoring system which meets the performance requirements of this part and is included in the certification (or recertification) application will be deemed certified (or recertified) for use under the Acid Rain Program.


(i) Approval notice. If the certification (or recertification) application is complete and shows that each continuous emission or opacity monitoring system meets the performance requirements of this part, then the Administrator will issue a notice of approval of the certification (or recertification) application within 120 days of receipt.


(ii) Incomplete application notice. A certification (or recertification) application will be considered complete when all of the applicable information required to be submitted in § 75.63 has been received by the Administrator, the EPA Regional Office, and the appropriate State and/or local air pollution control agency. If the certification (or recertification) application is not complete, then the Administrator will issue a notice of incompleteness that provides a reasonable timeframe for the designated representative to submit the additional information required to complete the certification (or recertification) application. If the designated representative has not complied with the notice of incompleteness by a specified due date, then the Administrator may issue a notice of disapproval specified under paragraph (a)(4)(iii) of this section. The 120-day review period shall not begin prior to receipt of a complete application.


(iii) Disapproval notice. If the certification (or recertification) application shows that any continuous emission or opacity monitoring system does not meet the performance requirements of this part, or if the certification (or recertification) application is incomplete and the requirement for disapproval under paragraph (a)(4)(ii) of this section has been met, the Administrator shall issue a written notice of disapproval of the certification (or recertification) application within 120 days of receipt. By issuing the notice of disapproval, the provisional certification (or recertification) is invalidated by the Administrator, and the data measured and recorded by each uncertified continuous emission or opacity monitoring system shall not be considered valid quality-assured data as follows: from the hour of the probationary calibration error test that began the initial certification (or recertification) test period (if the conditional data validation procedures of paragraph (b)(3) of this section were used to retrospectively validate data); or from the date and time of completion of the invalid certification or recertification tests (if the conditional data validation procedures of paragraph (b)(3) of this section were not used). The owner or operator shall follow the procedures for loss of initial certification in paragraph (a)(5) of this section for each continuous emission or opacity monitoring system which is disapproved for initial certification. For each disapproved recertification, the owner or operator shall follow the procedures of paragraph (b)(5) of this section.


(iv) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a continuous emission or opacity monitoring system, in accordance with § 75.21.


(5) Procedures for loss of certification. When the Administrator issues a notice of disapproval of a certification application or a notice of disapproval of certification status (as specified in paragraph (a)(4) of this section), then:


(i) Until such time, date, and hour as the continuous emission monitoring system can be adjusted, repaired, or replaced and certification tests successfully completed (or, if the conditional data validation procedures in paragraphs (b)(3)(ii) through (b)(3)(ix) of this section are used, until a probationary calibration error test is passed following corrective actions in accordance with paragraph (b)(3)(ii) of this section), the owner or operator shall substitute the following values, as applicable, for each hour of unit operation during the period of invalid data specified in paragraph (a)(4)(iii) of this section or in § 75.21: the maximum potential concentration of SO2, as defined in section 2.1.1.1 of appendix A to this part, to report SO2 concentration; the maximum potential NOX emission rate, as defined in § 72.2 of this chapter, to report NOX emissions in lb/mmBtu; the maximum potential concentration of NOX, as defined in section 2.1.2.1 of appendix A to this part, to report NOX emissions in ppm (when a NOX concentration monitoring system is used to determine NOX mass emissions, as defined under § 75.71(a)(2)); the maximum potential flow rate, as defined in section 2.1.4.1 of appendix A to this part, to report volumetric flow; the maximum potential concentration of CO2, as defined in section 2.1.3.1 of appendix A to this part, to report CO2 concentration data; and either the minimum potential moisture percentage, as defined in section 2.1.5 of appendix A to this part or, if 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 maximum potential moisture percentage, as defined in section 2.1.6 of appendix A to this part; and


(ii) The designated representative shall submit a notification of certification retest dates as specified in § 75.61(a)(1)(ii) and a new certification application according to the procedures in paragraph (a)(2) of this section; and


(iii) The owner or operator shall repeat all certification tests or other requirements that were failed by the continuous emission or opacity monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.


