§ 123.1. Prohibition of certain fugitive emissions.

 (a)  No person may permit the emission into the outdoor atmosphere of a fugitive air contaminant from a source other than the following:

   (1)  Construction or demolition of buildings or structures.

   (2)  Grading, paving and maintenance of roads and streets.

   (3)  Use of roads and streets. Emissions from material in or on trucks, railroad cars and other vehicular equipment are not considered as emissions from use of roads and streets.

   (4)  Clearing of land.

   (5)  Stockpiling of materials.

   (6)  Open burning operations.

   (7)  Blasting in open pit mines. Emissions from drilling are not considered as emissions from blasting.

   (8)  Coke oven batteries, provided the fugitive air contaminants emitted from any coke oven battery comply with the standards for visible fugitive emissions in § §  123.44 and 129.15 (relating to limitations of visible fugitive air contaminants from operation of any coke oven battery; and coke pushing operations).

   (9)  Sources and classes of sources other than those identified in paragraphs (1)—(8), for which the operator has obtained a determination from the Department that fugitive emissions from the source, after appropriate control, meet the following requirements:

     (i)   The emissions are of minor significance with respect to causing air pollution.

     (ii)   The emissions are not preventing or interfering with the attainment or maintenance of an ambient air quality standard.

 (b)  An application form for requesting a determination under either subsection (a)(9) or §  129.15(c) is available from the Department. In reviewing these applications, the Department may require the applicant to supply information including, but not limited to, a description of proposed control measures, charac-teristics of emissions, quantity of emissions and ambient air quality data and analysis showing the impact of the source on ambient air quality. The applicant is required to demonstrate that the requirements of subsections (a)(9) and (c) and §  123.2 (relating to fugitive particulate matter) or of the requirements of §  129.15(c) have been satisfied. Upon such demonstration, the Department will issue a determination, in writing, either as an operating permit condition, for those sources subject to permit requirements under the act, or as an order containing appropriate conditions and limitations.

 (c)  A person responsible for any source specified in subsections (a)(1)—(7) or (9) shall take all reasonable actions to prevent particulate matter from becoming airborne. These actions include, but not be limited to, the following:

   (1)  Use, where possible, of water or chemicals for control of dust in the demolition of buildings or structures, construction operations, the grading of roads or the clearing of land.

   (2)  Application of asphalt, oil, water or suitable chemicals on dirt roads, material stockpiles and other surfaces which may give rise to airborne dusts.

   (3)  Paving and maintenance of roadways.

   (4)  Prompt removal of earth or other material from paved streets onto which earth or other material has been transported by trucking or earth moving equipment, erosion by water, or other means.

 (d)  The requirements contained in subsection (a) and §  123.2 do not apply to fugitive emissions arising from the production of agricultural commodities in their unmanufactured state on the premises of the farm operation.

   The provisions of this §  123.1 adopted September 10, 1971, effective September 11, 1971, 1 Pa.B. 1804; amended March 3, 1972, effective March 20, 1972, 2 Pa.B. 383; amended August 12, 1977, effective August 29, 1977, 7 Pa.B. 2251. Immediately preceding text appears at serial pages (4620) and (24610).

   Agency Authority

   Although the Department of Environmental Resources under the Air Pollution Control Act (35 P. S. §  4001 et seq.) had been granted specific authority by the Legislature to regulate ‘‘air contamination sources’’ producing ‘‘air pollution’’ that includes obnoxious odors, nowhere was there any grant of authority to the Public Utility Commission, either directly or indirectly, to regulate air pollution emanating from a public utility. Country Place Waste Treatment Co. v. Pennsylvania Public Utility Commission, 654 A.2d 72 (Pa. Cmwlth. 1995).

   Application Properly Denied

   The Department was required to deny an application for reactivation of beehive coke ovens, regardless of economic consequences, when the application did not provide information which would show that the ovens would meet the limitations applicable to fugitive emissions, and constitutional rights are not violated even though there is no known method to operate beehive coke ovens in compliance with this title. Rochez Brothers Inc. v. Department of Environmental Resources, 334 A.2d 790 (Pa. Cmwlth. 1975).

   Burden of Proof

   Testimony by the environmental group’s president that the air was polluted (that is, ‘‘fuming’’ resulted from the reaction process used to treat waste at the industrial processors facility) was not credible on the issues relating to the existence or cause of air quality problems as would shift the burden of proof to the Department of Environmental Resources to justify the issuance of the solid waste disposal permit. Concerned Citizens of Yough, Inc. v. Department of Environmental Resources, 639 A.2d 1265 (Pa. Cmwlth. 1994).

   The Commonwealth need not prove that the fugitive dust emissions in question caused or contributed to a condition of air pollution because the determination that such emissions cause or contribute to a condition of air pollution had already been made at the time the section was promulgated, and the section is reasonably understandable and specific. Department of Environmental Resources v. Locust Point Quarries, Inc., 396 A.2d 1205 (Pa. 1979).

   Clearing of Land

   Environmental Hearing Board did not err in finding asphalt plant operator’s extracting soil down to bedrock to prepare area for blasting was not exempt from ‘‘clearing of land,’’ Department of Environmental Protection defined clearing of land as the removal of trees, brush and surface vegetation and not the removal of overburden down to bedrock. Eureka Stone Quarry v. Dep’t of Envtl. Protection, 957 A.2d 337, 348 (Pa. Cmwlth. 2008).

   Construction

   Since §  123.2 (relating to fugitive particulate matter) applies only to the nine exemptions listed in (a)(1)—(9), the two sections do not overlap and either one can stand alone as a basis for a violation. Medusa Corp. v. Department of Environmental Resources, 415 A.2d 105 (Pa. Cmwlth. 1980).

   Criminal Prosecution

   To prove a criminal violation of this section, as modified by §  123.13 (relating to processes), scientific evidence must be introduced proving beyond a reasonable doubt that the offensive fugitive emissions exceeded the permissible maximum set forth in §  123.12 (relating to incinerators). Department of Environmental Resources v. Locust Point Quarries Inc., 367 A.2d 392 (Pa. Cmwlth. 1976).

   Evidence

   To properly challenge the reasonableness of this section, evidence must be presented to establish that the section will not aid in reaching national ambient air quality standards and that the proscribed activity is insignificant as a cause of air pollution. Department of Environmental Resources v. Locust Point Quarries, Inc., 396 A.2d 1205 (Pa. 1979).

   A conviction for violation of this section cannot be sustained absent sufficient visual and/or scientific evidence to establish that the quarry dust observed by Department agents was such as to constitute air pollution as defined by the Air Pollution Control Act. Commonwealth v. Locust Point Quarries Inc., 72 Pa. D. & C.2d 700 (1975).

   Fugitive Emissions

   A fugitive emission is an emission of an air contaminant in a specific manner and it includes particulate matter, sulfur compounds, odor and visible emissions if emitted other than through a flue. Department of Environmental Resources v. Locust Point Quarries, Inc., 396 A.2d 1205 (Pa. 1979).

   General Comment

   This section was intended to stand alone and be construed independently of §  123.13 (relating to processes). Department of Environmental Resources v. Locust Point Quarries, Inc., 396 A.2d 1205 (Pa. 1979).

   Minor Significance

   The comment by the Environmental Hearing Board that the operator failed to invoke the ‘‘minor significance’’ exception of (a)(9) was proper because the exception existed throughout the relevant time period of 1973 to 1976, and the procedural provisions added by a 1977 amendment were immaterial. Medusa Corp. v. Department of Environmental Resources, 415 A.2d 105 (Pa. Cmwlth. 1980).

   A rock quarry was not a source of minor significance within the meaning of §  127.14 (relating to exemptions) if nothing in the record supported such a determination and the DER had not so determined. Mignatti Construction Co., Inc. v. Environmental Hearing Board, 411 A.2d 860 (Pa. Cmwlth. 1980).

   Review

   A request for a grace period for compliance with a temporary variance did not have a res judicata effect on a subsequent request for an exemption from emission control requirements under this provision, since there was no identity of the thing sued for. Bethlehem Steel Corporation v. Department of Environmental Resources, 390 A.2d 1383 (Pa. Cmwlth. 1978).

   On appeal from the Department’s refusal to grant applicant permission to reactivate certain coke ovens, if the appellant did not show that the oven would meet the limitations in this title, but showed only the ‘‘dire need’’ for the coke to be produced, the scope of review is limited to whether constitutional rights were violated, an error of law committed, or any necessary finding of fact was not supported by the evidence. Rochez Brothers, Inc. v. Department of Environmental Resources, 334 A.2d 790 (Pa. Cmwlth. 1975).

 A person may not permit fugitive particulate matter to be emitted into the outdoor atmosphere from a source specified in §  123.1(a)(1)—(9) (relating to prohibition of certain fugitive emissions) if the emissions are visible at the point the emissions pass outside the person’s property.

   The provisions of this §  123.2 adopted September 10, 1971, effective September 11, 1971, 1 Pa.B. 1804; amended March 3, 1972, effective March 20, 1972, 2 Pa.B. 383; amended August 12, 1983, effective August 13, 1983, 13 Pa.B. 2478. Immediately preceding text appears at serial page (60646).

   Evidence

   Visual evidence that dust emission left quarry property without witness as to the precise moment when fugitive dust escaped from the property was not proper grounds for dismissal of a violation as de minimis. Scurfield Coal, Inc. v. Commonwealth, 582 A.2d 694 (Pa. Cmwlth. 1990).

   Facility Operations

   This section which requires quarry owner to prevent emission into the atmosphere of particulate matter encompasses material stockpiled in both active and inactive operations, since the detriment to the public is the same. Eureka Stone Quarry, Inc. v. Commonwealth, 544 A.2d 1129 (Pa. Cmwlth. 1988).

   Prevention

   Quarry owner has an active duty to prevent particulate matter from visibly escaping into the atmosphere onto another’s property, which includes a responsibility to provide an adequate suppression system. Eureka Stone Quarry, Inc. v. Commonwealth, 544 A.2d 1129 (Pa. Cmwlth. 1988).

   Testimony of an air quality specialist who visited the defendant’s quarry and viewed dust blowing into the air from actual stone crushing areas, conveying areas, stockpiles and haulage ways was sufficient to prove defendant caused the prohibited emissions to be emitted into the atmosphere outside of its own property. Eureka Stone Quarry, Inc. v. Commonwealth, 544 A.2d 1129 (Pa. Cmwlth. 1988).

   This section which requires a quarry owner to prevent emission into the atmosphere of particulate matter encompasses material stockpiled in both active and inactive operations, since the detriment to the public is the same. Eureka Stone Quarry, Inc. v. Commonwealth, 544 A.2d 1129 (Pa. Cmwlth. 1988).

   Quarry owner has an active duty to prevent particulate matter from visibly escaping into the atmosphere onto another’s property, which includes a responsibility to provide an adequate suppression system. Eureka Stone Quarry, Inc. v. Commonwealth, 544 A.2d 1129 (Pa. Cmwlth. 1988).

   Since this section applies only to the nine exemptions listed in §  123.1(a)(1)—(9) (relating to fugitive emissions), the two sections do not overlap and either one can stand alone as a basis for a violation. Medusa Corp. v. Department of Environmental Resources, 415 A.2d 105 (Pa. Cmwlth. 1980).

   This section cited in 25 Pa. Code §  77.108 (relating to permit for small noncoal operations); 25 Pa. Code §  123.1 (relating to prohibition of certain fugitive emissions); and 25 Pa. Code §  264.521 (relating to design and operating standards).

PARTICULATE MATTER EMISSIONS

§ 123.11. Combustion units.

 (a)  A person may not permit the emission into the outdoor atmosphere of particulate matter from a combustion unit in excess of the following:

   (1)  The rate of 0.4 pound per million Btu of heat input, when the heat input to the combustion unit in millions of Btus per hour is greater than 2.5 but less than 50.

   (2)  The rate determined by the following formula:

   A = 3.6E^-0.56

   where:

   A = Allowable emissions in pounds per million Btus of heat input,
 and

   E = Heat input to the combustion unit in millions of Btus per hour,

   when E is equal to or greater than 50 but less than 600.

   (3)  The rate of 0.1 pound per million Btu of heat input when the heat input to the combustion unit in millions of Btus per hour is equal to or greater than 600.

 (b)  Allowable emissions under subsection (a) are graphically indicated in Appendix A.

   The provisions of this §  123.111 adopted September 10, 1971, effective September 11, 1971, 1 Pa.B. 1804; amended March 3, 1972, effective March 20, 1972, 2 Pa.B. 383.

   Impossibility

   There is no constitutional prohibition against imposition of civil penalties for failure to comply with technologically impossible standards, since the use of fines to spark technological development is reasonably related to the goal of reducing pollution. Department of Environmental Resources v. Pennsylvania Power Co. 416 A.2d 995 (Pa. 1980).

   Impossibility of performance is a defense in a contempt proceeding where an order of court ordering a power company to comply with the SO₂ regulations was impossible of performance and where, under the present state of technology, the power company’s proposed use of higher smokestacks to control SO₂ emissions was as close as the company could come to compliance with the regulations. Department of Environmental Resources v. Pennsylvania Power Company, 316 A.2d 96 (Pa. Cmwlth. 1974).

   Substantial Evidence

   Substantial evidence of a violation can be supplied by the violator itself and need not be independently produced by the Department. Department of Environmental Resources v. Pennsylvania Power Company, 384 A.2d 273 (Pa. Cmwlth. 1978).

   No person may permit the emission to the outdoor atmosphere of particulate matter from any incinerator, at any time, in such a manner that the particulate matter concentration in the effluent gas exceeds 0.1 grain per dry standard cubic foot, corrected to 12% carbon dioxide.

   The provisions of this §  123.12 adopted September 10, 1971, effective September 11, 1971, 1 Pa.B. 1804; amended March 3, 1972, effective March 20, 1972, 2 Pa.B. 383.

 (a)  Subsections (b) and (c) apply to all processes except combustion units, incinerators and pulp mill smelt dissolving tanks.

 (b)  No person may permit the emission into the outdoor atmosphere of particulate matter from a process listed in the following table, at any time, either in excess of the rate calculated by the formula in paragraph (2) or in a manner that the concentration of particulate matter in the effluent gas exceeds .02 grains per dry standard cubic foot, whichever is greater:

   (1)  Table.

   (2)  Formula.
A = .76E^0.42

 where:
A = Allowable emissions in pounds per hour.
E = Emission index = F X W pounds per hour.
F = Process factor in pounds per unit, and
W = Production or charging rate in units per hour.

   The factor F shall be obtained from the table in paragraph (1). The units for F and W shall be compatible.

   (3)  Allowable emissions. Allowable emissions under this subsection are graphically indicated in Appendix B.

 (c)  For processes not listed in subsection (b)(1), including, but not limited to, coke oven battery waste heat stacks and autogeneous zinc coker waste heat stacks, the following apply:

   (1)  Prohibited emissions. No person may permit the emission into the outdoor atmosphere of particulate matter from a process not listed in subsection (b)(1) in a manner that the concentration of particulate matter in the effluent gas exceeds any of the following:

     (i)   .04 grain per dry standard cubic foot, when the effluent gas volume is less than 150,000 dry standard cubic feet per minute.

