pt. 76 40 cfr ch. i (7–1–00 edition) · pt. 76 40 cfr ch. i (7–1–00 edition) ... project....

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40 CFR Ch. I (7–1–00 Edition)Pt. 76

required sample of fuel carbon content areeither missing or invalid. The substitute

data value shall be used until the next validcarbon content sample is obtained.

TABLE G–1.—MISSING DATA SUBSTITUTION PROCEDURES FOR MISSING CARBON CONTENT DATA

Parameter Sampling technique/frequency Missing data value

Oil and coal carbon content ...................... All oil and coal samples, prior to April 1,2000.

Most recent, previous carbon contentvalue available for that grade of oil, ordefault value, in this table.

Gas carbon content ................................... All gaseous fuel samples, prior to April1, 2000.

Most recent, previous carbon contentvalue available for that type of gas-eous fuel, or default value, in thistable.

Default coal carbon content ...................... All, on and after April 1, 2000 ................. Anthracite: 90.0 percent.Bituminous: 85.0 percent.Subbituminous/Lignite: 75.0 percent.

Default oil carbon content ......................... All, on and after April 1, 2000 ................. 90.0 percent.Default gas carbon content ....................... All, on and after April 1, 2000 ................. Natural gas: 75.0 percent.

Other gaseous fuels: 90.0 percent.

5.3 Gross Calorific Value Data

For a gas-fired unit using the procedures ofsection 2.3 of this appendix to determine CO2

emissions, substitute for missing gross calo-rific value data used to calculate heat inputby following the missing data procedures forgross calorific value in section 2.4 of appen-dix D to this part.

[58 FR 3701, Jan. 11, 1993, as amended at 60FR 26556-26557, May 17, 1995; 61 FR 25585, May22, 1996; 64 FR 28671, May 26, 1999]

APPENDIX H TO PART 75—REVISEDTRACEABILITY PROTOCOL NO. 1 [RE-SERVED]

APPENDIX I TO PART 75—OPTIONAL F—FACTOR/FUEL FLOW METHOD [RE-SERVED]

APPENDIX J TO PART 75—COMPLIANCEDATES FOR REVISED RECORDKEEPINGREQUIREMENTS AND MISSING DATAPROCEDURES [RESERVED]

[60 FR 26557, May 17, 1995]

PART 76—ACID RAIN NITROGENOXIDES EMISSION REDUCTIONPROGRAM

Sec.76.1 Applicability.76.2 Definitions.76.3 General Acid Rain Program provisions.76.4 Incorporation by reference.76.5 NOX emission limitations for Group 1

boilers.76.6 NOX emission limitations for Group 2

boilers.76.7 Revised NOX emission limitations for

Group 1, Phase II boilers.

76.8 Early election for Group 1, Phase IIboilers.

76.9 Permit application and complianceplans.

76.10 Alternative emission limitations.76.11 Emissions averaging.76.12 Phase I NOX compliance extension.76.13 Compliance and excess emissions.76.14 Monitoring, recordkeeping, and re-

porting.76.15 Test methods and procedures.

APPENDIX A TO PART 76—PHASE I AFFECTEDCOAL-FIRED UTILITY UNITS WITH GROUP 1OR CELL BURNER BOILERS

APPENDIX B TO PART 76—PROCEDURES ANDMETHODS FOR ESTIMATING COSTS OF NI-TROGEN OXIDES CONTROLS APPLIED TOGROUP 1, PHASE I BOILERS

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

SOURCE: 60 FR 18761, Apr. 13, 1995, unlessotherwise noted.

§ 76.1 Applicability.(a) Except as provided in paragraphs

(b) through (d) of this section, the pro-visions apply to each coal-fired utilityunit that is subject to an Acid Rainemissions limitation or reduction re-quirement for SO2 under Phase I orPhase II pursuant to sections 404, 405,or 409 of the Act.

(b) The emission limitations for NOX

under this part apply to each affectedcoal-fired utility unit subject to sec-tion 404(d) or 409(b) of the Act on thedate the unit is required to meet theAcid Rain emissions reduction require-ment for SO2.

(c) The provisions of this part applyto each coal-fired substitution unit orcompensating unit, designated and ap-proved as a Phase I unit pursuant to

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Environmental Protection Agency § 76.2

§ 72.41 or § 72.43 of this chapter as fol-lows:

(1) A coal-fired substitution unit thatis designated in a substitution planthat is approved and active as of Janu-ary 1, 1995 shall be treated as a PhaseI coal-fired utility unit for purposes ofthis part. In the event the designationof such unit as a substitution unit isterminated after December 31, 1995,pursuant to § 72.41 of this chapter andthe unit is no longer required to meetPhase I SO2 emissions limitations, theprovisions of this part (including thoseapplicable in Phase I) will continue toapply.

(2) A coal-fired substitution unit thatis designated in a substitution planthat is not approved or not active as ofJanuary 1, 1995, or a coal-fired compen-sating unit, shall be treated as a PhaseII coal-fired utility unit for purposes ofthis part.

(d) The provisions of this part forPhase I units apply to each coal-firedtransfer unit governed by a Phase I ex-tension plan, approved pursuant to§ 72.42 of this chapter, on January 1,1997. Notwithstanding the precedingsentence, a coal-fired transfer unitshall be subject to the Acid Rain emis-sions limitations for nitrogen oxidesbeginning on January 1, 1996 if, for thatyear, a transfer unit is allocated fewerPhase I extension reserve allowancesthan the maximum amount that thedesignated representative could haverequested in accordance with§ 72.42(c)(5) of this chapter (as adjustedunder § 72.42(d) of this chapter) unlessthe transfer unit is the last unit allo-cated Phase I extension reserve allow-ances under the plan.

§ 76.2 Definitions.All terms used in this part shall have

the meaning set forth in the Act, in§ 72.2 of this chapter, and in this sec-tion as follows:

Alternative contemporaneous annualemission limitation means the maximumallowable NOX emission rate (on a lb/mmBtu, annual average basis) assignedto an individual unit in a NOX emis-sions averaging plan pursuant to § 76.10.

Alternative technology means a con-trol technology for reducing NOX emis-sions that is outside the scope of thedefinition of low NOX burner tech-

nology. Alternative technology doesnot include overfire air as applied towall-fired boilers or separated overfireair as applied to tangentially firedboilers.

Approved clean coal technology dem-onstration project means a project usingfunds appropriated under the Depart-ment of Energy’s ‘‘Clean Coal Tech-nology Demonstration Program,’’ up toa total amount of $2,500,000,000 for com-mercial demonstration of clean coaltechnology, or similar projects fundedthrough appropriations for the Envi-ronmental Protection Agency. TheFederal contribution for a qualifyingproject shall be at least 20 percent ofthe total cost of the demonstrationproject.

Arch-fired boiler means a dry bottomboiler with circular burners, or coaland air pipes, oriented downward andmounted on waterwalls that are at anangle significantly different from thehorizontal axis and the vertical axis.This definition shall include only thefollowing units: Holtwood unit 17,Hunlock unit 6, and Sunbury units 1A,1B, 2A, and 2B. This definition shall ex-clude dry bottom turbo fired boilers.

Cell burner boiler means a wall-firedboiler that utilizes two or three cir-cular burners combined into a singlevertically oriented assembly that re-sults in a compact, intense flame. Anylow NOX retrofit of a cell burner boilerthat reuses the existing cell burner,close-coupled wall opening configura-tion would not change the designationof the unit as a cell burner boiler.

Coal-fired utility unit means a utilityunit in which the combustion of coal(or any coal-derived fuel) on a Btubasis exceeds 50.0 percent of its annualheat input during the following cal-endar year: for Phase I units, in cal-endar year 1990; and, for Phase II units,in calendar year 1995 or, for a Phase IIunit that did not combust any fuel thatresulted in the generation of elec-tricity in calendar year 1995, in anycalendar year during the period 1990–1995. For the purposes of this part, thisdefinition shall apply notwithstandingthe definition in § 72.2 of this chapter.

Combustion controls means technologythat minimizes NOX formation by stag-ing fuel and combustion air flows in aboiler. This definition shall include low

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NOX burners, overfire air, or low NOX

burners with overfire air.Cyclone boiler means a boiler with one

or more water-cooled horizontal cylin-drical chambers in which coal combus-tion takes place. The horizontal cylin-drical chamber(s) is (are) attached tothe bottom of the furnace. One or morecylindrical chambers are arranged ei-ther on one furnace wall or on two op-posed furnace walls. Gaseous combus-tion products exiting from the cham-ber(s) turn 90 degrees to go up throughthe boiler while coal ash exits the bot-tom of the boiler as a molten slag.

Demonstration period means a periodof time not less than 15 months, ap-proved under § 76.10, for demonstratingthat the affected unit cannot meet theapplicable emission limitation under§ 76.5, 76.6, or 76.7 and establishing theminimum NOX emission rate that theunit can achieve during long-term loaddispatch operation.

Dry bottom means the boiler has afurnace bottom temperature below theash melting point and the bottom ashis removed as a solid.

Economizer means the lowest tem-perature heat exchange section of autility boiler where boiler feed water isheated by the flue gas.

Flue gas means the combustion prod-ucts arising from the combustion offossil fuel in a utility boiler.

Group 1 boiler means a tangentiallyfired boiler or a dry bottom wall-firedboiler (other than a unit applying cellburner technology).

Group 2 boiler means a wet bottomwall-fired boiler, a cyclone boiler, aboiler applying cell burner technology,a vertically fired boiler, an arch-firedboiler, or any other type of utility boil-er (such as a fluidized bed or stokerboiler) that is not a Group 1 boiler.

Low NOX burners and low NOX burnertechnology means commercially avail-able combustion modification NOX con-trols that minimize NOX formation byintroducing coal and its associatedcombustion air into a boiler such thatinitial combustion occurs in a mannerthat promotes rapid coaldevolatilization in a fuel-rich (i.e., oxy-gen deficient) environment and intro-duces additional air to achieve a finalfuel-lean (i.e., oxygen rich) environ-ment to complete the combustion proc-

ess. This definition shall include thestaging of any portion of the combus-tion air using air nozzles or registerslocated inside any waterwall hole thatincludes a burner. This definition shallexclude the staging of any portion ofthe combustion air using air nozzles orports located outside any waterwallhole that includes a burner (commonlyreferred to as NOX ports or separatedoverfire air ports).

Maximum Continuous Steam Flow at100% of Load means the maximum ca-pacity of a boiler as reported in item 3(Maximum Continuous Steam Flow at100% Load in thousand pounds perhour), Section C ( design parameters),Part III (boiler information) of the De-partment of Energy’s Form EIA–767 for1995.

Non-plug-in combustion controls meansthe replacement, in a cell burner boil-er, of the portions of the waterwallscontaining the cell burners by new por-tions of the waterwalls containing lowNOX burners or low NOX burners withoverfire air.

Operating period means a period oftime of not less than three consecutivemonths and that occurs not more thanone month prior to applying for an al-ternative emission limitation dem-onstration period under § 76.10, duringwhich the owner or operator of an af-fected unit that cannot meet the appli-cable emission limitation:

(1) Operates the installed NOX emis-sion controls in accordance with pri-mary vendor specifications and proce-dures, with the unit operating undernormal conditions; and

(2) records and reports quality-as-sured continuous emission monitoring(CEM) and unit operating data accord-ing to the methods and procedures inpart 75 of this chapter.

Plug-in combustion controls means thereplacement, in a cell burner boiler, ofexisting cell burners by low NOX burn-ers or low NOX burners with overfireair.

Primary vendor means the vendor ofthe NOX emission control system whohas primary responsibility for pro-viding the equipment, service, andtechnical expertise necessary for de-tailed design, installation, and oper-ation of the controls, including process


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data, mechanical drawings, operatingmanuals, or any combination thereof.

Reburning means reducing the coaland combustion air to the main burn-ers and injecting a reburn fuel (such asgas or oil) to create a fuel-rich sec-ondary combustion zone above themain burner zone and final combustionair to create a fuel-lean burnout zone.The formation of NOX is inhibited inthe main burner zone due to the re-duced combustion intensity, and NOX isdestroyed in the fuel-rich secondarycombustion zone by conversion to mo-lecular nitrogen.

Selective catalytic reduction means anoncombustion control technologythat destroys NOX by injecting a reduc-ing agent (e.g., ammonia) into the fluegas that, in the presence of a catalyst(e.g., vanadium, titanium, or zeolite),converts NOX into molecular nitrogenand water.

Selective noncatalytic reduction meansa noncombustion control technologythat destroys NOX by injecting a reduc-ing agent (e.g., ammonia, urea, or cya-nuric acid) into the flue gas, down-stream of the combustion zone thatconverts NOX to molecular nitrogen,water, and when urea or cyanuric acidare used, to carbon dioxide (CO2).

Stoker boiler means a boiler thatburns solid fuel in a bed, on a sta-tionary or moving grate, that is lo-cated at the bottom of the furnace.

Tangentially fired boiler means a boil-er that has coal and air nozzles mount-ed in each corner of the furnace wherethe vertical furnace walls meet. Bothpulverized coal and air are directedfrom the furnace corners along a linetangential to a circle lying in a hori-zontal plane of the furnace.

