e-CFR banner

Home
gpo.gov
govinfo.gov

e-CFR Navigation Aids

Browse

Simple Search

Advanced Search

 — Boolean

 — Proximity

 

Search History

Search Tips

Corrections

Latest Updates

User Info

FAQs

Agency List

Incorporation By Reference

eCFR logo

Related Resources

 

Electronic Code of Federal Regulations

e-CFR data is current as of December 11, 2019

Title 40Chapter ISubchapter C → Part 76


Title 40: Protection of Environment


PART 76—ACID RAIN NITROGEN OXIDES EMISSION REDUCTION PROGRAM


Contents
§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 II boilers.
§76.9   Permit application and compliance plans.
§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 reporting.
§76.15   Test methods and procedures.

   

Appendix A to Part 76—Phase I Affected Coal-Fired Utility Units With Group 1 or Cell Burner Boilers
Appendix B to Part 76—Procedures and Methods for Estimating Costs of Nitrogen Oxides Controls Applied to Group 1, Boilers

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

Source: 60 FR 18761, Apr. 13, 1995, unless otherwise noted.

§76.1   Applicability.

(a) Except as provided in paragraphs (b) through (d) of this section, the provisions apply to each coal-fired utility unit that is subject to an Acid Rain emissions limitation or reduction requirement for SO2 under Phase I or Phase II pursuant to sections 404, 405, or 409 of the Act.

(b) The emission limitations for NOX under this part apply to each affected coal-fired utility unit subject to section 404(d) or 409(b) of the Act on the date the unit is required to meet the Acid Rain emissions reduction requirement for SO2.

(c) The provisions of this part apply to each coal-fired substitution unit or compensating unit, designated and approved as a Phase I unit pursuant to §72.41 or §72.43 of this chapter as follows:

(1) A coal-fired substitution unit that is designated in a substitution plan that is approved and active as of January 1, 1995 shall be treated as a Phase I coal-fired utility unit for purposes of this part. In the event the designation of such unit as a substitution unit is terminated after December 31, 1995, pursuant to §72.41 of this chapter and the unit is no longer required to meet Phase I SO2 emissions limitations, the provisions of this part (including those applicable in Phase I) will continue to apply.

(2) A coal-fired substitution unit that is designated in a substitution plan that is not approved or not active as of January 1, 1995, or a coal-fired compensating unit, shall be treated as a Phase II coal-fired utility unit for purposes of this part.

(d) The provisions of this part for Phase I units apply to each coal-fired transfer unit governed by a Phase I extension plan, approved pursuant to §72.42 of this chapter, on January 1, 1997. Notwithstanding the preceding sentence, a coal-fired transfer unit shall be subject to the Acid Rain emissions limitations for nitrogen oxides beginning on January 1, 1996 if, for that year, a transfer unit is allocated fewer Phase I extension reserve allowances than the maximum amount that the designated representative could have requested in accordance with §72.42(c)(5) of this chapter (as adjusted under §72.42(d) of this chapter) unless the transfer unit is the last unit allocated Phase I extension reserve allowances under the plan.

§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 section as follows:

Alternative contemporaneous annual emission limitation means the maximum allowable NOX emission rate (on a lb/mmBtu, annual average basis) assigned to an individual unit in a NOX emissions averaging plan pursuant to §76.10.

Alternative technology means a control technology for reducing NOX emissions that is outside the scope of the definition of low NOX burner technology. Alternative technology does not include overfire air as applied to wall-fired boilers or separated overfire air as applied to tangentially fired boilers.

Approved clean coal technology demonstration project means a project using funds appropriated under the Department of Energy's “Clean Coal Technology Demonstration Program,” up to a total amount of $2,500,000,000 for commercial demonstration of clean coal technology, or similar projects funded through appropriations for the Environmental Protection Agency. The Federal contribution for a qualifying project shall be at least 20 percent of the total cost of the demonstration project.

Arch-fired boiler means a dry bottom boiler with circular burners, or coal and air pipes, oriented downward and mounted on waterwalls that are at an angle significantly different from the horizontal axis and the vertical axis. This definition shall include only the following units: Holtwood unit 17, Hunlock unit 6, and Sunbury units 1A, 1B, 2A, and 2B. This definition shall exclude dry bottom turbo fired boilers.

Cell burner boiler means a wall-fired boiler that utilizes two or three circular burners combined into a single vertically oriented assembly that results in a compact, intense flame. Any low NOX retrofit of a cell burner boiler that reuses the existing cell burner, close-coupled wall opening configuration would not change the designation of the unit as a cell burner boiler.

Coal-fired utility unit means a utility unit in which the combustion of coal (or any coal-derived fuel) on a Btu basis exceeds 50.0 percent of its annual heat input during the following calendar year: for Phase I units, in calendar year 1990; and, for Phase II units, in calendar year 1995 or, for a Phase II unit that did not combust any fuel that resulted in the generation of electricity in calendar year 1995, in any calendar year during the period 1990-1995. For the purposes of this part, this definition shall apply notwithstanding the definition in §72.2 of this chapter.

Combustion controls means technology that minimizes NOX formation by staging fuel and combustion air flows in a boiler. This definition shall include low NOX burners, overfire air, or low NOX burners with overfire air.

Cyclone boiler means a boiler with one or more water-cooled horizontal cylindrical chambers in which coal combustion takes place. The horizontal cylindrical chamber(s) is (are) attached to the bottom of the furnace. One or more cylindrical chambers are arranged either on one furnace wall or on two opposed furnace walls. Gaseous combustion products exiting from the chamber(s) turn 90 degrees to go up through the boiler while coal ash exits the bottom of the boiler as a molten slag.

Demonstration period means a period of time not less than 15 months, approved under §76.10, for demonstrating that the affected unit cannot meet the applicable emission limitation under §76.5, 76.6, or 76.7 and establishing the minimum NOX emission rate that the unit can achieve during long-term load dispatch operation.

Dry bottom means the boiler has a furnace bottom temperature below the ash melting point and the bottom ash is removed as a solid.

Economizer means the lowest temperature heat exchange section of a utility boiler where boiler feed water is heated by the flue gas.

Flue gas means the combustion products arising from the combustion of fossil fuel in a utility boiler.

Group 1 boiler means a tangentially fired boiler or a dry bottom wall-fired boiler (other than a unit applying cell burner technology).

Group 2 boiler means a wet bottom wall-fired boiler, a cyclone boiler, a boiler applying cell burner technology, a vertically fired boiler, an arch-fired boiler, or any other type of utility boiler (such as a fluidized bed or stoker boiler) that is not a Group 1 boiler.

Low NOX burners and low NOX burner technology means commercially available combustion modification NOX controls that minimize NOX formation by introducing coal and its associated combustion air into a boiler such that initial combustion occurs in a manner that promotes rapid coal devolatilization in a fuel-rich (i.e., oxygen deficient) environment and introduces additional air to achieve a final fuel-lean (i.e., oxygen rich) environment to complete the combustion process. This definition shall include the staging of any portion of the combustion air using air nozzles or registers located inside any waterwall hole that includes a burner. This definition shall exclude the staging of any portion of the combustion air using air nozzles or ports located outside any waterwall hole that includes a burner (commonly referred to as NOX ports or separated overfire air ports).

Maximum Continuous Steam Flow at 100% of Load means the maximum capacity of a boiler as reported in item 3 (Maximum Continuous Steam Flow at 100% Load in thousand pounds per hour), Section C (design parameters), Part III (boiler information) of the Department of Energy's Form EIA-767 for 1995.

Non-plug-in combustion controls means the replacement, in a cell burner boiler, of the portions of the waterwalls containing the cell burners by new portions of the waterwalls containing low NOX burners or low NOX burners with overfire air.

Operating period means a period of time of not less than three consecutive months and that occurs not more than one month prior to applying for an alternative emission limitation demonstration period under §76.10, during which the owner or operator of an affected unit that cannot meet the applicable emission limitation:

(1) Operates the installed NOX emission controls in accordance with primary vendor specifications and procedures, with the unit operating under normal conditions; and

(2) records and reports quality-assured continuous emission monitoring (CEM) and unit operating data according to the methods and procedures in part 75 of this chapter.

Plug-in combustion controls means the replacement, in a cell burner boiler, of existing cell burners by low NOX burners or low NOX burners with overfire air.

Primary vendor means the vendor of the NOX emission control system who has primary responsibility for providing the equipment, service, and technical expertise necessary for detailed design, installation, and operation of the controls, including process data, mechanical drawings, operating manuals, or any combination thereof.

Reburning means reducing the coal and combustion air to the main burners and injecting a reburn fuel (such as gas or oil) to create a fuel-rich secondary combustion zone above the main burner zone and final combustion air to create a fuel-lean burnout zone. The formation of NOX is inhibited in the main burner zone due to the reduced combustion intensity, and NOX is destroyed in the fuel-rich secondary combustion zone by conversion to molecular nitrogen.

Selective catalytic reduction means a noncombustion control technology that destroys NOX by injecting a reducing agent (e.g., ammonia) into the flue gas that, in the presence of a catalyst (e.g., vanadium, titanium, or zeolite), converts NOX into molecular nitrogen and water.

Selective noncatalytic reduction means a noncombustion control technology that destroys NOX by injecting a reducing agent (e.g., ammonia, urea, or cyanuric acid) into the flue gas, downstream of the combustion zone that converts NOX to molecular nitrogen, water, and when urea or cyanuric acid are used, to carbon dioxide (CO2).

Stoker boiler means a boiler that burns solid fuel in a bed, on a stationary or moving grate, that is located at the bottom of the furnace.

Tangentially fired boiler means a boiler that has coal and air nozzles mounted in each corner of the furnace where the vertical furnace walls meet. Both pulverized coal and air are directed from the furnace corners along a line tangential to a circle lying in a horizontal plane of the furnace.

Turbo-fired boiler means a pulverized coal, wall-fired boiler with burners arranged on walls so that the individual flames extend down toward the furnace bottom and then turn back up through the center of the furnace.