     (ii)   The rate determined by the following formula:
A = 6000 E^-1

   where:
A = Allowable emissions in grains per dry standard cubic foot, and
E = Effluent gas volume in dry standard cubic feet per minute,

   when E is equal to or greater than 150,000 but less than 300,000.

     (iii)   .02 grain per dry standard cubic foot, when the effluent gas volume is greater than 300,000 dry standard cubic feet per minute.

   (2)  Allowable emissions. Allowable emissions under this subsection are graphically indicated in Appendix C.

 (d)  No person may permit the emission into the outdoor atmosphere of particulate matter from kraft and soda pulp mill smelt dissolving tanks in excess of .2 lb/ton black liquor solids—dry basis.

   The provisions of this §  123.13 issued under section 1920-A of The Administrative Code of 1929 (71 P. S. §  510-20); and section 5 of the Air Pollution Control Act (35 P. S. §  4005); amended under section 5 of the Air Pollution Control Act (35 P. S. §  4005).

   The provisions of this §  123.13 adopted September 10, 1971, effective September 11, 1971, 1 Pa.B. 1804; amended March 3, 1972, effective March 20, 1972, 2 Pa.B. 383; amended April 26, 1974, effective May 13, 1974, 4 Pa.B. 824; amended July 25, 1975, effective August 11, 1975, 5 Pa.B. 1916; amended July 23, 1976, effective August 9, 1976, 6 Pa.B. 1730; amended August 12, 1978, effective August 29, 1978, 8 Pa.B. 2251; amended September 26, 1980, effective September 27, 1980, 10 Pa.B. 3788; amended August 12, 1983, effective August 13, 1983, 13 Pa.B. 2478; amended May 6, 1988, effective May 7, 1988, 18 Pa.B. 2102. Immediately preceding text appears at serial pages (84509) to (84511).

   Criminal Violation

   To prove a criminal violation of §  123.1, as modified by this section, scientific evidence must be introduced proving beyond a reasonable doubt that the offensive fugitive emissions exceeded the permissible maximum set forth in this section. Department of Environmental Resources v. Locust Point Quarries, Inc., 367 A.2d 392 (Pa. Cmwlth. 1976).

   Denial of Application

   The Department is required to deny an application for reactivation of beehive coke ovens, regardless of economic consequences, when the application does not provide any information which would show that the ovens would meet the limitations applicable to fugitive emissions and constitutional rights are not violated even though there is no known method to operate beehive coke ovens in compliance with the regulations. Rochez Brothers Inc. v. Department of Environmental Resources, 334 A.2d 790 (Pa. Cmwlth. 1975).

   Failure to Appeal

   Where the party is aggrieved by Department order requiring compliance with this section by a certain date, failure to appeal the order bars an attack on the order and the validity of the regulation on which it was predicated in a subsequent enforcement proceeding brought by the Department. Department of Environmental Resources v. Wheeling-Pittsburgh Steel Corp., 348 A.2d 765 (Pa. Cmwlth. 1975); affirmed in part remanded in part; 357 A.2d 320 (Pa. 1977); cert. denied 98 S. Ct. 514 (Pa. 1977).

   Process

   A quarry operation would appear to be included among those manufacturing processes outlined in this section but this interpretation does not preclude prosecution under another regulation restricting a distinct form of air contamination even though the same sources of contamination and the same contaminant are involved. Commonwealth v. Locust Point Quarries Inc., 72 Pa. D. & C.2d 700 (1975).

   A steel corporation which is granted an extension of time for compliance with the standards relating to particulate matter emissions may not attack the validity of the order or the regulations on which it was predicated in a subsequent enforcement proceeding, and the corporation does not have the right to trial by jury even though it seeks declaratory relief in its answer to the enforcement petition. Department of Environmental Resources v. Wheeling-Pittsburgh Steel Corp., 375 A.2d 320 (Pa. Cmwlth. 1977); 348 A.2d 765 (Pa. Cmwlth. 1975).

   Scope of Review

   On appeal from the Department’s refusal to grant applicant permission to reactivate certain coke ovens, where the appellant does not show that the oven would meet the limitations in this title but shows only the ‘‘dire need’’ for the coke to be produced, the scope of review is limited to whether constitutional rights were violated, an error of law committed or any necessary finding of fact not supported by the evidence. Rochez Brothers, Inc. v. Department of Environmental Resources, 334 A.2d 790 (Pa. Cmwlth. 1975).

   This section cited in 25 Pa. Code §  121.8 (relating to compliance responsibilities); 25 Pa. Code §  129.15 (relating to coke pushing operations); and 25 Pa. Code §  139.12 (relating to emissions of particulate matter).

SULFUR COMPOUND EMISSIONS

§ 123.21. General.

 (a)  This section applies to sources except those subject to other provisions of this article, with respect to the control of sulfur compound emissions.

 (b)  No person may permit the emission into the outdoor atmosphere of sulfur oxides from a source in a manner that the concentration of the sulfur oxides, expressed as SO₂, in the effluent gas exceeds 500 parts per million, by volume, dry basis.

 (a)  Nonair basin areas. Combustion units in nonair basin areas shall conform with the following:

   (1)  General provision. No person may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂, from a combustion unit in excess of the rate of 4 pounds per million Btu of heat input over any 1-hour period except as provided for in paragraph (4).

   (2)  Commercial fuel oil. No person may offer for sale, deliver for use, exchange in trade or permit the use of commercial fuel oil in nonair basin areas which contains sulfur in excess of the applicable percentage by weight set forth in the following table:

   (3)  Equivalency provision. Paragraph (2) may not apply to those persons or installations where equipment or processes are used to reduce the emissions from the burning of fuels with a higher sulfur content than that specified in paragraph (2). The emissions may not exceed those which would result from the use of the fuels specified in paragraph (2).

   (4)  Solid fossil fuel fired combustion units. Solid fossil fuel fired combustion units shall conform with the following:

     (i)   This paragraph applies to solid fossil fuel fired combustion units with a rated capacity greater than or equal to 250 million Btus of heat input per hour.

     (ii)   The owner of a solid fossil fuel fired combustion unit with a rated capacity of less than 250 million Btu heat input per hour may petition the Department for application of the limitations in this paragraph in lieu of the limitations in paragraph (1). Upon demonstration of installation of continuous monitoring equipment which complies with Chapter 139 (relating to sampling and testing) the Department will grant the petition.

     (iii)   No person subject to this paragraph may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂ from a combustion unit in excess of the rates set forth in the following table:

     (iv)   A combustion unit which does not meet the requirements of §  123.25 (relating to monitoring requirements) for installation and operation of continuous SO₂ emission monitoring equipment shall be subject to the provisions of paragraph (1).

 (b)  Erie; Harrisburg; York; Lancaster; and Scranton, Wilkes-Barre air basins. Combustion units in these subject air basins shall conform with the following:

   (1)  General provision. No person may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂, from a combustion unit in excess of the rate of 4 pounds per million Btu of heat input over a 1-hour period except as provided for in paragraph (4).

   (2)  Commercial fuel oil. No person may offer for sale, deliver for use, exchange in trade or permit the use of commercial fuel oil in the subject air basins which contain sulfur in excess of the applicable percentage by weight set forth in the following table:

   (3)  Equivalency provision. Paragraph (2) does not apply to those persons or installations where equipment or processes are used to reduce the emissions from the burning of fuels with a higher sulfur content than that specified in paragraph (2). The emissions may not exceed those which would result from the use of the fuels specified in paragraph (2).

   (4)  Solid fossil fuel fired combustion units. Solid fossil fuel fired combustion units shall conform with the following:

     (i)   This paragraph applies to solid fossil fuel fired combustion units with a rated capacity greater than or equal to 250 million Btus of heat input per hour and to a solid fossil fuel fired combustion unit upon petition to and acceptance by the Department.

     (ii)   The owner of any solid fossil fuel fired combustion unit with a rated capacity of less than 250 million Btu heat input per hour may petition the Department for application of the limitations in this paragraph in lieu of the limitations in paragraph (1). Upon demonstration of installation of continuous monitoring equipment which complies with Chapter 139, the Department will grant such petition.

     (iii)   No person may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂, from a combustion unit, at any time, in excess of the rates set forth in the following table:

     (iv)   A combustion unit which does not meet the requirements of §  123.25 for installation and operation of continuous SO₂ emission monitoring equipment is subject to the provisions of paragraph (1).

 (c)  Allentown, Bethlehem, Easton, Reading, Upper Beaver Valley and Johnstown air basins. Combustion units in these subject air basins shall conform with the following:

   (1)  General provision. No person may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂, from any combustion unit, at any time, in excess of the rate of 3 pounds per million Btu of heat input over any 1-hour period except as provided for in paragraph (4).

   (2)  Commercial fuel oil. No person may, at any time, offer for sale, deliver for use, exchange in trade or permit the use of commercial fuel oil in the subject air basins on or after the effective dates listed in this paragraph which contains sulfur in excess of the applicable percentage by weight set forth in the following table:

   (3)  Equivalency provision. Paragraph (2) does not apply to those persons or installations where equipment or processes are used to reduce the emissions from the burning of fuels with a higher sulfur content than that specified in paragraph (2); however, the emissions may not exceed those which would result from the use of the fuels specified in paragraph (2).

   (4)  Solid fossil fuel fired combustion units. Solid fuel fired combustion units shall conform with the following:

     (i)   This paragraph applies to all solid fossil fuel fired combustion units with a rated capacity greater than or equal to 250 million Btus of heat input per hour and to any solid fossil fuel fired combustion unit upon petition to and acceptance by the Department.

     (ii)   The owner of a solid fossil fuel fired combustion unit with a rated capacity of less than 250 million Btu heat input per hour may petition the Department for application of the limitations in this paragraph in lieu of the limitations in paragraph (1). Upon demonstration of installation of continuous monitoring equipment which complies with Chapter 139 the Department will grant such petition.

     (iii)   No person may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂, from any combustion unit in excess of the rates set forth in the following table:

     (iv)   A combustion unit not meeting the requirements of §  123.25 (relating to monitoring requirements) for installation and operation of continuous SO₂₁ emission monitoring equipment is subject to the provisions of paragraph (1).

 (d)  Allegheny County, Lower Beaver Valley, and Monongahela Valley air basins. No person may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂, from any combustion unit in excess of any of the following:

   (1)  The rate of one pound per million Btu of heat input, when the heat input to the combustion unit in millions of Btus per hour is greater than 2.5 but less than 50.

   (2)  The rate determined by the following formula: A = 1.7E^-0.14, where: A = Allowable emissions in pounds per million Btu of heat input, and E = Heat input to the combustion unit in millions of Btus per hours when E is equal to or greater than 50 but less than 2,000.

   (3)  The rate of 0.6 pounds per million Btu of heat input when the heat input to the combustion unit in millions of Btus per hour is equal to or greater than 2,000.

 (e)  Southeast Pennsylvania air basin. Combustion units in the Southeast Pennsylvania air basin shall conform with the following:

   (1)  General provision. No person may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂, from any combustion unit except as provided for in paragraph (3) or (5), in excess of the applicable rate in pounds per million Btu of heat input specified in the following table:

   (2)  Commercial fuel oil. No person may, at any time, offer for sale, deliver or use, exchange in trade or permit the use of commercial fuel oil for use in combustion units in the Southeast Pennsylvania air basin which contains sulfur in excess of the applicable percentages by weight set forth in the following table:

   (3)  Noncommercial fuels. No person may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂, from any combustion unit using noncommercial fuel at any time in excess of the rate of 0.6 pounds per million Btu of heat input in the inner zone or 1.2 pounds per million Btu of heat input in the outer zone.

   (4)  Equivalency provision. Paragraph (2) does apply to those persons or installations where equipment or processes are used to reduce the emissions from the burning of fuels with a higher sulfur content than that specified in paragraph (2); however, the emissions may not exceed those which would result from the use of the fuels specified in paragraph (2).

   (5)  Solid fossil fuel fired combustion units. Solid fossil fuel fired combustion units shall conform with the following:

     (i)   This paragraph applies to all solid fossil fuel fired combustion units with a rated capacity greater than or equal to 250 million Btus of heat input per hour and to any solid fossil fuel fired combustion unit upon petition to and acceptance by the Department.

     (ii)   The owner of any solid fossil fuel fired combustion unit with a rated capacity of less than 250 million Btu heat input per hour may petition the Department for application of the limitations in this paragraph in lieu of the limitations in paragraph (1). Upon demonstration of installation of continuous monitoring equipment which complies with Chapter 139, the Department will grant the petition.

     (iii)   No person may permit the emission into the outdoor atmosphere of sulfur oxides, expressed as SO₂, from any combustion unit in excess of the applicable rate in pounds per million Btu of heat input specified in the following table:

     (iv)   A combustion unit not meeting the requirements of §  123.25 (relating to monitoring requirements) for installation and operation of continuous SO₂ emission monitoring equipment are subject to the provisions of paragraph (1).

   The provisions of this §  123.22 issued under section 5 of the Air Pollution Control Act (35 P. S. §  4005).

   The provisions of this §  123.22 adopted September 10, 1971, effective September 11, 1971, 1 Pa.B. 1804; amended March 3, 1972, effective March 20, 1972, 2 Pa.B. 383; amended August 4, 1978, effective October 1, 1978, 8 Pa.B. 2163; amended April 27, 1979, effective August 1, 1979, 9 Pa.B. 1447; corrected May 11, 1979, effective August 1, 1979, 9 Pa.B. 1534; amended November 7, 1980, effective January 1, 1981, 10 Pa.B. 4296; amended August 20, 1982, effective August 21, 1982, 12 Pa.B. 2787. Immediately preceding text appears at serial page (59076).

   Impossibility

   There is no constitutional prohibition against imposition of civil penalties for failure to comply with technologically impossible standards, since the use of fines to spark technological development is reasonably related to the goal of reducing pollution. Department of Environmental Resources v. Pennsylvania Power Co., 416 A.2d 995 (Pa. 1980).

   Impossibility of performance is a defense in a contempt proceeding where an order of court ordering a power company to comply with the SO₂ regulations was impossible of performance and where, under the present state of technology, the power company’s proposed use of higher smokestacks to control SO₂ emissions was as close as the company could come to compliance with the regulations. Department of Environmental Resources v. Pennsylvania Power Co., 316 A.2d 96 (Pa. Cmwlth. 1974).

 (a)  No person may permit the emission of byproduct coke oven gas into the outdoor atmosphere unless the gas is first burned.

 (b)  No person may permit the flaring or combustion of a coke oven byproduct gas which contains sulfur compounds, expressed as equivalent hydrogen sulfide, in concentrations greater than 50 grains per 100 dry standard cubic feet. The sulfur compounds, expressed as equivalent hydrogen sulfide, emitted into the outdoor atmosphere from any tail gas sulfur recovery equipment utilized in a coke oven gas desulfurization system approved by the Department shall be included in the determination of these concentrations.

 (c)  Subsections (a) and (b) do not apply to emissions of coke oven gas from:

   (1)  An oven which is dampered off:

     (i)   Prior to and during the pushing operation of the oven.