Turbo-fired boiler means a pulverizedcoal, wall-fired boiler with burners ar-ranged on walls so that the individualflames extend down toward the furnacebottom and then turn back up throughthe center of the furnace.

Vertically fired boiler means a dry bot-tom boiler with circular burners, orcoal and air pipes, oriented downwardand mounted on waterwalls that arehorizontal or at an angle. This defini-tion shall include dry bottom roof-firedboilers and dry bottom top-fired boil-ers, and shall exclude dry bottom arch-

fired boilers and dry bottom turbo-firedboilers.

Wall-fired boiler means a boiler thathas pulverized coal burners arrangedon the walls of the furnace. The burn-ers have discrete, individual flamesthat extend perpendicularly into thefurnace area.

Wet bottom means that the ash is re-moved from the furnace in a moltenstate. The term ‘‘wet bottom boiler’’shall include: wet bottom wall-firedboilers, including wet bottom turbo-fired boilers; and wet bottom boilersotherwise meeting the definition ofvertically fired boilers, including wetbottom arch-fired boilers, wet bottomroof-fired boilers, and wet bottom top-fired boilers. The term ‘‘wet bottomboiler’’ shall exclude cyclone boilersand tangentially fired boilers.

[60 FR 18761, Apr. 13, 1995, as amended at 61FR 67162, Dec. 19, 1996]

§ 76.3 General Acid Rain Program pro-visions.

The following provisions of part 72 ofthis chapter shall apply to this part:

(a) § 72.2 (Definitions);(b) § 72.3 (Measurements, abbrevia-

tions, 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 informa-

tion); and(j) § 72.11 (Computation of time).In addition, the procedures for ap-

peals of decisions of the Administratorunder this part are contained in part 78of this chapter.

§ 76.4 Incorporation by reference.(a) The materials listed in this sec-

tion are incorporated by reference inthe sections noted. Theseincorporations by reference (IBR’s)were approved by the Director of theFederal Register in accordance with 5U.S.C. 552(a) and 1 CFR part 51. Thesematerials are incorporated as they ex-isted on the date of approval, and no-tice of any change in these materialswill be published in the FEDERAL REG-ISTER. The materials are available for


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40 CFR Ch. I (7–1–00 Edition)§ 76.5

purchase at the corresponding addressnoted below and are available for in-spection at the Office of the FederalRegister, 800 North Capitol St., NW.,7th Floor, Suite 700, Washington, DC,at the Public Information ReferenceUnit, U.S. EPA, 401 M Street, SW.,Washington, DC, and at the Library(MD–35), U.S. EPA, Research TrianglePark, North Carolina.

(b) The following materials are avail-able for purchase from at least one ofthe following addresses: American So-ciety for Testing and Materials(ASTM), 1916 Race Street, Philadel-phia, Pennsylvania 19103; or the Uni-versity Microfilms International, 300North Zeeb Road, Ann Arbor, Michigan48106.

(1) ASTM D 3176–89, Standard Prac-tice for Ultimate Analysis of Coal andCoke, IBR approved May 23, 1995 for§ 76.15.

(2) ASTM D 3172–89, Standard Prac-tice for Proximate Analysis of Coal andCoke, IBR approved May 23, 1995 for§ 76.15.

(c) The following material is avail-able for purchase from the AmericanSociety of Mechanical Engineers(ASME), 22 Law Drive, Box 2350, Fair-field, NJ 07007–2350.

(1) ASME Performance Test Code 4.2(1991), Test Code for Coal Pulverizers,IBR approved May 23, 1995 for § 76.15.

(2) [Reserved](d) The following material is avail-

able for purchase from the AmericanNational Standards Institute, 11 West42nd Street, New York, NY 10036 orfrom the International Organizationfor Standardization (ISO), Case Postale56, CH–1211 Geneve 20, Switzerland.

(1) ISO 9931 (December, 1991) ‘‘Coal—Sampling of Pulverized Coal Conveyedby Gases in Direct Fired Coal Sys-tems,’’ IBR approved May 23, 1995 for§ 76.15.

(2) [Reserved]

§ 76.5 NOX emission limitations forGroup 1 boilers.

(a) Beginning January 1, 1996, or for aunit subject to section 404(d) of theAct, the date on which the unit is re-quired to meet Acid Rain emission re-duction requirements for SO2, theowner or operator of a Phase I coal-fired utility unit with a tangentially

fired boiler or a dry bottom wall-firedboiler (other than units applying cellburner technology) shall not discharge,or allow to be discharged, emissions ofNOX to the atmosphere in excess of thefollowing limits, except as provided inparagraphs (c) or (e) of this section orin § 76.10, 76.11, or 76.12:

(1) 0.45 lb/mmBtu of heat input on anannual average basis for tangentiallyfired boilers.

(2) 0.50 lb/mmBtu of heat input on anannual average basis for dry bottomwall-fired boilers (other than units ap-plying cell burner technology).

(b) The owner or operator shall deter-mine the annual average NOX emissionrate, in lb/mmBtu, using the methodsand procedures specified in part 75 ofthis chapter.

(c) Unless the unit meets the earlyelection requirement of § 76.8, theowner or operator of a coal-fired sub-stitution unit with a tangentially firedboiler or a dry bottom wall-fired boiler(other than units applying cell burnertechnology) that satisfies the require-ments of § 76.1(c)(2), shall comply withthe NOX emission limitations thatapply to Group 1, Phase II boilers.

(d) The owner or operator of a PhaseI unit with a cell burner boiler thatconverts to a conventional wall-firedboiler on or before January 1, 1995 or,for a unit subject to section 404(d) ofthe Act, the date the unit is requiredto meet Acid Rain emissions reductionrequirements for SO2 shall comply, bysuch respective date or January 1, 1996,whichever is later, with the NOX emis-sions limitation applicable to dry bot-tom wall-fired boilers under paragraph(a) of this section, except as providedin paragraphs (c) or (e) of this sectionor in § 76.10, 76.11, or 76.12.

(e) The owner or operator of a PhaseI unit with a Group 1 boiler that con-verts to a fluidized bed or other type ofutility boiler not included in Group 1boilers on or before January 1, 1995 or,for a unit subject to section 404(d) ofthe Act, the date the unit is requiredto meet Acid Rain emissions reductionrequirements for SO2 is exempt fromthe NOX emissions limitations specifiedin paragraph (a) of this section, butshall comply with the NOX emissionlimitations for Group 2 boilers under§ 76.6.


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(f) Except as provided in § 76.8 and inparagraph (c) of this section, each unitsubject to the requirements of this sec-tion is not subject to the requirementsof § 76.7.


§ 76.6 NOX emission limitations forGroup 2 boilers.

(a) Beginning January 1, 2000 or, for aunit subject to section 409(b) of theAct, the date on which the unit is re-quired to meet Acid Rain emission re-duction requirements for SO2, theowner or operator of a Group 2, coal-fired boiler with a cell burner boiler,cyclone boiler, a wet bottom boiler, ora vertically fired boiler shall not dis-charge, or allow to be discharged, emis-sions of NOX to the atmosphere in ex-cess of the following limits, except asprovided in §§ 76.10 or 76.11:

(1) 0.68 lb/mmBtu of heat input on anannual average basis for cell burnerboilers. The NOX emission control tech-nology on which the emission limita-tion is based is plug-in combustion con-trols or non-plug-in combustion con-trols. Except as provided in § 76.5(d),the owner or operator of a unit with acell burner boiler that installs non-plug-in combustion controls shall com-ply with the emission limitation appli-cable to cell burner boilers.

(2) 0.86 lb/mmBtu of heat input on anannual average basis for cyclone boil-ers with a Maximum Continuous SteamFlow at 100% of Load of greater than1060, in thousands of lb/hr. The NOX

emission control technology on whichthe emission limitation is based is nat-ural gas reburning or selective cata-lytic reduction.

(3) 0.84 lb/mmBtu of heat input on anannual average basis for wet bottomboilers, with a Maximum ContinuousSteam Flow at 100% of Load of greaterthan 450, in thousands of lb/hr. The NOX

emission control technology on whichthe emission limitation is based is nat-ural gas reburning or selective cata-lytic reduction.

(4) 0.80 lb/mmBtu of heat input on anannual average basis for verticallyfired boilers. The NOX emission controltechnology on which the emission limi-tation is based is combustion controls.


[62 FR 67162, Dec. 19, 1996; 62 FR 3464, Jan. 23,1997; 62 FR 32040, June 12, 1997; 64 FR 55838,Oct. 15, 1999]

§ 76.7 Revised NOX emission limita-tions for Group 1, Phase II boilers.

(a) Beginning January 1, 2000, theowner or operator of a Group 1, PhaseII coal-fired utility unit with a tangen-tially fired boiler or a dry bottom wall-fired boiler shall not discharge, orallow to be discharged, emissions ofNOX to the atmosphere in excess of thefollowing limits, except as provided in§§ 76.8, 76.10, or 76.11:

(1) 0.40 lb/mmBtu of heat input on anannual average basis for tangentiallyfired boilers.

(2) 0.46 lb/ mmBtu of heat input on anannual average basis for dry bottomwall-fired boilers (other than units ap-plying cell burner technology).



§ 76.8 Early election for Group 1,Phase II boilers.

(a) General provisions. (1) The owneror operator of a Phase II coal-fired util-ity unit with a Group 1 boiler mayelect to have the unit become subjectto the applicable emissions limitationfor NOX under § 76.5, starting no laterthan January 1, 1997.

(2) The owner or operator of a PhaseII coal-fired utility unit with a Group 1boiler that elects to become subject tothe applicable emission limitationunder § 76.5 shall not be subject to § 76.7until January 1, 2008, provided the des-ignated representative demonstratesthat the unit is in compliance with thelimitation under § 76.5, using the meth-ods and procedures specified in part 75of this chapter, for the period begin-ning January 1 of the year in which theearly election takes effect (but not


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later than January 1, 1997) and endingDecember 31, 2007.

(3) The owner or operator of anyPhase II unit with a cell burner boilerthat converts to conventional burnertechnology may elect to become sub-ject to the applicable emissions limita-tion under § 76.5 for dry bottom wall-fired boilers, provided the owner or op-erator complies with the provisions inparagraph (a)(2) of this section.

(4) The owner or operator of a PhaseII unit approved for early election shallnot submit an application for an alter-native emissions limitation demonstra-tion period under § 76.10 until the ear-lier of:

(i) January 1, 2008; or(ii) Early election is terminated pur-

suant to paragraph (e)(3) of this sec-tion.

(5) The owner or operator of a PhaseII unit approved for early election maynot incorporate the unit into an aver-aging plan prior to January 1, 2000. Onor after January 1, 2000, for purposes ofthe averaging plan, the early electionunit will be treated as subject to theapplicable emissions limitation forNOX for Phase II units with Group 1boilers under § 76.7.

(b) Submission requirements. In orderto obtain early election status, the des-ignated representative of a Phase IIunit with a Group 1 boiler shall submitan early election plan to the Adminis-trator by January 1 of the year theearly election is to take effect, but notlater than January 1, 1997. Notwith-standing § 72.40 of this chapter, and un-less the unit is a substitution unitunder § 72.41 of this chapter or a com-pensating unit under § 72.43 of thischapter, a complete compliance plancovering the unit shall not include theprovisions for SO2 emissions under§ 72.40(a)(1) of this chapter.

(c) Contents of an early election plan. Acomplete early election plan shall in-clude the following elements in a for-mat prescribed by the Administrator:

(1) A request for early election;(2) The first year for which early

election is to take effect, but not laterthan 1997; and

(3) The special provisions under para-graph (e) of this section.

(d)(1) Permitting authority’s action. Tothe extent the Administrator deter-

mines that an early election plan com-plies with the requirements of this sec-tion, the Administrator will approvethe plan and:

(i) If a Phase I Acid Rain permit gov-erning the source at which the unit islocated has been issued, will revise thepermit in accordance with the permitmodification procedures in § 72.81 ofthis chapter to include the early elec-tion plan; or

(ii) If a Phase I Acid Rain permit gov-erning the source at which the unit islocated has not been issued, will issuea Phase I Acid Rain permit effectivefrom January 1, 1995 through December31, 1999, that will include the earlyelection plan and a complete compli-ance plan under § 72.40(a) of this chap-ter and paragraph (b) of this section. Ifthe early election plan is not effectiveuntil after January 1, 1995, the permitwill not contain any NOX emissionslimitations until the effective date ofthe plan.

(2) Beginning January 1, 2000, the per-mitting authority will approve anyearly election plan previously approvedby the Administrator during Phase I,unless the plan is terminated pursuantto paragraph (e)(3) of this section.

(e) Special provisions—(1) Emissionslimitations—(i) Sulfur dioxide. Notwith-standing § 72.9 of this chapter, a unitthat is governed by an approved earlyelection plan and that is not a substi-tution unit under § 72.41 of this chapteror a compensating unit under § 72.43 ofthis chapter shall not be subject to thefollowing standard requirements under§ 72.9 of this chapter for Phase I:

(A) The permit requirements under§§ 72.9(a)(1) (i) and (ii) of this chapter;

(B) The sulfur dioxide requirementsunder § 72.9(c) of this chapter; and

(C) The excess emissions require-ments under § 72.9(e)(1) of this chapter.