Vertically fired boiler means a dry bottom boiler with circular burners, or coal and air pipes, oriented downward and mounted on waterwalls that are horizontal or at an angle. This definition shall include dry bottom roof-fired boilers and dry bottom top-fired boilers, and shall exclude dry bottom arch-fired boilers and dry bottom turbo-fired boilers.

Wall-fired boiler means a boiler that has pulverized coal burners arranged on the walls of the furnace. The burners have discrete, individual flames that extend perpendicularly into the furnace area.

Wet bottom means that the ash is removed from the furnace in a molten state. The term “wet bottom boiler” shall include: wet bottom wall-fired boilers, including wet bottom turbo-fired boilers; and wet bottom boilers otherwise meeting the definition of vertically fired boilers, including wet bottom arch-fired boilers, wet bottom roof-fired boilers, and wet bottom top-fired boilers. The term “wet bottom boiler” shall exclude cyclone boilers and tangentially fired boilers.

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

§76.3   General Acid Rain Program provisions.

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

(a) §72.2   (Definitions);

(b) §72.3   (Measurements, abbreviations, and acronyms);

(c) §72.4   (Federal authority);

(d) §72.5   (State authority);

(e) §72.6   (Applicability);

(f) §72.7   (New unit exemption);

(g) §72.8   (Retired units exemption);

(h) §72.9   (Standard requirements);

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

(j) §72.11   (Computation of time).

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

§76.4   Incorporation by reference.

(a) The materials listed in this section are incorporated by reference in the sections noted. These incorporations by reference (IBR's) were approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they existed on the date of approval, and notice of any change in these materials will be published in the Federal Register. The materials are available for purchase at the corresponding address noted below and are available for inspection at the Public Information Reference Unit, U.S. EPA, 401 M St., SW., Washington, DC, and at the Library (MD-35), U.S. EPA, Research Triangle Park, North Carolina or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202-741-6030, or go to: http://www.archives.gov/federal__register/code__of__federal__regulations/ibr__locations.html.

(b) The following materials are available for purchase from at least one of the following addresses: American Society for Testing and Materials (ASTM), 1916 Race Street, Philadelphia, Pennsylvania 19103; or the University Microfilms International, 300 North Zeeb Road, Ann Arbor, Michigan 48106.

(1) ASTM D 3176-89, Standard Practice for Ultimate Analysis of Coal and Coke, IBR approved May 23, 1995 for §76.15.

(2) ASTM D 3172-89, Standard Practice for Proximate Analysis of Coal and Coke, IBR approved May 23, 1995 for §76.15.

(c) The following material is available for purchase from the American Society of Mechanical Engineers (ASME), 22 Law Drive, Box 2350, Fairfield, NJ 07007-2350.

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

(2) [Reserved]

(d) The following material is available for purchase from the American National Standards Institute, 11 West 42nd Street, New York, NY 10036 or from the International Organization for Standardization (ISO), Case Postale 56, CH-1211 Geneve 20, Switzerland.

(1) ISO 9931 (December, 1991) “Coal—Sampling of Pulverized Coal Conveyed by Gases in Direct Fired Coal Systems,” IBR approved May 23, 1995 for §76.15.

(2) [Reserved]

§76.5   NOX emission limitations for Group 1 boilers.

(a) Beginning January 1, 1996, or for a unit subject to section 404(d) of the Act, the date on which the unit is required to meet Acid Rain emission reduction requirements for SO2, the owner or operator of a Phase I coal-fired utility unit with a tangentially fired boiler or a dry bottom wall-fired boiler (other than units applying cell burner technology) shall not discharge, or allow to be discharged, emissions of NOX to the atmosphere in excess of the following limits, except as provided in paragraphs (c) or (e) of this section or in §76.10, 76.11, or 76.12:

(1) 0.45 lb/mmBtu of heat input on an annual average basis for tangentially fired boilers.

(2) 0.50 lb/mmBtu of heat input on an annual average basis for dry bottom wall-fired boilers (other than units applying cell burner technology).

(b) The owner or operator shall determine the annual average NOX emission rate, in lb/mmBtu, using the methods and procedures specified in part 75 of this chapter.

(c) Unless the unit meets the early election requirement of §76.8, the owner or operator of a coal-fired substitution unit with a tangentially fired boiler or a dry bottom wall-fired boiler (other than units applying cell burner technology) that satisfies the requirements of §76.1(c)(2), shall comply with the NOX emission limitations that apply to Group 1, Phase II boilers.

(d) The owner or operator of a Phase I unit with a cell burner boiler that converts to a conventional wall-fired boiler on or before January 1, 1995 or, for a unit subject to section 404(d) of the Act, the date the unit is required to meet Acid Rain emissions reduction requirements for SO2 shall comply, by such respective date or January 1, 1996, whichever is later, with the NOX emissions limitation applicable to dry bottom wall-fired boilers under paragraph (a) of this section, except as provided in paragraphs (c) or (e) of this section or in §76.10, 76.11, or 76.12.

(e) The owner or operator of a Phase I unit with a Group 1 boiler that converts to a fluidized bed or other type of utility boiler not included in Group 1 boilers on or before January 1, 1995 or, for a unit subject to section 404(d) of the Act, the date the unit is required to meet Acid Rain emissions reduction requirements for SO2 is exempt from the NOX emissions limitations specified in paragraph (a) of this section, but shall comply with the NOX emission limitations for Group 2 boilers under §76.6.

(f) Except as provided in §76.8 and in paragraph (c) of this section, each unit subject to the requirements of this section is not subject to the requirements of §76.7.

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

§76.6   NOX emission limitations for Group 2 boilers.

(a) Beginning January 1, 2000 or, for a unit subject to section 409(b) of the Act, the date on which the unit is required to meet Acid Rain emission reduction requirements for SO2, the owner or operator of a Group 2, coal-fired boiler with a cell burner boiler, cyclone boiler, a wet bottom boiler, or a vertically fired boiler shall not discharge, or allow to be discharged, emissions of NOX to the atmosphere in excess of the following limits, except as provided in §§76.10 or 76.11:

(1) 0.68 lb/mmBtu of heat input on an annual average basis for cell burner boilers. The NOX emission control technology on which the emission limitation is based is plug-in combustion controls or non-plug-in combustion controls. Except as provided in §76.5(d), the owner or operator of a unit with a cell burner boiler that installs non-plug-in combustion controls shall comply with the emission limitation applicable to cell burner boilers.

(2) 0.86 lb/mmBtu of heat input on an annual average basis for cyclone boilers with a Maximum Continuous Steam Flow at 100% of Load of greater than 1060, in thousands of lb/hr. The NOX emission control technology on which the emission limitation is based is natural gas reburning or selective catalytic reduction.

(3) 0.84 lb/mmBtu of heat input on an annual average basis for wet bottom boilers, with a Maximum Continuous Steam Flow at 100% of Load of greater than 450, in thousands of lb/hr. The NOX emission control technology on which the emission limitation is based is natural gas reburning or selective catalytic reduction.

(4) 0.80 lb/mmBtu of heat input on an annual average basis for vertically fired boilers. The NOX emission control technology on which the emission limitation is based is combustion controls.

(b) The owner or operator shall determine the annual average NOX emission rate, in lb/mmBtu, using the methods and procedures specified in part 75 of this chapter.

[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 limitations for Group 1, Phase II boilers.

(a) Beginning January 1, 2000, the owner or operator of a Group 1, Phase II coal-fired utility unit with a tangentially fired boiler or a dry bottom wall-fired boiler shall not discharge, or allow to be discharged, emissions of NOX to the atmosphere in excess of the following limits, except as provided in §§76.8, 76.10, or 76.11:

(1) 0.40 lb/mmBtu of heat input on an annual average basis for tangentially fired boilers.

(2) 0.46 lb/ mmBtu of heat input on an annual average basis for dry bottom wall-fired boilers (other than units applying cell burner technology).

(b) The owner or operator shall determine the annual average NOX emission rate, in lb/mmBtu, using the methods and procedures specified in part 75 of this chapter.

[60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67163, Dec. 19, 1996]

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

(a) General provisions. (1) The owner or operator of a Phase II coal-fired utility unit with a Group 1 boiler may elect to have the unit become subject to the applicable emissions limitation for NOX under §76.5, starting no later than January 1, 1997.

(2) The owner or operator of a Phase II coal-fired utility unit with a Group 1 boiler that elects to become subject to the applicable emission limitation under §76.5 shall not be subject to §76.7 until January 1, 2008, provided the designated representative demonstrates that the unit is in compliance with the limitation under §76.5, using the methods and procedures specified in part 75 of this chapter, for the period beginning January 1 of the year in which the early election takes effect (but not later than January 1, 1997) and ending December 31, 2007.

(3) The owner or operator of any Phase II unit with a cell burner boiler that converts to conventional burner technology may elect to become subject to the applicable emissions limitation under §76.5 for dry bottom wall-fired boilers, provided the owner or operator complies with the provisions in paragraph (a)(2) of this section.

(4) The owner or operator of a Phase II unit approved for early election shall not submit an application for an alternative emissions limitation demonstration period under §76.10 until the earlier of:

(i) January 1, 2008; or

(ii) Early election is terminated pursuant to paragraph (e)(3) of this section.

(5) The owner or operator of a Phase II unit approved for early election may not incorporate the unit into an averaging plan prior to January 1, 2000. On or after January 1, 2000, for purposes of the averaging plan, the early election unit will be treated as subject to the applicable emissions limitation for NOX for Phase II units with Group 1 boilers under §76.7.

(b) Submission requirements. In order to obtain early election status, the designated representative of a Phase II unit with a Group 1 boiler shall submit an early election plan to the Administrator by January 1 of the year the early election is to take effect, but not later than January 1, 1997. Notwithstanding §72.40 of this chapter, and unless the unit is a substitution unit under §72.41 of this chapter or a compensating unit under §72.43 of this chapter, a complete compliance plan covering the unit shall not include the provisions for SO2 emissions under §72.40(a)(1) of this chapter.

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

(1) A request for early election;

(2) The first year for which early election is to take effect, but not later than 1997; and

(3) The special provisions under paragraph (e) of this section.

