PART 76—ACID RAIN NITROGEN OXIDES EMISSION REDUCTION PROGRAM 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 SO 2 (b) The emission limitations for NO X 2 (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 SO 2 (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 X X Alternative technology X X Approved clean coal technology demonstration project Arch-fired boiler Cell burner boiler X Coal-fired utility unit Combustion controls X X X Cyclone boiler Demonstration period X Dry bottom Economizer Flue gas Group 1 boiler Group 2 boiler Low NO X burners low NO X burner technology X X X Maximum Continuous Steam Flow at 100% of Load Non-plug-in combustion controls X X Operating period (1) Operates the installed NO X (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 X X Primary vendor X Reburning X X Selective catalytic reduction X X Selective noncatalytic reduction X X 2 Stoker boiler Tangentially fired boiler Turbo-fired boiler Vertically fired boiler Wall-fired boiler Wet bottom [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. 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 NO X (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 SO 2 X (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 NO X (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 NO X (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 SO 2 X (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 SO 2 X X (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 NO X (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 SO 2 X (1) 0.68 lb/mmBtu of heat input on an annual average basis for cell burner boilers. The NO X (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 NO X (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 NO X (4) 0.80 lb/mmBtu of heat input on an annual average basis for vertically fired boilers. The NO X (b) The owner or operator shall determine the annual average NO X [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 NO X (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 NO X (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 NO X [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. X (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 NO X (b) Submission requirements. 2 (c) Contents of an early election plan. (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. (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 NO X (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 Emissions limitations Sulfur dioxide. (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. X (2) Liability. (3) Termination. (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 NO X (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 NO X [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. X (2) The original and three copies of the permit application and compliance plan for NO X X (b) Deadlines. X (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 NO X (c) Information requirements for NO X compliance plans. X X X (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 (NO X X (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. X § 76.10 Alternative emission limitations. (a) General provisions. X (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 NO X (B) For a dry bottom wall-fired boiler (other than a unit applying cell burner technology), the owner or operator has properly installed low NO X (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 NO X (D) For a Group 2 boiler, the owner or operator has properly installed the appropriate NO X (ii) The installed NO X (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 NO X X (B) Unit operating data as specified in this section show that the unit and NO X X (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 NO X (b) Petitioning process. (1) Operation during a period of at least 3 months, following the installation of the NO X X X (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 NO X (4) Submission of a petition for a final alternative emission limitation as specified in paragraph (e) of this section. (c) Deadlines Petition for an alternative emission limitation demonstration period. X (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 NO X (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 NO X (2) Petition for a final alternative emission limitation. (3) Renewal of an alternative emission limitation. (d) Contents of petition for an alternative emission limitation demonstration period. X (1) Identification of the unit; (2) The type of NO X X (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 NO X X (5) The date the unit commenced operation following the installation of the NO X (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 NO X X X X (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 NO X X X (14) The special provisions at paragraph (g)(1) of this section. (e) Contents of petition for a final alternative emission limitation. (1) Identification of the unit; (2) Certification that the owner(s) or operator operated the affected unit and the NO X X X X (3) Certification that the owner(s) or operator have installed in the affected unit all NO X X X X (4) A clear description of each step or modification taken during the demonstration period to improve or optimize the performance of the installed NO X (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 NO X X (8) The minimum NO X X X (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 NO X X X X X X X (f) Permitting authority's action Alternative emission limitation demonstration 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. (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. X (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 Alternative emission limitation demonstration period Emission limitations. (B) When the owner or operator identifies, during the demonstration period, boiler operating or NO X X (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. X (B) A unit with an approved alternative emission limitation demonstration period shall install all NO X X (C) When the owner or operator identifies boiler or NO X X (iii) Testing requirements. (2) Final alternative emission limitation Emission limitations. (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. X (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 NO X (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: where: R Li R li li HI i n = Number of units in the averaging plan. (7) For units with an alternative emission limitation, R li (8) No unit may be included in more than one averaging plan. (b)(1) Submission requirements. (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 NO X averaging plan. X (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 NO X (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 Emission limitations. X (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: where: R ai X R li li HI ai n = Number of units in the averaging plan. (B) For units with an alternative emission limitation, R li (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. (3) Withdrawal or termination. § 76.12 Phase I NO X (a) General provisions. (i) The low NO X X (ii) The unit is participating in an approved clean coal technology demonstration project. (2) In order to obtain a Phase I NO X X (b) Contents of Phase I NO X compliance extension plan. X (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 NO X (ii) A copy of those portions of a legally binding contract with a qualified vendor that demonstrate that services and low NO X (iii) Scheduling information, including justification and test schedules. (iv) To demonstrate, if applicable, that the supply of the low NO X (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 NO X (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 NO X (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. X (2) The Administrator will approve or disapprove a proposed NO X (d) Special provisions. X (2) If a unit with an approved NO X (e) Extension until December 31, 1997. X (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 NO X X (iii) Installation of the redesigned low NO X (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 NO X (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 NO X § 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 EE i X where: EE i X R ai l R li HI i l (2) If EE i i i (3) Sum all EE i where: EE = Excess emissions for NO X 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, where: EE = Excess emissions for NO X R ai X R li HI i 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 NO X (ii) A copy of the performance guarantee submitted by the vendor of the installed NO X (iii) Documentation describing the operational and combustion conditions that are the basis of the performance guarantee. (iv) Certification by the primary vendor of the NO X (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 NO X 2 X (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 NO X X (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 NO X (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 NO X (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 NO X (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 NO X (C) In the event the performance guarantee or the NO X (3) In accordance with § 76.10(d)(10), the following information for the operating period: (i) The average NO X (ii) The highest hourly NO X (iii) Hourly NO X (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 NO X (3) Total integrated hourly gross unit load (MWge). (c) Reporting of the costs of low NO X burner technology applied to Group 1, Phase I boilers. X (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 NO X (ii) Units employing modifications to boiler operating parameters (e.g., burners out of service or fuel switching) without low NO X X (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 NO X (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 NO X (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 NO X X (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 NO X (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 NO X X X (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 NO X (2) For tangentially fired boilers, change the distribution of combustion air within the NO X X (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 State Plant Unit Operator ALABAMA EC GASTON 5 ALABAMA POWER CO. GEORGIA BOWEN 1BLR GEORGIA POWER CO. GEORGIA BOWEN 2BLR GEORGIA POWER CO. GEORGIA BOWEN 3BLR GEORGIA POWER CO. GEORGIA BOWEN 4BLR GEORGIA POWER CO. GEORGIA JACK MCDONOUGH MB1 GEORGIA POWER CO. GEORGIA JACK MCDONOUGH MB2 GEORGIA POWER CO. GEORGIA WANSLEY 1 GEORGIA POWER CO. GEORGIA WANSLEY 2 GEORGIA POWER CO. GEORGIA YATES Y1BR GEORGIA POWER CO. GEORGIA YATES Y2BR GEORGIA POWER CO. GEORGIA YATES Y3BR GEORGIA POWER CO. GEORGIA YATES Y4BR GEORGIA POWER CO. GEORGIA YATES Y5BR GEORGIA POWER CO. GEORGIA YATES Y6BR GEORGIA POWER CO. GEORGIA YATES Y7BR GEORGIA POWER CO. ILLINOIS BALDWIN 3 ILLINOIS POWER CO. ILLINOIS HENNEPIN 2 ILLINOIS POWER CO. ILLINOIS JOPPA 1 ELECTRIC ENERGY INC. ILLINOIS JOPPA 2 ELECTRIC ENERGY INC. ILLINOIS JOPPA 3 ELECTRIC ENERGY INC. ILLINOIS JOPPA 4 ELECTRIC ENERGY INC. ILLINOIS JOPPA 5 ELECTRIC ENERGY INC. ILLINOIS JOPPA 6 ELECTRIC ENERGY INC. ILLINOIS MEREDOSIA 5 CEN ILLINOIS PUB SER. ILLINOIS VERMILION 2 ILLINOIS POWER CO. INDIANA CAYUGA 1 PSI ENERGY INC. INDIANA CAYUGA 2 PSI ENERGY INC. INDIANA EW STOUT 50 INDIANAPOLIS PWR & LT. INDIANA EW STOUT 60 INDIANAPOLIS PWR & LT. INDIANA EW STOUT 70 INDIANAPOLIS PRW & LT. INDIANA HT PRITCHARD 6 INDIANAPOLIS PWR & LT. INDIANA PETERSBURG 1 INDIANAPOLIS PWR & LT. INDIANA PETERSBURG 2 INDIANAPOLIS PWR & LT. INDIANA WABASH RIVER 6 PSI ENERGY INC. IOWA BURLINGTON 1 IOWA