(ii) Nitrogen oxides. A unit that is gov-erned by an approved early electionplan shall be subject to an emissionslimitation for NOX as provided underparagraph (a)(2) of this section exceptas provided under paragraph (e)(3)(iii)of this section.

(2) Liability. The owners and opera-tors of any unit governed by an ap-proved early election plan shall be lia-ble for any violation of the plan or thissection at that unit. The owners and


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operators shall be liable, beginningJanuary 1, 2000, for fulfilling the obli-gations specified in part 77 of thischapter.

(3) Termination. An approved earlyelection plan shall be in effect onlyuntil the earlier of January 1, 2008 orJanuary 1 of the calendar year forwhich a termination of the plan takeseffect.

(i) If the designated representative ofthe unit under an approved early elec-tion plan fails to demonstrate compli-ance with the applicable emissions lim-itation under § 76.5 for any year duringthe period beginning January 1 of thefirst year the early election takes ef-fect and ending December 31, 2007, thepermitting authority will terminatethe plan. The termination will take ef-fect beginning January 1 of the yearafter the year for which there is a fail-ure to demonstrate compliance, andthe designated representative may notsubmit a new early election plan.

(ii) The designated representative ofthe unit under an approved early elec-tion plan may terminate the plan anyyear prior to 2008 but may not submita new early election plan. In order toterminate the plan, the designated rep-resentative must submit a notice under§ 72.40(d) of this chapter by January 1 ofthe year for which the termination isto take effect.

(iii)(A) If an early election plan isterminated any year prior to 2000, theunit shall meet, beginning January 1,2000, the applicable emissions limita-tion for NOX for Phase II units withGroup 1 boilers under § 76.7.

(B) If an early election plan is termi-nated in or after 2000, the unit shallmeet, beginning on the effective dateof the termination, the applicableemissions limitation for NOX for PhaseII units with Group 1 boilers under§ 76.7.


§ 76.9 Permit application and compli-ance plans.

(a) Duty to apply. (1) The designatedrepresentative of any source with anaffected unit subject to this part shallsubmit, by the applicable deadlineunder paragraph (b) of this section, a

complete Acid Rain permit application(or, if the unit is covered by an AcidRain permit, a complete permit revi-sion) that includes a complete compli-ance plan for NOX emissions coveringthe unit.

(2) The original and three copies ofthe permit application and complianceplan for NOX emissions for Phase Ishall be submitted to the EPA regionaloffice for the region where the applica-ble source is located. The original andthree copies of the permit applicationand compliance plan for NOX emissionsfor Phase II shall be submitted to thepermitting authority.

(b) Deadlines. (1) For a Phase I unitwith a Group 1 boiler, the designatedrepresentative shall submit a completepermit application and complianceplan for NOX covering the unit duringPhase I to the applicable permittingauthority not later than May 6, 1994.

(2) For a Phase I or Phase II unitwith a Group 2 boiler or a Phase II unitwith a Group 1 boiler, the designatedrepresentative shall submit a completepermit application and complianceplan for NOX emissions covering theunit in Phase II to the Administratornot later than January 1, 1998, exceptthat early election units shall also sub-mit an application not later than Janu-ary 1, 1997.

(c) Information requirements for NOX

compliance plans. (1) In accordancewith § 72.40(a)(2) of this chapter, a com-plete compliance plan for NOX shall,for each affected unit included in thepermit application and subject to thispart, either certify that the unit willcomply with the applicable emissionslimitation under § 76.5, 76.6, or 76.7 orspecify one or more other Acid Raincompliance options for NOX in accord-ance with the requirements of thispart. A complete compliance plan forNOX for a source shall include the fol-lowing elements in a format prescribedby the Administrator:

(i) Identification of the source;(ii) Identification of each affected

unit that is at the source and is subjectto this part;

(iii) Identification of the boiler typeof each unit;

(iv) Identification of the complianceoption proposed for each unit (i.e.,


440

40 CFR Ch. I (7–1–00 Edition)§ 76.10

meeting the applicable emissions limi-tation under § 76.5, 76.6, 76.7, 76.8 (earlyelection), 76.10 (alternative emissionlimitation), 76.11 (NOX emissions aver-aging), or 76.12 (Phase I NOX compli-ance extension)) and any additional in-formation required for the appropriateoption in accordance with this part;

(v) Reference to the standard require-ments in § 72.9 of this chapter (con-sistent with § 76.8(e)(1)(i)); and

(vi) The requirements of §§ 72.21 (a)and (b) of this chapter.

(2) [Reserved](d) Duty to reapply. The designated

representative of any source with anaffected unit subject to this part shallsubmit a complete Acid Rain permitapplication, including a complete com-pliance plan for NOX emissions cov-ering the unit, in accordance with thedeadlines in § 72.30(c) of this chapter.

§ 76.10 Alternative emission limita-tions.

(a) General provisions. (1) The des-ignated representative of an affectedunit that is not an early election unitpursuant to § 76.8 and cannot meet theapplicable emission limitation in § 76.5,76.6, or 76.7 using, for Group 1 boilers,either low NOX burner technology or analternative technology in accordancewith paragraph (e)(11) of this section,or, for tangentially fired boilers, sepa-rated overfire air, or, for Group 2 boil-ers, the technology on which the appli-cable emission limitation is based maypetition the permitting authority foran alternative emission limitation lessstringent than the applicable emissionlimitation.

(2) In order for the unit to qualify foran alternative emission limitation, thedesignated representative shall dem-onstrate that the affected unit cannotmeet the applicable emission limita-tion in § 76.5, 76.6, or 76.7 based on ashowing, to the satisfaction of the Ad-ministrator, that:

(i)(A) For a tangentially fired boiler,the owner or operator has either prop-erly installed low NOX burner tech-nology or properly installed separatedoverfire air; or

(B) For a dry bottom wall-fired boiler(other than a unit applying cell burnertechnology), the owner or operator has

properly installed low NOX burner tech-nology; or

(C) For a Group 1 boiler, the owner oroperator has properly installed an al-ternative technology (including butnot limited to reburning, selective non-catalytic reduction, or selective cata-lytic reduction) that achieves NOX

emission reductions demonstrated inaccordance with paragraph (e)(11) ofthis section; or

(D) For a Group 2 boiler, the owner oroperator has properly installed the ap-propriate NOX emission control tech-nology on which the applicable emis-sion limitation in § 76.6 is based; and

(ii) The installed NOX emission con-trol system has been designed to meetthe applicable emission limitation in§ 76.5, 76.6, or 76.7; and

(iii) For a demonstration period of atleast 15 months or other period of time,as provided in paragraph (f)(1) of thissection:

(A) The NOX emission control systemhas been properly installed and prop-erly operated according to specifica-tions and procedures designed to mini-mize the emissions of NOX to the at-mosphere;

(B) Unit operating data as specifiedin this section show that the unit andNOX emission control system were op-erated in accordance with the bid anddesign specifications on which the de-sign of the NOX emission control sys-tem was based; and

(C) Unit operating data as specifiedin this section, continuous emissionmonitoring data obtained pursuant topart 75 of this chapter, and the testdata specific to the NOX emission con-trol system show that the unit couldnot meet the applicable emission limi-tation in § 76.5, 76.6, or 76.7.

(b) Petitioning process. The petitioningprocess for an alternative emissionlimitation shall consist of the fol-lowing steps:

(1) Operation during a period of atleast 3 months, following the installa-tion of the NOX emission control sys-tem, that shows that the specific unitand the NOX emission control systemwas unable to meet the applicableemissions limitation under § 76.5, 76.6,or 76.7 and was operated in accordancewith the operating conditions uponwhich the design of the NOX emission


441


control system was based and with ven-dor specifications and procedures;

(2) Submission of a petition for an al-ternative emission limitation dem-onstration period as specified in para-graph (d) of this section;

(3) Operation during a demonstrationperiod of at least 15 months, or otherperiod of time as provided in paragraph(f)(1) of this section, that demonstratesthe inability of the specific unit tomeet the applicable emissions limita-tion under § 76.5, 76.6, or 76.7 and theminimum NOX emissions rate that thespecific unit can achieve during long-term load dispatch operation; and

(4) Submission of a petition for afinal alternative emission limitation asspecified in paragraph (e) of this sec-tion.

(c) Deadlines—(1) Petition for an alter-native emission limitation demonstrationperiod. The designated representativeof the unit shall submit a petition foran alternative emission limitationdemonstration period to the permittingauthority after the unit has been oper-ated for at least 3 months after instal-lation of the NOX emission control sys-tem required under paragraph (a)(2) ofthis section and by the following dead-line:

(i) For units that seek to have an al-ternative emission limitation dem-onstration period apply during all orpart of calendar year 1996, or any pre-vious calendar year by the later of:

(A) 120 days after startup of the NOX

emission control system, or(B) May 1, 1996.(ii) For units that seek an alter-

native emission limitation demonstra-tion period beginning in a calendaryear after 1996, not later than:

(A) 120 days after January 1 of thatcalendar year, or

(B) 120 days after startup of the NOX

emission control system if the unit isnot operating at the beginning of thatcalendar year.

(2) Petition for a final alternative emis-sion limitation. Not later than 90 daysafter the end of an approved alter-native emission limitation demonstra-tion period for the unit, the designatedrepresentative of the unit may submita petition for an alternative emissionlimitation to the permitting authority.

(3) Renewal of an alternative emissionlimitation. In order to request continu-ation of an alternative emission limi-tation, the designated representativemust submit a petition to renew the al-ternative emission limitation on thedate that the application for renewal ofthe source’s Acid Rain permit con-taining the alternative emission limi-tation is due.

(d) Contents of petition for an alter-native emission limitation demonstrationperiod. The designated representativeof an affected unit that has met theminimum criteria under paragraph (a)of this section and that has been oper-ated for a period of at least 3 monthsfollowing the installation of the re-quired NOX emission control systemmay submit to the permitting author-ity a petition for an alternative emis-sion limitation demonstration period.In the petition, the designated rep-resentative shall provide the followinginformation in a format prescribed bythe Administrator:

(1) Identification of the unit;(2) The type of NOX control tech-

nology installed (e.g., low NOX burnertechnology, selective noncatalytic re-duction, selective catalytic reduction,reburning);

(3) If an alternative technology is in-stalled, the time period (not less than 6consecutive months) prior to installa-tion of the technology to be used forthe demonstration required in para-graph (e)(11) of this section.

(4) Documentation as set forth in§ 76.14(a)(1) showing that the installedNOX emission control system has beendesigned to meet the applicable emis-sion limitation in § 76.5, 76.6, or 76.7 andthat the system has been properly in-stalled according to procedures andspecifications designed to minimize theemissions of NOX to the atmosphere;

(5) The date the unit commenced op-eration following the installation ofthe NOX emission control system or thedate the specific unit became subjectto the emission limitations of § 76.5,76.6, or 76.7, whichever is later;

(6) The dates of the operating period(which must be at least 3 months long);

(7) Certification by the designatedrepresentative that the owner(s) or op-erator operated the unit and the NOX


442

40 CFR Ch. I (7–1–00 Edition)§ 76.10

emission control system during the op-erating period in accordance with:Specifications and procedures designedto achieve the maximum NOX reduc-tion possible with the installed NOX

emission control system or the applica-ble emission limitation in § 76.5, 76.6, or76.7; the operating conditions uponwhich the design of the NOX emissioncontrol system was based; and vendorspecifications and procedures;

(8) A brief statement describing thereason or reasons why the unit cannotachieve the applicable emission limita-tion in § 76.5, 76.6, or 76.7;

(9) A demonstration period plan, asset forth in § 76.14(a)(2);

(10) Unit operating data and quality-assured continuous emission moni-toring data (including the specific dataitems listed in § 76.14(a)(3) collected inaccordance with part 75 of this chapterduring the operating period) and dem-onstrating the inability of the specificunit to meet the applicable emissionlimitation in § 76.5, 76.6, or 76.7 on anannual average basis while operatingas certified under paragraph (d)(7) ofthis section;

(11) An interim alternative emissionlimitation, in lb/mmBtu, that the unitcan achieve during a demonstration pe-riod of at least 15 months. The interimalternative emission limitation shallbe derived from the data specified inparagraph (d)(10) of this section usingmethods and procedures satisfactory tothe Administrator;

(12) The proposed dates of the dem-onstration period (which must be atleast 15 months long);

(13) A report which outlines the test-ing and procedures to be taken duringthe demonstration period in order todetermine the maximum NOX emissionreduction obtainable with the installedsystem. The report shall include thereasons for the NOX emission controlsystem’s failure to meet the applicableemission limitation, and the tests andprocedures that will be followed to op-timize the NOX emission control sys-tem’s performance. Such tests and pro-cedures may include those identified in§ 76.15 as appropriate.

(14) The special provisions at para-graph (g)(1) of this section.