(d)(1) Permitting authority's action. To the extent the Administrator determines that an early election plan complies with the requirements of this section, the Administrator will approve the plan and:

(i) If a Phase I Acid Rain permit governing the source at which the unit is located has been issued, will revise the permit in accordance with the permit modification procedures in §72.81 of this chapter to include the early election plan; or

(ii) If a Phase I Acid Rain permit governing the source at which the unit is located has not been issued, will issue a Phase I Acid Rain permit effective from January 1, 1995 through December 31, 1999, that will include the early election plan and a complete compliance plan under §72.40(a) of this chapter and paragraph (b) of this section. If the early election plan is not effective until after January 1, 1995, the permit will not contain any NOX emissions limitations until the effective date of the plan.

(2) Beginning January 1, 2000, the permitting authority will approve any early election plan previously approved by the Administrator during Phase I, unless the plan is terminated pursuant to paragraph (e)(3) of this section.

(e) Special provisions—(1) Emissions limitations—(i) Sulfur dioxide. Notwithstanding §72.9 of this chapter, a unit that is governed by an approved early election plan and that is not a substitution unit under §72.41 of this chapter or a compensating unit under §72.43 of this chapter shall not be subject to the following 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 requirements under §72.9(c) of this chapter; and

(C) The excess emissions requirements under §72.9(e)(1) of this chapter.

(ii) Nitrogen oxides. A unit that is governed by an approved early election plan shall be subject to an emissions limitation for NOX as provided under paragraph (a)(2) of this section except as provided under paragraph (e)(3)(iii) of this section.

(2) Liability. The owners and operators of any unit governed by an approved early election plan shall be liable for any violation of the plan or this section at that unit. The owners and operators shall be liable, beginning January 1, 2000, for fulfilling the obligations specified in part 77 of this chapter.

(3) Termination. An approved early election plan shall be in effect only until the earlier of January 1, 2008 or January 1 of the calendar year for which a termination of the plan takes effect.

(i) If the designated representative of the unit under an approved early election plan fails to demonstrate compliance with the applicable emissions limitation under §76.5 for any year during the period beginning January 1 of the first year the early election takes effect and ending December 31, 2007, the permitting authority will terminate the plan. The termination will take effect beginning January 1 of the year after the year for which there is a failure to demonstrate compliance, and the designated representative may not submit a new early election plan.

(ii) The designated representative of the unit under an approved early election plan may terminate the plan any year prior to 2008 but may not submit a new early election plan. In order to terminate the plan, the designated representative must submit a notice under §72.40(d) of this chapter by January 1 of the year for which the termination is to take effect.

(iii)(A) If an early election plan is terminated any year prior to 2000, the unit shall meet, beginning January 1, 2000, the applicable emissions limitation for NOX for Phase II units with Group 1 boilers under §76.7.

(B) If an early election plan is terminated in or after 2000, the unit shall meet, beginning on the effective date of the termination, the applicable emissions limitation for NOX for Phase II units with Group 1 boilers under §76.7.

[60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67163, Dec. 19, 1996]

§76.9   Permit application and compliance plans.

(a) Duty to apply. (1) The designated representative of any source with an affected unit subject to this part shall submit, by the applicable deadline under paragraph (b) of this section, a complete Acid Rain permit application (or, if the unit is covered by an Acid Rain permit, a complete permit revision) that includes a complete compliance plan for NOX emissions covering the unit.

(2) The original and three copies of the permit application and compliance plan for NOX emissions for Phase I shall be submitted to the EPA regional office for the region where the applicable source is located. The original and three copies of the permit application and compliance plan for NOX emissions for Phase II shall be submitted to the permitting authority.

(b) Deadlines. (1) For a Phase I unit with a Group 1 boiler, the designated representative shall submit a complete permit application and compliance plan for NOX covering the unit during Phase I to the applicable permitting authority not later than May 6, 1994.

(2) For a Phase I or Phase II unit with a Group 2 boiler or a Phase II unit with a Group 1 boiler, the designated representative shall submit a complete permit application and compliance plan for NOX emissions covering the unit in Phase II to the Administrator not later than January 1, 1998, except that early election units shall also submit an application not later than January 1, 1997.

(c) Information requirements for NOX compliance plans. (1) In accordance with §72.40(a)(2) of this chapter, a complete compliance plan for NOX shall, for each affected unit included in the permit application and subject to this part, either certify that the unit will comply with the applicable emissions limitation under §76.5, 76.6, or 76.7 or specify one or more other Acid Rain compliance options for NOX in accordance with the requirements of this part. A complete compliance plan for NOX for a source shall include the following elements in a format prescribed by the Administrator:

(i) Identification of the source;

(ii) Identification of each affected unit that is at the source and is subject to this part;

(iii) Identification of the boiler type of each unit;

(iv) Identification of the compliance option proposed for each unit (i.e., meeting the applicable emissions limitation under §76.5, 76.6, 76.7, 76.8 (early election), 76.10 (alternative emission limitation), 76.11 (NOX emissions averaging), or 76.12 (Phase I NOX compliance extension)) and any additional information required for the appropriate option in accordance with this part;

(v) Reference to the standard requirements in §72.9 of this chapter (consistent with §76.8(e)(1)(i)); and

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

(2) [Reserved]

(d) Duty to reapply. The designated representative of any source with an affected unit subject to this part shall submit a complete Acid Rain permit application, including a complete compliance plan for NOX emissions covering the unit, in accordance with the deadlines in §72.30(c) of this chapter.

§76.10   Alternative emission limitations.

(a) General provisions. (1) The designated representative of an affected unit that is not an early election unit pursuant to §76.8 and cannot meet the applicable emission limitation in §76.5, 76.6, or 76.7 using, for Group 1 boilers, either low NOX burner technology or an alternative technology in accordance with paragraph (e)(11) of this section, or, for tangentially fired boilers, separated overfire air, or, for Group 2 boilers, the technology on which the applicable emission limitation is based may petition the permitting authority for an alternative emission limitation less stringent than the applicable emission limitation.

(2) In order for the unit to qualify for an alternative emission limitation, the designated representative shall demonstrate that the affected unit cannot meet the applicable emission limitation in §76.5, 76.6, or 76.7 based on a showing, to the satisfaction of the Administrator, that:

(i)(A) For a tangentially fired boiler, the owner or operator has either properly installed low NOX burner technology or properly installed separated overfire air; or

(B) For a dry bottom wall-fired boiler (other than a unit applying cell burner technology), the owner or operator has properly installed low NOX burner technology; or

(C) For a Group 1 boiler, the owner or operator has properly installed an alternative technology (including but not limited to reburning, selective noncatalytic reduction, or selective catalytic reduction) that achieves NOX emission reductions demonstrated in accordance with paragraph (e)(11) of this section; or

(D) For a Group 2 boiler, the owner or operator has properly installed the appropriate NOX emission control technology on which the applicable emission limitation in §76.6 is based; and

(ii) The installed NOX emission control system has been designed to meet the applicable emission limitation in §76.5, 76.6, or 76.7; and

(iii) For a demonstration period of at least 15 months or other period of time, as provided in paragraph (f)(1) of this section:

(A) The NOX emission control system has been properly installed and properly operated according to specifications and procedures designed to minimize the emissions of NOX to the atmosphere;

(B) Unit operating data as specified in this section show that the unit and NOX emission control system were operated in accordance with the bid and design specifications on which the design of the NOX emission control system was based; and

(C) Unit operating data as specified in this section, continuous emission monitoring data obtained pursuant to part 75 of this chapter, and the test data specific to the NOX emission control system show that the unit could not meet the applicable emission limitation in §76.5, 76.6, or 76.7.

(b) Petitioning process. The petitioning process for an alternative emission limitation shall consist of the following steps:

(1) Operation during a period of at least 3 months, following the installation of the NOX emission control system, that shows that the specific unit and the NOX emission control system was unable to meet the applicable emissions limitation under §76.5, 76.6, or 76.7 and was operated in accordance with the operating conditions upon which the design of the NOX emission control system was based and with vendor specifications and procedures;

(2) Submission of a petition for an alternative emission limitation demonstration period as specified in paragraph (d) of this section;

(3) Operation during a demonstration period of at least 15 months, or other period of time as provided in paragraph (f)(1) of this section, that demonstrates the inability of the specific unit to meet the applicable emissions limitation under §76.5, 76.6, or 76.7 and the minimum NOX emissions rate that the specific unit can achieve during long-term load dispatch operation; and

(4) Submission of a petition for a final alternative emission limitation as specified in paragraph (e) of this section.

(c) Deadlines—(1) Petition for an alternative emission limitation demonstration period. The designated representative of the unit shall submit a petition for an alternative emission limitation demonstration period to the permitting authority after the unit has been operated for at least 3 months after installation of the NOX emission control system required under paragraph (a)(2) of this section and by the following deadline:

(i) For units that seek to have an alternative emission limitation demonstration period apply during all or part of calendar year 1996, or any previous calendar year by the later of:

(A) 120 days after startup of the NOX emission control system, or

(B) May 1, 1996.

(ii) For units that seek an alternative emission limitation demonstration period beginning in a calendar year after 1996, not later than:

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

(B) 120 days after startup of the NOX emission control system if the unit is not operating at the beginning of that calendar year.

(2) Petition for a final alternative emission limitation. Not later than 90 days after the end of an approved alternative emission limitation demonstration period for the unit, the designated representative of the unit may submit a petition for an alternative emission limitation to the permitting authority.

(3) Renewal of an alternative emission limitation. In order to request continuation of an alternative emission limitation, the designated representative must submit a petition to renew the alternative emission limitation on the date that the application for renewal of the source's Acid Rain permit containing the alternative emission limitation is due.

(d) Contents of petition for an alternative emission limitation demonstration period. The designated representative of an affected unit that has met the minimum criteria under paragraph (a) of this section and that has been operated for a period of at least 3 months following the installation of the required NOX emission control system may submit to the permitting authority a petition for an alternative emission limitation demonstration period. In the petition, the designated representative shall provide the following information in a format prescribed by the Administrator:

(1) Identification of the unit;

(2) The type of NOX control technology installed (e.g., low NOX burner technology, selective noncatalytic reduction, selective catalytic reduction, reburning);

(3) If an alternative technology is installed, the time period (not less than 6 consecutive months) prior to installation of the technology to be used for the demonstration required in paragraph (e)(11) of this section.