     (ii)   Because of some malfunction associated with the oven.

   (2)  Unavoidable oven leakage occurring during the coking cycle.

 (d)  Sections 129.12 and 129.13 (relating to sulfuric acid plants; and sulfur recovery plants) may not be applicable to processes operated in conjunction with the desulfurization of byproduct coke oven gas, provided that the standards in this section have been complied with.

   The provisions of this §  123.23 adopted September 10, 1971, effective September 11, 1971, 1 Pa.B. 1804; amended March 3, 1972, effective March 20, 1972, 2 Pa.B. 383; amended October 25, 1974, effective November 11, 1974, 4 Pa.B. 2283; amended April 27, 1979, effective August 1, 1979, 9 Pa.B. 1534. Immediately preceding text appears at serial page (38907).

 (a)  No person may permit the emission into the outdoor atmosphere of sulfur oxides from any zinc roasting operation in such a manner that the concentration of sulfur oxides, expressed as SO₂, in the effluent gas exceeds 500 parts per million by volume, dry basis, calculated as a 2-hour moving average.

 (b)  No person may permit the emission into the outdoor atmosphere of sulfur oxides from any zinc sintering operation in excess of the rate calculated by the following formula:

 Y = 0.054X,

 Where:

 X = Calcine feed rate to the sinter plant (lbs/hr); and

 Y = Allowable sulfur oxide emissions (lbs/hr).

 (a)  This section applies to the following:

   (1)  Combustion units specified in §  123.22(a)(4), (b)(4), (c)(4) or (e)(5) (relating to combustion units).

   (2)  Fossil fuel—fired steam generators of greater than 250 million Btus per hour of heat input which has installed sulfur dioxide pollutant control equipment.

   (3)  Sulfuric acid plants of greater than 300 tons per day production capacity, the production being expressed as 100% acid.

 (b)  A source subject to this section shall install, operate and maintain continuous SO₂ monitoring systems in compliance with Chapter 139 Subchapter C (relating to requirements for continuous in-stack monitoring for stationary sources). Results of emission monitoring shall be submitted to the Department on a regular basis in compliance with Chapter 139 Subchapter C.

 (c)  Continuous SO₂ monitoring systems installed under this section shall meet the minimum data availability requirements in Chapter 139 Subchapter C.

 (d)  The following are alternative monitoring systems:

   (1)  The Department will allow sources specified in subsection (a)(1) to utilize sulfur-in-fuel sampling programs in lieu of the requirements of subsection (b). These programs shall meet the requirements of Chapter 139 Subchapter C.

   (2)  The Department may exempt a source from the requirements of subsection (b) if the Department determines that the installation of a continuous emission monitoring system would not provide accurate determination of emissions or that installation of a continuous emission monitoring system cannot be implemented by a source due to physical plant limitations or to extreme economic reasons. The Department will require an exempted source to fulfill alternative emission monitoring and reporting requirements.

 (e)  The Department may use the data from the SO₂ monitoring devices or from the alternative monitoring systems required by this section to enforce the emission limitations for SO₂ defined in this article.

 (f)  Compliance with this section shall be obtained no later than 18 months after the effective date of the listing of any source identified in subsection (a). The Department may grant orders providing reasonable extension of time for sources that have made good faith efforts to install, operate and maintain continuous monitoring devices, but that have been unable to complete the operations within the time period provided.

 (g)  The Department may use the data from the SO₂ monitoring systems or from the alternative monitoring systems required by this section to determine compliance with the applicable emission limitations for SO₂ established in this article.

   The provisions of this §  123.25 issued under the Air Pollution Control Act (35 P. S. § §  4001—4015).

   The provisions of this §  123.25 adopted April 27, 1979, effective August 1, 1979, 9 Pa.B. 1447; amended April 27, 1979, effective August 1, 1979, 9 Pa.B. 1534; amended June 19, 1981, effective June 20, 1981, 11 Pa.B. 2132; amended October 26, 1990, effective October 27, 1990, 20 Pa.B. 5416. Immediately preceding text appears at serial pages (136379) to (136380).

   This section cited in 25 Pa. Code §  123.22 (relating to combustion units); and 25 Pa. Code §  139.104 (relating to sulfur dioxide and nitrogen oxides monitoring requirements for combustion sources).

ODOR EMISSIONS

§ 123.31. Limitations.

 (a)  Limitations are as follows:

   (1)  If control of malodorous air contaminants is required under subsection (b), emissions shall be incinerated at a minimum of 1200°F for at least 0.3 second prior to their emission into the outdoor atmosphere.

   (2)  Techniques other than incineration may be used to control malodorous air contaminants if such techniques are equivalent to or better than the required incineration in terms of control of the odor emissions and are approved in writing by the Department.

 (b)  A person may not permit the emission into the outdoor atmosphere of any malodorous air contaminants from any source, in such a manner that the malodors are detectable outside the property of the person on whose land the source is being operated.

 (c)  The prohibition in subsection (b) does not apply to odor emissions arising from the production of agricultural commodities in their unmanufactured state on the premises of the farm operation.

   The provisions of this §  123.31 adopted September 10, 1971, effective September 11, 1971, 1 Pa.B. 1804; amended March 3, 1972, effective March 20, 1972, 2 Pa.B. 383; amended August 12, 1977, effective August 29, 1977, 7 Pa.B. 2251; amended August 12, 1983, effective August 13, 1983, 13 Pa.B. 2478. Immediately preceding text appears at serial page (75541).

   Compliance

   The Department of Environmental Resources was required to deny an application for reactivation of beehive coke ovens, regardless of economic consequences, when the application did not provide any information which would show that the ovens would meet the limitations applicable to fugitive emissions and constitutional rights were not violated even though there was no known method to operate beehive coke ovens in compliance with this title. Rochez Brothers, Inc. v. Department of Environmental Resources, 334 A.2d 790 (Pa. Cmwlth. 1975).

   Review

   On appeal from the Department of Environmental Resources’ refusal to grant an applicant permission to reactivate certain coke ovens, where the appellant did not show that the oven would meet the limitations in this title, but showed only the ‘‘dire need’’ for the coke to be produced, the scope of review was limited to whether constitutional rights were violated, an error of law committed or any necessary finding of fact not supported by the evidence. Rochez Brothers, Inc. v. Department of Environmental Resources, 334 A.2d. 790 (Pa. Cmwlth. 1975).

   This section cited in 25 Pa. Code §  271.902 (relating to permits and direct enforceability).

VISIBLE EMISSIONS

§ 123.41. Limitations.

 A person may not permit the emission into the outdoor atmosphere of visible air contaminants in such a manner that the opacity of the emission is either of the following:

   (1)  Equal to or greater than 20% for a period or periods aggregating more than 3 minutes in any 1 hour.

   (2)  Equal to or greater than 60% at any time.

   The provisions of this §  123.41 adopted September 10, 1971, effective September 11, 1971, 1 Pa.B. 1804; amended March 3, 1972, effective March 20, 1972, 2 Pa.B. 383.

   Denial of Application

   On appeal from the Department’s refusal to grant applicant permission to reactivate certain coke ovens, where the appellant does not show that the oven would meet the limitations in this title, but shows only the ‘‘dire need’’ for the coke to be produced, the scope of review is limited to whether constitutional rights were violated, an error of law committed or any necessary finding of fact not supported by the evidence. Rochez Brothers, Inc. v. Department of Environmental Resources, 334 A.2d 790 (Pa. Cmwlth. 1975).

   The Department is required to deny an application for reactivation of beehive coke ovens, regardless of economic consequences, when the application does not provide any information which would show that the ovens would meet the limitations applicable to fugitive emissions, and constitutional rights are not violated even though there is no known method to operate beehive coke ovens in compliance with the regulations. Rochez Brothers, Inc. v. Department of Environmental Resources, 334 A.2d 790 (Pa. Cmwlth. 1975).

   Due Process

   There is no violation of procedural due process where an order to make certain changes in coke oven operations does not place new or increased legal duties on the operator but only redefines and mitigates what had been an immediate, current legal duty under the regulations and a compliance schedule is specified and no variance request is made. Commonwealth v. Crucible, Inc., 65 Pa. D. & C.2d 151 (1973).

   Failure to Appeal

   Where the party is aggrieved by the Department order requiring compliance with 25 Pa. Code §  123.41 (relating to limitations), by a certain date, failure to appeal such order bars an attack on the order and the validity of the regulation on which it was predicated, in a subsequent enforcement proceeding brought by the Department. Department of Environmental Resources v. Wheeling-Pittsburgh Steel Corporation, 348 A.2d 765 (Pa. Cmwlth. 1975); affirmed in part remanded in part; 357 A.2d 320 (Pa. 1977); cert. denied 98 S. Ct. 514 (Pa. 1977).

   Validity of Order

   A steel corporation which is granted an extension of time for compliance with the standards relating to particulate matter emissions may not attack the validity of the order or the regulations on which it was predicated in a subsequent enforcement proceeding, and the corporation does not have the right to trial by jury even though it seeks declaratory relief in its answer to the enforcement petition. Department of Environmental Resources v. Wheeling-Pittsburgh Steel Corporation, 348 A.2d 765 (Pa. Cmwlth. 1975).

 The limitations of §  123.41 (relating to limitations) shall not apply to a visible emission in any of the following instances:

   (1)  When the presence of uncombined water is the only reason for failure of the emission to meet the limitations.

   (2)  When the emission results from the operation of equipment used solely to train and test persons in observing the opacity of visible emissions.

   (3)  When the emission results from sources specified in §  123.1 (a)(1)—(9) (relating to prohibition of certain fugitive emissions).

   (4)  When arising from the production of agricultural commodities in their unmanufactured state on the premises of the farm operation.

 Visible emissions may be measured using either of the following:

   (1)  A device approved by the Department and maintained to provide accurate opacity measurements.

   (2)  Observers, trained and qualified to measure plume opacity with the naked eye or with the aid of devices approved by the Department.

 (a)  A person may not permit the operation of a coke oven battery in a manner that visible fugitive air contaminants are emitted in excess of the emissions allowed by the following limitations:

   (1)  The following open charging limitation applies to existing batteries listed in §  121.1 (relating to definitions). The following closed charging limitation applies to any existing battery on which a closed charging system is installed:

     (i)   Open charging. At no time may the aggregated times of visible open charging emissions during any four consecutive charges equal more than 75 seconds.

     (ii)   Closed charging. At no time may there be closed charging emissions during more than one charge out of any ten consecutive charges.

   (2)  At no time may door area emissions from any coke oven exceed 40% opacity 15 minutes or longer after the last charge to that oven.

   (3)  At no time may there be any visible door area emissions from more than 10% of the door area of operating coke ovens, excluding the two-door area representing the last oven charged on any battery and any door areas obstructed from view.

   (4)  At no time may there be visible topside emissions from more than 2.0% of the charging port seals on operating coke ovens in any battery, excluding visible emissions from no more than three ovens which may be dampered off.

   (5)  At no time may there be topside emissions from more than 5.0% of the offtake piping on operating coke ovens in any battery, excluding visible emissions from open standpipe caps on no more than three ovens which may be dampered off.

   (6)  At no time may there be topside emissions from any point on the topside other than allowed emissions from charging port seals and offtake piping under paragraphs (4) and (5).

   (7)  At no time may there be visible emissions from the coke oven gas collector main.

 (b)  The following techniques shall be used for measuring and recording visible fugitive air contaminants from a coke oven battery:

   (1)  Observations of open and closed charging emissions shall be made from any point or points on the topside of a coke oven battery from which an observer can obtain an unobstructed view of the charging operation. The observer shall determine and record the total number of seconds that charging emissions are visible during the charging of coal to the coke oven. The observer shall time the visible charging emissions with a stopwatch while observing the charging operation. Simultaneous emissions from more than one emission point shall be timed and recorded as one emission and may not be added individually to the total time. Open charging emissions may not include any emissions observed after all the charging port covers have been firmly seated following the removal of the larry car, such as emissions occurring when a cover is temporarily removed to permit the sweep-in of spilled coal. The total number of seconds of visible emissions observed, clock time for the initiation and completion of the charging operation, battery identification, and oven number for each charge shall be recorded by the observer. In the event that observations of emissions from a charge are interrupted due to events beyond the control of observer, the data from that charge shall be invalidated and the observer shall note on his observation sheet the reason for invalidating the data. The observer shall then resume observation of the next consecutive charge or charges, and continue until he has obtained a set of four charges for comparison with the emission standard. Compliance with subsection (a)(1) shall be determined by summing the seconds of charging emissions observed during each of the four charges.

   (2)  Observations of door area emissions for the purpose of determining compliance with subsection (a)(2) shall be made at a point above the top of the door but below the battery top, or at the top of any local door area emission control hood. The observer shall place himself no less than 25 feet from the face of the door in a location where his view of the door area is unobstructed.

   (3)  Observations of door area emissions for determining compliance with subsection (a)(3) shall be made from a minimum distance of 25 feet from each door. Each door area shall be observed in sequence for only that period necessary to determine whether or not, at the time, there are visible emissions from any point on the door area while the observer walks along the side of the battery. If the observer’s view of a door area is more than momentarily obstructed, for example, by door machinery, pushing machinery, coke guide, luter truck or opaque steam plumes, he shall record the door area obstructed and the nature of the obstruction and continue the observations with the next door area in sequence which is not obstructed. The observer shall continue this procedure along the entire length of the battery for both sides and shall record the battery identification, battery side and oven door identification number of each door area exhibiting visible emissions. Before completing the observation of door area emissions, the observer shall attempt to reobserve the obstructed doors. Compliance with subsection (a)(3) shall be calculated by application of the following formula, which excludes two door areas representing the last oven charged from the numerator and obstructed door areas from the denominator:

   (4)  Observations of visible emissions from a coke oven topside, other than emissions from the topside defined as open or closed charging emissions or pushing emissions, shall be made and recorded during the time an observer walks the topside of a battery from one end to the other, positioning himself near the center line. During the traverse, the observer may stray from near the center line of the battery and walk as close to the offtake piping as is necessary to determine whether an observed emission is emanating from the offtake piping. Each oven shall be observed in sequence. The observer shall record the battery identification, the points of topside emission from each oven, the oven number and whether an oven was dampered off. Compliance with subsection (a)(4) shall be determined by application of the following formula:

   The provisions of this §  123.44 issued under section 1920-A of The Administrative Code of 1929 (71 P. S. §  510-20); and section 5 of the Air Pollution Control Act (35 P. S. §  4005).

   The provisions of this §  123.44 adopted August 12, 1977, effective December 31, 1977, 7 Pa.B. 2251; corrected November 4, 1977, effective December 31, 1977, 7 Pa.B. 3260; amended August 12, 1983, effective August 13, 1983, 13 Pa.B. 2478; amended December 26, 1997, effective December 27, 1997, 27 Pa.B. 6804. Immediately preceding text appears at serial pages (215785) to (215788).

 (a)  Coverage. Coverage shall comply with the following:

   (1)  This section applies to a source:

     (i)   That is covered under §  123.41 (relating to limitations) and is also covered by an emission limitation in the form of a mass rate or a stack gas concentration or a fuel requirement.