(e) Contents of petition for a final alter-native emission limitation. After the ap-

proved demonstration period, the des-ignated representative of the unit maypetition the permitting authority foran alternative emission limitation.The petition shall include the fol-lowing elements in a format prescribedby the Administrator:

(1) Identification of the unit;(2) Certification that the owner(s) or

operator operated the affected unit andthe NOX emission control system dur-ing the demonstration period in ac-cordance with: specifications and pro-cedures designed to achieve the max-imum NOX reduction possible with theinstalled NOX emission control systemor the applicable emissions limitationin § 76.5, 76.6, or 76.7; the operating con-ditions (including load dispatch condi-tions) upon which the design of theNOX emission control system wasbased; and vendor specifications andprocedures.

(3) Certification that the owner(s) oroperator have installed in the affectedunit all NOX emission control systems,made any operational modifications,and completed any planned upgradesand/or maintenance to equipment spec-ified in the approved demonstration pe-riod plan for optimizing NOX emissionreduction performance, consistent withthe demonstration period plan and theproper operation of the installed NOX

emission control system. Such certifi-cation shall explain any differences be-tween the installed NOX emission con-trol system and the equipment configu-ration described in the approved dem-onstration period plan.

(4) A clear description of each step ormodification taken during the dem-onstration period to improve or opti-mize the performance of the installedNOX emission control system.

(5) Engineering design calculationsand drawings that show the technicalspecifications for installation of anyadditional operational or emission con-trol modifications installed during thedemonstration period.

(6) Unit operating and quality-as-sured continuous emission monitoringdata (including the specific data listedin § 76.14(b)) collected in accordancewith part 75 of this chapter during thedemonstration period and dem-onstrating the inability of the specificunit to meet the applicable emission


443


limitation in § 76.5, 76.6, or 76.7 on anannual average basis while operating inaccordance with the certificationunder paragraph (e)(2) of this section.

(7) A report (based on the parametrictest requirements set forth in the ap-proved demonstration period plan asidentified in paragraph (d)(13) of thissection), that demonstrates the unitwas operated in accordance with theoperating conditions upon which thedesign of the NOX emission control sys-tem was based and describes the reasonor reasons for the failure of the in-stalled NOX emission control system tomeet the applicable emission limita-tion in § 76.5, 76.6, or 76.7 on an annualaverage basis.

(8) The minimum NOX emission rate,in lb/mmBtu, that the affected unit canachieve on an annual average basiswith the installed NOX emission con-trol system. This value, which shall bethe requested alternative emission lim-itation, shall be derived from the dataspecified in this section using methodsand procedures satisfactory to the Ad-ministrator and shall be the lowest an-nual emission rate the unit can achievewith the installed NOX emission con-trol system;

(9) All supporting data and calcula-tions documenting the determinationof the requested alternative emissionlimitation and its conformance withthe methods and procedures satisfac-tory to the Administrator;

(10) The special provisions in para-graph (g)(2) of this section.

(11) In addition to the other require-ments of this section, the owner or op-erator of an affected unit with a Group1 boiler that has installed an alter-native technology in addition to or inlieu of low NOX burner technology andcannot meet the applicable emissionlimitation in § 76.5 shall demonstrate,to the satisfaction of the Adminis-trator, that the actual percentage re-duction in NOX emissions (lbs/mmBtu),on an annual average basis is greaterthan 65 percent of the average annualNOX emissions prior to the installationof the NOX emission control system.The percentage reduction in NOX emis-sions shall be determined using contin-uous emissions monitoring data forNOX taken during the time period(under paragraph (d)(3) of this section)

prior to the installation of the NOX

emission control system and duringlong-term load dispatch operation ofthe specific boiler.

(f) Permitting authority’s action—(1)Alternative emission limitation demonstra-tion period. (i) The permitting author-ity may approve an alternative emis-sion limitation demonstration periodand demonstration period plan, pro-vided that the requirements of this sec-tion are met to the satisfaction of thepermitting authority. The permittingauthority shall disapprove a dem-onstration period if the requirementsof paragraph (a) of this section werenot met during the operating period.

(ii) If the demonstration period is ap-proved, the permitting authority willinclude, as part of the demonstrationperiod, the 4 month period prior to sub-mission of the application in the dem-onstration period.

(iii) The alternative emission limita-tion demonstration period will author-ize the unit to emit at a rate not great-er than the interim alternative emis-sion limitation during the demonstra-tion period on or after January 1, 1996for Phase I units and the applicabledate established in § 76.6 or 76.7 forPhase II units, and until the date thatthe Administrator approves or denies afinal alternative emission limitation.

(iv) After an alternative emissionlimitation demonstration period is ap-proved, if the designated representa-tive requests an extension of the dem-onstration period in accordance withparagraph (g)(1)(i)(B) of this section,the permitting authority may extendthe demonstration period by adminis-trative amendment (under § 72.83 of thischapter) to the Acid Rain permit.

(v) The permitting authority shalldeny the demonstration period if thedesignated representative cannot dem-onstrate that the unit met the require-ments of paragraph (a)(2) of this sec-tion. In such cases, the permitting au-thority shall require that the owner oroperator operate the unit in compli-ance with the applicable emission limi-tation in § 76.5, 76.6, or 76.7 for the pe-riod preceding the submission of theapplication for an alternative emissionlimitation demonstration period, in-cluding the operating period, if suchperiods are after the date on which the


444

40 CFR Ch. I (7–1–00 Edition)§ 76.10

unit is subject to the standard limitunder § 76.5, 76.6, or 76.7.

(2) Alternative emission limitation. (i) Ifthe permitting authority determinesthat the requirements in this sectionare met, the permitting authority willapprove an alternative emission limi-tation and issue or revise an Acid Rainpermit to apply the approved limita-tion, in accordance with subparts Fand G of part 72 of this chapter. Thepermit will authorize the unit to emitat a rate not greater than the approvedalternative emission limitation, start-ing the date the permitting authorityrevises an Acid Rain permit to approvean alternative emission limitation.

(ii) If a permitting authority dis-approves an alternative emission limi-tation under paragraph (a)(2) of thissection, the owner or operator shall op-erate the affected unit in compliancewith the applicable emission limitationin § 76.5, 76.6, or 76.7 (unless the unit isparticipating in an approved averagingplan under § 76.11) beginning on thedate the permitting authority revisesan Acid Rain permit to disapprove analternative emission limitation.

(3) Alternative emission limitation re-newal. (i) If, upon review of a petitionto renew an approved alternative emis-sion limitation, the permitting author-ity determines that no changes havebeen made to the control technology,its operation, the operating conditionson which the alternative emission limi-tation was based, or the actual NOX

emission rate, the alternative emissionlimitation will be renewed.

(ii) If the permitting authority deter-mines that changes have been made tothe control technology, its operation,the fuel quality, or the operating con-ditions on which the alternative emis-sion limitation was based, the des-ignated representative shall submit, inorder to renew the alternative emissionlimitation or to obtain a new alter-native emission limitation, a petitionfor an alternative emission limitationdemonstration period that meets therequirements of paragraph (d) of thissection using a new demonstration pe-riod.

(g) Special provisions—(1) Alternativeemission limitation demonstration pe-riod—(i) Emission limitations. (A) Eachunit with an approved alternative

emission limitation demonstration pe-riod shall comply with the interimemission limitation specified in theunit’s permit beginning on the effec-tive date of the demonstration periodspecified in the permit and, if a timelypetition for a final alternative emis-sion limitation is submitted, extendinguntil the date on which the permittingauthority issues or revises an AcidRain permit to approve or disapprovean alternative emission limitation. If atimely petition is not submitted, thenthe unit shall comply with the stand-ard emission limit under § 76.5, 76.6, or76.7 beginning on the date the petitionwas required to be submitted underparagraph (c)(2) of this section.

(B) When the owner or operator iden-tifies, during the demonstration period,boiler operating or NOX emission con-trol system modifications or upgradesthat would produce further NOX emis-sion reductions, enabling the affectedunit to comply with or bring its emis-sion rate closer to the applicable emis-sions limitation under § 76.5, 76.6, or76.7, the designated representative maysubmit a request and the permittingauthority may grant, by administra-tive amendment under § 72.83 of thischapter, an extension of the dem-onstration period for such period oftime (not to exceed 12 months) as maybe necessary to implement such modi-fications or upgrades.

(C) If the approved interim alter-native emission limitation applies to aunit for part, but not all, of a calendaryear, the unit shall determine compli-ance for the calendar year in accord-ance with the procedures in § 76.13(a).

(ii) Operating requirements. (A) A unitwith an approved alternative emissionlimitation demonstration period shallbe operated under load dispatch condi-tions consistent with the operatingconditions upon which the design ofthe NOX emission control system andperformance guarantee were based, andin accordance with the demonstrationperiod plan.

(B) A unit with an approved alter-native emission limitation demonstra-tion period shall install all NOX emis-sion control systems, make any oper-ational modifications, and completeany upgrades and maintenance toequipment specified in the approved


445


demonstration period plan for opti-mizing NOX emission reduction per-formance.

(C) When the owner or operator iden-tifies boiler or NOX emission controlsystem operating modifications thatwould produce higher NOX emission re-ductions, enabling the affected unit tocomply with, or bring its emission ratecloser to, the applicable emission limi-tation under § 76.5, 76.6, or 76.7, the des-ignated representative shall submit anadministrative amendment under§ 72.83 of this chapter to revise theunit’s Acid Rain permit and dem-onstration period plan to include suchmodifications.

(iii) Testing requirements. A unit withan approved alternative emission limi-tation demonstration period shall mon-itor in accordance with part 75 of thischapter and shall conduct all tests re-quired under the approved demonstra-tion period plan.

(2) Final alternative emission limita-tion—(i) Emission limitations. (A) Eachunit with an approved alternativeemission limitation shall comply withthe alternative emission limitationspecified in the unit’s permit beginningon the date specified in the permit asissued or revised by the permitting au-thority to apply the final alternativeemission limitation.

(B) If the approved interim or finalalternative emission limitation appliesto a unit for part, but not all, of a cal-endar year, the unit shall determinecompliance for the calendar year in ac-cordance with the procedures in§ 76.13(a).


§ 76.11 Emissions averaging.(a) General provisions. In lieu of com-

plying with the applicable emissionlimitation in § 76.5, 76.6, or 76.7, any af-fected units subject to such emissionlimitation, under control of the sameowner or operator, and having thesame designated representative mayaverage their NOX emissions under anaveraging plan approved under this sec-tion.

(1) Each affected unit included in anaveraging plan for Phase I shall be a

Phase I unit with a Group 1 boiler sub-ject to an emission limitation in § 76.5during all years for which the unit isincluded in the plan.

(i) If a unit with an approved NOX

compliance extension is included in anaveraging plan for 1996, the unit shallbe treated, for the purposes of applyingEquation 1 in paragraph (a)(6) of thissection and Equation 2 in paragraph(d)(1)(ii)(A) of this section, as subjectto the applicable emissions limitationunder § 76.5 for the entire year 1996.

(ii) A Phase II unit approved for earlyelection under § 76.8 shall not be in-cluded in an averaging plan for Phase I.

(2) Each affected unit included in anaveraging plan for Phase II shall be aboiler subject to an emission limita-tion in § 76.5, 76.6, or 76.7 for all yearsfor which the unit is included in theplan.

(3) Each unit included in an aver-aging plan shall have an alternativecontemporaneous annual emission lim-itation (lb/mmBtu) and can only be in-cluded in one averaging plan.

(4) Each unit included in an aver-aging plan shall have a minimum al-lowable annual heat input value(mmBtu), if it has an alternative con-temporaneous annual emission limita-tion more stringent than that unit’sapplicable emission limitation under§ 76.5, 76.6, or 76.7, and a maximum al-lowable annual heat input value, if ithas an alternative contemporaneousannual emission limitation less strin-gent than that unit’s applicable emis-sion limitation under § 76.5, 76.6, or 76.7.

(5) The Btu-weighted annual averageemission rate for the units in an aver-aging plan shall be less than or equalto the Btu-weighted annual averageemission rate for the same units hadthey each been operated, during thesame period of time, in compliancewith the applicable emission limita-tions in § 76.5, 76.6, or 76.7.

(6) In order to demonstrate that theproposed plan is consistent with para-graph (a)(5) of this section, the alter-native contemporaneous annual emis-sion limitations and annual heat inputvalues assigned to the units in the pro-posed averaging plan shall meet thefollowing requirement:


446

40 CFR Ch. I (7–1–00 Edition)§ 76.11

R HI

HI

R HI

HI

Li ii

n

ii

n

li ii

n

ii

n

×( )≤

×( )( )=

=

=

=

∑

∑

∑

∑1

1

1

1

Equation 1

where:

RLi = Alternative contemporaneous annualemission limitation for unit i, lb/mmBtu,as specified in the averaging plan;

Rli = Applicable emission limitation for uniti, lb/mmBtu, as specified in § 76.5, 76.6, or76.7 except that for early election units,which may be included in an averagingplan only on or after January 1, 2000, Rli

shall equal the most stringent applicableemission limitation under § 76.5 or 76.7;

HIi = Annual heat input for unit i, mmBtu,as specified in the averaging plan;

n = Number of units in the averaging plan.