(4) Documentation as set forth in §76.14(a)(1) showing that the installed NOX emission control system has been designed to meet the applicable emission limitation in §76.5, 76.6, or 76.7 and that the system has been properly installed according to procedures and specifications designed to minimize the emissions of NOX to the atmosphere;

(5) The date the unit commenced operation following the installation of the NOX emission control system or the date the specific unit became subject to 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 designated representative that the owner(s) or operator operated the unit and the NOX emission control system during the operating period in accordance with: Specifications and procedures designed to achieve the maximum NOX reduction possible with the installed NOX emission control system or the applicable emission limitation in §76.5, 76.6, or 76.7; the operating conditions upon which the design of the NOX emission control system was based; and vendor specifications and procedures;

(8) A brief statement describing the reason or reasons why the unit cannot achieve the applicable emission limitation in §76.5, 76.6, or 76.7;

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

(10) Unit operating data and quality-assured continuous emission monitoring data (including the specific data items listed in §76.14(a)(3) collected in accordance with part 75 of this chapter during the operating period) and demonstrating the inability of the specific unit to meet the applicable emission limitation in §76.5, 76.6, or 76.7 on an annual average basis while operating as certified under paragraph (d)(7) of this section;

(11) An interim alternative emission limitation, in lb/mmBtu, that the unit can achieve during a demonstration period of at least 15 months. The interim alternative emission limitation shall be derived from the data specified in paragraph (d)(10) of this section using methods and procedures satisfactory to the Administrator;

(12) The proposed dates of the demonstration period (which must be at least 15 months long);

(13) A report which outlines the testing and procedures to be taken during the demonstration period in order to determine the maximum NOX emission reduction obtainable with the installed system. The report shall include the reasons for the NOX emission control system's failure to meet the applicable emission limitation, and the tests and procedures that will be followed to optimize the NOX emission control system's performance. Such tests and procedures may include those identified in §76.15 as appropriate.

(14) The special provisions at paragraph (g)(1) of this section.

(e) Contents of petition for a final alternative emission limitation. After the approved demonstration period, the designated representative of the unit may petition the permitting authority for an alternative emission limitation. The petition shall include the following elements in a format prescribed by the Administrator:

(1) Identification of the unit;

(2) Certification that the owner(s) or operator operated the affected unit and the NOX emission control system during the demonstration period in accordance with: specifications and procedures designed to achieve the maximum NOX reduction possible with the installed NOX emission control system or the applicable emissions limitation in §76.5, 76.6, or 76.7; the operating conditions (including load dispatch conditions) upon which the design of the NOX emission control system was based; and vendor specifications and procedures.

(3) Certification that the owner(s) or operator have installed in the affected unit all NOX emission control systems, made any operational modifications, and completed any planned upgrades and/or maintenance to equipment specified in the approved demonstration period plan for optimizing NOX emission reduction performance, consistent with the demonstration period plan and the proper operation of the installed NOX emission control system. Such certification shall explain any differences between the installed NOX emission control system and the equipment configuration described in the approved demonstration period plan.

(4) A clear description of each step or modification taken during the demonstration period to improve or optimize the performance of the installed NOX emission control system.

(5) Engineering design calculations and drawings that show the technical specifications for installation of any additional operational or emission control modifications installed during the demonstration period.

(6) Unit operating and quality-assured continuous emission monitoring data (including the specific data listed in §76.14(b)) collected in accordance with part 75 of this chapter during the demonstration period and demonstrating the inability of the specific unit to meet the applicable emission limitation in §76.5, 76.6, or 76.7 on an annual average basis while operating in accordance with the certification under paragraph (e)(2) of this section.

(7) A report (based on the parametric test requirements set forth in the approved demonstration period plan as identified in paragraph (d)(13) of this section), that demonstrates the unit was operated in accordance with the operating conditions upon which the design of the NOX emission control system was based and describes the reason or reasons for the failure of the installed NOX emission control system to meet the applicable emission limitation in §76.5, 76.6, or 76.7 on an annual average basis.

(8) The minimum NOX emission rate, in lb/mmBtu, that the affected unit can achieve on an annual average basis with the installed NOX emission control system. This value, which shall be the requested alternative emission limitation, shall be derived from the data specified in this section using methods and procedures satisfactory to the Administrator and shall be the lowest annual emission rate the unit can achieve with the installed NOX emission control system;

(9) All supporting data and calculations documenting the determination of the requested alternative emission limitation and its conformance with the methods and procedures satisfactory to the Administrator;

(10) The special provisions in paragraph (g)(2) of this section.

(11) In addition to the other requirements of this section, the owner or operator of an affected unit with a Group 1 boiler that has installed an alternative technology in addition to or in lieu of low NOX burner technology and cannot meet the applicable emission limitation in §76.5 shall demonstrate, to the satisfaction of the Administrator, that the actual percentage reduction in NOX emissions (lbs/mmBtu), on an annual average basis is greater than 65 percent of the average annual NOX emissions prior to the installation of the NOX emission control system. The percentage reduction in NOX emissions shall be determined using continuous emissions monitoring data for NOX taken during the time period (under paragraph (d)(3) of this section) prior to the installation of the NOX emission control system and during long-term load dispatch operation of the specific boiler.

(f) Permitting authority's action—(1) Alternative emission limitation demonstration period. (i) The permitting authority may approve an alternative emission limitation demonstration period and demonstration period plan, provided that the requirements of this section are met to the satisfaction of the permitting authority. The permitting authority shall disapprove a demonstration period if the requirements of paragraph (a) of this section were not met during the operating period.

(ii) If the demonstration period is approved, the permitting authority will include, as part of the demonstration period, the 4 month period prior to submission of the application in the demonstration period.

(iii) The alternative emission limitation demonstration period will authorize the unit to emit at a rate not greater than the interim alternative emission limitation during the demonstration period on or after January 1, 1996 for Phase I units and the applicable date established in §76.6 or 76.7 for Phase II units, and until the date that the Administrator approves or denies a final alternative emission limitation.

(iv) After an alternative emission limitation demonstration period is approved, if the designated representative requests an extension of the demonstration period in accordance with paragraph (g)(1)(i)(B) of this section, the permitting authority may extend the demonstration period by administrative amendment (under §72.83 of this chapter) to the Acid Rain permit.

(v) The permitting authority shall deny the demonstration period if the designated representative cannot demonstrate that the unit met the requirements of paragraph (a)(2) of this section. In such cases, the permitting authority shall require that the owner or operator operate the unit in compliance with the applicable emission limitation in §76.5, 76.6, or 76.7 for the period preceding the submission of the application for an alternative emission limitation demonstration period, including the operating period, if such periods are after the date on which the unit is subject to the standard limit under §76.5, 76.6, or 76.7.

(2) Alternative emission limitation. (i) If the permitting authority determines that the requirements in this section are met, the permitting authority will approve an alternative emission limitation and issue or revise an Acid Rain permit to apply the approved limitation, in accordance with subparts F and G of part 72 of this chapter. The permit will authorize the unit to emit at a rate not greater than the approved alternative emission limitation, starting the date the permitting authority revises an Acid Rain permit to approve an alternative emission limitation.

(ii) If a permitting authority disapproves an alternative emission limitation under paragraph (a)(2) of this section, the owner or operator shall operate the affected unit in compliance with the applicable emission limitation in §76.5, 76.6, or 76.7 (unless the unit is participating in an approved averaging plan under §76.11) beginning on the date the permitting authority revises an Acid Rain permit to disapprove an alternative emission limitation.

(3) Alternative emission limitation renewal. (i) If, upon review of a petition to renew an approved alternative emission limitation, the permitting authority determines that no changes have been made to the control technology, its operation, the operating conditions on which the alternative emission limitation was based, or the actual NOX emission rate, the alternative emission limitation will be renewed.

(ii) If the permitting authority determines that changes have been made to the control technology, its operation, the fuel quality, or the operating conditions on which the alternative emission limitation was based, the designated representative shall submit, in order to renew the alternative emission limitation or to obtain a new alternative emission limitation, a petition for an alternative emission limitation demonstration period that meets the requirements of paragraph (d) of this section using a new demonstration period.

(g) Special provisions—(1) Alternative emission limitation demonstration period—(i) Emission limitations. (A) Each unit with an approved alternative emission limitation demonstration period shall comply with the interim emission limitation specified in the unit's permit beginning on the effective date of the demonstration period specified in the permit and, if a timely petition for a final alternative emission limitation is submitted, extending until the date on which the permitting authority issues or revises an Acid Rain permit to approve or disapprove an alternative emission limitation. If a timely petition is not submitted, then the unit shall comply with the standard emission limit under §76.5, 76.6, or 76.7 beginning on the date the petition was required to be submitted under paragraph (c)(2) of this section.

(B) When the owner or operator identifies, during the demonstration period, boiler operating or NOX emission control system modifications or upgrades that would produce further NOX emission reductions, enabling the affected unit to comply with or bring its emission rate closer to the applicable emissions limitation under §76.5, 76.6, or 76.7, the designated representative may submit a request and the permitting authority may grant, by administrative amendment under §72.83 of this chapter, an extension of the demonstration period for such period of time (not to exceed 12 months) as may be necessary to implement such modifications or upgrades.

(C) If the approved interim alternative emission limitation applies to a unit for part, but not all, of a calendar year, the unit shall determine compliance for the calendar year in accordance with the procedures in §76.13(a).

(ii) Operating requirements. (A) A unit with an approved alternative emission limitation demonstration period shall be operated under load dispatch conditions consistent with the operating conditions upon which the design of the NOX emission control system and performance guarantee were based, and in accordance with the demonstration period plan.

(B) A unit with an approved alternative emission limitation demonstration period shall install all NOX emission control systems, make any operational modifications, and complete any upgrades and maintenance to equipment specified in the approved demonstration period plan for optimizing NOX emission reduction performance.