     (ii)   That is not a fugitive air contaminant.

     (iii)   For which the mass rate or concentration can be determined:

       (A)   Using techniques specified in § §  139.11—139.16.

       (B)   By any other method approved by the Department that is consistent with accepted air pollution testing practices and with obtaining accurate results that are representative of the conditions evaluated.

   (2)  Appendix D presents the applicability of this section for various emission limitation formats.

 (b)  Procedure for application. The procedure for application shall comply with the following:

   (1)  The owner or operator of a source may request the Department to determine the opacity of emissions from the source during a demonstration of compliance with the applicable mass rate standard or stack gas concentration standard or fuel requirement. The request must be made in the form of a plan approval application under Chapter 127 Subchapter A (relating to general).

   (2)  The owner or operator shall provide for any test the Department deems necessary for determining compliance with the applicable emission limitation.

   (3)  The owner or operator shall provide sufficient notification to the Department so that the proposed test methods may be reviewed and approved by the Department. No test will be considered by the Department for the purpose of establishing an alternative opacity limitation unless the test methods have been first approved by the Department and a trained and qualified observer is present during the test.

 (c)  Eligibility. A source shall be eligible for an alternative opacity limitation (AOL) if the following conditions are met:

   (1)  The Department finds that the source is in compliance with this article except §  123.41. The Department will specify the method of demonstrating compliance.

   (2)  During the time the determination of compliance and AOL is conducted, the source fails to meet any applicable opacity limitation.

   (3)  The Department finds:

     (i)   That the source has not discontinued measures to minimize opacity of emissions, within the bounds of good engineering and good economic practice.

     (ii)   That the source and associated air pollution control equipment are operated and maintained in a manner to minimize the opacity of emissions, within the bounds of good engineering and good economic practice.

   (4)  The demonstration of compliance and the alternative opacity tests are performed under the conditions established by the Department.

   (5)  The Department determines that the AOL would not create or contribute to a public nuisance nor cause air pollution as defined under the act.

 (d)  Level of the alternative standard. The Department will set the AOL at the opacity levels measured during the performance test, even if the emissions were substantially less than those allowed under the regulations or permit conditions of the Department. The Department will enter the AOL as a condition of the operating permit of the source.

 (e)  Operating conditions. The Department will specify the operating conditions under which the determination of compliance and AOL will be made. The conditions must be based on technical knowledge of the process concerning normal operation and the effects of deviations from normal operations.

 (f)  Timing of test. The Department will specify the day, time of day and time of year for conducting the determination of compliance and AOL where these factors may substantially affect the determination of source opacity. Where the source exhibits high opacity only under certain specified conditions or during certain times, the Department may limit the applicability of the AOL to operation during those conditions or times. These conditions or times must be specified in the permit.

 (g)  Continuous monitoring. Continuous monitoring shall consist of the following:

   (1)  A source that requests an AOL must install, operate and maintain a continuous opacity monitor before the determination of compliance and AOL is made.

   (2)  The Department will use the data from the monitor during the determination of compliance and AOL to set the AOL. After the AOL is entered on the operating permit of the source, the Department will use the data from the monitor to enforce the AOL.

   (3)  The Department may exempt a source from the requirement of paragraph (1) if the Department determines that the monitor would not give representative opacity readings for that source. The Department may require an exempted source to:

     (i)   Use trained and qualified observers to measure the opacity.

     (ii)   Monitor and report operating parameters of the process and of air pollution control equipment.

     (iii)   Perform such activities on a specified schedule maintaining relevant records for inspection by the Department.

 (h)  Granting and quantifying the AOL. Granting and quantifying the AOL include the following:

   (1)  The Department will issue a permit establishing the AOL for the source or will deny the application for plan approval if the Department determines that the source is not eligible for, or entitled to, an AOL.

   (2)  The Department will use the procedure of § §  139.17 and 139.18 (relating to general requirements; and calculation of alternative opacity limitations) to quantify the AOL.

 (i)  Special situations. Special situations include the following:

   (1)  For sources that make several products of varying opacity-producing capabilities, the Department may establish an overall AOL independent of the product. The Department may, however, establish a separate AOL for each product where the Department determines that the opacities from the products differ to such an extent that enforcement of the mass rate standard or stack gas concentration standard or fuel requirement may be hampered with only one AOL.

   (2)  For cases in which several processes vent to a single stack, the Department will set an AOL at the opacity level produced after each process is determined to be in compliance with the appropriate mass rate standard or stack gas concentration standard or fuel requirement.

 (j)  Revocation of AOL. Revocation of AOL shall be as follows:

   (1)  The Department may revoke a source’s AOL if the Department determines that:

     (i)   The source is not in compliance with this article.

     (ii)   The source has discontinued measures to minimize opacity of emissions, within the bounds of good engineering and good economic practice.

     (iii)   The plume opacity of the source creates or contributes to a public nuisance or causes air pollution as defined under the act.

   (2)  If the Department revokes a source’s AOL, the opacity of the source will be regulated by §  123.41. The Department may reinstate a revoked AOL if it determines that the conditions which caused the revocation no longer exist.

 (k)  Maintenance of continuous monitor; reestablishment of AOL. Reestablishment of an AOL shall be as follows:

   (1)  The Department may require the owner or operator of a source with an approved AOL and a continuous opacity monitor to do any or all of the following if a trained observer of the Department determines that the source is violating an AOL:

     (i)   Adjust or replace the continuous opacity monitor.

     (ii)   Retest opacity with monitor and trained and qualified observer.

     (iii)   Perform a test to determine compliance with the appropriate mass rate standard or stack gas concentration standard or fuel requirement.

   (2)  For a source with an AOL established by use of a continuous opacity monitor, the Department may establish a new AOL based on opacity readings by a trained and qualified observer if:

     (i)   The Department determines that the source complies with the applicable mass rate standard or stack gas concentration standard or fuel requirement.

     (ii)   The trained and qualified observer of the Department notifies the source that it does not comply with the existing AOL.

     (iii)   The data from the continuous opacity monitor indicate that the source complies with the existing AOL.

   The provisions of this §  123.45 issued under the Air Pollution Control Act (35 P. S. § §  4001—4015).

   The provisions of this §  123.45 adopted June 19, 1981, effective June 20, 1981, 11 Pa.B. 2132.

 (a)  The following sources are subject to this section:

   (1)  Fossil fuel-fired steam generators with an annual average capacity factor of greater than 30%, as demonstrated to the Department by the owner or operator, and of greater than 250 million Btu per hour heat input except where:

     (i)   Natural gas is the only fuel burned.

     (ii)   Oil or a mixture of gas and oil are the fuels burned and the source is able to comply with the applicable particulate matter and opacity regulations without utilization of particulate matter collection equipment and the source has not been found, within the 5 years previous to the applicability of this section, through any administrative or judicial proceedings to be in violation of any visible emissions standard.

   (2)  Catalyst regenerators for fluid bed catalytic cracking units at petroleum refineries, if the unit is of greater than 20,000 barrels per day fresh feed capacity.

 (b)  All sources subject to the provisions of this section shall install, operate and maintain continuous opacity monitoring devices in compliance with Chapter 139, Subchapter C (relating to requirements for continuous in-stack monitoring for stationary sources). Results of opacity monitoring shall be submitted to the Department on a regular basis in compliance with the requirements of Chapter 139, Subchapter C.

 (c)  The Department may exempt a source from the requirements of subsection (b) if the Department determines that the installation of a continuous emission monitoring system would not provide accurate determination of emissions or that installation of a continuous emission monitoring system may not be implemented by a source due to physical plant limitations or to extreme economic reasons. The Department will require such an exempted source to fulfill alternative emission monitoring and reporting requirements.

 (d)  The Department may use the data from the monitoring devices or from the alternative monitoring systems required by this section to enforce the visible emission limitations defined in this article.

 (e)  Compliance with this section shall be obtained no later than 18 months after the effective date of the listing of any source identified in subsection (a). The Department may grant orders providing reasonable extension of time for sources that have made good faith efforts to install, operate and maintain continuous monitoring devices but have been unable to complete such operations within the time period provided.

   The provisions of this §  123.46 issued under the Air Pollution Control Act (35 P. S. § §  4001—4015).

   The provisions of this §  123.46 adopted June 19, 1981, effective June 20, 1981, 11 Pa.B. 2132; corrected June 26, 1981, effective June 20, 1981, 11 Pa.B. 2225.

NITROGEN COMPOUND EMISSIONS

§ 123.51. Monitoring requirements.

 (a)  This section applies to combustion units with a rated heat input of 250 million Btus per hour or greater and with an annual average capacity factor of greater than 30%.

 (b)  Sources subject to this section shall install, operate and maintain continuous nitrogen oxides monitoring systems and other monitoring systems to convert data to required reporting units in compliance with Chapter 139, Subchapter C (relating to requirements for continuous in-stack monitoring for stationary sources).

 (c)  Sources subject to this section shall submit results on a regular schedule and in a format acceptable to the Department and in compliance with Chapter 139, Subchapter C.

 (d)  Continuous nitrogen oxides monitoring systems installed under the requirements of this section shall meet the minimum data availability requirements in Chapter 139, Subchapter C.

 (e)  The Department may exempt a source from the requirements of subsection (b) if the Department determines that the installation of a continuous emission monitoring system would not provide accurate determination of emissions or that installation of a continuous emission monitoring system cannot be implemented by a source due to physical plant limitations or to extreme economic reasons. A source exempted from the requirements of subsection (b) shall satisfy alternative emission monitoring and reporting requirements proposed by the source and approved by the Department which provide oxides emission data that is representative of actual emissions of the source.

 (f)  Sources subject to this section shall comply by October 20, 1993, unless the source becomes subject to the requirements later than October 20, 1990. For sources which become subject to the requirements after October 20, 1990, the source has 36 months from the date the source becomes subject to this section. The Department may issue orders providing a reasonable extension of time for sources that have made good faith efforts to install, operate and maintain continuous monitoring devices, but that have been unable to complete the operations within the time period provided.

   The provisions of this §  123.51 issued under the Air Pollution Control Act (35 P. S. § §  4001—4015).

   The provisions of this §  123.51 adopted October 19, 1990, effective October 20, 1990, 20 Pa.B. 5291.

   This section cited in 25 Pa. Code §  129.91 (relating to control of major sources of NO_x and VOCs).

NO_x ALLOWANCE REQUIREMENTS

§ 123.101. Purpose.

 Sections 123.102—123.120 and this section establish a NO_x budget and a NO_x allowance trading program for NO_x affected sources for the purpose of achieving the health based ozone ambient air quality standard.

   The provisions of this §  123.101 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  The owner or operator or each NO_x affected source shall, by December 31 of each calendar year, hold a quantity of NO_x allowances meeting the requirements of §  123.110(a) (relating to source compliance requirements) in the source’s current year NATS account that is equal to or greater than the total NO_x emitted from the source during that year’s NO_x allowance control period.

 (b)  The initial NO_x allowance control period begins on May 1, 1999.

   The provisions of this §  123.102 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  NO_x allowances shall be allocated, transferred or used as whole NO_x allowances. To determine the number of whole NO_x allowances, the number of NO_x allowances shall be rounded down for decimals less than 0.50 and rounded up for decimals of 0.50 or greater.

 (b)  A NO_x allowance does not constitute a security or other form of property.

 (c)  Allowances may not be used to meet the requirements of this subchapter prior to the year for which they are allocated.

 (d)  For the purposes of account reconciliation, NO_x allowances allocated for the NO_x allowance control period shall be deducted first, and remaining allowances if not otherwise designated by the source shall be deducted on a first-in, first-out basis.

 (e)  NO_x allowances may only be used to comply with § §  123.101, 123.102, 123.104—123.120 and this section.

   The provisions of this §  123.103 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683; 25 Pa. Code §  123.121 (relating to NO_x Allowance Program transition); and 25 Pa. Code §  145.43 (relating to compliance supplement pool).

 (a)  The owner or operator of a NO_x affected source shall designate for each source account, one authorized account representative and one alternate. Initial designations shall be submitted to the Department by December 1, 1997. An authorized account representative may be replaced or, for a new NO_x affected source, designated with the submittal of a new ‘‘Account Certificate of Representation.’’

 (b)  The ‘‘Account Certificate of Representation’’ shall be signed by the authorized account representative for the NO_x affected source and contain, at a minimum, the following:

   (1)  Identification of the NO_x affected source by plant name, state and fossil fired indirect heat transfer combustion unit number for which the certification of representation is submitted.

   (2)  The name, address, telephone and facsimile number of the authorized account representative and the alternate.

   (3)  A list of owners and operators of the NO_x affected source.

   (4)  The verbatim statement, ‘‘I certify that I,

 (c)  The alternate authorized account representative shall have the same authority as the authorized account representative. Correspondence from the NO_x budget administrator shall be directed to the authorized account representative.

 (d)  Only an authorized account representative or the designated alternate may request transfers of NO_x allowances in a NATS account. The authorized account representative shall be responsible for all transactions and reports submitted to the NATS.

 (e)  Authorized account representative designation or changes become effective upon the logged date of receipt of a complete application by the NO_x budget administrator from the Department. The NO_x budget administrator will acknowledge receipt and the effective date of the changes by written correspondence to the authorized account representative.

   The provisions of this §  123.104 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  The NATS account records shall constitute a NO_x affected source’s NO_x allowance holdings.

 (b)  The transfer, use and deduction of NO_x allowances become effective only after entry in the tracking system account records.

 (c)  Any person may hold an account in the NATS.

   The provisions of this §  123.105 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  NO_x allowances may be transferred at any time between January 31 and December 31 in accordance with §  123.107 (relating to NO_x allowance transfer procedures).

 (b)  NO_x allowances shall be held by the originating account at the time of the transfer request.

 (c)  A transfer request shall be filed jointly with the NO_x budget administrator and the Department by the person named as the authorized account representative for the originating account.

 (d)  The transfer is effective as of the date the NO_x budget administrator posts the transfer of the allowances on the NATS.

   The provisions of this §  123.106 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 NO_x allowances may be transferred under the following conditions:

   (1)  The transfer request shall be documented on a form, or electronic media, approved by the Department. The following information, at a minimum, shall be provided:

     (i)   The account number identifying both the originating account and the acquiring account.

     (ii)   The name and address associated with the owners of the originating account and the acquiring account.

     (iii)   The identification of the serial numbers for each NO_x allowance being transferred.

   (2)  The transfer request shall be authorized and certified by the authorized account representative for the originating account. To be considered correctly submitted, the request for transfer shall include the following statement of certification:

  ‘‘I am authorized to make this submission on behalf of the owners and operators of the NO_x affected source and I hereby certify under the penalty provisions contained in the Air Pollution Control Act, that I have personally examined the foregoing and am familiar with the information contained in this document, and all attachments, and that based on my inquiry of those individuals immediately responsible for obtaining the information, I believe the information is true, accurate and complete. I am aware that there are significant penalties for submitting false information, including possible fines and imprisonment.’’

 The authorized account representative for the originating account shall provide a copy of the transfer request to each owner or operator of the NO_x affected source.