(7) For units with an alternativeemission limitation, Rli shall equal theapplicable emissions limitation under§ 76.5, 76.6, or 76.7, not the alternativeemissions limitation.

(8) No unit may be included in morethan one averaging plan.

(b)(1) Submission requirements. Thedesignated representative of a unitmeeting the requirements of para-graphs (a)(1), (a)(2), and (a)(8) of thissection may submit an averaging plan(or a revision to an approved averagingplan) to the permitting authority(ies)at any time up to and including Janu-ary 1 (or July 1, if the plan is restrictedto units located within a single permit-ting authority’s jurisdiction) of thecalendar year for which the averagingplan is to become effective.

(2) The designated representativeshall submit a copy of the same aver-aging plan (or the same revision to anapproved averaging plan) to each per-mitting authority with jurisdictionover a unit in the plan.

(3) When an averaging plan (or a revi-sion to an approved averaging plan) isnot approved, the owner or operator ofeach unit in the plan shall operate theunit in compliance with the emissionlimitation that would apply in the ab-sence of the averaging plan (or revisionto a plan).

(c) Contents of NOX averaging plan. Acomplete NOX averaging plan shall in-

clude the following elements in a for-mat prescribed by the Administrator:

(1) Identification of each unit in theplan;

(2) Each unit’s applicable emissionlimitation in § 76.5, 76.6, or 76.7;

(3) The alternative contemporaneousannual emission limitation for eachunit (in lb/mmBtu). If any of the unitsidentified in the NOX averaging planutilize a common stack pursuant to§ 75.17(a)(2)(i)(B) of this chapter, thesame alternative contemporaneousemission limitation shall be assignedto each such unit and different heatinput limits may be assigned;

(4) The annual heat input limit foreach unit (in mmBtu);

(5) The calculation for Equation 1 inparagraph (a)(6) of this section;

(6) The calendar years for which theplan will be in effect; and

(7) The special provisions in para-graph (d)(1) of this section.

(d) Special provisions. (1) Emission limi-tations. Each affected unit in an ap-proved averaging plan is in compliancewith the Acid Rain emission limitationfor NOX under the plan only if the fol-lowing requirements are met:

(i) For each unit, the unit’s actualannual average emission rate for thecalendar year, in lb/mmBtu, is lessthan or equal to its alternative con-temporaneous annual emission limita-tion in the averaging plan; and

(A) For each unit with an alternativecontemporaneous emission limitationless stringent than the applicable emis-sion limitation in § 76.5, 76.6, or 76.7, theactual annual heat input for the cal-endar year does not exceed the annualheat input limit in the averaging plan;

(B) For each unit with an alternativecontemporaneous annual emission lim-itation more stringent than the appli-cable emission limitation in § 76.5, 76.6,or 76.7, the actual annual heat input forthecalendar year is not less than the


447


annual heat input limit in the aver-aging plan; or

(ii) If one or more of the units doesnot meet the requirements under para-graph (d)(1)(i) of this section, the des-ignated representative shall dem-onstrate, in accordance with paragraph(d)(1)(ii)(A) of this section (Equation 2)that the actual Btu-weighted annualaverage emission rate for the units in

the plan is less than or equal to theBtu-weighted annual average rate forthe same units had they each been op-erated, during the same period of time,in compliance with the applicableemission limitations in § 76.5, 76.6, or76.7.

(A) A group showing of complianceshall be made based on the followingequation:

R HI

HI

R HI

HI

Equation 2ai ai

i

n

aii

n

li aii

n

aii

n

×( )≤

×( )( )=

=

=

=

∑

∑

∑

∑1

1

1

1

where:

Rai = Actual annual average emission rate forunit i, lb/mmBtu, as determined using theprocedures in part 75 of this chapter. Forunits in an averaging plan utilizing a com-mon stack pursuant to § 75.17(a)(2)(i)(B) ofthis chapter, use the same NOX emissionrate value for each unit utilizing the com-mon stack, and calculate this value in ac-cordance with appendix F to part 75 of thischapter;

Rli = Applicable annual emission limitationfor unit i lb/mmBtu, as specified in § 76.5,76.6, or 76.7, except that for early electionunits, which may be included in an aver-aging plan only on or after January 1, 2000,Rli shall equal the most stringent applica-ble emission limitation under § 76.5 or 76.7;

HIai = Actual annual heat input for unit i,mmBtu, as determined using the proce-dures in part 75 of this chapter;


(B) For units with an alternativeemission limitation, Rli shall equal theapplicable emission limitation under§ 76.5, 76.6, or 76.7, not the alternativeemission limitation.

(C) If there is a successful groupshowing of compliance under paragraph(d)(1)(ii)(A) of this section for a cal-endar year, then all units in the aver-aging plan shall be deemed to be incompliance for that year with their al-ternative contemporaneous emissionlimitations and annual heat input lim-its under paragraph (d)(1)(i) of this sec-tion.

(2) Liability. The owners and opera-tors of a unit governed by an approved

averaging plan shall be liable for anyviolation of the plan or this section atthat unit or any other unit in the plan,including liability for fulfilling the ob-ligations specified in part 77 of thischapter and sections 113 and 411 of theAct.

(3) Withdrawal or termination. The des-ignated representative may submit anotification to terminate an approvedaveraging plan in accordance with§ 72.40(d) of this chapter, no later thanOctober 1 of the calendar year forwhich the plan is to be withdrawn orterminated.

§ 76.12 Phase I NOX compliance exten-sion.

(a) General provisions. (1) The des-ignated representative of a Phase Iunit with a Group 1 boiler may applyfor and receive a 15-month extension ofthe deadline for meeting the applicableemissions limitation under § 76.5 whereit is demonstrated, to the satisfactionof the Administrator, that:

(i) The low NOX burner technologydesigned to meet the applicable emis-sion limitation is not in adequate sup-ply to enable installation and oper-ation at the unit, consistent with sys-tem reliability, by January 1, 1995 andthe reliability problems are due sub-stantially to NOX emission control sys-tem installation and availability; or

(ii) The unit is participating in an ap-proved clean coal technology dem-onstration project.


448

40 CFR Ch. I (7–1–00 Edition)§ 76.12

(2) In order to obtain a Phase I NOX

compliance extension, the designatedrepresentative shall submit a Phase INOX compliance extension plan by Oc-tober 1, 1994.

(b) Contents of Phase I NOX complianceextension plan. A complete Phase I NOX

compliance extension plan shall in-clude the following elements in a for-mat prescribed by the Administrator:

(1) Identification of the unit.(2) For units applying pursuant to

paragraph (a)(1)(i) of this section:(i) A list of the company names, ad-

dresses, and telephone numbers of ven-dors who are qualified to provide theservices and low NOX burner tech-nology designed to meet the applicableemission limitation under § 76.5 andhave been contacted to obtain the re-quired services and technology. Thelist shall include the dates of contact,and a copy of each request for bidsshall be submitted, along with anyother information necessary to show agood-faith effort to obtain the requiredservices and technology necessary tomeet the requirements of this part onor before January 1, 1995.

(ii) A copy of those portions of a le-gally binding contract with a qualifiedvendor that demonstrate that servicesand low NOX burner technology de-signed to meet the applicable emissionlimitation under § 76.5, with a comple-tion date not later than December 31,1995 have been contracted for.

(iii) Scheduling information, includ-ing justification and test schedules.

(iv) To demonstrate, if applicable,that the supply of the low NOX burnertechnology designed to meet the appli-cable emission limitation under § 76.5 isinadequate to enable its installationand operation at the unit, consistentwith system reliability, in time for theunit to comply with the applicableemission limitation on or before Janu-ary 1, 1995, either:

(A) Certification from the selectedvendor(s) (by a certifying official) list-ed in paragraph (b)(2)(i) of this sectionstating that they cannot provide thenecessary services and install the lowNOX burner technology on or beforeJanuary 1, 1995 and explaining the rea-sons why the services cannot be pro-vided and why the equipment cannot beinstalled in a timely manner; or

(B) The following information:(i) Standard load forecasts, based on

standard forecasting models availablethroughout the utility industry and ap-plied to the period, January 1, 1993,through December 31, 1994.

(ii) Specific reasons why an outagecannot be scheduled to enable the unitto install and operate the low NOX

burner technology by January 1, 1995,including reasons why no other unitscan be used to replace this unit’s gen-eration during such outage.

(iii) Fuel and energy balance sum-maries and power and other consump-tion requirements (including those forair, steam, and cooling water).

(3) To demonstrate, if applicable, par-ticipation in an approved clean coaltechnology demonstration project, adescription of the project, including allsources of Federal, State, and otheroutside funding, amount and date forapproval of Federal funding, the dura-tion of the project, and the anticipatedcompletion date of the project.

(4) The special provisions in para-graph (d) of this section.

(c)(1) Administrator’s action. To theextent the Administrator determinesthat a Phase I NOX compliance exten-sion plan complies with the require-ments of this section, the Adminis-trator will approve the plan and revisethe Acid Rain permit governing theunit in the plan in order to incorporatethe plan by administrative amendmentunder § 72.83 of this chapter, exceptthat the Administrator shall have 90days from receipt of the compliance ex-tension plan to take final action.

(2) The Administrator will approve ordisapprove a proposed NOX complianceextension plan within 3 months of re-ceipt.

(d) Special provisions. (1) Emissionlimitations. The unit shall complywith the applicable emission limitationunder § 76.5 beginning April 1, 1996.Compliance shall be determined asspecified in part 75 of this chapterusing measured values of NOX emis-sions and heat input only for the por-tion of the year that the emission limitis in effect.

(2) If a unit with an approved NOX

compliance extension is included in anaveraging plan under § 76.11 for year


449


1996, the unit shall be treated, for pur-poses of applying Equation 1 in§ 76.11(a)(6) and Equation 2 in§ 76.11(d)(1)(ii)(A), as subject to the ap-plicable emission limitation under§ 76.5 for the entire year 1996.

(e) Extension until December 31, 1997.(1) The designated representative of aPhase I unit that is subject to section404(d) of the Act, has a tangentiallyfired boiler, and is unable to install lowNOX burner technology by January 1,1997 may submit a petition for and re-ceive an extension for meeting the ap-plicable emission limitation under§ 76.5 where it is demonstrated, to thesatisfaction of the Administrator, that:

(i) The unit is located at a sourcewith two or more other units, all ofwhich are Phase I units that are sub-ject to section 404(d) of the Act andhave tangentially fired boilers;

(ii) The NOX control system at theunit was scheduled to be installed byJanuary 1, 1997 and, because of oper-ational problems associated with theNOX control system, will be redesigned;and

(iii) Installation of the redesignedlow NOX burner technology at the unitcannot be completed by January 1, 1997without causing system reliabilityproblems.

(2) A complete petition shall includethe following elements and shall besubmitted by April 28, 1995.

(i) Identification of the unit and theother units at the source;

(ii) A statement describing how therequirements of paragraphs (e)(1)(ii)and (e)(1)(iii) of this section are met;

(iii) The earliest date, not later thanDecember 31, 1997, by which installa-tion of the redesigned low NOX burnertechnology can be completed con-sistent with system reliability; and

(iv) The provisions in paragraph (e)(4)of this section.

(3) To the extent the Administratordetermines that a Phase I unit meetsthe requirements of paragraphs (e)(1)and (e)(2) of this section, the Adminis-trator will approve the petition within90 days from receipt of the completepetition. The Acid Rain permit gov-erning the unit will be revised in orderto incorporate the approved extension,which shall terminate no later thanDecember 31, 1997, by administrative

amendment under § 72.83 of this chapterexcept that the Administrator willhave 90 days to take final action.

(4) The unit shall comply with theapplicable emission limitation under§ 76.5 beginning on the day immediatelyfollowing the day on which the exten-sion approved under paragraph (e)(3) ofthis section terminates. Complianceshall be determined as specified in part75 of this chapter using measured val-ues of NOX emissions and heat inputonly for the portion of the year thatthe emission limit is in effect. If a unitwith an approved extension is includedin an averaging plan under § 76.11 foryear 1997, the unit shall be treated, forthe purpose of applying Equation 1 in§ 76.11(a)(6) and Equation 2 in§ 76.11(d)(1)(ii)(A), as subject to the ap-plicable emission limitation under§ 76.5 for the entire year 1997.

§ 76.13 Compliance and excess emis-sions.

Excess emissions of nitrogen oxidesunder § 77.6 of this chapter shall be cal-culated as follows:

(a) For a unit that is not in an ap-proved averaging plan:

(1) Calculate EEi for each portion ofthe calendar year that the unit is sub-ject to a different NOX emission limita-tion:

EER R HI

Equation 3iai li i=

−( ) × ( )2000

where:

EEi = Excess emissions for NOX for the por-tion of the calendar year (in tons);

Rai = Actual average emission rate for theunit (in lb/mmBtu), determined accordingto part 75 of this chapter for the portion ofthe calendar year for which the applicableemission limitation Rl is in effect;

Rli = Applicable emission limitation for theunit, (in lb/mmBtu), as specified in § 76.5,76.6, or 76.7 or as determined under § 76.10;

EE EE Equationii

n

= ( )=∑

1

4

HIi = Actual heat input for the unit, (inmmBtu), determined according to part 75of this chapter for the portion of the cal-endar year for which the applicable emis-sion limitation, Rl, is in effect.