(C) When the owner or operator identifies boiler or NOX emission control system operating modifications that would produce higher NOX emission reductions, enabling the affected unit to comply with, or bring its emission rate closer to, the applicable emission limitation under §76.5, 76.6, or 76.7, the designated representative shall submit an administrative amendment under §72.83 of this chapter to revise the unit's Acid Rain permit and demonstration period plan to include such modifications.

(iii) Testing requirements. A unit with an approved alternative emission limitation demonstration period shall monitor in accordance with part 75 of this chapter and shall conduct all tests required under the approved demonstration period plan.

(2) Final alternative emission limitation—(i) Emission limitations. (A) Each unit with an approved alternative emission limitation shall comply with the alternative emission limitation specified in the unit's permit beginning on the date specified in the permit as issued or revised by the permitting authority to apply the final alternative emission limitation.

(B) If the approved interim or final alternative emission limitation applies to a unit for part, but not all, of a calendar year, the unit shall determine compliance for the calendar year in accordance with the procedures in §76.13(a).

[60 FR 18761, Apr. 13, 1995, as amended at 61 FR 67163, Dec. 19, 1996]

§76.11   Emissions averaging.

(a) General provisions. In lieu of complying with the applicable emission limitation in §76.5, 76.6, or 76.7, any affected units subject to such emission limitation, under control of the same owner or operator, and having the same designated representative may average their NOX emissions under an averaging plan approved under this section.

(1) Each affected unit included in an averaging plan for Phase I shall be a Phase I unit with a Group 1 boiler subject to an emission limitation in §76.5 during all years for which the unit is included in the plan.

(i) If a unit with an approved NOX compliance extension is included in an averaging plan for 1996, the unit shall be treated, for the purposes of applying Equation 1 in paragraph (a)(6) of this section and Equation 2 in paragraph (d)(1)(ii)(A) of this section, as subject to the applicable emissions limitation under §76.5 for the entire year 1996.

(ii) A Phase II unit approved for early election under §76.8 shall not be included in an averaging plan for Phase I.

(2) Each affected unit included in an averaging plan for Phase II shall be a boiler subject to an emission limitation in §76.5, 76.6, or 76.7 for all years for which the unit is included in the plan.

(3) Each unit included in an averaging plan shall have an alternative contemporaneous annual emission limitation (lb/mmBtu) and can only be included in one averaging plan.

(4) Each unit included in an averaging plan shall have a minimum allowable annual heat input value (mmBtu), if it has an alternative contemporaneous annual emission limitation more stringent than that unit's applicable emission limitation under §76.5, 76.6, or 76.7, and a maximum allowable annual heat input value, if it has an alternative contemporaneous annual emission limitation less stringent than that unit's applicable emission limitation under §76.5, 76.6, or 76.7.

(5) The Btu-weighted annual average emission rate for the units in an averaging plan shall be less than or equal to the Btu-weighted annual average emission rate for the same units had they each been operated, during the same period of time, in compliance with the applicable emission limitations in §76.5, 76.6, or 76.7.

(6) In order to demonstrate that the proposed plan is consistent with paragraph (a)(5) of this section, the alternative contemporaneous annual emission limitations and annual heat input values assigned to the units in the proposed averaging plan shall meet the following requirement:

eCFR graphic er13ap95.000.gif

View or download PDF

where:

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

Rli = Applicable emission limitation for unit i, lb/mmBtu, as specified in §76.5, 76.6, or 76.7 except that for early election units, which may be included in an averaging plan only on or after January 1, 2000, Rli shall equal the most stringent applicable emission 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 alternative emission limitation, Rli shall equal the applicable emissions limitation under §76.5, 76.6, or 76.7, not the alternative emissions limitation.

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

(b)(1) Submission requirements. The designated representative of a unit meeting the requirements of paragraphs (a)(1), (a)(2), and (a)(8) of this section may submit an averaging plan (or a revision to an approved averaging plan) to the permitting authority(ies) at any time up to and including January 1 (or July 1, if the plan is restricted to units located within a single permitting authority's jurisdiction) of the calendar year for which the averaging plan is to become effective.

(2) The designated representative shall submit a copy of the same averaging plan (or the same revision to an approved averaging plan) to each permitting authority with jurisdiction over a unit in the plan.

(3) When an averaging plan (or a revision to an approved averaging plan) is not approved, the owner or operator of each unit in the plan shall operate the unit in compliance with the emission limitation that would apply in the absence of the averaging plan (or revision to a plan).

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

(1) Identification of each unit in the plan;

(2) Each unit's applicable emission limitation in §76.5, 76.6, or 76.7;

(3) The alternative contemporaneous annual emission limitation for each unit (in lb/mmBtu). If any of the units identified in the NOX averaging plan utilize a common stack pursuant to §75.17(a)(2)(i)(B) of this chapter, the same alternative contemporaneous emission limitation shall be assigned to each such unit and different heat input limits may be assigned;

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

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

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

(7) The special provisions in paragraph (d)(1) of this section.

(d) Special provisions—(1) Emission limitations. Each affected unit in an approved averaging plan is in compliance with the Acid Rain emission limitation for NOX under the plan only if the following requirements are met:

(i) For each unit, the unit's actual annual average emission rate for the calendar year, in lb/mmBtu, is less than or equal to its alternative contemporaneous annual emission limitation in the averaging plan; and

(A) For each unit with an alternative contemporaneous emission limitation less stringent than the applicable emission limitation in §76.5, 76.6, or 76.7, the actual annual heat input for the calendar year does not exceed the annual heat input limit in the averaging plan;

(B) For each unit with an alternative contemporaneous annual emission limitation more stringent than the applicable emission limitation in §76.5, 76.6, or 76.7, the actual annual heat input for thecalendar year is not less than the annual heat input limit in the averaging plan; or

(ii) If one or more of the units does not meet the requirements under paragraph (d)(1)(i) of this section, the designated representative shall demonstrate, in accordance with paragraph (d)(1)(ii)(A) of this section (Equation 2) that the actual Btu-weighted annual average emission rate for the units in the plan is less than or equal to the Btu-weighted annual average rate for the same units had they each been operated, during the same period of time, in compliance with the applicable emission limitations in §76.5, 76.6, or 76.7.

(A) A group showing of compliance shall be made based on the following equation:

eCFR graphic er13ap95.001.gif

View or download PDF

where:

Rai = Actual annual average emission rate for unit i, lb/mmBtu, as determined using the procedures in part 75 of this chapter. For units in an averaging plan utilizing a common stack pursuant to §75.17(a)(2)(i)(B) of this chapter, use the same NOX emission rate value for each unit utilizing the common stack, and calculate this value in accordance with appendix F to part 75 of this chapter;

Rli = Applicable annual emission limitation for unit i lb/mmBtu, as specified in §76.5, 76.6, or 76.7, except that for early election units, which may be included in an averaging plan only on or after January 1, 2000, Rli shall equal the most stringent applicable emission limitation under §76.5 or 76.7;

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

n = Number of units in the averaging plan.

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

(C) If there is a successful group showing of compliance under paragraph (d)(1)(ii)(A) of this section for a calendar year, then all units in the averaging plan shall be deemed to be in compliance for that year with their alternative contemporaneous emission limitations and annual heat input limits under paragraph (d)(1)(i) of this section.

(2) Liability. The owners and operators of a unit governed by an approved averaging plan shall be liable for any violation of the plan or this section at that unit or any other unit in the plan, including liability for fulfilling the obligations specified in part 77 of this chapter and sections 113 and 411 of the Act.

(3) Withdrawal or termination. The designated representative may submit a notification to terminate an approved averaging plan in accordance with §72.40(d) of this chapter, no later than October 1 of the calendar year for which the plan is to be withdrawn or terminated.

§76.12   Phase I NOX compliance extension.

(a) General provisions. (1) The designated representative of a Phase I unit with a Group 1 boiler may apply for and receive a 15-month extension of the deadline for meeting the applicable emissions limitation under §76.5 where it is demonstrated, to the satisfaction of the Administrator, that:

(i) The low NOX burner technology designed to meet the applicable emission limitation is not in adequate supply to enable installation and operation at the unit, consistent with system reliability, by January 1, 1995 and the reliability problems are due substantially to NOX emission control system installation and availability; or

(ii) The unit is participating in an approved clean coal technology demonstration project.

(2) In order to obtain a Phase I NOX compliance extension, the designated representative shall submit a Phase I NOX compliance extension plan by October 1, 1994.

(b) Contents of Phase I NOX compliance extension plan. A complete Phase I NOX compliance extension plan shall include the following elements in a format 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, addresses, and telephone numbers of vendors who are qualified to provide the services and low NOX burner technology designed to meet the applicable emission limitation under §76.5 and have been contacted to obtain the required services and technology. The list shall include the dates of contact, and a copy of each request for bids shall be submitted, along with any other information necessary to show a good-faith effort to obtain the required services and technology necessary to meet the requirements of this part on or before January 1, 1995.

(ii) A copy of those portions of a legally binding contract with a qualified vendor that demonstrate that services and low NOX burner technology designed to meet the applicable emission limitation under §76.5, with a completion date not later than December 31, 1995 have been contracted for.

(iii) Scheduling information, including justification and test schedules.

(iv) To demonstrate, if applicable, that the supply of the low NOX burner technology designed to meet the applicable emission limitation under §76.5 is inadequate to enable its installation and operation at the unit, consistent with system reliability, in time for the unit to comply with the applicable emission limitation on or before January 1, 1995, either:

(A) Certification from the selected vendor(s) (by a certifying official) listed in paragraph (b)(2)(i) of this section stating that they cannot provide the necessary services and install the low NOX burner technology on or before January 1, 1995 and explaining the reasons why the services cannot be provided and why the equipment cannot be installed in a timely manner; or

(B) The following information:

(i) Standard load forecasts, based on standard forecasting models available throughout the utility industry and applied to the period, January 1, 1993, through December 31, 1994.

(ii) Specific reasons why an outage cannot be scheduled to enable the unit to install and operate the low NOX burner technology by January 1, 1995, including reasons why no other units can be used to replace this unit's generation during such outage.

(iii) Fuel and energy balance summaries and power and other consumption requirements (including those for air, steam, and cooling water).