(b) Recertification approval process. Whenever the owner or operator makes a replacement, modification, or change in a certified continuous emission monitoring system or continuous opacity monitoring system that may significantly affect the ability of the system to accurately measure or record the SO2 or CO2 concentration, stack gas volumetric flow rate, NOX emission rate, NOX concentration, percent moisture, or opacity, or to meet the requirements of § 75.21 or appendix B to this part, the owner or operator shall recertify the continuous emission monitoring system or continuous opacity monitoring system, according to the procedures in this paragraph. Furthermore, whenever the owner or operator makes a replacement, modification, or change to the flue gas handling system or the unit operation that may significantly change the flow or concentration profile, the owner or operator shall recertify the monitoring system according to the procedures in this paragraph. Examples of changes which require recertification include: replacement of the analyzer; change in location or orientation of the sampling probe or site; and complete replacement of an existing continuous emission monitoring system or continuous opacity monitoring system. The owner or operator shall also recertify the continuous emission monitoring systems for a unit that has recommenced commercial operation following a period of long-term cold storage as defined in § 72.2 of this chapter. The owner or operator shall recertify a continuous opacity monitoring system whenever the monitor path length changes or as required by an applicable State or local regulation or permit. Any change to a flow monitor or gas monitoring system for which a RATA is not necessary shall not be considered a recertification event. In addition, changing the polynomial coefficients or K factor(s) of a flow monitor shall require a 3-load RATA, but is not considered to be a recertification event; however, records of the polynomial coefficients or K factor (s) currently in use shall be maintained on-site in a format suitable for inspection. Changing the coefficient or K factor(s) of a moisture monitoring system shall require a RATA, but is not considered to be a recertification event; however, records of the coefficient or K factor (s) currently in use by the moisture monitoring system shall be maintained on-site in a format suitable for inspection. In such cases, any other tests that are necessary to ensure continued proper operation of the monitoring system (e.g., 3-load flow RATAs following changes to flow monitor polynomial coefficients, linearity checks, calibration error tests, DAHS verifications, etc.) shall be performed as diagnostic tests, rather than as recertification tests. The data validation procedures in paragraph (b)(3) of this section shall be applied to RATAs associated with changes to flow or moisture monitor coefficients, and to linearity checks, 7-day calibration error tests, and cycle time tests, when these are required as diagnostic tests. When the data validation procedures of paragraph (b)(3) of this section are applied in this manner, replace the word “recertification” with the word “diagnostic.”


(1) Tests required. For all recertification testing, the owner or operator shall complete all initial certification tests in paragraph (c) of this section that are applicable to the monitoring system, except as otherwise approved by the Administrator. For diagnostic testing after changing the flow rate monitor polynomial coefficients, the owner or operator shall complete a 3-level RATA. For diagnostic testing after changing the K factor or mathematical algorithm of a moisture monitoring system, the owner or operator shall complete a RATA.


(2) Notification of recertification test dates. The owner, operator, or designated representative shall submit notice of testing dates for recertification under this paragraph as specified in § 75.61(a)(1)(ii), unless all of the tests in paragraph (c) of this section are required for recertification, in which case the owner or operator shall provide notice in accordance with the notice provisions for initial certification testing in § 75.61(a)(1)(i).


(3) Recertification test period requirements and data validation. The data validation provisions in paragraphs (b)(3)(i) through (b)(3)(ix) of this section shall apply to all CEMS recertifications and diagnostic testing. The provisions in paragraphs (b)(3)(ii) through (b)(3)(ix) of this section may also be applied to initial certifications (see sections 6.2(a), 6.3.1(a), 6.3.2(a), 6.4(a) and 6.5(f) of appendix A to this part) and may be used to supplement the linearity check and RATA data validation procedures in sections 2.2.3(b) and 2.3.2(b) of appendix B to this part.


(i) The owner or operator shall use substitute data, according to the standard missing data procedures in §§ 75.33 through 75.37 (or shall report emission data using a reference method or another monitoring system that has been certified or approved for use under this part), in the period extending from the hour of the replacement, modification or change made to a monitoring system that triggers the need to perform recertification testing, until either: the hour of successful completion of all of the required recertification tests; or the hour in which a probationary calibration error test (according to paragraph (b)(3)(ii) of this section) is performed and passed, following all necessary repairs, adjustments or reprogramming of the monitoring system. The first hour of quality-assured data for the recertified monitoring system shall either be the hour after all recertification tests have been completed or, if conditional data validation is used, the first quality-assured hour shall be determined in accordance with paragraphs (b)(3)(ii) through (b)(3)(ix) of this section. Notwithstanding these requirements, if the replacement, modification, or change requiring recertification of the CEMS is such that the historical data stream is no longer representative (e.g., where the SO2 concentration and stack flow rate change significantly after installation of a wet scrubber), the owner or operator shall substitute for missing data as follows, in lieu of using the standard missing data procedures in §§ 75.33 through 75.37: for a change that results in a significantly higher concentration or flow rate, substitute maximum potential values according to the procedures in paragraph (a)(5) of this section; or for a change that results in a significantly lower concentration or flow rate, substitute data using the standard missing data procedures. The owner or operator shall then use the initial missing data procedures in § 75.31, beginning with the first hour of quality-assured data obtained with the recertified monitoring system, unless otherwise provided by § 75.34 for units with add-on emission controls.


(ii) Once the modification or change to the CEMS has been completed and all of the associated repairs, component replacements, adjustments, linearization, and reprogramming of the CEMS have been completed, a probationary calibration error test is required to establish the beginning point of the recertification test period. In this instance, the first successful calibration error test of the monitoring system following completion of all necessary repairs, component replacements, adjustments, linearization and reprogramming shall be the probationary calibration error test. The probationary calibration error test must be passed before any of the required recertification tests are commenced.


(iii) Beginning with the hour of commencement of a recertification test period, emission data recorded by the CEMS are considered to be conditionally valid, contingent upon the results of the subsequent recertification tests.