450

40 CFR Ch. I (7–1–00 Edition)§ 76.14

(2) If EEi is a negative number forany portion of the calendar year, theEE value for that portion of the cal-endar year shall be equal to zero (e.g.,if EEi = ¥100, then EEi = 0).

(3) Sum all EEi values for the cal-endar year:

where:

EE = Excess emissions for NOX for the year(in tons);

n = The number of time periods during whicha unit is subject to different emission limi-tations; and

(b) For units participating in an ap-proved averaging plan, when all the re-quirements under § 76.11(d)(1) are notmet,

EE

R HI R HI

Equationai i li i

i

n

i

n

=×( ) − ×( )

( )==∑∑

11

20005

where:EE = Excess emissions for NOX for the year

(in tons);Rai = Actual annual average emission rate for

NOX for unit i, (in lb/mmBtu), determinedaccording to part 75 of this chapter;

Rli = Applicable emission limitation for uniti, (in lb/mmBtu), as specified in § 76.5, 76.6,or 76.7;

HIi = Actual annual heat input for unit i,mmBtu, determined according to part 75 ofthis chapter;


§ 76.14 Monitoring, recordkeeping, andreporting.

(a) A petition for an alternativeemission limitation demonstration pe-riod under § 76.10(d) shall include thefollowing information:

(1) In accordance with § 76.10(d)(4),the following information:

(i) Documentation that the owner oroperator solicited bids for a NOX emis-sion control system designed for appli-cation to the specific boiler and de-signed to achieve the applicable emis-sion limitation in § 76.5, 76.6, or 76.7 onan annual average basis. This docu-mentation must include a copy of allbid specifications.

(ii) A copy of the performance guar-antee submitted by the vendor of theinstalled NOX emission control systemto the owner or operator showing thatsuch system was designed to meet theapplicable emission limitation in § 76.5,76.6, or 76.7 on an annual average basis.

(iii) Documentation describing theoperational and combustion conditionsthat are the basis of the performanceguarantee.

(iv) Certification by the primary ven-dor of the NOX emission control systemthat such equipment and associatedauxiliary equipment was properly in-stalled according to the modificationsand procedures specified by the vendor.

(v) Certification by the designatedrepresentative that the owner(s) or op-erator installed technology that meetsthe requirements of § 76.10(a)(2).

(2) In accordance with § 76.10(d)(9),the following information:

(i) The operating conditions of theNOX emission control system includingload range, O2 range, coal volatile mat-ter range, and, for tangentially firedboilers, distribution of combustion airwithin the NOX emission control sys-tem;

(ii) Certification by the designatedrepresentative that the owner(s) or op-erator have achieved and are followingthe operating conditions, boiler modi-fications, and upgrades that formed thebasis for the system design and per-formance guarantee;

(iii) Any planned equipment modi-fications and upgrades for the purposeof achieving the maximum NOX reduc-tion performance of the NOX emissioncontrol system that were not includedin the design specifications and per-formance guarantee, but that wereachieved prior to submission of this ap-plication and are being followed;

(iv) A list of any modifications or re-placements of equipment that are to bedone prior to the completion of thedemonstration period for the purposeof reducing emissions of NOX; and


451


(v) The parametric testing that willbe conducted to determine the reasonor reasons for the failure of the unit toachieve the applicable emission limita-tion and to verify the proper operationof the installed NOX emission controlsystem during the demonstration pe-riod. The tests shall include tests in§ 76.15, which may be modified as fol-lows:

(A) The owner or operator of the unitmay add tests to those listed in § 76.15,if such additions provide data relevantto the failure of the installed NOX

emission control system to meet theapplicable emissions limitation in§ 76.5, 76.6, or 76.7; or

(B) The owner or operator of the unitmay remove tests listed in § 76.15 thatare shown, to the satisfaction of thepermitting authority, not to be rel-evant to NOX emissions from the af-fected unit; and

(C) In the event the performanceguarantee or the NOX emission controlsystem specifications require addi-tional tests not listed in § 76.15, orspecify operating conditions notverified by tests listed in § 76.15, theowner or operator of the unit shall in-clude such additional tests.

(3) In accordance with § 76.10(d)(10),the following information for the oper-ating period:

(i) The average NOX emission rate (inlb/mmBtu) of the specific unit;

(ii) The highest hourly NOX emissionrate (in lb/mmBtu) of the specific unit;

(iii) Hourly NOX emission rate (in lb/mmBtu), calculated in accordance withpart 75 of this chapter;

(iv) Total heat input (in mmBtu) forthe unit for each hour of operation,calculated in accordance with the re-quirements of part 75 of this chapter;and

(v) Total integrated hourly gross unitload (in MWge).

(b) A petition for an alternativeemission limitation shall include thefollowing information in accordancewith § 76.10(e)(6).

(1) Total heat input (in mmBtu) forthe unit for each hour of operation,calculated in accordance with the re-quirements of part 75 of this chapter;

(2) Hourly NOX emission rate (in lb/mmBtu), calculated in accordance with

the requirements of part 75 of thischapter; and

(3) Total integrated hourly gross unitload (MWge).

(c) Reporting of the costs of low NOX

burner technology applied to Group 1,Phase I boilers. (1) Except as provided inparagraph (c)(2) of this section, the des-ignated representative of a Phase Iunit with a Group 1 boiler that has in-stalled or is installing any form of lowNOX burner technology shall submit tothe Administrator a report containingthe capital cost, operating cost, andbaseline and post-retrofit emissiondata specified in appendix B to thispart. If any of the required equipment,cost, and schedule information are notavailable (e.g., the retrofit project isstill underway), the designated rep-resentative shall include in the reportdetailed cost estimates and other pro-jected or estimated data in lieu of theinformation that is not available.

(2) The report under paragraph (c)(1)of this section is not required with re-gard to the following types of Group 1,Phase I units:

(i) Units employing no new NOX emis-sion control system after November 15,1990;

(ii) Units employing modifications toboiler operating parameters (e.g., burn-ers out of service or fuel switching)without low NOX burners or otheremission reduction equipment for re-ducing NOX emissions;

(iii) Units with wall-fired boilers em-ploying only overfire air and units withtangentially fired boilers employingonly separated overfire air; or

(iv) Units beginning installation of anew NOX emission control system afterAugust 11, 1995.

(3) The report under paragraph (c)(1)of this section shall be submitted tothe Administrator by:

(i) 120 days after completion of thelow NOX burner technology retrofitproject; or

(ii) May 23, 1995, if the project wascompleted on or before January 23,1995.

§ 76.15 Test methods and procedures.

(a) The owner or operator may usethe following tests as a basis for the re-port required by § 76.10(e)(7):


452

40 CFR Ch. I (7–1–00 Edition)Pt. 76, App. A

(1) Conduct an ultimate analysis ofcoal using ASTM D 3176–89 (incor-porated by reference as specified in§ 76.4);

(2) Conduct a proximate analysis ofcoal using ASTM D 3172–89 (incor-porated by reference as specified in§ 76.4); and

(3) Measure the coal mass flow rateto each individual burner using ASMEPower Test Code 4.2 (1991), ‘‘Test Codefor Coal Pulverizers’’ or ISO 9931 (1991),‘‘Coal—Sampling of Pulverized CoalConveyed by Gases in Direct Fired CoalSystems’’ (incorporated by reference asspecified in § 76.4).

(b) The owner or operator may meas-ure and record the actual NOX emissionrate in accordance with the require-ments of this part while varying thefollowing parameters where possible todetermine their effects on the emis-sions of NOX from the affected boiler:

(1) Excess air levels;(2) Settings of burners or coal and air

nozzles, including tilt and yaw, orswirl;

(3) For tangentially fired boilers, dis-tribution of combustion air within theNOX emission control system;

(4) Coal mass flow rates to each indi-vidual burner;

(5) Coal-to-primary air ratio (basedon pound per hour) for each burner, theaverage coal-to-primary air ratio forall burners, and the deviations of indi-vidual burners’ coal-to-primary air ra-tios from the average value; and

(6) If the boiler uses varying types ofcoal, the type of coal. Provide the re-sults of proximate and ultimate anal-yses of each type of as-fired coal.

(c) In performing the tests specifiedin paragraph (a) of this section, theowner or operator shall begin the testsusing the equipment settings for whichthe NOX emission control system wasdesigned to meet the NOX emission rateguaranteed by the primary NOX emis-sion control system vendor. These re-sults constitute the ‘‘baseline con-trolled’’ condition.

(d) After establishing the baselinecontrolled condition under paragraph(c) of this section, the owner or oper-ator may:

(1) Change excess air levels ± 5 per-cent from the baseline controlled con-dition to determine the effects onemissions of NOX, by providing a min-imum of three readings (e.g., with abaseline reading of 20 percent excessair, excess air levels will be changed to19 percent and 21 percent);

(2) For tangentially fired boilers,change the distribution of combustionair within the NOX emission controlsystem to determine the effects on NOX

emissions by providing a minimum ofthree readings, one with the minimum,one with the baseline, and one with themaximum amounts of staged combus-tion air; and

(3) Show that the combustion processwithin the boiler is optimized (e.g.,that the burners are balanced).

APPENDIX A TO PART 76—PHASE I AFFECTED COAL-FIRED UTILITY UNITS WITHGROUP 1 OR CELL BURNER BOILERS

TABLE 1—PHASE I TANGENTIALLY FIRED UNITS

State Plant Unit Operator

ALABAMA ...................................... EC GASTON ............................. 5 ALABAMA POWER CO.GEORGIA ....................................... BOWEN ..................................... 1BLR GEORGIA POWER CO.GEORGIA ....................................... BOWEN ..................................... 2BLR GEORGIA POWER CO.GEORGIA ....................................... BOWEN ..................................... 3BLR GEORGIA POWER CO.GEORGIA ....................................... BOWEN ..................................... 4BLR GEORGIA POWER CO.GEORGIA ....................................... JACK MCDONOUGH ............... MB1 GEORGIA POWER CO.GEORGIA ....................................... JACK MCDONOUGH ............... MB2 GEORGIA POWER CO.GEORGIA ....................................... WANSLEY ................................. 1 GEORGIA POWER CO.GEORGIA ....................................... WANSLEY ................................. 2 GEORGIA POWER CO.GEORGIA ....................................... YATES ...................................... Y1BR GEORGIA POWER CO.GEORGIA ....................................... YATES ...................................... Y2BR GEORGIA POWER CO.GEORGIA ....................................... YATES ...................................... Y3BR GEORGIA POWER CO.GEORGIA ....................................... YATES ...................................... Y4BR GEORGIA POWER CO.GEORGIA ....................................... YATES ...................................... Y5BR GEORGIA POWER CO.GEORGIA ....................................... YATES ...................................... Y6BR GEORGIA POWER CO.GEORGIA ....................................... YATES ...................................... Y7BR GEORGIA POWER CO.ILLINOIS ......................................... BALDWIN .................................. 3 ILLINOIS POWER CO.ILLINOIS ......................................... HENNEPIN ................................ 2 ILLINOIS POWER CO.ILLINOIS ......................................... JOPPA ...................................... 1 ELECTRIC ENERGY INC.