(3) To demonstrate, if applicable, participation in an approved clean coal technology demonstration project, a description of the project, including all sources of Federal, State, and other outside funding, amount and date for approval of Federal funding, the duration of the project, and the anticipated completion date of the project.

(4) The special provisions in paragraph (d) of this section.

(c)(1) Administrator's action. To the extent the Administrator determines that a Phase I NOX compliance extension plan complies with the requirements of this section, the Administrator will approve the plan and revise the Acid Rain permit governing the unit in the plan in order to incorporate the plan by administrative amendment under §72.83 of this chapter, except that the Administrator shall have 90 days from receipt of the compliance extension plan to take final action.

(2) The Administrator will approve or disapprove a proposed NOX compliance extension plan within 3 months of receipt.

(d) Special provisions. (1) Emission limitations. The unit shall comply with the applicable emission limitation under §76.5 beginning April 1, 1996. Compliance shall be determined as specified in part 75 of this chapter using measured values of NOX emissions and heat input only for the portion of the year that the emission limit is in effect.

(2) If a unit with an approved NOX compliance extension is included in an averaging plan under §76.11 for year 1996, the unit shall be treated, for purposes of applying Equation 1 in §76.11(a)(6) and Equation 2 in §76.11(d)(1)(ii)(A), as subject to the applicable emission limitation under §76.5 for the entire year 1996.

(e) Extension until December 31, 1997. (1) The designated representative of a Phase I unit that is subject to section 404(d) of the Act, has a tangentially fired boiler, and is unable to install low NOX burner technology by January 1, 1997 may submit a petition for and receive an extension for meeting the applicable emission limitation under §76.5 where it is demonstrated, to the satisfaction of the Administrator, that:

(i) The unit is located at a source with two or more other units, all of which are Phase I units that are subject to section 404(d) of the Act and have tangentially fired boilers;

(ii) The NOX control system at the unit was scheduled to be installed by January 1, 1997 and, because of operational problems associated with the NOX control system, will be redesigned; and

(iii) Installation of the redesigned low NOX burner technology at the unit cannot be completed by January 1, 1997 without causing system reliability problems.

(2) A complete petition shall include the following elements and shall be submitted by April 28, 1995.

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

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

(iii) The earliest date, not later than December 31, 1997, by which installation of the redesigned low NOX burner technology can be completed consistent with system reliability; and

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

(3) To the extent the Administrator determines that a Phase I unit meets the requirements of paragraphs (e)(1) and (e)(2) of this section, the Administrator will approve the petition within 90 days from receipt of the complete petition. The Acid Rain permit governing the unit will be revised in order to incorporate the approved extension, which shall terminate no later than December 31, 1997, by administrative amendment under §72.83 of this chapter except that the Administrator will have 90 days to take final action.

(4) The unit shall comply with the applicable emission limitation under §76.5 beginning on the day immediately following the day on which the extension approved under paragraph (e)(3) of this section terminates. Compliance shall be determined as specified in part 75 of this chapter using measured values of NOX emissions and heat input only for the portion of the year that the emission limit is in effect. If a unit with an approved extension is included in an averaging plan under §76.11 for year 1997, the unit shall be treated, for the purpose of applying Equation 1 in §76.11(a)(6) and Equation 2 in §76.11(d)(1)(ii)(A), as subject to the applicable emission limitation under §76.5 for the entire year 1997.

§76.13   Compliance and excess emissions.

Excess emissions of nitrogen oxides under §77.6 of this chapter shall be calculated as follows:

(a) For a unit that is not in an approved averaging plan:

(1) Calculate EEi for each portion of the calendar year that the unit is subject to a different NOX emission limitation:

eCFR graphic er13ap95.002.gif

View or download PDF

where:

EEi = Excess emissions for NOX for the portion of the calendar year (in tons);

Rai = Actual average emission rate for the unit (in lb/mmBtu), determined according to part 75 of this chapter for the portion of the calendar year for which the applicable emission limitation Rl is in effect;

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

eCFR graphic er13ap95.003.gif

View or download PDF

HIi = Actual heat input for the unit, (in mmBtu), determined according to part 75 of this chapter for the portion of the calendar year for which the applicable emission limitation, Rl, is in effect.

(2) If EEi is a negative number for any portion of the calendar year, the EE value for that portion of the calendar year shall be equal to zero (e.g., if EEi = −100, then EEi = 0).

(3) Sum all EEi values for the calendar year:

where:

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

n = The number of time periods during which a unit is subject to different emission limitations; and

(b) For units participating in an approved averaging plan, when all the requirements under §76.11(d)(1) are not met,

eCFR graphic er13ap95.004.gif

View or download PDF

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), determined according to part 75 of this chapter;

Rli = Applicable emission limitation for unit i, (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 of this chapter;

n = Number of units in the averaging plan.

§76.14   Monitoring, recordkeeping, and reporting.

(a) A petition for an alternative emission limitation demonstration period under §76.10(d) shall include the following information:

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

(i) Documentation that the owner or operator solicited bids for a NOX emission control system designed for application to the specific boiler and designed to achieve the applicable emission limitation in §76.5, 76.6, or 76.7 on an annual average basis. This documentation must include a copy of all bid specifications.

(ii) A copy of the performance guarantee submitted by the vendor of the installed NOX emission control system to the owner or operator showing that such system was designed to meet the applicable emission limitation in §76.5, 76.6, or 76.7 on an annual average basis.

(iii) Documentation describing the operational and combustion conditions that are the basis of the performance guarantee.

(iv) Certification by the primary vendor of the NOX emission control system that such equipment and associated auxiliary equipment was properly installed according to the modifications and procedures specified by the vendor.

(v) Certification by the designated representative that the owner(s) or operator installed technology that meets the requirements of §76.10(a)(2).

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

(i) The operating conditions of the NOX emission control system including load range, O2 range, coal volatile matter range, and, for tangentially fired boilers, distribution of combustion air within the NOX emission control system;

(ii) Certification by the designated representative that the owner(s) or operator have achieved and are following the operating conditions, boiler modifications, and upgrades that formed the basis for the system design and performance guarantee;

(iii) Any planned equipment modifications and upgrades for the purpose of achieving the maximum NOX reduction performance of the NOX emission control system that were not included in the design specifications and performance guarantee, but that were achieved prior to submission of this application and are being followed;

(iv) A list of any modifications or replacements of equipment that are to be done prior to the completion of the demonstration period for the purpose of reducing emissions of NOX; and

(v) The parametric testing that will be conducted to determine the reason or reasons for the failure of the unit to achieve the applicable emission limitation and to verify the proper operation of the installed NOX emission control system during the demonstration period. The tests shall include tests in §76.15, which may be modified as follows:

(A) The owner or operator of the unit may add tests to those listed in §76.15, if such additions provide data relevant to the failure of the installed NOX emission control system to meet the applicable emissions limitation in §76.5, 76.6, or 76.7; or

(B) The owner or operator of the unit may remove tests listed in §76.15 that are shown, to the satisfaction of the permitting authority, not to be relevant to NOX emissions from the affected unit; and

(C) In the event the performance guarantee or the NOX emission control system specifications require additional tests not listed in §76.15, or specify operating conditions not verified by tests listed in §76.15, the owner or operator of the unit shall include such additional tests.

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

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

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

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

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

(v) Total integrated hourly gross unit load (in MWge).

(b) A petition for an alternative emission limitation shall include the following information in accordance with §76.10(e)(6).

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

(2) Hourly NOX emission rate (in lb/mmBtu), calculated in accordance with the requirements of part 75 of this chapter; and

(3) Total integrated hourly gross unit load (MWge).

(c) Reporting of the costs of low NOX burner technology applied to Group 1, Phase I boilers. (1) Except as provided in paragraph (c)(2) of this section, the designated representative of a Phase I unit with a Group 1 boiler that has installed or is installing any form of low NOX burner technology shall submit to the Administrator a report containing the capital cost, operating cost, and baseline and post-retrofit emission data specified in appendix B to this part. If any of the required equipment, cost, and schedule information are not available (e.g., the retrofit project is still underway), the designated representative shall include in the report detailed cost estimates and other projected or estimated data in lieu of the information that is not available.

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

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

(ii) Units employing modifications to boiler operating parameters (e.g., burners out of service or fuel switching) without low NOX burners or other emission reduction equipment for reducing NOX emissions;

(iii) Units with wall-fired boilers employing only overfire air and units with tangentially fired boilers employing only separated overfire air; or

(iv) Units beginning installation of a new NOX emission control system after August 11, 1995.

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

(i) 120 days after completion of the low NOX burner technology retrofit project; or

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

§76.15   Test methods and procedures.

(a) The owner or operator may use the following tests as a basis for the report required by §76.10(e)(7):

(1) Conduct an ultimate analysis of coal using ASTM D 3176-89 (incorporated by reference as specified in §76.4);

(2) Conduct a proximate analysis of coal using ASTM D 3172-89 (incorporated by reference as specified in §76.4); and

(3) Measure the coal mass flow rate to each individual burner using ASME Power Test Code 4.2 (1991), “Test Code for Coal Pulverizers” or ISO 9931 (1991), “Coal—Sampling of Pulverized Coal Conveyed by Gases in Direct Fired Coal Systems” (incorporated by reference as specified in §76.4).

(b) The owner or operator may measure and record the actual NOX emission rate in accordance with the requirements of this part while varying the following parameters where possible to determine their effects on the emissions of NOX from the affected boiler:

(1) Excess air levels;

(2) Settings of burners or coal and air nozzles, including tilt and yaw, or swirl;

(3) For tangentially fired boilers, distribution of combustion air within the NOX emission control system;

(4) Coal mass flow rates to each individual burner;

(5) Coal-to-primary air ratio (based on pound per hour) for each burner, the average coal-to-primary air ratio for all burners, and the deviations of individual burners' coal-to-primary air ratios from the average value; and

(6) If the boiler uses varying types of coal, the type of coal. Provide the results of proximate and ultimate analyses of each type of as-fired coal.

(c) In performing the tests specified in paragraph (a) of this section, the owner or operator shall begin the tests using the equipment settings for which the NOX emission control system was designed to meet the NOX emission rate guaranteed by the primary NOX emission control system vendor. These results constitute the “baseline controlled” condition.