(iv) Each required recertification test shall be completed no later than the following number of unit operating hours (or unit operating days) after the probationary calibration error test that initiates the test period:


(A) For a linearity check and/or cycle time test, 168 consecutive unit operating hours, as defined in § 72.2 of this chapter or, for CEMS installed on common stacks or bypass stacks, 168 consecutive stack operating hours, as defined in § 72.2 of this chapter;


(B) For a RATA (whether normal-load or multiple-load), 720 consecutive unit operating hours, as defined in § 72.2 of this chapter or, for CEMS installed on common stacks or bypass stacks, 720 consecutive stack operating hours, as defined in § 72.2 of this chapter; and


(C) For a 7-day calibration error test, 21 consecutive unit operating days, as defined in § 72.2 of this chapter.


(v) All recertification tests shall be performed hands-off. No adjustments to the calibration of the CEMS, other than the routine calibration adjustments following daily calibration error tests as described in section 2.1.3 of appendix B to this part, are permitted during the recertification test period. Routine daily calibration error tests shall be performed throughout the recertification test period, in accordance with section 2.1.1 of appendix B to this part. The additional calibration error test requirements in section 2.1.3 of appendix B to this part shall also apply during the recertification test period.


(vi) If all of the required recertification tests and required daily calibration error tests are successfully completed in succession with no failures, and if each recertification test is completed within the time period specified in paragraph (b)(3)(iv)(A), (B), or (C) of this section, then all of the conditionally valid emission data recorded by the CEMS shall be considered quality-assured, from the hour of commencement of the recertification test period until the hour of completion of the required test(s).


(vii) If a required recertification test is failed or aborted due to a problem with the CEMS, or if a daily calibration error test is failed during a recertification test period, data validation shall be done as follows:


(A) If any required recertification test is failed, it shall be repeated. If any recertification test other than a 7-day calibration error test is failed or aborted due to a problem with the CEMS, the original recertification test period is ended, and a new recertification test period must be commenced with a probationary calibration error test. The tests that are required in the new recertification test period will include any tests that were required for the initial recertification event which were not successfully completed and any recertification or diagnostic tests that are required as a result of changes made to the monitoring system to correct the problems that caused the failure of the recertification test. For a 2- or 3-load flow RATA, if the relative accuracy test is passed at one or more load levels, but is failed at a subsequent load level, provided that the problem that caused the RATA failure is corrected without re-linearizing the instrument, the length of the new recertification test period shall be equal to the number of unit operating hours remaining in the original recertification test period, as of the hour of failure of the RATA. However, if re-linearization of the flow monitor is required after a flow RATA is failed at a particular load level, then a subsequent 3-load RATA is required, and the new recertification test period shall be 720 consecutive unit (or stack) operating hours. The new recertification test sequence shall not be commenced until all necessary maintenance activities, adjustments, linearizations, and reprogramming of the CEMS have been completed;


(B) If a linearity check, RATA, or cycle time test is failed or aborted due to a problem with the CEMS, all conditionally valid emission data recorded by the CEMS are invalidated, from the hour of commencement of the recertification test period to the hour in which the test is failed or aborted, except for the case in which a multiple-load flow RATA is passed at one or more load levels, failed at a subsequent load level, and the problem that caused the RATA failure is corrected without re-linearizing the instrument. In that case, data invalidation shall be prospective, from the hour of failure of the RATA until the commencement of the new recertification test period. Data from the CEMS remain invalid until the hour in which a new recertification test period is commenced, following corrective action, and a probationary calibration error test is passed, at which time the conditionally valid status of emission data from the CEMS begins again;


(C) If a 7-day calibration error test is failed within the recertification test period, previously-recorded conditionally valid emission data from the CEMS are not invalidated. The conditionally valid data status is unaffected, unless the calibration error on the day of the failed 7-day calibration error test exceeds twice the performance specification in section 3 of appendix A to this part, as described in paragraph (b)(3)(vii)(D) of this section; and


(D) If a daily calibration error test is failed during a recertification test period (i.e., the results of the test exceed twice the performance specification in section 3 of appendix A to this part), the CEMS is out-of-control as of the hour in which the calibration error test is failed. Emission data from the CEMS shall be invalidated prospectively from the hour of the failed calibration error test until the hour of completion of a subsequent successful calibration error test following corrective action, at which time the conditionally valid status of data from the monitoring system resumes. Failure to perform a required daily calibration error test during a recertification test period shall also cause data from the CEMS to be invalidated prospectively, from the hour in which the calibration error test was due until the hour of completion of a subsequent successful calibration error test. Whenever a calibration error test is failed or missed during a recertification test period, no further recertification tests shall be performed until the required subsequent calibration error test has been passed, re-establishing the conditionally valid status of data from the monitoring system. If a calibration error test failure occurs while a linearity check or RATA is still in progress, the linearity check or RATA must be re-started.


(E) Trial gas injections and trial RATA runs are permissible during the recertification test period, prior to commencing a linearity check or RATA, for the purpose of optimizing the performance of the CEMS. The results of such gas injections and trial runs shall not affect the status of previously-recorded conditionally valid data or result in termination of the recertification test period, provided that the following specifications and conditions are met:


(1) For gas injections, the stable, ending monitor response is within ±5 percent or within 5 ppm of the tag value of the reference gas;


(2) For RATA trial runs, the average reference method reading and the average CEMS reading for the run differ by no more than ±10% of the average reference method value or ±15 ppm, or ±1.5% H2O, or ±0.02 lb/mmBtu from the average reference method value, as applicable;


(3) No adjustments to the calibration of the CEMS are made following the trial injection(s) or run(s), other than the adjustments permitted under section 2.1.3 of appendix B to this part; and


(4) The CEMS is not repaired, re-linearized or reprogrammed (e.g., changing flow monitor polynomial coefficients, linearity constants, or K-factors) after the trial injection(s) or run(s).