453

Environmental Protection Agency Pt. 76, App. A

TABLE 1—PHASE I TANGENTIALLY FIRED UNITS—Continued


ILLINOIS ......................................... JOPPA ...................................... 2 ELECTRIC ENERGY INC.ILLINOIS ......................................... JOPPA ...................................... 3 ELECTRIC ENERGY INC.ILLINOIS ......................................... JOPPA ...................................... 4 ELECTRIC ENERGY INC.ILLINOIS ......................................... JOPPA ...................................... 5 ELECTRIC ENERGY INC.ILLINOIS ......................................... JOPPA ...................................... 6 ELECTRIC ENERGY INC.ILLINOIS ......................................... MEREDOSIA ............................. 5 CEN ILLINOIS PUB SER.ILLINOIS ......................................... VERMILION .............................. 2 ILLINOIS POWER CO.INDIANA ......................................... CAYUGA ................................... 1 PSI ENERGY INC.INDIANA ......................................... CAYUGA ................................... 2 PSI ENERGY INC.INDIANA ......................................... EW STOUT ............................... 50 INDIANAPOLIS PWR & LT.INDIANA ......................................... EW STOUT ............................... 60 INDIANAPOLIS PWR & LT.INDIANA ......................................... EW STOUT ............................... 70 INDIANAPOLIS PRW & LT.INDIANA ......................................... HT PRITCHARD ....................... 6 INDIANAPOLIS PWR & LT.INDIANA ......................................... PETERSBURG ......................... 1 INDIANAPOLIS PWR & LT.INDIANA ......................................... PETERSBURG ......................... 2 INDIANAPOLIS PWR & LT.INDIANA ......................................... WABASH RIVER ...................... 6 PSI ENERGY INC.IOWA .............................................. BURLINGTON ........................... 1 IOWA SOUTHERN UTL.IOWA .............................................. ML KAPP .................................. 2 INTERSTATE POWER CO.IOWA .............................................. RIVERSIDE ............................... 9 IOWA-ILL GAS & ELEC.KENTUCKY .................................... ELMER SMITH ......................... 2 OWENSBORO MUN UTIL.KENTUCKY .................................... EW BROWN ............................. 2 KENTUCKY UTL CO.KENTUCKY .................................... EW BROWN ............................. 3 KENTUCKY UTL CO.KENTUCKY .................................... GHENT ...................................... 1 KENTUCKY UTL CO.MARYLAND ................................... MORGANTOWN ....................... 1 POTOMAC ELEC PWR CO.MARYLAND ................................... MORGANTOWN ....................... 2 POTOMAC ELEC PWR CO.MICHIGAN ..................................... JH CAMPBELL ......................... 1 CONSUMERS POWER CO.MISSOURI ...................................... LABADIE ................................... 1 UNION ELECTRIC CO.MISSOURI ...................................... LABADIE ................................... 2 UNION ELECTRIC CO.MISSOURI ...................................... LABADIE ................................... 3 UNION ELECTRIC CO.MISSOURI ...................................... LABADIE ................................... 4 UNION ELECTRIC CO.MISSOURI ...................................... MONTROSE ............................. 1 KANSAS CITY PWR & LT.MISSOURI ...................................... MONTROSE ............................. 2 KANSAS CITY PWR & LT.MISSOURI ...................................... MONTROSE ............................. 3 KANSAS CITY PWR & LT.NEW YORK .................................... DUNKIRK .................................. 3 NIAGARA MOHAWK PWR.NEW YORK .................................... DUNKIRK .................................. 4 NIAGARA MOHAWK PWR.NEW YORK .................................... GREENIDGE ............................. 6 NY STATE ELEC & GAS.NEW YORK .................................... MILLIKEN .................................. 1 NY STATE ELEC & GAS.NEW YORK .................................... MILLIKEN .................................. 2 NY STATE ELEC & GAS.OHIO .............................................. ASHTABULA ............................. 7 CLEVELAND ELEC ILLUM.OHIO .............................................. AVON LAKE .............................. 11 CLEVELAND ELEC ILLUM.OHIO .............................................. CONESVILLE ............................ 4 COLUMBUS STHERN PWR.OHIO .............................................. EASTLAKE ................................ 1 CLEVELAND ELEC ILLUM.OHIO .............................................. EASTLAKE ................................ 2 CLEVELAND ELEC ILLUM.OHIO .............................................. EASTLAKE ................................ 3 CLEVELAND ELEC ILLUM.OHIO .............................................. EASTLAKE ................................ 4 CLEVELAND ELEC ILLUM.OHIO .............................................. MIAMI FORT ............................. 6 CINCINNATI GAS & ELEC.OHIO .............................................. WC BECKJORD ....................... 5 CINCINNATI GAS & ELEC.OHIO .............................................. WC BECKJORD ....................... 6 CINCINNATI GAS & ELEC.PENNSYLVANIA ............................ BRUNNER ISLAND .................. 1 PENNSYLVANIA PWR & LT.PENNSYLVANIA ............................ BRUNNER ISLAND .................. 2 PENNSYLVANIA PWR & LT.PENNSYLVANIA ............................ BRUNNER ISLAND .................. 3 PENNSYLVANIA PWR & LT.PENNSYLVANIA ............................ CHESWICK ............................... 1 DUQUESNE LIGHT CO.PENNSYLVANIA ............................ CONEMAUGH .......................... 1 PENNSYLVANIA ELEC CO.PENNSYLVANIA ............................ CONEMAUGH .......................... 2 PENNSYLVANIA ELEC CO.PENNSYLVANIA ............................ PORTLAND ............................... 1 METROPOLITAN EDISON.PENNSYLVANIA ............................ PORTLAND ............................... 2 METROPOLITAN EDISON.PENNSYLVANIA ............................ SHAWVILLE .............................. 3 PENNSYLVANIA ELEC CO.PENNSYLVANIA ............................ SHAWVILLE .............................. 4 PENNSYLVANIA ELEC CO.TENNESSEE .................................. GALLATIN ................................. 1 TENNESSEE VAL AUTH.TENNESSEE .................................. GALLATIN ................................. 2 TENNESSEE VAL AUTH.TENNESSEE .................................. GALLATIN ................................. 3 TENNESSEE VAL AUTH.TENNESSEE .................................. GALLATIN ................................. 4 TENNESSEE VAL AUTH.TENNESSEE .................................. JOHNSONVILLE ....................... 1 TENNESSEE VAL AUTH.TENNESSEE .................................. JOHNSONVILLE ....................... 2 TENNESSEE VAL AUTH.TENNESSEE .................................. JOHNSONVILLE ....................... 3 TENNESSEE VAL AUTH.TENNESSEE .................................. JOHNSONVILLE ....................... 4 TENNESSEE VAL AUTH.TENNESSEE .................................. JOHNSONVILLE ....................... 5 TENNESSEE VAL AUTH.TENNESSEE .................................. JOHNSONVILLE ....................... 6 TENNESSEE VAL AUTH.WEST VIRGINIA ............................ ALBRIGHT ................................ 3 MONONGAHELA POWER CO.WEST VIRGINIA ............................ FORT MARTIN ......................... 1 MONONGAHELA POWER CO.WEST VIRGINIA ............................ MOUNT STORM ....................... 1 VIRGINIA ELEC & PWR.WEST VIRGINIA ............................ MOUNT STORM ....................... 2 VIRGINIA ELEC & PWR.


454

40 CFR Ch. I (7–1–00 Edition)Pt. 76, App. A

TABLE 1—PHASE I TANGENTIALLY FIRED UNITS—Continued


WEST VIRGINIA ............................ MOUNT STORM ....................... 3 VIRGINIA ELEC & PWR.WISCONSIN ................................... GENOA ..................................... 1 DAIRYLAND POWER COOP.WISCONSIN ................................... SOUTH OAK CREEK ............... 7 WISCONSIN ELEC POWER.WISCONSIN ................................... SOUTH OAK CREEK ............... 8 WISCONSIN ELEC POWER.

TABLE 2—PHASE I DRY BOTTOM-FIRED UNITS


ALABAMA ................................................. COLBERT ................................. 1 TENNESSEE VAL AUTH.ALABAMA ................................................. COLBERT ................................. 2 TENNESSEE VAL AUTH.ALABAMA ................................................. COLBERT ................................. 3 TENNESSEE VAL AUTH.ALABAMA ................................................. COLBERT ................................. 4 TENNESSEE VAL AUTH.ALABAMA ................................................. COLBERT ................................. 5 TENNESSEE VAL AUTH.ALABAMA ................................................. EC GASTON ............................. 1 ALABAMA POWER CO.ALABAMA ................................................. EC GASTON ............................. 2 ALABAMA POWER CO.ALABAMA ................................................. EC GASTON ............................. 3 ALABAMA POWER CO.ALABAMA ................................................. EC GASTON ............................. 4 ALABAMA POWER CO.FLORIDA ................................................... CRIST ....................................... 6 GULF POWER CO.FLORIDA ................................................... CRIST ....................................... 7 GULF POWER CO.GEORGIA ................................................. HAMMOND ............................... 1 GEORGIA POWER CO.GEORGIA ................................................. HAMMOND ............................... 2 GEORGIA POWER CO.GEORGIA ................................................. HAMMOND ............................... 3 GEORGIA POWER CO.GEORGIA ................................................. HAMMOND ............................... 4 GEORGIA POWER CO.ILLINOIS ................................................... GRAND TOWER ....................... 9 CEN ILLINOIS PUB SER.INDIANA .................................................... CULLEY .................................... 2 STHERN IND GAS & EL.INDIANA .................................................... CULLEY .................................... 3 STHERN IND GAS & EL.INDIANA .................................................... GIBSON .................................... 1 PSI ENERGY INC.INDIANA .................................................... GIBSON .................................... 2 PSI ENERGY INC.INDIANA .................................................... GIBSON .................................... 3 PSI ENERGY INC.INDIANA .................................................... GIBSON .................................... 4 PSI ENERGY INC.INDIANA .................................................... RA GALLAGHER ...................... 1 PSI ENERGY INC.INDIANA .................................................... RA GALLAGHER ...................... 2 PSI ENERGY INC.INDIANA .................................................... RA GALLAGHER ...................... 3 PSI ENERGY INC.INDIANA .................................................... RA GALLAGHER ...................... 4 PSI ENERGY INC.INDIANA .................................................... FRANK E RATTS ..................... 1SG1 HOOSIER ENERGY REC.INDIANA .................................................... FRANK E RATTS ..................... 2SG1 HOOSIER ENERGY REC.INDIANA .................................................... WABASH RIVER ...................... 1 PSI ENERGY INC.INDIANA .................................................... WABASH RIVER ...................... 2 PSI ENERGY INC.INDIANA .................................................... WABASH RIVER ...................... 3 PSI ENERGY INC.INDIANA .................................................... WABASH RIVER ...................... 5 PSI ENERGY INC.IOWA ......................................................... DES MOINES ........................... 11 IOWA PWR & LT CO.IOWA ......................................................... PRAIRIE CREEK ...................... 4 IOWA ELEC LT & PWR.KANSAS .................................................... QUINDARO ............................... 2 KS CITY BD PUB UTIL.KENTUCKY ............................................... COLEMAN ................................ C1 BIG RIVERS ELEC CORP.KENTUCKY ............................................... COLEMAN ................................ C2 BIG RIVERS ELEC CORP.KENTUCKY ............................................... COLEMAN ................................ C3 BIG RIVERS ELEC CORP.KENTUCKY ............................................... EW BROWN ............................. 1 KENTUCKY UTL CO.KENTUCKY ............................................... GREEN RIVER ......................... 5 KENTUCKY UTL CO.KENTUCKY ............................................... HMP&L STATION 2 .................. H1 BIG RIVERS ELEC CORP.KENTUCKY ............................................... HMP&L STATION 2 .................. H2 BIG RIVERS ELEC CORP.KENTUCKY ............................................... HL SPURLOCK ......................... 1 EAST KY PWR COOP.KENTUCKY ............................................... JS COOPER ............................. 1 EAST KY PWR COOP.KENTUCKY ............................................... JS COOPER ............................. 2 EAST KY PWR COOP.MARYLAND .............................................. CHALK POINT .......................... 1 POTOMAC ELEC PWR CO.MARYLAND .............................................. CHALK POINT .......................... 2 POTOMAC ELEC PWR CO.MINNESOTA ............................................. HIGH BRIDGE .......................... 6 NORTHERN STATES PWR.MISSISSIPPI ............................................. JACK WATSON ........................ 4 MISSISSIPPI PWR CO.MISSISSIPPI ............................................. JACK WATSON ........................ 5 MISSISSIPPI PWR CO.MISSOURI ................................................ JAMES RIVER .......................... 5 SPRINGFIELD UTL.OHIO ......................................................... CONESVILLE ............................ 3 COLUMBUS STHERN PWR.OHIO ......................................................... EDGEWATER ........................... 13 OHIO EDISON CO.OHIO ......................................................... MIAMI FORT 1 ........................... 5–1 CINCINNATI GAS&ELEC.OHIO ......................................................... MIAMI FORT 1 ........................... 5–2 CINCINNATI GAS&ELEC.OHIO ......................................................... PICWAY .................................... 9 COLUMBUS STHERN PWR.OHIO ......................................................... RE BURGER ............................. 7 OHIO EDISON CO.OHIO ......................................................... RE BURGER ............................. 8 OHIO EDISON CO.OHIO ......................................................... WH SAMMIS ............................. 5 OHIO EDISON CO.OHIO ......................................................... WH SAMMIS ............................. 6 OHIO EDISON CO.PENNSYLVANIA ....................................... ARMSTRONG ........................... 1 WEST PENN POWER CO.PENNSYLVANIA ....................................... ARMSTRONG ........................... 2 WEST PENN POWER CO.