(d) After establishing the baseline controlled condition under paragraph (c) of this section, the owner or operator may:

(1) Change excess air levels ±5 percent from the baseline controlled condition to determine the effects on emissions of NOX, by providing a minimum of three readings (e.g., with a baseline reading of 20 percent excess air, excess air levels will be changed to 19 percent and 21 percent);

(2) For tangentially fired boilers, change the distribution of combustion air within the NOX emission control system to determine the effects on NOX emissions by providing a minimum of three readings, one with the minimum, one with the baseline, and one with the maximum amounts of staged combustion air; and

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

   

Appendix A to Part 76—Phase I Affected Coal-Fired Utility Units With Group 1 or Cell Burner Boilers

Table 1—Phase I Tangentially Fired Units

StatePlantUnitOperator
ALABAMAEC GASTON5ALABAMA POWER CO.
GEORGIABOWEN1BLRGEORGIA POWER CO.
GEORGIABOWEN2BLRGEORGIA POWER CO.
GEORGIABOWEN3BLRGEORGIA POWER CO.
GEORGIABOWEN4BLRGEORGIA POWER CO.
GEORGIAJACK MCDONOUGHMB1GEORGIA POWER CO.
GEORGIAJACK MCDONOUGHMB2GEORGIA POWER CO.
GEORGIAWANSLEY1GEORGIA POWER CO.
GEORGIAWANSLEY2GEORGIA POWER CO.
GEORGIAYATESY1BRGEORGIA POWER CO.
GEORGIAYATESY2BRGEORGIA POWER CO.
GEORGIAYATESY3BRGEORGIA POWER CO.
GEORGIAYATESY4BRGEORGIA POWER CO.
GEORGIAYATESY5BRGEORGIA POWER CO.
GEORGIAYATESY6BRGEORGIA POWER CO.
GEORGIAYATESY7BRGEORGIA POWER CO.
ILLINOISBALDWIN3ILLINOIS POWER CO.
ILLINOISHENNEPIN2ILLINOIS POWER CO.
ILLINOISJOPPA1ELECTRIC ENERGY INC.
ILLINOISJOPPA2ELECTRIC ENERGY INC.
ILLINOISJOPPA3ELECTRIC ENERGY INC.
ILLINOISJOPPA4ELECTRIC ENERGY INC.
ILLINOISJOPPA5ELECTRIC ENERGY INC.
ILLINOISJOPPA6ELECTRIC ENERGY INC.
ILLINOISMEREDOSIA5CEN ILLINOIS PUB SER.
ILLINOISVERMILION2ILLINOIS POWER CO.
INDIANACAYUGA1PSI ENERGY INC.
INDIANACAYUGA2PSI ENERGY INC.
INDIANAEW STOUT50INDIANAPOLIS PWR & LT.
INDIANAEW STOUT60INDIANAPOLIS PWR & LT.
INDIANAEW STOUT70INDIANAPOLIS PRW & LT.
INDIANAHT PRITCHARD6INDIANAPOLIS PWR & LT.
INDIANAPETERSBURG1INDIANAPOLIS PWR & LT.
INDIANAPETERSBURG2INDIANAPOLIS PWR & LT.
INDIANAWABASH RIVER6PSI ENERGY INC.
IOWABURLINGTON1IOWA SOUTHERN UTL.
IOWAML KAPP2INTERSTATE POWER CO.
IOWARIVERSIDE9IOWA-ILL GAS & ELEC.
KENTUCKYELMER SMITH2OWENSBORO MUN UTIL.
KENTUCKYEW BROWN2KENTUCKY UTL CO.
KENTUCKYEW BROWN3KENTUCKY UTL CO.
KENTUCKYGHENT1KENTUCKY UTL CO.
MARYLANDMORGANTOWN1POTOMAC ELEC PWR CO.
MARYLANDMORGANTOWN2POTOMAC ELEC PWR CO.
MICHIGANJH CAMPBELL1CONSUMERS POWER CO.
MISSOURILABADIE1UNION ELECTRIC CO.
MISSOURILABADIE2UNION ELECTRIC CO.
MISSOURILABADIE3UNION ELECTRIC CO.
MISSOURILABADIE4UNION ELECTRIC CO.
MISSOURIMONTROSE1KANSAS CITY PWR & LT.
MISSOURIMONTROSE2KANSAS CITY PWR & LT.
MISSOURIMONTROSE3KANSAS CITY PWR & LT.
NEW YORKDUNKIRK3NIAGARA MOHAWK PWR.
NEW YORKDUNKIRK4NIAGARA MOHAWK PWR.
NEW YORKGREENIDGE6NY STATE ELEC & GAS.
NEW YORKMILLIKEN1NY STATE ELEC & GAS.
NEW YORKMILLIKEN2NY STATE ELEC & GAS.
OHIOASHTABULA7CLEVELAND ELEC ILLUM.
OHIOAVON LAKE11CLEVELAND ELEC ILLUM.
OHIOCONESVILLE4COLUMBUS STHERN PWR.
OHIOEASTLAKE1CLEVELAND ELEC ILLUM.
OHIOEASTLAKE2CLEVELAND ELEC ILLUM.
OHIOEASTLAKE3CLEVELAND ELEC ILLUM.
OHIOEASTLAKE4CLEVELAND ELEC ILLUM.
OHIOMIAMI FORT6CINCINNATI GAS & ELEC.
OHIOWC BECKJORD5CINCINNATI GAS & ELEC.
OHIOWC BECKJORD6CINCINNATI GAS & ELEC.
PENNSYLVANIABRUNNER ISLAND1PENNSYLVANIA PWR & LT.
PENNSYLVANIABRUNNER ISLAND2PENNSYLVANIA PWR & LT.
PENNSYLVANIABRUNNER ISLAND3PENNSYLVANIA PWR & LT.
PENNSYLVANIACHESWICK1DUQUESNE LIGHT CO.
PENNSYLVANIACONEMAUGH1PENNSYLVANIA ELEC CO.
PENNSYLVANIACONEMAUGH2PENNSYLVANIA ELEC CO.
PENNSYLVANIAPORTLAND1METROPOLITAN EDISON.
PENNSYLVANIAPORTLAND2METROPOLITAN EDISON.
PENNSYLVANIASHAWVILLE3PENNSYLVANIA ELEC CO.
PENNSYLVANIASHAWVILLE4PENNSYLVANIA ELEC CO.
TENNESSEEGALLATIN1TENNESSEE VAL AUTH.
TENNESSEEGALLATIN2TENNESSEE VAL AUTH.
TENNESSEEGALLATIN3TENNESSEE VAL AUTH.
TENNESSEEGALLATIN4TENNESSEE VAL AUTH.
TENNESSEEJOHNSONVILLE1TENNESSEE VAL AUTH.
TENNESSEEJOHNSONVILLE2TENNESSEE VAL AUTH.
TENNESSEEJOHNSONVILLE3TENNESSEE VAL AUTH.
TENNESSEEJOHNSONVILLE4TENNESSEE VAL AUTH.
TENNESSEEJOHNSONVILLE5TENNESSEE VAL AUTH.
TENNESSEEJOHNSONVILLE6TENNESSEE VAL AUTH.
WEST VIRGINIAALBRIGHT3MONONGAHELA POWER CO.
WEST VIRGINIAFORT MARTIN1MONONGAHELA POWER CO.
WEST VIRGINIAMOUNT STORM1VIRGINIA ELEC & PWR.
WEST VIRGINIAMOUNT STORM2VIRGINIA ELEC & PWR.
WEST VIRGINIAMOUNT STORM3VIRGINIA ELEC & PWR.
WISCONSINGENOA1DAIRYLAND POWER COOP.
WISCONSINSOUTH OAK CREEK7WISCONSIN ELEC POWER.
WISCONSINSOUTH OAK CREEK8WISCONSIN ELEC POWER.