SOUTHERN UTL. IOWA ML KAPP 2 INTERSTATE POWER CO. IOWA RIVERSIDE 9 IOWA-ILL GAS & ELEC. KENTUCKY ELMER SMITH 2 OWENSBORO MUN UTIL. KENTUCKY EW BROWN 2 KENTUCKY UTL CO. KENTUCKY EW BROWN 3 KENTUCKY UTL CO. KENTUCKY GHENT 1 KENTUCKY UTL CO. MARYLAND MORGANTOWN 1 POTOMAC ELEC PWR CO. MARYLAND MORGANTOWN 2 POTOMAC ELEC PWR CO. MICHIGAN JH CAMPBELL 1 CONSUMERS POWER CO. MISSOURI LABADIE 1 UNION ELECTRIC CO. MISSOURI LABADIE 2 UNION ELECTRIC CO. MISSOURI LABADIE 3 UNION ELECTRIC CO. MISSOURI LABADIE 4 UNION ELECTRIC CO. MISSOURI MONTROSE 1 KANSAS CITY PWR & LT. MISSOURI MONTROSE 2 KANSAS CITY PWR & LT. MISSOURI MONTROSE 3 KANSAS CITY PWR & LT. NEW YORK DUNKIRK 3 NIAGARA MOHAWK PWR. NEW YORK DUNKIRK 4 NIAGARA MOHAWK PWR. NEW YORK GREENIDGE 6 NY STATE ELEC & GAS. NEW YORK MILLIKEN 1 NY STATE ELEC & GAS. NEW YORK MILLIKEN 2 NY STATE ELEC & GAS. OHIO ASHTABULA 7 CLEVELAND ELEC ILLUM. OHIO AVON LAKE 11 CLEVELAND ELEC ILLUM. OHIO CONESVILLE 4 COLUMBUS STHERN PWR. OHIO EASTLAKE 1 CLEVELAND ELEC ILLUM. OHIO EASTLAKE 2 CLEVELAND ELEC ILLUM. OHIO EASTLAKE 3 CLEVELAND ELEC ILLUM. OHIO EASTLAKE 4 CLEVELAND ELEC ILLUM. OHIO MIAMI FORT 6 CINCINNATI GAS & ELEC. OHIO WC BECKJORD 5 CINCINNATI GAS & ELEC. OHIO WC BECKJORD 6 CINCINNATI GAS & ELEC. PENNSYLVANIA BRUNNER ISLAND 1 PENNSYLVANIA PWR & LT. PENNSYLVANIA BRUNNER ISLAND 2 PENNSYLVANIA PWR & LT. PENNSYLVANIA BRUNNER ISLAND 3 PENNSYLVANIA PWR & LT. PENNSYLVANIA CHESWICK 1 DUQUESNE LIGHT CO. PENNSYLVANIA CONEMAUGH 1 PENNSYLVANIA ELEC CO. PENNSYLVANIA CONEMAUGH 2 PENNSYLVANIA ELEC CO. PENNSYLVANIA PORTLAND 1 METROPOLITAN EDISON. PENNSYLVANIA PORTLAND 2 METROPOLITAN EDISON. PENNSYLVANIA SHAWVILLE 3 PENNSYLVANIA ELEC CO. PENNSYLVANIA SHAWVILLE 4 PENNSYLVANIA ELEC CO. TENNESSEE GALLATIN 1 TENNESSEE VAL AUTH. TENNESSEE GALLATIN 2 TENNESSEE VAL AUTH. TENNESSEE GALLATIN 3 TENNESSEE VAL AUTH. TENNESSEE GALLATIN 4 TENNESSEE VAL AUTH. TENNESSEE JOHNSONVILLE 1 TENNESSEE VAL AUTH. TENNESSEE JOHNSONVILLE 2 TENNESSEE VAL AUTH. TENNESSEE JOHNSONVILLE 3 TENNESSEE VAL AUTH. TENNESSEE JOHNSONVILLE 4 TENNESSEE VAL AUTH. TENNESSEE JOHNSONVILLE 5 TENNESSEE VAL AUTH. TENNESSEE JOHNSONVILLE 6 TENNESSEE VAL AUTH. WEST VIRGINIA ALBRIGHT 3 MONONGAHELA POWER CO. WEST VIRGINIA FORT MARTIN 1 MONONGAHELA POWER CO. WEST VIRGINIA MOUNT STORM 1 VIRGINIA ELEC & PWR. WEST VIRGINIA MOUNT STORM 2 VIRGINIA ELEC & PWR. WEST VIRGINIA MOUNT STORM 3 VIRGINIA ELEC & PWR. WISCONSIN GENOA 1 DAIRYLAND POWER COOP. WISCONSIN SOUTH OAK CREEK 7 WISCONSIN ELEC POWER. WISCONSIN SOUTH OAK CREEK 8 WISCONSIN ELEC POWER. Table 2—Phase I Dry Bottom-Fired Units State Plant Unit Operator ALABAMA COLBERT 1 TENNESSEE VAL AUTH. ALABAMA COLBERT 2 TENNESSEE VAL AUTH. ALABAMA COLBERT 3 TENNESSEE VAL AUTH. ALABAMA COLBERT 4 TENNESSEE VAL AUTH. ALABAMA COLBERT 5 TENNESSEE VAL AUTH. ALABAMA EC GASTON 1 ALABAMA POWER CO. ALABAMA EC GASTON 2 ALABAMA POWER CO. ALABAMA EC GASTON 3 ALABAMA POWER CO. ALABAMA EC GASTON 4 ALABAMA POWER CO. FLORIDA CRIST 6 GULF POWER CO. FLORIDA CRIST 7 GULF POWER CO. GEORGIA HAMMOND 1 GEORGIA POWER CO. GEORGIA HAMMOND 2 GEORGIA POWER CO. GEORGIA HAMMOND 3 GEORGIA POWER CO. GEORGIA HAMMOND 4 GEORGIA POWER CO. ILLINOIS GRAND TOWER 9 CEN ILLINOIS PUB SER. INDIANA CULLEY 2 STHERN IND GAS & EL. INDIANA CULLEY 3 STHERN IND GAS & EL. INDIANA GIBSON 1 PSI ENERGY INC. INDIANA GIBSON 2 PSI ENERGY INC. INDIANA GIBSON 3 PSI ENERGY INC. INDIANA GIBSON 4 PSI ENERGY INC. INDIANA RA GALLAGHER 1 PSI ENERGY INC. INDIANA RA GALLAGHER 2 PSI ENERGY INC. INDIANA RA GALLAGHER 3 PSI ENERGY INC. INDIANA RA GALLAGHER 4 PSI ENERGY INC. INDIANA FRANK E RATTS 1SG1 HOOSIER ENERGY REC. INDIANA FRANK E RATTS 2SG1 HOOSIER ENERGY REC. INDIANA WABASH RIVER 1 PSI ENERGY INC. INDIANA WABASH RIVER 2 PSI ENERGY INC. INDIANA WABASH RIVER 3 PSI ENERGY INC. INDIANA WABASH RIVER 5 PSI ENERGY INC. IOWA DES MOINES 11 IOWA PWR & LT CO. IOWA PRAIRIE CREEK 4 IOWA ELEC LT & PWR. KANSAS QUINDARO 2 KS CITY BD PUB