   The provisions of this §  123.107 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 The owner and operator of each NO_x affected source shall comply with the following requirements:

   (1)  NO_x emissions from each NO_x affected source shall be monitored as specified by this section and in accordance with the procedures contained in the document titled, ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

   (2)  The owner or operator of each NO_x affected source shall submit to the Department and the NO_x budget administrator a monitoring plan in accordance with the procedures outlined in the document titled, ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

   (3)  New and existing unit emission monitoring systems, as required and specified by this section, shall be installed and be operational and shall have met all of the certification testing requirements in accordance with the procedures and deadlines specified in the document titled, ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program’’ in a manner consistent with Chapter 139 (relating to sampling and testing).

   (4)  Monitoring systems are subject to initial performance testing and periodic calibration, accuracy testing and quality assurance/quality control testing as specified in the document titled ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’ Notwithstanding this provision, Non-Part 75 Sources which have Department approved NO_x CEMS reporting in accordance with §  139.101 (relating to gen-eral requirements) in units of pounds of NO_x per hour shall complete the periodic self-audits listed in the quality assurance section of §  139.102(3) (relating to references) at least annually and no sooner than 6 months following the previous periodic self-audit. If practicable, the audit shall be conducted between April 1 and May 31.

   (5)  During a period when valid data is not being recorded by devices approved for use to demonstrate compliance with this subchapter, missing or invalid data shall be replaced with representative default data in accordance with 40 CFR Part 75 (relating to continuous emission monitoring) and the document titled, ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’ Notwithstanding this provision, Non-Part 75 Sources which have Department approved NO_x CEMS reporting in accordance with §  139.101 in units of pounds of NO_x per hour shall report this data to the NETS and shall continue report submissions as required under Chapter 139 to the Department.

   (6)  Sources subject to 40 CFR Part 75 shall demonstrate compliance with this section with a certified Part 75 monitoring system.

     (i)   If the source has a flow monitor certified under Part 75, NO_x in pounds per hour shall be determined using the Part 75 NO_x CEMS and the flow monitor. The NO_x emission rate in pounds per million Btu shall be determined using the procedure in 40 CFR Part 75 Appendix F, Section 3 (relating to procedures for NO_x emission rate). The hourly heat input shall be determined by using the procedures in 40 CFR Part 75 Appendix F, Section 5 (relating to procedures for heat input). NO_x in pounds per hour shall be determined by multiplying the NO_x per million Btu by the Btus per hour.

     (ii)   If a Part 75 source does not have a certified flow monitor, but does have a certified NO_x CEMS, NO_x emissions in pounds per hour emissions shall be determined by using the NO_x CEMS to determine the NO_x emission rate in pounds per million Btu and the heat input shall be determined by using the procedures in 40 CFR Part 75 Appendix D (relating to optional SO₂ emissions data protocol for gas-fired and oil-fired units). NO_x in pounds per hour shall be determined by multiplying the NO_x per million Btu and Btus per hour.

     (iii)   If the owner or operator of a source uses the procedures in 40 CFR Part 75, Appendix E (relating to optional NO_x emissions estimation protocol for gas-fired peaking units and oil-fired peaking units) to determine the NO_x emission rate, NO_x emissions in pounds per hour shall be determined by multiplying the NO_x emission rate determined by using the Appendix E procedures times the heat input determined using the procedures in 40 CFR Part 75, Appendix D.

     (iv)   If the owner or operator of a source uses the procedures in 40 CFR Part 75, Subpart E (relating to alternative monitoring systems) to determine NO_x emission rate, NO_x emissions in pounds per hour shall be determined using the alternative monitoring method approved under 40 CFR Part 75 Subpart E and the procedures contained in the document titled, ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

     (v)   If the source emits to common or multiple stacks, or both, the source shall monitor emissions according to the procedures contained in the document titled, ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

   (7)  Sources not subject to 40 CFR Part 75 and not meeting the requirements of paragraph (11) shall meet the monitoring requirements of this section by:

     (i)   Preparing and obtaining approval of a monitoring plan as specified in the document titled, ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

     (ii)   Determining NO_x emission rate and heat input using a methodology specified in paragraphs (8) and (9) respectively or determining NO_x concentration and flow using a methodology specified in paragraphs (8) and (9) respectively.

     (iii)   Calculating NO_x emissions in pounds per hour using the procedure described in paragraph (10).

   (8)  The owner or operator of a NO_x affected source which is not subject to 40 CFR Part 75, may implement an alternative emission rate monitoring method. The NO_x emission rate in pounds per million Btu or NO_x concentration in ppm shall be determined using one of the following methods:

     (i)   The owner or operator of a NO_x affected source that has a maximum rated heat input capacity of 250 MMBtu/hr or greater which is not a peaking unit as defined in 40 CFR 72.2 (relating to definitions), which combusts any solid fuel or is required to or has installed a NO_x continuous emissions monitoring system (NO_x CEMS) for the purposes of meeting either the requirements of 40 CFR Part 60 (relating to standards of performance for new stationary sources) or another Department or Federal requirement, shall use that NO_x CEMS to meet the requirements of this section. If the owner or operator of the unit monitors flow according to paragraph (9), the owner or operator may use the NO_x CEMS to measure NO_x in ppm, otherwise the NO_x CEMS shall be used to measure the emission rate in lb/MMBtu. The owner or operator shall install, certify, operate and maintain this monitor in accordance with the ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’ When a NO_x CEMS cannot be used to report data for this program because it does not meet the requirements of the ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program,’’ missing data shall be substituted using the procedures in that document. In addition, the NO_x CEMS shall meet the initial certification requirements contained in the ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

     (ii)   The owner or operator of a source that is not required to have a NO_x CEMS, may request approval from the Department to use any of the following appropriate methodologies to determine the NO_x emission rate:

       (A)   Boilers or turbines may use the procedures contained in 40 CFR Part 75 Appendix E to measure NO_x emission rate in pounds/MMBtu, consistent with the ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

       (B)   Owners and operators of combustion turbines that are subject to this section and § §  123.101—123.107 and 123.109—123.120 may also meet the monitoring requirements of this section and § §  123.101—123.107 and 123.109—123.120 by using default emission factors to determine NO_x emissions in pounds per hour as follows:

         (I)   For gas-fired turbines, the default emission factor is 0.7 pounds NO_x per MMBtu.

         (II)   For oil-fired turbines, the default factor is 1.2 pounds NO_x per MMBtu.

         (III)   Owners and operators of gas turbines or oil-fired turbines may perform testing, consistent with ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program,’’ to determine unit specific maximum potential NO_x emission rates.

       (C)   Owners and operators of boilers that are subject to this section and § §  123.101—123.107 and 123.109—123.120 may meet the monitoring requirements of this section and § §  123.101—123.107 and 123.109—123.120 by using a default emission factor of 2.0 pounds per MMBtu if they burn oil and 1.5 lb/MMBtu if they burn natural gas to determine NO_x emissions in pounds per hour, or may perform testing consistent with the ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program,’’ to determine a unit specific maximum potential emission rate.

   (9)  The owner or operator of a source which is not subject to 40 CFR Part 75, and not meeting the requirements of paragraph (11), shall determine heat input in MMBtu or flow in standard cubic feet per hour using one of the following methods:

     (i)   The owner or operator of a source may install and operate a flow monitor according to 40 CFR Part 75.

       (A)   The owner or operator may either use the flow CEMS to monitor stack flow in standard cubic feet per hour and a NO_x CEMS to monitor NO_x in ppm.

       (B)   In the alternative, the owner or operator may use the flow CEMS and a diluent CEMS to determine heat input in MMBtu and a NO_x CEMS to monitor NO_x in lbs/MMBtu.

     (ii)   The owner or operator of a source that does not have a flow CEMS may request approval from the Department to use any of the following methodologies to determine their heat input rate:

       (A)   The owner or operator of a source may determine heat input using a flow monitor and a diluent monitor meeting 40 CFR Part 75 and the procedures in 40 CFR Part 75, Appendix F Section 5.

       (B)   The owner or operator of a source that combusts only oil or natural gas may determine heat input using a fuel flow monitor meeting 40 CFR Part 75 Appendix D and the procedures of 40 CFR Part 75, Appendix F Section 5.

       (C)   The owner or operator of a source that combusts only oil or natural gas which uses a unit specific or generic default NO_x emission rate, may determine heat input by measuring the fuel usage for a specified frequency of longer than an hour. This fuel usage shall then be reported on an hourly basis by apportioning the fuel based on electrical load in accordance with the following formula:

       (D)   The owner or operator of a source that combusts any fuel other than oil or natural gas, may request permission from the Department to use an alternative method of determining heat input. Alternative methods include:

         (I)   Conducting fuel sampling and analysis and monitoring fuel usage.

         (II)   Using boiler efficiency curves and other monitored information such as boiler steam output.

         (III)   Other methods approved by the Department and which meet the requirements in the ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

       (E)   Alternative methods for determining heat input are subject to both initial and periodic relative accuracy, and quality assurance testing as prescribed by ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

   (10)  If the owner or operator determines NO_x emission rate in pounds per million Btu in accordance with paragraph (6)(iii) and heat input rate in MMBtu per hour in accordance with paragraph (7), the two values shall be multiplied to result in NO_x emissions in pounds per hour. If the owner or operator determines NO_x emissions in ppm and flow in standard cubic feet per hour, the procedures in ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program’’ may be used to determine NO_x emissions of this rule in pounds per hour. This value shall be reported to the NETS.

   (11)  Non-Part 75 sources which have Department approved NO_x CEMS reporting in accordance with §  139.101 in units of pounds of NO_x per hour may meet the monitoring requirements of paragraph (7); or shall comply with the following:

     (i)   Calibration standards used shall be in accordance with both 40 CFR Part 75, Appendix A, Section 5.2 (relating to concentrations) and with §  139.102(3).

     (ii)   Testing listed in 40 CFR Part 75, Appendix A, Section 6.4 (relating to cycle time/response time test) not already conducted as part of the response time testing in §  139.102(3) shall be conducted.

     (iii)   Bias testing of the relative accuracy test data in accordance with 40 CFR Part 75, Appendix A, Section 6.5 (relating to relative accuracy and bias tests) shall be conducted. Data from previously conducted relative accuracy testing may be used to meet this requirement.

     (iv)   Adjustment of data due to failure of bias test (in accordance with 40 CFR Part 75, Appendix A, Section 7.6.5 (relating to bias adjustment) and Appendix B, Section 2.3.3 (relating to bias adjustment factor)) or relative accuracy greater than 10% but less than or equal to 20% (by multiplying the NO_x emissions rate by 1.1), or both, shall be conducted only for reporting to the NO_x budget administrator for purposes of this section.

     (v)   A Data Acquisition Handling System verification demonstrating that both the missing data procedures and formulas as applicable to this section shall be conducted.

   The provisions of this §  123.108 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  The authorized account representative for each NO_x affected source shall submit to the NO_x budget administrator, electronically in a format which meets the requirements of the EPA’s Electronic Data Reporting convention, emissions and operations information for each calendar quarter of each year in accordance with the document titled, ‘‘Guidance for Implementation of Emission Monitoring Requirements for the NO_x Budget Program.’’

 (b)  Upon permanent shutdown, NO_x affected sources may be exempted from this section after receiving written Department approval of a request filed by the authorized account representative for the NO_x affected source which identifies the source and date of shutdown.

   The provisions of this §  123.109 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  Each year from November 1 through December 31, inclusive, the authorized account representative shall request the NO_x budget administrator to deduct, consistent with §  123.107 (relating to NO_x allowance transfer procedures) a designated amount of NO_x allowances by serial number, from the NO_x affected source’s compliance account in an amount equivalent to the NO_x emitted from the NO_x affected source during that year’s NO_x allowance control period in accordance with the following:

   (1)  Allowances allocated for the current NO_x control period may be used without restriction.

   (2)  Allowances allocated for future NO_x control periods may not be used.

   (3)  NO_x allowances which were allocated for any preceding NO_x allowance control period which were not used (banked) may be used in the current control period even if this may result in an unlimited exceedance of the NO_x budget. Banked allowances shall be deducted against emissions in accordance with a ratio of NO_x allowances to emissions as specified by the NO_x budget administrator as follows:

     (i)   If the total NO_x allowances remaining in the NATS for all sources for preceding NO_x allowance control periods are less than or equal to 10% of the total NO_x allowances allocated for that NO_x allowance control period, the ratio is 1:1.

     (ii)   If the total NO_x allowances remaining in the NATS for all sources for preceding NO_x allowance control periods are greater than 10% of the NO_x allowances allocated for that NO_x allowance control period, the ratio is 2:1 for the portion of banked allowances used for compliance from an account which are in excess of the amount calculated by multiplying the total allowances banked in the account times the PFC (progressive flow control).

 where

 (b)  If, by the December 31 compliance deadline, the authorized account representative either makes no NO_x allowance deduction request, or a NO_x allowance deduction request insufficient to meet the requirements of subsection (a), the NO_x budget administrator may deduct the necessary number of NO_x allowances from the NO_x affected source’s compliance account. The NO_x budget administrator shall provide written notice to the authorized account representative that NO_x allowances were deducted from the source’s account. If the necessary number of NO_x allowances is available, the source will be in compliance after the NO_x allowance deduction is completed. If there is an insufficient number of NO_x allowances available for NO_x allowance deduction, §  123.111 (relating to failure to meet source compliance requirements) applies.

 (c)  For each NO_x allowance control period, the authorized account representative for the NO_x affected source shall submit an annual compliance certification to the Department.

 (d)  The compliance certification shall be submitted no later than the NO_x allowance transfer deadline (December 31) of each year.

 (e)  The compliance certification shall contain, at a minimum, the following:

   (1)  An identification of the NO_x affected source, including the name, address, the name of the authorized account representative and the NATS account number.

   (2)  A statement indicating whether or not emissions data has been submitted to the NETS in accordance with §  123.108 (relating to source emissions monitoring requirements).

   (3)  A statement indicating whether or not the NO_x affected source held sufficient NO_x allowances, as determined in subsection (a), in its compliance account for the NO_x allowance control period, as of the NO_x allowance transfer deadline, to equal or exceed the NO_x affected source’s actual emissions and the emissions reported to the NETS for the NO_x allowance control period.

   (4)  A statement indicating whether or not the monitoring plan which governs the NO_x affected source was followed when monitoring the actual operation of the NO_x affected source.

   (5)  A statement indicating that all emissions from the NO_x affected source were accounted for, either through the applicable monitoring or through application of the appropriate missing data procedures.

   (6)  A statement indicating whether there were any changes in the method of operation of the NO_x affected source or the method of monitoring of the NO_x affected source during the current year.

 (f)  The Department may verify compliance by whatever means necessary, including one or more of the following:

   (1)  Inspection of facility operating records.

   (2)  Obtaining information on NO_x allowance deduction and transfers from the NATS.

   (3)  Obtaining information on emissions from the NETS.

   (4)  Testing emission monitoring devices.

   (5)  Requiring the NO_x affected source to conduct emissions testing in accordance with Chapter 139 (relating to sampling and testing).