Table 2—Phase I Dry Bottom-Fired Units

StatePlantUnitOperator
ALABAMACOLBERT1TENNESSEE VAL AUTH.
ALABAMACOLBERT2TENNESSEE VAL AUTH.
ALABAMACOLBERT3TENNESSEE VAL AUTH.
ALABAMACOLBERT4TENNESSEE VAL AUTH.
ALABAMACOLBERT5TENNESSEE VAL AUTH.
ALABAMAEC GASTON1ALABAMA POWER CO.
ALABAMAEC GASTON2ALABAMA POWER CO.
ALABAMAEC GASTON3ALABAMA POWER CO.
ALABAMAEC GASTON4ALABAMA POWER CO.
FLORIDACRIST6GULF POWER CO.
FLORIDACRIST7GULF POWER CO.
GEORGIAHAMMOND1GEORGIA POWER CO.
GEORGIAHAMMOND2GEORGIA POWER CO.
GEORGIAHAMMOND3GEORGIA POWER CO.
GEORGIAHAMMOND4GEORGIA POWER CO.
ILLINOISGRAND TOWER9CEN ILLINOIS PUB SER.
INDIANACULLEY2STHERN IND GAS & EL.
INDIANACULLEY3STHERN IND GAS & EL.
INDIANAGIBSON1PSI ENERGY INC.
INDIANAGIBSON2PSI ENERGY INC.
INDIANAGIBSON3PSI ENERGY INC.
INDIANAGIBSON4PSI ENERGY INC.
INDIANARA GALLAGHER1PSI ENERGY INC.
INDIANARA GALLAGHER2PSI ENERGY INC.
INDIANARA GALLAGHER3PSI ENERGY INC.
INDIANARA GALLAGHER4PSI ENERGY INC.
INDIANAFRANK E RATTS1SG1HOOSIER ENERGY REC.
INDIANAFRANK E RATTS2SG1HOOSIER ENERGY REC.
INDIANAWABASH RIVER1PSI ENERGY INC.
INDIANAWABASH RIVER2PSI ENERGY INC.
INDIANAWABASH RIVER3PSI ENERGY INC.
INDIANAWABASH RIVER5PSI ENERGY INC.
IOWADES MOINES11IOWA PWR & LT CO.
IOWAPRAIRIE CREEK4IOWA ELEC LT & PWR.
KANSASQUINDARO2KS CITY BD PUB UTIL.
KENTUCKYCOLEMANC1BIG RIVERS ELEC CORP.
KENTUCKYCOLEMANC2BIG RIVERS ELEC CORP.
KENTUCKYCOLEMANC3BIG RIVERS ELEC CORP.
KENTUCKYEW BROWN1KENTUCKY UTL CO.
KENTUCKYGREEN RIVER5KENTUCKY UTL CO.
KENTUCKYHMP&L STATION 2H1BIG RIVERS ELEC CORP.
KENTUCKYHMP&L STATION 2H2BIG RIVERS ELEC CORP.
KENTUCKYHL SPURLOCK1EAST KY PWR COOP.
KENTUCKYJS COOPER1EAST KY PWR COOP.
KENTUCKYJS COOPER2EAST KY PWR COOP.
MARYLANDCHALK POINT1POTOMAC ELEC PWR CO.
MARYLANDCHALK POINT2POTOMAC ELEC PWR CO.
MINNESOTAHIGH BRIDGE6NORTHERN STATES PWR.
MISSISSIPPIJACK WATSON4MISSISSIPPI PWR CO.
MISSISSIPPIJACK WATSON5MISSISSIPPI PWR CO.
MISSOURIJAMES RIVER5SPRINGFIELD UTL.
OHIOCONESVILLE3COLUMBUS STHERN PWR.
OHIOEDGEWATER13OHIO EDISON CO.
OHIOMIAMI FORT15-1CINCINNATI GAS&ELEC.
OHIOMIAMI FORT15-2CINCINNATI GAS&ELEC.
OHIOPICWAY9COLUMBUS STHERN PWR.
OHIORE BURGER7OHIO EDISON CO.
OHIORE BURGER8OHIO EDISON CO.
OHIOWH SAMMIS5OHIO EDISON CO.
OHIOWH SAMMIS6OHIO EDISON CO.
PENNSYLVANIAARMSTRONG1WEST PENN POWER CO.
PENNSYLVANIAARMSTRONG2WEST PENN POWER CO.
PENNSYLVANIAMARTINS CREEK1PENNSYLVANIA PWR & LT.
PENNSYLVANIAMARTINS CREEK2PENNSYLVANIA PWR & LT.
PENNSYLVANIASHAWVILLE1PENNSYLVANIA ELEC CO.
PENNSYLVANIASHAWVILLE2PENNSYLVANIA ELEC CO.
PENNSYLVANIASUNBURY3PENNSYLVANIA PWR & LT.
PENNSYLVANIASUNBURY4PENNSYLVANIA PWR & LT.
TENNESSEEJOHNSONVILLE7TENNESSEE VAL AUTH.
TENNESSEEJOHNSONVILLE8TENNESSEE VAL AUTH.
TENNESSEEJOHNSONVILLE9TENNESSEE VAL AUTH.
TENNESSEEJOHNSONVILLE10TENNESSEE VAL AUTH.
WEST VIRGINIAHARRISON1MONONGAHELA POWER CO.
WEST VIRGINIAHARRISON2MONONGAHELA POWER CO.
WEST VIRGINIAHARRISON3MONONGAHELA POWER CO.
WEST VIRGINIAMITCHELL1OHIO POWER CO.
WEST VIRGINIAMITCHELL2OHIO POWER CO.
WISCONSINJP PULLIAM8WISCONSIN PUB SER CO.
WISCONSINNORTH OAK CREEK21WISCONSIN ELEC PWR.
WISCONSINNORTH OAK CREEK22WISCONSIN ELEC PWR.
WISCONSINNORTH OAK CREEK23WISCONSIN ELEC PWR.
WISCONSINNORTH OAK CREEK24WISCONSIN ELEC PWR.
WISCONSINSOUTH OAK CREEK25WISCONSIN ELEC PWR.
WISCONSINSOUTH OAK CREEK26WISCONSIN ELEC PWR.

1Vertically fired boiler.

2Arch-fired boiler.

Table 3—Phase I Cell Burner Technology Units

StatePlantUnitOperator
INDIANAWARRICK4STHERN IND GAS & EL.
MICHIGANJH CAMPBELL2CONSUMERS POWER CO.
OHIOAVON LAKE12CLEVELAND ELEC ILLUM.
OHIOCARDINAL1CARDINAL OPERATING.
OHIOCARDINAL2CARDINAL OPERATING.
OHIOEASTLAKE5CLEVELAND ELEC ILLUM.
OHIOGENRL JM GAVIN1OHIO POWER CO.
OHIOGENRL JM GAVIN2OHIO POWER CO.
OHIOMIAMI FORT7CINCINNATI GAS & EL.
OHIOMUSKINGUM RIVER5OHIO POWER CO.
OHIOWH SAMMIS7OHIO EDISON CO.
PENNSYLVANIAHATFIELDS FERRY1WEST PENN POWER CO.
PENNSYLVANIAHATFIELDS FERRY2WEST PENN POWER CO.
PENNSYLVANIAHATFIELDS FERRY3WEST PENN POWER CO.
TENNESSEECUMBERLAND1TENNESSEE VAL AUTH.
TENNESSEECUMBERLAND2TENNESSEE VAL AUTH.
WEST VIRGINIAFORT MARTIN2MONONGAHELA POWER CO.

Appendix B to Part 76—Procedures and Methods for Estimating Costs of Nitrogen Oxides Controls Applied to Group 1, Boilers

1. Purpose and Applicability

This technical appendix specifies the procedures, methods, and data that the Administrator will use in establishing “***the degree of reduction achievable through this retrofit application of the best system of continuous emission reduction, taking into account available technology, costs, and energy and environmental impacts; and which is comparable to the costs of nitrogen oxides controls set pursuant to subsection (b)(1) (of section 407 of the Act).” In developing the allowable NOX emissions limitations for Group 2 boilers pursuant to subsection (b)(2) of section 407 of the Act, the Administrator will consider only those systems of continuous emission reduction that, when applied on a retrofit basis, are comparable in cost to the cost in constant dollars of low NOX burner technology applied to Group 1, Phase I boilers.

The Administrator will evaluate the capital cost (in dollars per kilowatt electrical ($/kW)), the operating and maintenance costs (in $/year), and the cost-effectiveness (in annualized $/ton NOX removed) of installed low NOX burner technology controls over a range of boiler sizes (as measured by the gross electrical capacity of the associated generator in megawatt electrical (MW)) and utilization rates (in percent gross nameplate capacity on an annual basis) to develop estimates of the capital costs and cost effectiveness for Group 1, Phase I boilers. The following units will be excluded from these determinations of the capital costs and cost effectiveness of NOX controls set pursuant to subsection (b)(1) of section 407 of the Act: (1) Units employing an alternative technology, or overfire air as applied to wall-fired boilers or separated overfire air as applied to tangentially fired boilers, in lieu of low NOX burner technology for reducing NOX emissions; (2) units employing no controls, only controls installed before November 15, 1990, or only modifications to boiler operating parameters (e.g., burners out of service or fuel switching) for reducing NOX emissions; and (3) units that have not achieved the applicable emission limitation.

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

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

2.1   Using cost data submitted pursuant to the reporting requirements in section 4 below, boiler-specific actual or estimated actual capital costs will be determined for each unit in the population specified in section 1 above for assessing the costs of installed low NOX burner technology. The scope of installed low NOX burner technology costs will include the following capital costs for retrofit application: (1) For the burner portion—burners or air and coal nozzles, burner throat and waterwall modifications, and windbox modifications; and, where applicable, (2) for the combustion air staging portion—waterwall modifications or panels, windbox modifications, and ductwork, and (3) scope adders or supplemental equipment such as replacement or additional fans, dampers, or ignitors necessary for the proper operation of the low NOX burner technology. Capital costs associated with boiler restoration or refurbishment such as replacement of air heaters, asbestos abatement, and recasing will not be included in the cost basis for installed low NOX burner technology. The scope of installed low NOX burner technology retrofit capital costs will include materials, construction and installation labor, engineering, and overhead costs.

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

2.3   Capital cost curves ($/kW versus boiler size in MW) or equations for installed low NOX burner technology retrofit costs will be developed for: (1) Dry bottom wall fired boilers (excluding units applying cell burner technology) and (2) tangentially fired boilers.

3. [Reserved]

4. Reporting Requirements

4.1   The following information is to be submitted by each designated representative of a Phase I affected unit subject to the reporting requirements of §76.14(c):

4.1.1   Schedule and dates for baseline testing, installation, and performance testing of low NOX burner technology.

4.1.2   Estimates of the annual average baseline NOX emission rate, as specified in section 3.1.1, and the annual average controlled NOX emission rate, as specified in section 3.1.2, including the supporting continuous emission monitoring or other test data.

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

4.1.4   Detailed estimates of the capital costs based on actual contract bids for each component of the installed low NOX burner technology including the items listed in section 2.1. Indicate number of bids solicited. Provide a copy of the actual agreement for the installed technology.

4.1.5   Detailed estimates of the capital costs of system replacements or upgrades such as coal pipe changes, fan replacements/upgrades, or mill replacements/upgrades undertaken as part of the low NOX burner technology retrofit project.

4.1.6   Detailed breakdown of the actual costs of the completed low NOX burner technology retrofit project where low NOX burner technology costs (section 4.1.4) are disaggregated, if feasible, from system replacement or upgrade costs (section 4.1.5).

4.1.7   Description of the probable causes for significant differences between actual and estimated low NOX burner technology retrofit project costs.

4.1.8   Detailed breakdown of the burner and, if applicable, combustion air staging system annual operating and maintenance costs for the items listed in section 3.3 before and after the installation, shakedown, and/or optimization of the installed low NOX burner technology. Include estimates and a description of the probable causes of the incremental annual operating and maintenance costs (or savings) attributable to the installed low NOX burner technology.

4.2   All capital cost estimates are to be broken down into materials costs, construction and installation labor costs, and engineering and overhead costs. All operating and maintenance costs are to be broken down into maintenance materials costs, maintenance labor costs, operating labor costs, and fan electricity costs. All capital and operating costs are to be reported in dollars with the year of expenditure or estimate specified for each component.

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

Need assistance?