(F) If the results of any trial gas injection(s) or RATA run(s) are outside the limits in paragraphs (b)(3)(vii)(E)(1) or (2) of this section or if the CEMS is repaired, re-linearized or reprogrammed after the trial injection(s) or run(s), the trial injection(s) or run(s) shall be counted as a failed linearity check or RATA attempt. If this occurs, follow the procedures pertaining to failed and aborted recertification tests in paragraphs (b)(3)(vii)(A) and (b)(3)(vii)(B) of this section.


(viii) If any required recertification test is not completed within its allotted time period, data validation shall be done as follows. For a late linearity test, RATA, or cycle time test that is passed on the first attempt, data from the monitoring system shall be invalidated from the hour of expiration of the recertification test period until the hour of completion of the late test. For a late 7-day calibration error test, whether or not it is passed on the first attempt, data from the monitoring system shall also be invalidated from the hour of expiration of the recertification test period until the hour of completion of the late test. For a late linearity test, RATA, or cycle time test that is failed on the first attempt or aborted on the first attempt due to a problem with the monitor, all conditionally valid data from the monitoring system shall be considered invalid back to the hour of the first probationary calibration error test which initiated the recertification test period. Data from the monitoring system shall remain invalid until the hour of successful completion of the late recertification test and any additional recertification or diagnostic tests that are required as a result of changes made to the monitoring system to correct problems that caused failure of the late recertification test.


(ix) If any required recertification test of a monitoring system has not been completed by the end of a calendar quarter and if data contained in the quarterly report are conditionally valid pending the results of test(s) to be completed in a subsequent quarter, the owner or operator shall indicate this by means of a suitable conditionally valid data flag in the electronic quarterly report for that quarter. The owner or operator shall resubmit the report for that quarter if the required recertification test is subsequently failed. In the resubmitted report, the owner or operator shall use the appropriate missing data routine in § 75.31 or § 75.33 to replace with substitute data each hour of conditionally valid data that was invalidated by the failed recertification test. Alternatively, if any required recertification test is not completed by the end of a particular calendar quarter but is completed no later than 30 days after the end of that quarter (i.e., prior to the deadline for submitting the quarterly report under § 75.64), the test data and results may be submitted with the earlier quarterly report even though the test date(s) are from the next calendar quarter. In such instances, if the recertification test(s) are passed in accordance with the provisions of paragraph (b)(3) of this section, conditionally valid data may be reported as quality-assured, in lieu of reporting a conditional data flag. If the recertification test(s) is failed and if conditionally valid data are replaced, as appropriate, with substitute data, then neither the reporting of a conditional data flag nor resubmission is required. In addition, if the owner or operator uses a conditionally valid data flag in any of the four quarterly reports for a given year, the owner or operator shall indicate the final status of the conditionally valid data (i.e., resolved or unresolved) in the annual compliance certification report required under § 72.90 of this chapter for that year. The Administrator may invalidate any conditionally valid data that remains unresolved at the end of a particular calendar year and may require the owner or operator to resubmit one or more of the quarterly reports for that calendar year, replacing the unresolved conditionally valid data with substitute data values determined in accordance with § 75.31 or § 75.33, as appropriate.


(4) Recertification application. The designated representative shall apply for recertification of each continuous emission or opacity monitoring system used under the Acid Rain Program. The owner or operator shall submit the recertification application in accordance with § 75.60, and each complete recertification application shall include the information specified in § 75.63.


(5) Approval or disapproval of request for recertification. The procedures for provisional certification in paragraph (a)(3) of this section shall apply to recertification applications. The Administrator will issue a notice of approval, disapproval, or incompleteness according to the procedures in paragraph (a)(4) of this section. In the event that a recertification application is disapproved, data from the monitoring system are invalidated and the applicable missing data procedures in §§ 75.31 or 75.33 shall be used from the date and hour of receipt of the disapproval notice back to the hour of the adjustment or change to the CEMS that triggered the need for recertification testing or, if the conditional data validation procedures in paragraphs (b)(3)(ii) through (b)(3)(ix) of this section were used, back to the hour of the probationary calibration error test that began the recertification test period. Data from the monitoring system remain invalid until all required recertification tests have been passed or until a subsequent probationary calibration error test is passed, beginning a new recertification test period. The owner or operator shall repeat all recertification tests or other requirements, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval. The designated representative shall submit a notification of the recertification retest dates, as specified in § 75.61(a)(1)(ii), and shall submit a new recertification application according to the procedures in paragraph (b)(4) of this section.