   The provisions of this §  123.110 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  Failure by the NO_x affected source to hold in its compliance account, for a NO_x allowance control period, as of the NO_x allowance transfer deadline, sufficient NO_x allowances equal to or exceeding actual emissions for the NO_x allowance control period as specified under §  123.102 (relating to source allowance requirements and NO_x allowance control period) shall result in NO_x allowance deduction from the NO_x affected source’s compliance account at the rate of 3 NO_x allowances for every 1 ton of excess emissions. If sufficient allowances meeting the requirements of §  123.110(a) (relating to source compliance requirements) are not available, the source shall provide other sufficient allowances which shall be deducted prior to the beginning of the next NO_x allowance control period, otherwise the source may not operate during subsequent control periods.

 (b)  In addition to the NO_x allowance deduction required by subsection (a), the Department may enforce the provisions of this section and § §  123.101—123.110 and 123.112—123.120 under the act and the Clean Air Act.

   (1)  For purposes of determining the number of days of violation, any excess emissions for the NO_x allowance control period shall presume that each day in the NO_x allowance control period constitutes a day in violation (153 days) unless the NO_x affected source can demonstrate, to the satisfaction of the Department, that a lesser number of days should be considered.

   (2)  Each ton of excess emissions is a separate violation.

   The provisions of this §  123.111 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 The operating permit required under Chapter 127 (relating to construction, modification, reactivation and operations of sources) shall include a condition requiring compliance with § §  123.101—123.111, 123.113—123.120 and this section (relating to NO_x allowance requirements). The NATS compliance account number and the authorized account representative shall be listed on the permit.

   The provisions of this §  123.112 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 The owner or operator of a NO_x affected source shall maintain for each NO_x affected source and for 5 years, or any other period consistent with the terms of the NO_x affected source’s operating permit, the measurements, data, reports and other information required by § §  123.101—123.112, 123.114—123.120 and this section.

   The provisions of this §  123.113 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  NO_x allocations to NO_x affected sources may only be made by the Department.

 (b)  Except as provided in §  123.116 (relating to source opt-in provisions), for NO_x affected sources identified in Appendix A which shutdown or curtail operations, the source account will continue to receive NO_x allowances for each NO_x allowance control period.

   The provisions of this §  123.114 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  The sources contained in Appendix E are subject to the requirements of § §  123.101—123.114, 123.116—123.120 and this section. These sources are allocated NO_x allowances for the 1999-2002 NO_x allowance control periods as listed in Appendix E.

 (b)  The Department may allocate allowances to Duquesne Light Company’s Phillips and Brunot Island facilities. The allowances allocated to these facilities are limited as follows:

   (1)  The facility shall be fully operational.

   (2)  The allowances allocated to the facility may only be used by the baseline sources located at that facility, and may not be banked or transferred.

   (3)  The allocation to Brunot Island source identification numbers 001—012 may not exceed an aggregate 246 allowances for the period May 1—September 30.

   (4)  The allocation to Phillips Station boilers 1—6 may not exceed an aggregate 1,686 allowances for the period May 1—September 30.

   The provisions of this §  123.115 amended under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.115 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683; amended March 10, 2000, effective March 11, 2000, 30 Pa.B. 1370; amended September 22, 2000, effective September 23, 2000, 30 Pa.B. 4899. Immediately preceding text appears at serial pages (263985) to (263986).

 (a)  A person who owns, operates, leases or controls a non-NO_x affected source located in this Commonwealth may apply to the Department to opt-in that source to become a NO_x affected source. For replacement sources, all sources to which production may be shifted to shall be opted-in together.

 (b)  A source which began operations without emission reduction credits transferred from a NO_x affected source may become a NO_x affected source under the following conditions:

   (1)  Submission of an opt-in application to the Department, including:

     (i)   Documentation of baseline NO_x allowance control period emissions which shall be the average of the actual emissions for the preceding two consecutive NO_x allowance control periods. The Department may approve selection of an alternative two consecutive NO_x allowance control periods within the 5 years preceding the opt-in application if the preceding two control periods are not representative of normal operations. The baseline may not exceed applicable emission limits.

     (ii)   Evidence that the requirements of § §  123.101—123.115, 123.117—123.120 and this section (relating to NO_x allowance requirements) can be complied with, including, submission of an emission monitoring plan, designation of an authorized account representative, and that the source is not on the compliance docket established under section 7.1 of the act (35 P. S. §  4005).

   (2)  Submission of NO_x allowances established under paragraph (1)(i) or subsection (c) by the Department to the NO_x budget administrator.

 (c)  A source which began operations with emission reduction credits from a NO_x affected source may become a NO_x affected source by complying with subsection (b)(1). To operate the source, NO_x allowances shall be acquired by the owner or operator from those available in the NATS.

 (d)  Opt-in sources which opted-in under subsection (b) and which shutdown or curtail operations during any NO_x allowance control period within the 5-calendar years after opting-in shall, prior to January 31 following the shutdown or curtailment, surrender to the Department NO_x allowances for the current NO_x allowance control period equivalent to the difference resulting from the reduction in utilization from the source’s baseline operations as established in subsection (b)(1)(i) between the NO_x allowance control period allowance allocation and the emissions reported in accordance with §  123.109 (relating to source emissions reporting requirements). NO_x allocations for future NO_x allocation control periods shall also be surrendered. NO_x allowances which were allocated for any preceding NO_x allowance control period which were not used (banked) may not be surrendered. Surrendered NO_x allowances shall be retired from the NATS and NO_x budget except that upon request by the source owner or operator, the Department may reallocate the NO_x allowances to a qualifying replacement source.

 (e)  Opt-in sources which remain in operation for 5- calendar years from the date of opt-in shall have a new baseline and allowance allocation set in accordance with the procedure in subsection (b)(1)(i). This baseline may not exceed the opt-in baseline. Thereafter, the source is not subject to this section.

 (f)  Once electing to opt-in, a source may not revert to a non-NO_x affected source unless it is shut down.

   The provisions of this §  123.117 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  NO_x allowances may not be created for new NO_x affected sources. New NO_x affected sources are sources which are not listed in §  123.115 (relating to initial NO_x allowance NO_x allocations). The owner or operator of a new NO_x affected source shall establish a compliance account prior to the commencement of operations and is responsible to acquire any required NO_x allowances from those available in the NATS.

 (b)  Newly discovered NO_x affected sources not included in Appendix A which operated at any time between May 1 and September 30, 1990, shall comply with § §  123.101—123.116, 123.118—123.120 and this section (relating to NO_x allowance requirements) within 1-calendar year from the date of discovery. For those sources which notify the Department by April 1, 1998, the Department will petition the OTC to include the emissions in the NO_x MOU Budget and provide NO_x allowances to the source using the historical May 1 to September 30, 1990, emissions reduced as specified in §  123.119(a)(4)(ii) (relating to bonus NO_x allowance awards).

   The provisions of this §  123.117 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  NO_x affected sources may create, transfer and use emission reduction credits in accordance with Chapter 127 (relating to construction, modification, reactivation and operation of sources) and this section. ERCs may not be used to satisfy NO_x allowance requirements.

 (b)  Emission reductions made through overcontrol, curtailment or shutdown for which allowances are banked are not surplus and may not be used to create ERCs.

 (c)  A NO_x affected source may transfer NO_x ERCs to an NO_x affected source if the new or modified NO_x affected source’s ozone season (May 1—September 30) allowable emissions do not exceed the ozone season portion of the baseline emissions which were used to generate the NO_x ERCs.

 (d)  A NO_x affected source may transfer NO_x ERCs to a non-NO_x affected source under the following conditions:

   (1)  The non-NO_x affected source’s ozone season (May 1—September 30) allowable emissions may not exceed the ozone season portion of the baseline emissions which were used to generate the NO_x ERCs.

   (2)  The NATS account for NO_x affected sources which generated ERCs transferred to non-NO_x affected sources, including prior to the date of publication in the Pennsylvania Bulletin, shall have a corresponding number of allowances retired that reflect the transfer of emissions regulated under § §  123.101—123.117, 123.119—123.120 and this section (relating to NO_x allowance requirements) to the NO_x nonaffected sources. The amount of annual NO_x allowances deducted shall be equivalent to that portion of the nonaffected source’s NO_x control period allowable emissions which were provided for by the NO_x ERCs from the affected source.

   (3)  Allocations for NO_x allowance control periods following 2002 to the NO_x ERC generating source may not include the allowances identified in paragraph (2).

   The provisions of this §  123.118 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  The Department will, upon receipt of a complete application by November 1, 1998, award a NO_x affected source with bonus NO_x allowances for certain creditable emission reductions made during the 1997 and 1998 ozone seasons (May 1—September 30) under the following conditions:

   (1)  Creditable reductions shall be in excess of the OTC MOU reduction requirements and any applicable emission limits including RACT and maximum achievable control technology.

   (2)  Bonus allowances shall be calculated separately for the 1997 and 1998 ozone seasons (May 1—September 30).

   (3)  The actual average ozone season (May 1—September 30) heat input used to calculate the emission reduction may not exceed the average 1995 and 1996 ozone season actual heat input, or if the Department finds that it is more representative of normal operations, the average ozone season (May 1—September 30) actual heat input which occurred during another consecutive 2 years between and including 1991 and 1995.

   (4)  Bonus NO_x allowances shall be calculated by multiplying the actual 1997 or 1998, as applicable, average ozone season (May 1—September 30) heat input, times the difference between the following:

     (i)   The after-control emission rate calculated using the average rate occurring during the 1997 or 1998 NO_x allowance control.

     (ii)   The lower of the source’s applicable emission rate for NO_x expressed in pounds of NO_x per MMBtu, or the baseline emission rate established in Appendix A after applying the following reduction, as applicable. The reduction for sources located in the outer zone is 55% or 0.2 lbs/MMBtu whichever is less stringent, and for sources located in the inner zone, 65%, or 0.2 lbs/MMBtu whichever is less stringent. The inner zone includes Berks, Bucks, Chester, Delaware, Montgomery and Philadelphia counties, and the outer zone includes the remaining counties within this Commonwealth.

   (5)  Applications shall include the information necessary to determine that the reductions meet the requirements of this section.

 (b)  On or before May 1, 1999, the Department will publish a report in the Pennsylvania Bulletin which documents the number of bonus NO_x allowances awarded.

   The provisions of this §  123.119 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  The Department will complete an audit of the program established by § §  123.101—123.119 and this section (relating to NO_x allowance requirements) prior to May 1, 2002, and at a minimum every 3 years thereafter. The audit shall include the following:

   (1)  The resulting geographic distribution of emissions as well as the hourly, daily and running average emission totals shall be examined in the context of ozone control requirements. This analysis shall be used in making a determination as to whether the zonal, seasonal and interseasonal trading and banking provisions of the rule require modification to ensure the reductions are as effective as daily emission limits on all sources would be at reducing ozone.

   (2)  Confirmation of emissions reporting accuracy through validation of NO_x allowance CEMS and data acquisition systems at the NO_x affected source.

   (3)  If emissions in excess of the NO_x allowances allocated occurred in any NO_x allowance control period, as a result of banking provisions, a determination whether or not the NO_x allowance banking provisions require modification or deletion.

   (4)  NO_x allowance banking privileges will be examined to determine whether they adversely influenced market availability and price of NO_x allowances or created unfair competitive advantages and if so, recommend amendments to rectify these problems.

   (5)  An assessment of whether the program is providing the level of emission reductions included in the current SIP.

 (b)  In addition to the Department audit, the Department may seek a third party audit of the program. The third party audit can be implemented on a state by state basis or can be performed on a region-wide basis under the supervision of the Ozone Transport Commission.

 (c)  The Department will propose regulation revisions consistent with the audit results within 6 months of the completion of the audit.

   The provisions of this §  123.120 adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683.

 (a)  NO_x allocations for the NO_x allowance control periods starting May 1, 2003, will be distributed in accordance with Chapter 145 (relating to interstate pollution transport reduction).

 (b)  The emission limitations and monitoring requirements established in § §  123.101—123.120 are replaced by the requirements in Chapter 145 beginning with the May 1, 2003, control period. If a source has failed to demonstrate compliance with §  123.111 (relating to failure to meet source compliance requirements), the provisions in §  145.54(d) (relating to compliance) shall be used to withhold NO_x allowances in calendar year 2003 and beyond. If no NO_x allowances are provided to the source under §  145.42 (relating to NO_x allowance allocations), the source will be obligated to acquire and retire a number of NO_x allowances as specified in §  145.54.

   The provisions of this §  123.121 adopted September 22, 2000, effective September 23, 2000, 30 Pa.B. 4899.

APPENDIX A

   This appendix cited in 25 Pa. Code §  123.11 (relating to combustion units).

APPENDIX B

   This appendix cited in 25 Pa. Code §  123.13 (relating to processes).

APPENDIX C

   This appendix cited in 25 Pa. Code §  123.13 (relating to processes).

APPENDIX D
ALTERNATIVE OPACITY LIMITATION—APPLICATION

   NOTE: Sources incapable of a stack test are ineligible for an AOL
Abbreviations: AOL—alternative opacity limitation
NSPS—New source performance standards
PAA—plan approval application
BACT—best available control technology
LAER—lowest achievable emission rate
RACT—reasonably available control technology
PSD—prevention of significant deterioration

   This appendix cited in 25 Pa. Code §  123.45 (relating to alternative opacity limitations).

   The provisions of this Appendix D adopted June 19, 1981, effective June 20, 1981, 11 Pa.B. 1447; corrected June 26, 1981, effective June 20, 1981, 11 Pa.B. 2225.

APPENDIX E

   The provisions of this Appendix E adopted October 31, 1997, effective November 1, 1997, 27 Pa.B. 5683; amended March 10, 2000, effective March 11, 2000, 30 Pa.B. 1370. Immediately preceding text appears at serial pages (237287) to (237300).

STANDARDS FOR CONTAMINANTS MERCURY EMISSIONS

§ 123.201. Purpose.

 Sections 123.202—123.215 establish mercury emission standards, annual emission limitations as part of a Statewide mercury allowance program with annual nontradable mercury allowances and other requirements for the purpose of reducing mercury emissions from coal-fired EGUs or cogeneration units.

   The provisions of this §  123.201 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.201 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  In addition to the words and terms in subsection (b), the definitions promulgated in 40 CFR Part 60, Subpart Da (relating to standards of performance for electric utility steam generating units for which construction is commenced after September 18, 1978) and 40 CFR Part 60, Subpart HHHH (relating to emission guidelines and compliance times for coal-fired electric steam generating units) are adopted in their entirety and incorporated by reference in this subsection.

 (b)  The following words and terms, when used in this section and § §  123.201 and 123.203—123.215, have the following meanings, unless the context clearly indicates otherwise:

   Act—The Air Pollution Control Act (35 P. S. § §  4001—4015).

   Administrator—The Administrator of the EPA or the Administrator’s authorized representative.

   Btu—British thermal unit—The amount of thermal energy necessary to raise the temperature of 1 pound of pure liquid water by 1° F. at the temperature at which water has its greatest density (39° F.).

   Bottoming-cycle cogeneration unit—A cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.

   CFB—Circulating fluidized bed unit—Combustion of fuel in a bed or series of beds in which these materials are forced upward by the flow of combustion air and the gaseous products of combustion.