UTIL. KENTUCKY COLEMAN C1 BIG RIVERS ELEC CORP. KENTUCKY COLEMAN C2 BIG RIVERS ELEC CORP. KENTUCKY COLEMAN C3 BIG RIVERS ELEC CORP. KENTUCKY EW BROWN 1 KENTUCKY UTL CO. KENTUCKY GREEN RIVER 5 KENTUCKY UTL CO. KENTUCKY HMP&L STATION 2 H1 BIG RIVERS ELEC CORP. KENTUCKY HMP&L STATION 2 H2 BIG RIVERS ELEC CORP. KENTUCKY HL SPURLOCK 1 EAST KY PWR COOP. KENTUCKY JS COOPER 1 EAST KY PWR COOP. KENTUCKY JS COOPER 2 EAST KY PWR COOP. MARYLAND CHALK POINT 1 POTOMAC ELEC PWR CO. MARYLAND CHALK POINT 2 POTOMAC ELEC PWR CO. MINNESOTA HIGH BRIDGE 6 NORTHERN STATES PWR. MISSISSIPPI JACK WATSON 4 MISSISSIPPI PWR CO. MISSISSIPPI JACK WATSON 5 MISSISSIPPI PWR CO. MISSOURI JAMES RIVER 5 SPRINGFIELD UTL. OHIO CONESVILLE 3 COLUMBUS STHERN PWR. OHIO EDGEWATER 13 OHIO EDISON CO. OHIO MIAMI FORT 1 5-1 CINCINNATI GAS&ELEC. OHIO MIAMI FORT 1 5-2 CINCINNATI GAS&ELEC. OHIO PICWAY 9 COLUMBUS STHERN PWR. OHIO RE BURGER 7 OHIO EDISON CO. OHIO RE BURGER 8 OHIO EDISON CO. OHIO WH SAMMIS 5 OHIO EDISON CO. OHIO WH SAMMIS 6 OHIO EDISON CO. PENNSYLVANIA ARMSTRONG 1 WEST PENN POWER CO. PENNSYLVANIA ARMSTRONG 2 WEST PENN POWER CO. PENNSYLVANIA MARTINS CREEK 1 PENNSYLVANIA PWR & LT. PENNSYLVANIA MARTINS CREEK 2 PENNSYLVANIA PWR & LT. PENNSYLVANIA SHAWVILLE 1 PENNSYLVANIA ELEC CO. PENNSYLVANIA SHAWVILLE 2 PENNSYLVANIA ELEC CO. PENNSYLVANIA SUNBURY 3 PENNSYLVANIA PWR & LT. PENNSYLVANIA SUNBURY 4 PENNSYLVANIA PWR & LT. TENNESSEE JOHNSONVILLE 7 TENNESSEE VAL AUTH. TENNESSEE JOHNSONVILLE 8 TENNESSEE VAL AUTH. TENNESSEE JOHNSONVILLE 9 TENNESSEE VAL AUTH. TENNESSEE JOHNSONVILLE 10 TENNESSEE VAL AUTH. WEST VIRGINIA HARRISON 1 MONONGAHELA POWER CO. WEST VIRGINIA HARRISON 2 MONONGAHELA POWER CO. WEST VIRGINIA HARRISON 3 MONONGAHELA POWER CO. WEST VIRGINIA MITCHELL 1 OHIO POWER CO. WEST VIRGINIA MITCHELL 2 OHIO POWER CO. WISCONSIN JP PULLIAM 8 WISCONSIN PUB SER CO. WISCONSIN NORTH OAK CREEK 2 1 WISCONSIN ELEC PWR. WISCONSIN NORTH OAK CREEK 2 2 WISCONSIN ELEC PWR. WISCONSIN NORTH OAK CREEK 2 3 WISCONSIN ELEC PWR. WISCONSIN NORTH OAK CREEK 2 4 WISCONSIN ELEC PWR. WISCONSIN SOUTH OAK CREEK 2 5 WISCONSIN ELEC PWR. WISCONSIN SOUTH OAK CREEK 2 6 WISCONSIN ELEC PWR. 1 2 Table 3—Phase I Cell Burner Technology Units State Plant Unit Operator INDIANA WARRICK 4 STHERN IND GAS & EL. MICHIGAN JH CAMPBELL 2 CONSUMERS POWER CO. OHIO AVON LAKE 12 CLEVELAND ELEC ILLUM. OHIO CARDINAL 1 CARDINAL OPERATING. OHIO CARDINAL 2 CARDINAL OPERATING. OHIO EASTLAKE 5 CLEVELAND ELEC ILLUM. OHIO GENRL JM GAVIN 1 OHIO POWER CO. OHIO GENRL JM GAVIN 2 OHIO POWER CO. OHIO MIAMI FORT 7 CINCINNATI GAS & EL. OHIO MUSKINGUM RIVER 5 OHIO POWER CO. OHIO WH SAMMIS 7 OHIO EDISON CO. PENNSYLVANIA HATFIELDS FERRY 1 WEST PENN POWER CO. PENNSYLVANIA HATFIELDS FERRY 2 WEST PENN POWER CO. PENNSYLVANIA HATFIELDS FERRY 3 WEST PENN POWER CO. TENNESSEE CUMBERLAND 1 TENNESSEE VAL AUTH. TENNESSEE CUMBERLAND 2 TENNESSEE VAL AUTH. WEST VIRGINIA FORT MARTIN 2 MONONGAHELA POWER CO. Appendix B to Part 76—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 NO X X 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 NO X X X X X X 2. Average Capital Cost for Low NO X The Administrator will use the procedures, methods, and data specified in this section to estimate the average capital cost (in $/kW) of installed low NO X 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 NO X X X X X 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 NO X 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 NO X 4.1.2 Estimates of the annual average baseline NO X X 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 NO X 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 NO X 4.1.6 Detailed breakdown of the actual costs of the completed low NO X X 4.1.7 Description of the probable causes for significant differences between actual and estimated low NO X 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 NO X X 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]