(c) Initial certification and recertification procedures. Prior to the deadline in § 75.4, the owner or operator shall conduct initial certification tests and in accordance with § 75.63, the designated representative shall submit an application to demonstrate that the continuous emission or opacity monitoring system and components thereof meet the specifications in appendix A to this part. The owner or operator shall compare reference method values with output from the automated data acquisition and handling system that is part of the continuous emission monitoring system being tested. Except as otherwise specified in paragraphs (b)(1), (d), and (e) of this section, and in sections 6.3.1 and 6.3.2 of appendix A to this part, the owner or operator shall perform the following tests for initial certification or recertification of continuous emission or opacity monitoring systems or components according to the requirements of appendix A to this part:


(1) For each SO2 pollutant concentration monitor, each NOX concentration monitoring system used to determine NOX mass emissions, as defined under § 75.71(a)(2), and each NOX-diluent continuous emission monitoring system:


(i) A 7-day calibration error test, where, for the NOX -diluent continuous emission monitoring system, the test is performed separately on the NOX pollutant concentration monitor and the diluent gas monitor;


(ii) A linearity check, where, for the NOX-diluent continuous emission monitoring system, the test is performed separately on the NOX pollutant concentration monitor and the diluent gas monitor;


(iii) A relative accuracy test audit. For the NOX-diluent continuous emission monitoring system, the RATA shall be done on a system basis, in units of lb/mmBtu. For the NOX concentration monitoring system, the RATA shall be done on a ppm basis;


(iv) A bias test;


(v) A cycle time test, (where, for the NOX-diluent continuous emission monitoring system, the test is performed separately on the NOX pollutant concentration monitor and the diluent gas monitor); and


(2) For each flow monitor:


(i) A 7-day calibration error test;


(ii) Relative accuracy test audits, as follows:


(A) A single-load (or single-level) RATA at the normal load (or level), as defined in section 6.5.2.1(d) of appendix A to this part, for a flow monitor installed on a peaking unit or bypass stack, or for a flow monitor exempted from multiple-level RATA testing under section 6.5.2(e) of appendix A to this part;


(B) For all other flow monitors, a RATA at each of the three load levels (or operating levels) corresponding to the three flue gas velocities described in section 6.5.2(a) of appendix A to this part;


(iii) A bias test for the single-load (or single-level) flow RATA described in paragraph (c)(2)(ii)(A) of this section; and


(iv) A bias test (or bias tests) for the 3-level flow RATA described in paragraph (c)(2)(ii)(B) of this section, at the following load or operational level(s):


(A) At each load level designated as normal under section 6.5.2.1(d) of appendix A to this part, for units that produce electrical or thermal output, or


(B) At the operational level identified as normal in section 6.5.2.1(d) of appendix A to this part, for units that do not produce electrical or thermal output.


(3) The initial certification test data from an O2 or a CO2 diluent gas monitor certified for use in a NOX continuous emission monitoring system may be submitted to meet the requirements of paragraph (c)(4) of this section. Also, for a diluent monitor that is used both as a CO2 monitoring system and to determine heat input, only one set of diluent monitor certification data need be submitted (under the component and system identification numbers of the CO2 monitoring system).


(4) For each CO2 pollutant concentration monitor, each CO2 monitoring system that uses an O2 monitor to determine CO2 concentration, and each diluent gas monitor used only to monitor heat input rate:


(i) A 7-day calibration error test;


(ii) A linearity check;


(iii) A relative accuracy test audit, where, for an O2 monitor used to determine CO2 concentration, the CO2 reference method shall be used for the RATA; and


(iv) A cycle-time test.


(5) For each continuous moisture monitoring system consisting of wet- and dry-basis O2 analyzers:


(i) A 7-day calibration error test of each O2 analyzer;


(ii) A cycle time test of each O2 analyzer;


(iii) A linearity test of each O2 analyzer; and


(iv) A RATA, directly comparing the percent moisture measured by the monitoring system to a reference method.


(6) For each continuous moisture sensor: A RATA, directly comparing the percent moisture measured by the monitor sensor to a reference method.


(7) For a continuous moisture monitoring system consisting of a temperature sensor and a data acquisition and handling system (DAHS) software component programmed with a moisture lookup table:


(i) A demonstration that the correct moisture value for each hour is being taken from the moisture lookup tables and applied to the emission calculations. At a minimum, the demonstration shall be made at three different temperatures covering the normal range of stack temperatures from low to high.


(ii) [Reserved]


(8) The owner or operator shall ensure that initial certification or recertification of a continuous opacity monitor for use under the Acid Rain Program is conducted according to one of the following procedures:


(i) Performance of the tests for initial certification or recertification, according to the requirements of Performance Specification 1 in appendix B to part 60 of this chapter; or


(ii) A continuous opacity monitoring system tested and certified previously under State or other Federal requirements to meet the requirements of Performance Specification 1 shall be deemed certified for the purposes of this part.


(9) [Reserved]


(10) For the automated data acquisition and handling system, tests designed to verify:


(i) Proper computation of hourly averages for pollutant concentrations, flow rate, pollutant emission rates, and pollutant mass emissions; and


(ii) Proper computation and application of the missing data substitution procedures in subpart D of this part and the bias adjustment factors in section 7 of appendix A to this part.