   CO₂—Carbon dioxide.

   CS-ESP—Cold side electrostatic precipitator—A particulate control device installed downstream of a boiler air preheater that does the following:

     (i)   Charges particles with an electric field and causes them to migrate from the gas to a collection surface.

     (ii)   Treats flue gas after heat extraction from the gas has been completed.

     (iii)   Operates within a temperature range of no greater than 400° F.

   Clean Air Act—The Clean Air Act (42 U.S.C.A. § §  7401—7642) and the rules and regulations promulgated thereunder.

   Coal—

     (i)   Solid fuels classified as anthracite, bituminous, subbituminous or lignite by the ASTM International Standard D 388—77, 90, 91, 95, 98A or 99, Specification for Classification of Coals by Rank.

     (ii)   The term includes synthetic fuels derived from coal and coal refuse for the purpose of creating useful heat, including solvent refined coal, gasified coal, coal-oil mixtures and coal-water mixtures.

   Coal refuse—Waste products of coal mining, physical coal cleaning and coal preparation operations (for example—culm, gob, and the like) containing coal, matrix material, clay and other organic and inorganic material.

   Cogeneration unit—A stationary, coal-fired boiler or stationary, coal-fired combustion turbine which:

     (i)   Has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating or cooling purposes through the sequential use of energy.

     (ii)   Produces, for a topping-cycle cogeneration unit, during the 12-month period starting on the date the unit first produces electricity and during any calendar year after the 12-month period in which the unit first produces electricity:

       (A)   Useful thermal energy not less than 5% of total energy output.

       (B)   Useful power that when added to one-half of useful thermal energy produced:

         (I)   Is not less than 42.5% of total energy input, if useful thermal energy produced is 15% or more of total energy output.

         (II)   Is not less than 45% of total energy input, if useful thermal energy produced is less than 15% of total energy output.

     (iii)   Produces, for a bottoming-cycle cogeneration unit, during the 12-month period starting on the date the unit first produces electricity and during any calendar year after the 12-month period in which the unit first produces electricity, useful power not less than 45% of total energy input.

   Commence operation—To have begun any mechanical, chemical or electronic process, including, with regard to a unit, a start-up of a unit’s combustion chamber.

   Control period—The period beginning January 1 of a calendar year and ending on December 31 of the same year, inclusive.

   EGU—Electric generating unit—

     (i)   Except as provided in subparagraphs (iv) and (v), a stationary, coal or coal refuse-fired boiler or stationary, coal-fired combustion turbine in this Commonwealth that serves or has served at any time, since the later of November 15, 1990, or the start-up of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

     (ii)   A stationary boiler or stationary combustion turbine in this Commonwealth that is not an EGU under subparagraph (i) that begins to combust coal or coal-derived fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale shall become an electric generating unit as provided in subparagraph (i) on the first date on which it both combusts coal or coal-derived fuel and serves the generator.

     (iii)   A unit that qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and meets the requirements of subparagraph (iv) for at least 1 calendar year, but subsequently no longer meets the requirements shall become an EGU starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of subparagraph (iv)(B).

     (iv)   A unit that is an EGU under subparagraphs (i) or (ii) and meets both of the following requirements will not be an EGU if it:

       (A)   Qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continues to qualify as a cogeneration unit.

       (B)   Has not served at any time, since the later of November 15, 1990, or the startup of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit’s potential electric output capacity or 219,000 MWhs, whichever is greater, to any utility power distribution system for sale.

     (v)   A ‘‘solid waste incineration unit’’ as defined in section 129(g)(1) of the Clean Air Act (42 U.S.C.A. §  7554(g)(1)) that combusts ‘‘municipal waste’’ as defined in section 129(g)(5) of the Clean Air Act will not be an EGU if it is subject to one of the following rules:

       (A)   An EPA-approved state plan for implementing the requirements of 40 CFR Part 60, Subpart Cb (relating to emissions guidelines and compliance times for large municipal waste combustors that are constructed on or before September 20, 1994).

       (B)   40 CFR Part 60, Subpart Eb (relating to standards of performance for large municipal waste combustors for which construction is commenced after September 20, 1994 or for which modification or reconstruction is commenced after June 19, 1996).

       (C)   40 CFR Part 60, Subpart AAAA (relating to standards of performance for small municipal waste combustors for which construction is commenced after August 30, 1999 or for which modification or reconstruction is commenced after June 6, 2001).

       (D)   An EPA-approved state plan for implementing 40 CFR Part 60, Subpart BBBB (relating to emission guidelines and compliance times for small municipal waste combustion units constructed on or before August 30, 1999).

       (E)   40 CFR Part 62, Subpart FFF (relating to Federal plan requirements for large municipal waste combustors constructed on or before September 20, 1994).

       (F)   40 CFR Part 62, Subpart JJJ (relating to Federal plan requirements for small municipal waste combustion units constructed on or before August 30, 1999).

   Existing EGU—An EGU which commenced construction, modification or reconstruction on or before January 30, 2004, or which has three complete control periods of heat input data as of December 31 of the preceding control period.

   FF-Fabric filter—An add-on air pollution control system that removes particulate matter (PM) and emissions of nonvaporous metals by passing flue gas through filter bags.

   Facility—All units located on one or more contiguous or adjacent properties and which are owned or operated by the same person under common control.

   GWh—Gigawatt-hour—One billion watt-hours.

   Heat input—For a specified period of time, the product, expressed as million ‘‘Btus’’ per unit time (MMBtu/time), of the gross calorific value of the fuel (in ‘‘Btus’’ per pound fuel (Btu/LB fuel) divided by 1,000,000 Btu/MMBtu) multiplied by the fuel feed rate into a combustion device (in pounds of fuel per unit time (LB fuel/time)), as measured, recorded and reported to the Department by the owner or operator of an EGU and determined in accordance with 40 CFR 60.4170—60.4176 and excluding the heat derived from preheated combustion air, reticulated flue gases or exhaust from other sources.

   IGCC—Integrated gasification combined cycle unit—An electric utility steam generating unit that burns a synthetic gas derived from coal in a combined-cycle gas turbine. No coal is directly burned in the unit during operation.

   MMBtu—One million British thermal units.

   MW—Megawatt—A unit for measuring power equal to one million watts.

   MWe—Megawatt electric—One million watts of electric capacity.

   MWh—Megawatt-hour—One million watt-hours.

   Nameplate capacity—The maximum electrical generating output (in MWe) that the generator is capable of producing on a steady-state basis during continuous operation (when not restricted by seasonal or other deratings):

     (i)   As specified by the manufacturer, starting from the initial installation of the generator.

     (ii)   As specified by the person conducting the physical change, starting from the completion of a subsequent physical change in the generator resulting in an increase in the maximum electrical generating output in MWe.

   New EGU—An EGU which commenced construction, modification or reconstruction, as defined under 40 CFR Part 60 (relating to standards of performance for new stationary sources), on or after January 30, 2004, and has less than three complete control periods of heat input data as of December 31 of the preceding control period.

   O₂—Oxygen.

   Operator—

     (i)   A person who operates, controls or supervises an EGU or a facility that includes an EGU.

     (ii)   The term also includes a holding company, utility system or plant manager of an EGU or facility.

   Owner—

     (i)   A holder of any portion of the legal or equitable title in an EGU or a facility in this Commonwealth that includes an EGU.

     (ii)   The term also includes a holder of a leasehold interest in an EGU or a facility in this Commonwealth that includes an EGU.

   PCF—Pulverized coal-fired unit—

     (i)   A steam generating unit in which pulverized coal is introduced into an air stream that carries the coal to the combustion chamber of the steam generating unit where it is fired in suspension.

     (ii)   The term includes both conventional pulverized coal-fired and micropulverized coal-fired steam generating units.

   Phase 1—The period from January 1, 2010, through December 31, 2014.

   Phase 2—The period beginning January 1, 2015, and each subsequent year thereafter.

   Rolling 12-month basis—A determination made on a monthly basis from the relevant data for a particular calendar month and the preceding 11 calendar months (total of 12 months of data).

   SCR—Selective catalytic reduction—A process where a gaseous or liquid reductant (most commonly ammonia or urea) is added to the flue gas stream in the presence of a catalyst. The reductant reacts with nitrogen oxides in the flue gas to form molecular nitrogen.

   SO₂—Sulfur dioxide.

   Space velocity—The exhaust gas volume per hour of the SCR corrected to standard temperature and pressure divided by the volume of the catalyst.

   Standby unit—A unit that is out of operation but under a Department-approved maintenance plan as provided under §  127.11a (relating to reactivation of sources), which will enable the source to be reactivated in accordance with the terms of the permit issued to the source.

   System—The total number of EGUs under common ownership or operator control in this Commonwealth, which an owner or operator identifies to the Department as participating in an emissions compliance demonstration for the purpose of complying with §  123.207 (relating to annual emission limitations for coal-fired EGUs).

   System-wide compliance demonstration—Demonstrating compliance with the annual emission limitation by ensuring that the aggregate of actual mass emissions is less than the aggregate of allowable mass emissions for all EGUs in the system which are included in the demonstration.

   Topping-cycle cogeneration unit—A cogeneration unit in which the energy input to the unit is first used to produce useful power, including electricity, and at least some of the reject heat from the electricity production is then used to provide useful thermal energy.

   WFGD—Wet flue gas desulfurization unit—An SO₂ control system located downstream of the steam generating unit that removes SO₂ from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution including lime and limestone.

   Watt-hour—A unit of energy equivalent to 1 watt of power expended for 1 hour of time.

   The provisions of this §  123.202 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.202 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 The requirements of this section and § §  123.201, 123.202 and 123.204—123.215 apply to owners and operators of an EGU located in this Commonwealth and, except as otherwise noted, supersede those requirements adopted in their entirety and incorporated by reference in §  122.3 (relating to adoption of standards).

   The provisions of this §  123.203 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.203 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 Consistent with §  123.207(b)(1) (relating to annual emission limitations for coal-fired EGUs), the owner or operator of an EGU that enters into an enforceable agreement with the Department not later than December 31, 2007, for the shutdown and replacement of the unit with IGCC technology no later than December 31, 2012, shall be exempted from compliance with the Phase 1 emission standards specified in §  123.205 (relating to emission standards for coal-fired EGUs).

   The provisions of this §  123.204 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.204 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  New EGUs. In addition to the mercury emission limitation requirements in §  123.207 (relating to annual emission limitations for coal-fired EGUs), the owner or operator of a new EGU subject to §  123.203 (relating to applicability) shall comply at the commencement of operation on a rolling 12-month basis with one of the following standards:

   (1)  PCF EGU. The owner or operator of a PCF EGU shall comply with either of the following:

     (i)   A mercury emission standard of 0.011 pound of mercury per GWh.

     (ii)   A minimum 90% control of total mercury as measured from the mercury content in the coal, either as fired or as approved in writing by the Department.

   (2)  CFB EGU. The owner or operator of a CFB EGU shall comply with the following applicable provisions:

     (i)   CFB EGUs burning 100% coal refuse as the only solid fossil fuel shall comply with either of the following:

       (A)   A mercury emission standard of 0.0096 pound of mercury per GWh.

       (B)   A minimum 95% control of total mercury as measured from the mercury content in the coal refuse, either as fired or as approved in writing by the Department.

     (ii)   CFB EGUs burning 100% coal as the only solid fossil fuel shall comply with either of the following:

       (A)   A mercury emission standard of 0.011 pound of mercury per GWh.

       (B)   A minimum 90% control of total mercury as measured from the mercury content in the coal, either as fired or as approved in writing by the Department.

     (iii)   CFB EGUs burning multiple fuels shall comply with a prorated emission standard based on the percentage of heat input from the coal and the percentage of heat input from the coal refuse.

   (3)  IGCC EGU. The owner or operator of an IGCC EGU shall comply with one of the following:

     (i)   A mercury emission standard of 0.0048 pound of mercury per GWh.

     (ii)   A minimum 95% control of total mercury as measured from the mercury content in the coal, either as processed or as approved in writing by the Department.

 (b)  Other requirements for new EGUs. In addition to the emission requirements of subsection (a), the applicable requirements for a new EGU include:

   (1)  Best available technology requirement. The emission standards in this subsection will serve as a baseline for review and approval of case-by-case best available technology determinations for a new EGU in accordance with Chapter 127 (relating to construction, modification, reactivation and operation of sources).

   (2)  Standards of performance for new stationary sources requirements. In addition to the requirements of this section and § §  123.201—123.204 and 123.206—123.215, the owner or operator of a new EGU shall also comply with the standards of performance for new stationary sources promulgated in 40 CFR Part 60, Subpart Da (relating to standards of performance for electric utility steam generating units for which construction is commenced after September 18, 1978) and adopted in their entirety and incorporated by reference in Chapter 122 (relating to National standards of performance for new stationary sources).

 (c)  Existing EGUs. In addition to the mercury emission limitation requirements of §  123.207, the owner or operator of an existing EGU subject to the emission standards for EGUs specified in this section shall comply on a rolling 12-month basis with one of the following standards:

   (1)  Phase 1. Effective from January 1, 2010, through December 31, 2014:

     (i)   PCF EGU. The owner or operator of a PCF shall comply with one of the following:

       (A)   A mercury emission standard of 0.024 pound of mercury per GWh.

       (B)   A minimum 80% control of total mercury as measured from the mercury content in the coal, either as fired or as approved in writing by the Department.

     (ii)   CFB EGU. The owner or operator of a CFB burning coal refuse shall comply with one of the following:

       (A)   A mercury emission standard of 0.0096 pound of mercury per GWh.

       (B)   A minimum 95% control of total mercury as measured from the mercury content in the coal refuse, either as fired or as approved in writing by the Department.

   (2)  Phase 2. Effective beginning January 1, 2015, and each subsequent year:

     (i)   PCF EGU. The owner or operator of a PCF shall comply with one of the following:

       (A)   A mercury emission standard of 0.012 pound of mercury per GWh.

       (B)   A minimum 90% control of total mercury as measured from the mercury content in the coal, either as fired or as approved in writing by the Department.

     (ii)   CFB EGU. The owner or operator of a CFB burning coal refuse shall comply with one of the following:

       (A)   A mercury emission standard of 0.0096 pound of mercury per GWh.

       (B)   A minimum 95% control of total mercury as measured from the mercury content in the coal refuse, either as fired or as approved in writing by the Department.

 (d)  Credit for fuel pretreatment. The owner or operator of an EGU may request, in writing, credit for the mercury removal efficiency resulting from the pretreatment of coal or coal refuse towards the minimum percent control efficiency of total mercury requirements specified in this section. The credit shall be approved, in writing, by the Department consistent with the process outlined in 40 CFR 60.50da (relating to compliance determination procedures and methods).

   The provisions of this §  123.205 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.205 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  The owner or operator of one or more EGUs subject to the emission standards of §  123.205 (relating to emission standards for coal-fired EGUs) shall demonstrate compliance with the standards using one of the following methods:

   (1)  Compliance on a unit-by-unit basis.

   (2)  Facility-wide emissions averaging.