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Environmental Protection Agency Pt. 76, App. B

TABLE 2—PHASE I DRY BOTTOM-FIRED UNITS—Continued


PENNSYLVANIA ....................................... MARTINS CREEK .................... 1 PENNSYLVANIA PWR & LT.PENNSYLVANIA ....................................... MARTINS CREEK .................... 2 PENNSYLVANIA PWR & LT.PENNSYLVANIA ....................................... SHAWVILLE .............................. 1 PENNSYLVANIA ELEC CO.PENNSYLVANIA ....................................... SHAWVILLE .............................. 2 PENNSYLVANIA ELEC CO.PENNSYLVANIA ....................................... SUNBURY ................................. 3 PENNSYLVANIA PWR & LT.PENNSYLVANIA ....................................... SUNBURY ................................. 4 PENNSYLVANIA PWR & LT.TENNESSEE ............................................ JOHNSONVILLE ....................... 7 TENNESSEE VAL AUTH.TENNESSEE ............................................ JOHNSONVILLE ....................... 8 TENNESSEE VAL AUTH.TENNESSEE ............................................ JOHNSONVILLE ....................... 9 TENNESSEE VAL AUTH.TENNESSEE ............................................ JOHNSONVILLE ....................... 10 TENNESSEE VAL AUTH.WEST VIRGINIA ....................................... HARRISON ............................... 1 MONONGAHELA POWER CO.WEST VIRGINIA ....................................... HARRISON ............................... 2 MONONGAHELA POWER CO.WEST VIRGINIA ....................................... HARRISON ............................... 3 MONONGAHELA POWER CO.WEST VIRGINIA ....................................... MITCHELL ................................ 1 OHIO POWER CO.WEST VIRGINIA ....................................... MITCHELL ................................ 2 OHIO POWER CO.WISCONSIN ............................................. JP PULLIAM ............................. 8 WISCONSIN PUB SER CO.WISCONSIN ............................................. NORTH OAK CREEK 2 ............. 1 WISCONSIN ELEC PWR.WISCONSIN ............................................. NORTH OAK CREEK 2 ............. 2 WISCONSIN ELEC PWR.WISCONSIN ............................................. NORTH OAK CREEK 2 ............. 3 WISCONSIN ELEC PWR.WISCONSIN ............................................. NORTH OAK CREEK 2 ............. 4 WISCONSIN ELEC PWR.WISCONSIN ............................................. SOUTH OAK CREEK 2 ............. 5 WISCONSIN ELEC PWR.WISCONSIN ............................................. SOUTH OAK CREEK 2 ............. 6 WISCONSIN ELEC PWR.

1 Vertically fired boiler.2 Arch-fired boiler.

TABLE 3—PHASE I CELL BURNER TECHNOLOGY UNITS


INDIANA .............................................. WARRICK ................................. 4 STHERN IND GAS & EL.MICHIGAN ........................................... JH CAMPBELL ......................... 2 CONSUMERS POWER CO.OHIO .................................................... AVON LAKE .............................. 12 CLEVELAND ELEC ILLUM.OHIO .................................................... CARDINAL ................................ 1 CARDINAL OPERATING.OHIO .................................................... CARDINAL ................................ 2 CARDINAL OPERATING.OHIO .................................................... EASTLAKE ................................ 5 CLEVELAND ELEC ILLUM.OHIO .................................................... GENRL JM GAVIN ................... 1 OHIO POWER CO.OHIO .................................................... GENRL JM GAVIN ................... 2 OHIO POWER CO.OHIO .................................................... MIAMI FORT ............................. 7 CINCINNATI GAS & EL.OHIO .................................................... MUSKINGUM RIVER ................ 5 OHIO POWER CO.OHIO .................................................... WH SAMMIS ............................. 7 OHIO EDISON CO.PENNSYLVANIA ................................. HATFIELDS FERRY ................. 1 WEST PENN POWER CO.PENNSYLVANIA ................................. HATFIELDS FERRY ................. 2 WEST PENN POWER CO.PENNSYLVANIA ................................. HATFIELDS FERRY ................. 3 WEST PENN POWER CO.TENNESSEE ....................................... CUMBERLAND ......................... 1 TENNESSEE VAL AUTH.TENNESSEE ....................................... CUMBERLAND ......................... 2 TENNESSEE VAL AUTH.WEST VIRGINIA .................................. FORT MARTIN ......................... 2 MONONGAHELA POWER CO.

APPENDIX B TO PART 76—PROCEDURESAND METHODS FOR ESTIMATINGCOSTS OF NITROGEN OXIDES CON-TROLS APPLIED TO GROUP 1, BOILERS

1. Purpose and Applicability

This technical appendix specifies the pro-cedures, methods, and data that the Admin-istrator will use in establishing ‘‘***the de-gree of reduction achievable through thisretrofit application of the best system ofcontinuous emission reduction, taking intoaccount available technology, costs, and en-ergy and environmental impacts; and whichis comparable to the costs of nitrogen oxidescontrols set pursuant to subsection (b)(1) (ofsection 407 of the Act).’’ In developing the al-lowable NOX emissions limitations for Group

2 boilers pursuant to subsection (b)(2) of sec-tion 407 of the Act, the Administrator willconsider only those systems of continuousemission reduction that, when applied on aretrofit basis, are comparable in cost to thecost in constant dollars of low NOX burnertechnology applied to Group 1, Phase I boil-ers.

The Administrator will evaluate the cap-ital cost (in dollars per kilowatt electrical ($/kW)), the operating and maintenance costs(in $/year), and the cost-effectiveness (inannualized $/ton NOX removed) of installedlow NOX burner technology controls over arange of boiler sizes (as measured by thegross electrical capacity of the associatedgenerator in megawatt electrical (MW)) andutilization rates (in percent gross nameplate


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40 CFR Ch. I (7–1–00 Edition)Pt. 76, App. B

capacity on an annual basis) to develop esti-mates of the capital costs and cost effective-ness for Group 1, Phase I boilers. The fol-lowing units will be excluded from these de-terminations of the capital costs and cost ef-fectiveness of NOX controls set pursuant tosubsection (b)(1) of section 407 of the Act: (1)Units employing an alternative technology,or overfire air as applied to wall-fired boilersor separated overfire air as applied to tan-gentially fired boilers, in lieu of low NOX

burner technology for reducing NOX emis-sions; (2) units employing no controls, onlycontrols installed before November 15, 1990,or only modifications to boiler operating pa-rameters (e.g., burners out of service or fuelswitching) for reducing NOX emissions; and(3) units that have not achieved the applica-ble emission limitation.

2. Average Capital Cost for Low NOX BurnerTechnology Applied to Group 1 Boilers

The Administrator will use the procedures,methods, and data specified in this section toestimate the average capital cost (in $/kW)of installed low NOX burner technology ap-plied to Group 1 boilers.

2.1 Using cost data submitted pursuant tothe reporting requirements in section 4below, boiler-specific actual or estimated ac-tual capital costs will be determined for eachunit in the population specified in section 1above for assessing the costs of installed lowNOX burner technology. The scope of in-stalled low NOX burner technology costs willinclude the following capital costs for ret-rofit application: (1) For the burner por-tion—burners or air and coal nozzles, burnerthroat and waterwall modifications, andwindbox modifications; and, where applica-ble, (2) for the combustion air staging por-tion—waterwall modifications or panels,windbox modifications, and ductwork, and(3) scope adders or supplemental equipmentsuch as replacement or additional fans,dampers, or ignitors necessary for the properoperation of the low NOX burner technology.Capital costs associated with boiler restora-tion or refurbishment such as replacement ofair heaters, asbestos abatement, and re-casing will not be included in the cost basisfor installed low NOX burner technology. Thescope of installed low NOX burner technologyretrofit capital costs will include materials,construction and installation labor, engi-neering, and overhead costs.

2.2 Using gross nameplate capacity (inMW) for each unit as reported in the Na-tional Allowance Data Base (NADB), boiler-specific capital costs will be converted to a $/kW basis.

2.3 Capital cost curves ($/kW versus boilersize in MW) or equations for installed lowNOX burner technology retrofit costs will bedeveloped for: (1) Dry bottom wall fired boil-ers (excluding units applying cell burner

technology) and (2) tangentially fired boil-ers.

3. [Reserved]

4. Reporting Requirements

4.1 The following information is to be sub-mitted by each designated representative ofa Phase I affected unit subject to the report-ing requirements of § 76.14(c):

4.1.1 Schedule and dates for baseline test-ing, installation, and performance testing oflow NOX burner technology.

4.1.2 Estimates of the annual averagebaseline NOX emission rate, as specified insection 3.1.1, and the annual average con-trolled NOX emission rate, as specified insection 3.1.2, including the supporting con-tinuous emission monitoring or other testdata.

4.1.3 Copies of pre-retrofit and post-ret-rofit performance test reports.

4.1.4 Detailed estimates of the capitalcosts based on actual contract bids for eachcomponent of the installed low NOX burnertechnology including the items listed in sec-tion 2.1. Indicate number of bids solicited.Provide a copy of the actual agreement forthe installed technology.

4.1.5 Detailed estimates of the capitalcosts of system replacements or upgradessuch as coal pipe changes, fan replacements/upgrades, or mill replacements/upgrades un-dertaken as part of the low NOX burner tech-nology retrofit project.

4.1.6 Detailed breakdown of the actualcosts of the completed low NOX burner tech-nology retrofit project where low NOX burnertechnology costs (section 4.1.4) aredisaggregated, if feasible, from system re-placement or upgrade costs (section 4.1.5).

4.1.7 Description of the probable causesfor significant differences between actualand estimated low NOX burner technologyretrofit project costs.

4.1.8 Detailed breakdown of the burnerand, if applicable, combustion air stagingsystem annual operating and maintenancecosts for the items listed in section 3.3 beforeand after the installation, shakedown, and/oroptimization of the installed low NOX burnertechnology. Include estimates and a descrip-tion of the probable causes of the incre-mental annual operating and maintenancecosts (or savings) attributable to the in-stalled low NOX burner technology.

4.2 All capital cost estimates are to bebroken down into materials costs, construc-tion and installation labor costs, and engi-neering and overhead costs. All operatingand maintenance costs are to be brokendown into maintenance materials costs,maintenance labor costs, operating laborcosts, and fan electricity costs. All capital


457


and operating costs are to be reported in dol-lars with the year of expenditure or estimatespecified for each component.

[60 FR 18761, Apr. 13, 1995, as amended at 61FR 67164, Dec. 19, 1996; 62 FR 3464, Jan. 23,1997]

PART 77—EXCESS EMISSIONS

Sec.77.1 Purpose and scope.77.2 General.77.3 Offset plans for excess emissions of sul-

fur dioxide.77.4 Administrator’s action on proposed off-

set plans.77.5 Deduction of allowances to offset ex-

cess emissions of sulfur dioxide.77.6 Penalties for excess emissions of sulfur

dioxide and nitrogen oxides.

AUTHORITY: 42 U.S.C. 7601 and 7651, et seq.

SOURCE: 58 FR 3757, Jan. 11, 1993, unlessotherwise noted.

§ 77.1 Purpose and scope.(a) This part sets forth the excess

emissions offset planning and offsetpenalty requirements under section 411of the Clean Air Act, 42 U.S.C. 7401, etseq., as amended by Public Law 101–549(November 15, 1990). These require-ments shall apply to the owners andoperators and, to the extent applicable,the designated representative of eachaffected unit and affected source underthe Acid Rain Program.

(b) Nothing in this part shall limit orotherwise affect the application of sec-tions 112(r)(9), 113, 114, 120, 303, 304, or306 of the Act, as amended. Any allow-ance deduction, excess emission pen-alty, or interest required under thispart shall not affect the liability of theaffected unit’s and affected source’sowners and operators for any addi-tional fine, penalty, or assessment, ortheir obligation to comply with anyother remedy, for the same violation,as ordered under the Act.

§ 77.2 General.Part 72 of this chapter, including

§§ 72.2 (definitions), 72.3 (measurements,abbreviations, and acronyms), 72.4(Federal authority), 72.5 (State author-ity), 72.6 (applicability), 72.7 (new unitsexemption), 72.8 (retired units exemp-tion), 72.9 (standard requirements),72.10 (availability of information), and72.11 (computation of time), shall apply

to this part. The procedures for appealsof decisions of the Administrator underthis part are contained in part 78 ofthis chapter.

§ 77.3 Offset plans for excess emissionsof sulfur dioxide.

(a) Applicability. The owners and op-erators of any affected unit that hasexcess emissions of sulfur dioxide inany calendar year shall be liable to off-set the amount of such excess emis-sions by an equal amount of allowancesfrom the unit’s Allowance TrackingSystem account.

(b) Deadline. Not later than 60 daysafter the end of any calendar year dur-ing which an affected unit had excessemissions of sulfur dioxide (except forany increase in excess emissions under§ 72.91(b) of this chapter), the des-ignated representative for the unitshall submit to the Administrator acomplete proposed offset plan to offsetthose emissions. Each day after the 60-day deadline that the designated rep-resentative fails to submit a completeproposed offset plan shall be a separateviolation of this part.

(c) Number of Plans. The designatedrepresentative shall submit a proposedoffset plan for each affected unit withexcess emissions of sulfur dioxide.

(d) Contents of Plan. A complete pro-posed offset plan shall include the fol-lowing elements in a format prescribedby the Administrator for the unit andfor the calendar year for which theplan is submitted:

(1) Identification of the unit.(2) If the unit had excess emissions

for the calendar year prior to the yearfor which the plan is submitted, an ex-planation of how and why the excessemissions occurred for the year forwhich the plan is submitted and a de-scription of any measures that were orwill be taken to prevent excess emis-sions in the future.

(3) At the designated representative’soption, the number of allowances to bededucted from the unit’s AllowanceTracking System account to offset theexcess emissions for the year for whichthe plan is submitted.

(4) At the designated representative’soption, the serial numbers of the allow-ances that are to be deducted from the


pt. 76 40 cfr ch. i (7–1–00 edition) · pt. 76 40 cfr ch. i (7–1–00 edition) ... project....

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