(11) The owner or operator shall provide adequate facilities for initial certification or recertification testing that include:


(i) Sampling ports adequate for test methods applicable to such facility, such that:


(A) Volumetric flow rate, pollutant concentration, and pollutant emission rates can be accurately determined by applicable test methods and procedures; and


(B) A stack or duct free of cyclonic flow during performance tests is available, as demonstrated by applicable test methods and procedures.


(ii) Basic facilities (e.g., electricity) for sampling and testing equipment.


(d) Initial certification and recertification and quality assurance procedures for optional backup continuous emission monitoring systems – (1) Redundant backups. The owner or operator of an optional redundant backup CEMS shall comply with all the requirements for initial certification and recertification according to the procedures specified in paragraphs (a), (b), and (c) of this section. The owner or operator shall operate the redundant backup CEMS during all periods of unit operation, except for periods of calibration, quality assurance, maintenance, or repair. The owner or operator shall perform upon the redundant backup CEMS all quality assurance and quality control procedures specified in appendix B to this part, except that the daily assessments in section 2.1 of appendix B to this part are optional for days on which the redundant backup CEMS is not used to report emission data under this part. For any day on which a redundant backup CEMS is used to report emission data, the system must meet all of the applicable daily assessment criteria in appendix B to this part.


(2) Non-redundant backups. The owner or operator of an optional non-redundant backup CEMS or like-kind replacement analyzer shall comply with all of the following requirements for initial certification, quality assurance, recertification, and data reporting:


(i) Except as provided in paragraph (d)(2)(v) of this section, for a regular non-redundant backup CEMS (i.e., a non-redundant backup CEMS that has its own separate probe, sample interface, and analyzer), or a non-redundant backup flow monitor, all of the tests in paragraph (c) of this section are required for initial certification of the system, except for the 7-day calibration error test.


(ii) For a like-kind replacement non-redundant backup analyzer (i.e., a non-redundant backup analyzer that uses the same probe and sample interface as a primary monitoring system), no initial certification of the analyzer is required. A non-redundant backup analyzer, connected to the same probe and interface as a primary CEMS in order to satisfy the dual span requirements of section 2.1.1.4 or 2.1.2.4 of appendix A to this part, shall be treated in the same manner as a like-kind replacement analyzer.


(iii) Each non-redundant backup CEMS or like-kind replacement analyzer shall comply with the daily and quarterly quality assurance and quality control requirements in appendix B to this part for each day and quarter that the non-redundant backup CEMS or like-kind replacement analyzer is used to report data, and shall meet the additional linearity and calibration error test requirements specified in this paragraph. The owner or operator shall ensure that each non-redundant backup CEMS or like-kind replacement analyzer passes a linearity check (for pollutant concentration and diluent gas monitors) or a calibration error test (for flow monitors) prior to each use for recording and reporting emissions. For a primary NOX-diluent CEMS consisting of the primary pollutant analyzer and a like-kind replacement diluent analyzer (or vice-versa), provided that the primary pollutant or diluent analyzer (as applicable) is operating and is not out-of-control with respect to any of its quality assurance requirements, only the like-kind replacement analyzer must pass a linearity check before the system is used for data reporting. When a non-redundant backup CEMS or like-kind replacement analyzer is brought into service, prior to conducting the linearity test, a probationary calibration error test (as described in paragraph (b)(3)(ii) of this section), which will begin a period of conditionally valid data, may be performed in order to allow the validation of data retrospectively, as follows. Conditionally valid data from the CEMS or like-kind replacement analyzer are validated back to the hour of completion of the probationary calibration error test if the following conditions are met: if no adjustments are made to the CEMS or like-kind replacement analyzer other than the allowable calibration adjustments specified in section 2.1.3 of appendix B to this part between the probationary calibration error test and the successful completion of the linearity test; and if the linearity test is passed within 168 unit (or stack) operating hours of the probationary calibration error test. However, if the linearity test is performed within 168 unit or stack operating hours but is either failed or aborted due to a problem with the CEMS or like-kind replacement analyzer, then all of the conditionally valid data are invalidated back to the hour of the probationary calibration error test, and data from the non-redundant backup CEMS or from the primary monitoring system of which the like-kind replacement analyzer is a part remain invalid until the hour of completion of a successful linearity test. Notwithstanding this requirement, the conditionally valid data status may be re-established after a failed or aborted linearity check, if corrective action is taken and a calibration error test is subsequently passed. However, in no case shall the use of conditional data validation extend for more than 168 unit or stack operating hours beyond the date and time of the original probationary calibration error test when the analyzer was brought into service.


(iv) When data are reported from a non-redundant backup CEMS or like-kind replacement analyzer, the appropriate bias adjustment factor shall be determined as follows:


(A) For a regular non-redundant backup CEMS, as described in paragraph (d)(2)(i) of this section, apply the bias adjustment factor from the most recent RATA of the non-redundant backup system (even if that RATA was done more than 12 months previously); or


(B) When a like-kind replacement non-redundant backup analyzer is used as a component of a primary CEMS (as described in paragraph (d)(2)(ii) of this section), apply the primary monitoring system bias adjustment factor.


(v) For each parameter monitored (i.e., SO2, CO2, O2, NOX, Hg or flow rate) at each unit or stack, a regular non-redundant backup CEMS may not be used to report data at that affected unit or common stack for more than 720 hours in any one calendar year (or 720 hours in any ozone season, for sources that report emission data only during the ozone season, in accordance with § 75.74(c)), unless the CEMS passes a RATA at that unit or stack. For each parameter monitored at each unit or stack, the use of a like-kind replacement non-redundant backup analyzer (or analyzers) is restricted to 720 cumulative hours per calendar year (or ozone season, as applicable), unless the owner or operator redesignates the like-kind replacement analyzer(s) as component(s) of regular non-redundant backup CEMS and each redesignated CEMS passes a RATA at that unit or stack.


(vi) For each regular non-redundant backup CEMS, no more than eight successive calendar quarters shall elapse following the quarter in which the last RATA of the CEMS was done at a particular unit or stack, without performing a subsequent RATA. Otherwise, the CEMS may not be used to report data from that unit or stack until the hour of completion of a passing RATA at that location.


(vii) Each regular non-redundant backup CEMS shall be represented in the monitoring plan required under § 75.53 as a separate monitoring system, with unique system and component identification numbers. When like-kind replacement non-redundant backup analyzers are used, the owner or operator shall represent each like-kind replacement analyzer used during a particular calendar quarter in the monitoring plan required under § 75.53 as a component of a primary monitoring system. The owner or operator shall also assign a unique component identification number to each like-kind replacement analyzer, beginning with the letters “LK” (e.g., “LK1,” “LK2,” etc.) and shall specify the manufacturer, model and serial number of the like-kind replacement analyzer. This information may be added, deleted or updated as necessary, from quarter to quarter. The owner or operator shall also report data from the like-kind replacement analyzer using the system identification number of the primary monitoring system and the assigned component identification number of the like-kind replacement analyzer. For the purposes of the electronic quarterly report required under § 75.64, the owner or operator may manually enter the appropriate component identification number(s) of any like-kind replacement analyzer(s) used for data reporting during the quarter.


(viii) When reporting data from a certified regular non-redundant backup CEMS, use a method of determination (MODC) code of “02.” When reporting data from a like-kind replacement non-redundant backup analyzer, use a MODC of “17” (see Table 4a under § 75.57). For the purposes of the electronic quarterly report required under § 75.64, the owner or operator may manually enter the required MODC of “17” for a like-kind replacement analyzer.


(3) Reference method backups. A monitoring system that is operated as a reference method backup system pursuant to the reference method requirements of methods 2, 6C, 7E, or 3A in appendix A of part 60 of this chapter need not perform and pass the certification tests required by paragraph (c) of this section prior to its use pursuant to this paragraph.


(e) Certification/recertification procedures for either peaking unit or by-pass stack/duct continuous emission monitoring systems. The owner or operator of either a peaking unit or by-pass stack/duct continuous emission monitoring system shall comply with all the requirements for certification or recertification according to the procedures specified in paragraphs (a), (b), and (c) of this section, except as follows: the owner or operator need only perform one nine-run relative accuracy test audit for certification or recertification of a flow monitor installed on the by-pass stack/duct or on the stack/duct used only by affected peaking unit(s). The relative accuracy test audit shall be performed during normal operation of the peaking unit(s) or the by-pass stack/duct.


(f) Certification/recertification procedures for alternative monitoring systems. The designated representative representing the owner or operator of each alternative monitoring system approved by the Administrator as equivalent to or better than a continuous emission monitoring system according to the criteria in subpart E of this part shall apply for certification to the Administrator prior to use of the system under the Acid Rain Program, and shall apply for recertification to the Administrator following a replacement, modification, or change according to the procedures in paragraph (c) of this section. The owner or operator of an alternative monitoring system shall comply with the notification and application requirements for certification or recertification according to the procedures specified in paragraphs (a) and (b) of this section.


(g) Initial certification and recertification procedures for excepted monitoring systems under appendices D and E. The owner or operator of a gas-fired unit, oil-fired unit, or diesel-fired unit using the optional protocol under appendix D or E to this part shall ensure that an excepted monitoring system under appendix D or E to this part meets the applicable general operating requirements of § 75.10, the applicable requirements of appendices D and E to this part, and the initial certification or recertification requirements of this paragraph.


(1) Initial certification and recertification testing. The owner or operator shall use the following procedures for initial certification and recertification of an excepted monitoring system under appendix D or E to this part.


(i) When the optional SO2 mass emissions estimation procedure in appendix D to this part or the optional NOX emissions estimation protocol in appendix E to this part is used, the owner or operator shall provide data from a flowmeter accuracy test (or shall provide a statement of calibration if the flowmeter meets the accuracy standard by design) for each fuel flowmeter, according to section 2.1.5.1 of appendix D to this part. For orifice, nozzle, and venturi-type flowmeters, the results of primary element visual inspections and/or calibrations of the transmitters or transducers shall also be provided.


(ii) For the automated data acquisition and handling system used under either the optional SO2 mass emissions estimation procedure in appendix D of this part or the optional NOX emissions estimation protocol in appendix E of this part, the owner or operator shall perform tests designed to verify:


(A) The proper computation of hourly averages for pollutant concentrations, fuel flow rates, emission rates, heat input, and pollutant mass emissions; and


(B) Proper computation and application of the missing data substitution procedures in appendix D or E of this part.


(iii) When the optional NOX emissions protocol in appendix E is used, the owner or operator shall complete all initial performance testing under section 2.1 of appendix E.


(2) Initial certification, recertification, and QA testing notification. The designated representative shall provide initial certification testing notification, recertification testing notification, and routine periodic quality-assurance testing, as specified in § 75.61. Initial certification testing notification, recertification testing notification, or periodic quality assurance testing notification is not required for an excepted monitoring system under appendix D to this part.


(3) Monitoring plan. The designated representative shall submit an initial monitoring plan in accordance with § 75.62(a).


(4) Initial certification or recertification application. The designated representative shall submit an initial certification or recertification application in accordance with §§ 75.60 and 75.63.


(5) Provisional approval of initial certification and recertification applications. Upon the successful completion of the required initial certification or recertification procedures for each excepted monitoring system under appendix D or E to this part, each excepted monitoring system under appendix D or E to this part shall be deemed provisionally certified (or recertified) for use under the Acid Rain Program during the period for the Administrator’s review. The provisions for the initial certification or recertification application formal approval process in paragraph (a)(4) of this section shall apply, except that the term “excepted monitoring system” shall apply rather than “continuous emission or opacity monitoring system” and except that the procedures for loss of certification or for disapproval of a recertification request in paragraph (g)(7) of this section shall apply rather than the procedures for loss of certification or denial of a recertification request in paragraph (a)(5) or (b)(5) of this section. Data measured and recorded by a provisionally certified (or recertified) excepted monitoring system under appendix D or E to this part will be considered quality-assured data from the date and time of completion of the last initial certification or recertification test, provided that the Administrator does not revoke the provisional certification or recertification by issuing a notice of disapproval in accordance with the provisions in paragraph (a)(4) or (b)(5) of this section.


(6) Recertification requirements. Recertification of an excepted monitoring system under appendix D or E to this part is required for any modification to the system or change in operation that could significantly affect the ability of the system to accurately account for emissions and for which the Administrator determines that an accuracy test of the fuel flowmeter or a retest under appendix E to this part to re-establish the NOX correlation curve is required. Examples of such changes or modifications include fuel flowmeter replacement, changes in unit configuration, or exceedance of operating parameters.


(7) Procedures for loss of certification or recertification for excepted monitoring systems under appendices D and E to this part. In the event that a certification or recertification application is disapproved for an excepted monitoring system, data from the monitoring system are invalidated, and the applicable missing data procedures in section 2.4 of appendix D or section 2.5 of appendix E to this part shall be used from the date and hour of receipt of such notice back to the hour of the provisional certification. Data from the excepted monitoring system remain invalid until all required tests are repeated and the excepted monitoring system is again provisionally certified. The owner or operator shall repeat all certification or recertification tests or other requirements, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval. The designated representative shall submit a notification of the certification or recertification retest dates if required under paragraph (g)(2) of this section and shall submit a new certification or recertification application according to the procedures in paragraph (g)(4) of this section.


(h) Initial certification and recertification procedures for low mass emission units using the excepted methodologies under § 75.19. The owner or operator of a gas-fired or oil-fired unit using the low mass emissions excepted methodology under § 75.19 shall meet the applicable general operating requirements of § 75.10, the applicable requirements of § 75.19, and the applicable certification requirements of this paragraph.


(1) Monitoring plan. The designated representative shall submit a monitoring plan in accordance with §§ 75.53 and 75.62.


(2) Certification application. The designated representative shall submit a certification application in accordance with § 75.63(a)(1)(ii).


(3) Approval of certification applications. The provisions for the certification application formal approval process in the introductory text of paragraph (a)(4) and in paragraphs (a)(4)(i), (ii), and (iv) of this section shall apply, except that “continuous emission or opacity monitoring system” shall be replaced with “low mass emissions excepted methodology.” Provisional certification status for the low mass emissions methodology begins on the date of submittal (consistent with the definition of “submit” in § 72.2 of this chapter) of a complete certification application, and the methodology is considered to be certified either upon receipt of a written approval notice from the Administrator or, if such notice is not provided, at the end of the Administrator’s 120-day review period. However, in contrast to CEM systems or appendix D and E monitoring systems, a provisionally certified or certified low mass emissions excepted methodology may not be used to report data under the Acid Rain Program or in a NOX mass emissions reduction program under subpart H of this part prior to the applicable commencement date specified in § 75.19(a)(2)(i).


(4) Disapproval of low mass emissions unit certification applications. If the Administrator determines that the certification application for a low mass emissions unit does not demonstrate that the unit meets the requirements of §§ 75.19(a) and (b), the Administrator shall issue a written notice of disapproval of the certification application within 120 days of receipt. By issuing the notice of disapproval, the provisional certification is invalidated by the Administrator, and any emission data reported using the excepted methodology during the Administrator’s 120-day review period shall be considered invalid. The owner or operator shall use the following procedures when a certification application is disapproved:


(i) The owner or operator shall substitute the following values, as applicable, for each hour of unit operation in which data were reported usi