 (b)  The Department may approve in a plan approval or operating permit, or both, an alternate mercury emission standard or compliance schedule, or both, if the owner or operator of an EGU subject to the emission standards of §  123.205 demonstrates in writing to the Department’s satisfaction that the mercury reduction requirements are economically or technologically infeasible. The Department’s written approval of an alternate mercury emission standard or compliance schedule does not relieve the owner or operator of the EGU from complying with the other requirements of § §  123.201—123.205 and 123.207—123.215. The owner or operator shall:

   (1)  Submit a plan approval application or operating permit application requesting an alternate emission standard or compliance schedule, or both, to the Department for approval no later than 120 days before the applicable compliance deadline.

   (2)  Include the following in the application:

     (i)   A brief description, including make, model and location of each EGU.

     (ii)   A list of all air pollution control technologies and measures that have been installed on each EGU and are operating to control emissions of air contaminants including mercury.

     (iii)   The dates of installation and commencement of operation for each of the technologies and measures required under subparagraph (ii).

     (iv)   An explanation of how the technology or measure was installed and if it is being operated according to the manufacturer’s instructions for each of the technologies and measures required under subparagraph (ii).

     (v)   The results of each mercury stack test and other emissions measurements for the EGU following installation and commencement of operation of the air pollution control technologies and measures listed in accordance with subparagraph (ii).

     (vi)   A list of other air pollution control technologies or measures that the owner or operator proposes to install and operate on each EGU to control emissions of air contaminants including mercury.

     (vii)   A summary of how the owner or operator of the EGU intends to operate and maintain the unit during the term of the approved plan approval or operating permit, or both, including the associated air pollution control equipment and measures that are designed to maintain compliance with all other applicable plan approval or operating permit requirements and that are designed and operated to minimize the emissions of mercury to the extent practicable.

     (viii)   A proposed schedule that lists the increments of progress and the date for final compliance if an alternate compliance schedule is requested.

     (ix)   An emission reduction proposal and information on the technological feasibility of meeting the requirements of this section and §  123.205 if an alternate emission standard is requested.

     (x)   Other information which the Department requests that is necessary for the approval of the application.

 (c)  The Department’s written approval of an alternate emission standard or compliance schedule will be based on the information provided in the application submitted by the owner or operator of the EGU in accordance with subsection (b).

 (d)  For an EGU complying with the energy output-based mercury emission standards of §  123.205 (expressed in pounds of mercury per GWh), the actual mercury emission rate of the EGU for each 12-month rolling period, monitored in accordance with § §  123.210—123.215 and calculated as follows, may not exceed the applicable emission standard:

 ER = i=1 12 E_i ÷i=1 12 O_i

 Where:

 ER = Actual mercury emissions rate of the EGU for the particular 12-month rolling period, expressed in pounds per GWh.

 E_i = Actual mercury emissions of the EGU, in pounds, in an individual month in the 12-month rolling period, as determined in accordance with the monitoring provisions.

 O_i = Gross electrical output of the EGU, in GWhs, in an individual month in the 12-month rolling period.

 (e)  For an EGU complying with the percent control requirements of §  123.205, the actual control efficiency for mercury emissions achieved by the EGU for each 12-month rolling period, monitored in accordance with § §  123.210—123.215 and calculated as follows, shall meet or exceed the applicable efficiency requirement:

 CE = 100 * {1 – (i=1 12 Ei ÷i=1 12 Ii)}

 Where:

 CE = Actual control efficiency for mercury emissions of the EGU for the particular 12-month rolling period, expressed as a percent.

 E_i = Actual mercury emissions of the EGU, in pounds, in an individual month in the 12-month rolling period, as determined in accordance with the monitoring provisions of § §  123.210—123.215.

 I_i = Amount of mercury in the fuel fired in the EGU, in pounds, in an individual month in the 12-month rolling period, as determined in accordance with §  123.214 (relating to coal sampling and analysis for input mercury levels).

 (f)  The owner or operator of an EGU may demonstrate compliance with §  123.205 by means of facility-wide averaging that demonstrates that the actual mercury emissions from EGUs covered under the emissions averaging demonstration are less than the allowable mercury emissions from all EGUs covered by the demonstration on a rolling 12-month basis.

   The provisions of this §  123.206 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.206 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  Statewide mercury nontradable allowance program. In addition to the mercury emission standard requirements of §  123.205 (relating to emission standards for coal-fired EGUs), the owner or operator of a new or existing affected EGU subject to §  123.203 (relating to applicability) shall comply with the annual emission limitations established through a Statewide mercury nontradable allowance program under this section. The Department will issue to the owner or operator of an affected EGU a plan approval or operating permit (including Title V) that contains the applicable requirements of this section and § §  123.202—123.206 and 123.208—123.215 before the later of January 1, 2010, or the date on which the affected EGU commences operation.

 (b)  Emission limitation set-asides. The total ounces of mercury emissions available for emission limitation set-asides as annual nontradable mercury allowances in the Statewide mercury allowance program are:

   (1)  56,928 ounces (3,558 pounds) of mercury emissions for Phase 1, effective from January 1, 2010, through December 31, 2014.

   (2)  22,464 ounces (1,404 pounds) of mercury emissions for Phase 2, effective beginning January 1, 2015, and each subsequent year.

 (c)  New affected EGUs. For each calendar year beginning January 1, 2010, the Department will set aside a total number of annual nontradable mercury allowances for the owners and operators of new affected EGUs in this Commonwealth that do not yet have a baseline heat input determined in accordance with the requirements of an approved plan approval or operating permit.

   (1)  The total number of annual nontradable mercury allowances set aside for the owners and operators of new affected EGUs will be equal to a percentage of the amount of ounces of mercury emissions in the Statewide mercury allowance program established in subsection (a). The percentage of set-aside is:

     (i)   5% of the Phase 1 annual nontradable mercury allowances established in subsection (b)(1) for the years beginning January 1, 2010, through December 31, 2014.

     (ii)   3% of the Phase 2 annual nontradable mercury allowances established in subsection (b)(2) for the calendar year beginning January 1, 2015, and subsequent years.

   (2)  The annual nontradable mercury allowances set aside for the owners and operators of new affected EGUs shall be placed in the annual emission limitation supplement pool established under §  123.208 (relating to annual emission limitation supplement pool).

   (3)  After a new EGU has commenced operation and completed three control periods, the EGU will become an existing EGU. The new EGU will continue to receive annual nontradable mercury allowances from the new unit set-aside until the new EGU is eligible for annual nontradable mercury allowances allocated from the set-aside for existing EGUs. The annual nontradable mercury allowances allocated from the set-aside for existing EGUs may not exceed the allowable mercury emissions limitation specified in a plan approval or operating permit (including Title V) for the new EGU.

   (4)  When a new EGU is eligible to receive annual nontradable mercury allowances from the set-aside for existing EGUs, new maximum allowance levels for all existing EGUs will be established and published in the Pennsylvania Bulletin for comment by May 31 of the year that is 2 years prior to the affected control period.

   (5)  If the actual emissions of mercury reported to the Department from the operation of a new EGU during a specific control period are less than the maximum number of annual nontradable mercury allowances specified in the plan approval or operating permit for the EGU, the Department will include the unused portion of the annual nontradable mercury allowances in the set-aside for new EGUs.

   (6)  The unused portion of annual nontradable mercury allowances set aside under paragraph (3) may not be added to the maximum number of annual nontradable mercury allowances set aside in subsequent years for the owner or operator of a new EGU. The annual nontradable mercury allowances may not be banked for use in future years.

 (d)  Existing affected CFBs. For each calendar year beginning January 1, 2010, the Department will set aside for the owners and operators of existing affected CFBs a total number of annual nontradable mercury allowances from the total ounces of mercury emissions available for annual emission limitation set-asides in Phase 2 of the Statewide mercury allowance program established in subsection (b)(2).

 (e)  Maximum allowances set aside for CFBs. The maximum number of annual nontradable mercury allowances set aside for the owner or operator of each existing affected CFB in accordance with subsection (d) shall be determined by multiplying the affected CFB’s baseline heat input fraction of the State’s total baseline annual heat input for all EGUs by the Department’s Phase 2 annual mercury allowance set-aside for existing EGUs, as follows:

   (1)  The baseline heat input in MMBtu for each existing affected CFB will be the average of the three highest amounts of annual heat input using the heat input data for the CFB from EPA’s acid rain database and the Department’s database for the calendar years 2000—2004.

   (2)  The State’s annual mercury allowance set-aside for existing EGUs for Phase 2 is 21,790 ounces.

 (f)  Existing affected EGUs other than CFBs. For each calendar year beginning January 1, 2010, the Department will set aside for the owners and operators of existing affected EGUs other than CFBs a total number of annual nontradable mercury allowances from the total ounces of mercury emissions available for annual emission limitation set-asides in Phase 1 and Phase 2 of the Statewide mercury allowance program established in subsection (b).

 (g)  Maximum allowances set aside for existing affected EGUs other than CFBs. The maximum number of annual nontradable mercury allowances set aside for the owner or operator of each existing affected EGU other than CFB in accordance with subsection (f) shall be determined for the existing affected EGU other than CFB by multiplying its baseline heat input fraction of the State’s total baseline annual heat input for all EGUs by the Department’s annual mercury allowance set-aside for existing affected EGUs in each phase, as follows:

   (1)  The baseline heat input in MMBtu for each existing affected EGU other than CFB will be the average of the three highest amounts of annual heat input using the heat input data for the EGU other than CFB from the EPA’s acid rain database and the Department’s database for calendar years 2000—2004.

   (2)  The State’s annual mercury allowance set-aside for existing affected EGUs is:

     (i)   54,080 ounces for Phase 1.

     (ii)   21,790 ounces for Phase 2.

 (h)  Publication of maximum number of allowances set aside for Phase 1. By May 31, 2008, the Department will publish for comment in the Pennsylvania Bulletin the maximum number of annual nontradable mercury allowances set aside for the owner or operator of each existing affected CFB and EGU other than CFB for Phase 1 of the Statewide mercury allowance program. The nontradable allowances shall only be used to demonstrate compliance with the annual emission limitation requirements.

 (i)  Publication of maximum number of allowances set aside for Phase 2. By May 31, 2013, the Department will publish for comment in the Pennsylvania Bulletin the maximum number of annual nontradable mercury allowances set aside for the owner or operator of each existing affected CFB and EGU other than CFB for Phase 2 of the Statewide mercury allowance program. The nontradable allowances shall only be used to demonstrate compliance with the annual emission limitation requirements.

 (j)  Maximum number of allowances awarded. By March 31 of the year following each reporting year, the Department will notify the owner or operator of each affected EGU, facility or system, in writing, of the actual number of annual nontradable mercury allowances awarded to the owner or operator of the EGU, facility or system for the control period.

   (1)  The actual number of annual nontradable mercury allowances awarded to the owner or operator of the EGU, facility, or system shall be based on the actual emissions reported to the Department in accordance with § §  123.210—123.215.

   (2)  If the actual emissions of mercury reported to the Department in accordance with § §  123.210—123.215 are less than the maximum number of annual nontradable mercury allowances set aside in the Statewide mercury allowance program for the owner or operator of an EGU, facility or system in accordance with either subsection (c), (d) or (f), the Department will place the unused portion of annual nontradable mercury allowances in the annual emission limitation supplement pool established under §  123.208.

   (3)  The unused portion of annual nontradable mercury allowances set aside under subsection (c), (d) or (f) may not be added to the maximum number of annual nontradable mercury allowances set aside for the owner or operator of the affected EGU, facility or system for subsequent years. The annual nontradable mercury allowances may not be banked for use in future years.

   (4)  The actual number of annual nontradable mercury allowances awarded to the owner or operator of the EGU, facility or system may not exceed the maximum number of annual nontradable mercury allowances set aside for the owner or operator of the EGU, facility or system in the Statewide mercury allowance program in accordance with subsection (c), (d) or (f) except as provided in §  123.209 (relating to petition process).

   (5)  Each ounce of mercury emitted in excess of the maximum number of annual nontradable mercury allowances set aside for the owner or operator of the affected EGU, facility or system in accordance with subsection (c), (d) or (f) shall constitute a violation of this section and the act, except as provided under §  123.209.

 (k)  Standby units and units permanently shut down. Annual nontradable mercury allowances will not be set aside for the owner or operator of an existing affected EGU that is already shut down or scheduled for shutdown unless the owner or operator of the EGU obtains a plan approval for the construction of a new EGU, or is on standby as of the effective date of each set-aside phase under subsection (c), (d) or (f). When a standby unit is ready for normal operation, the owner and operator may petition the Department for a number of annual nontradable mercury allowances as provided under §  123.209. Annual nontradable mercury allowances will be allocated to the owner or operator of the EGU. The annual nontradable mercury allowances allocated from the existing EGU set-aside may not exceed the allowable mercury emissions limitation specified in a plan approval or operating permit (including Title V) for the new EGU.

 (l)  Units scheduled for permanent shutdown.

   (1)  The requirements of this section and § §  123.202—123.206 and 123.208—123.215 do not apply to the owner or operator of an EGU that will be permanently shut down no later than December 31, 2009. The owner or operator of the EGU scheduled for shutdown shall do the following:

     (i)   Within 180 days prior to the shutdown, notify the Administrator and the Department, in writing, that the EGU is scheduled to be permanently shut down. The notice must contain a description of the actions that have been taken to shut down the EGU, the future actions and schedule for completing the shut down of the EGU, and the anticipated date of permanent shutdown of the EGU.

     (ii)   Execute a legally enforceable document prior to shutdown that requires the EGU to be permanently shut down in accordance with this section.

   (2)  Within 30 days after the permanent shutdown of the EGU, the mercury designated representative shall provide written notice to the Administrator and the Department of the actual date of the permanent shutdown of the unit.

   (3)  For 5 years from the date the records are created, the owner and operator of an EGU shall retain records demonstrating that the EGU is permanently shut down. The Administrator or Department may, in writing, extend the recordkeeping time period for cause, at any time before the end of the 5-year period. The owners and operators bear the burden of proof that the unit is permanently shut down. The records shall be retained at the facility where the EGU is located and submitted to the Department upon request.

 (m)  Future emission limitations. The Department may revise the percentage of set-aside used to determine the number of ounces of mercury set aside for future annual mercury emission limitations to accommodate the emissions from new EGUs so that the total number of ounces of mercury emissions in the Statewide mercury allowance program is not exceeded. The Department will publish notice of the proposed and final revisions in the Pennsylvania Bulletin.

 (n)  Changes in calculation of baseline heat input. The Department may revise the percentage of set-aside used to determine the number of ounces of mercury set aside for future annual mercury emission limitations to accommodate changes in the calculation of baseline heat input in accordance with subsection (e) or (g) so that the total number of ounces of mercury emissions in the Statewide mercury allowance program is not exceeded. The Department will publish notice of the proposed and final revisions in the Pennsylvania Bulletin.

 (o)  Maintained by Department. The Statewide mercury allowance program established under subsection (a) and the annual nontradable mercury allowances set aside for emission limitations under subsections (b)—(n) will be maintained by the Department.

 (p)  Demonstration of compliance. The owner or operator of one or more affected mercury allowance program EGUs subject to this section shall demonstrate compliance with the applicable requirements using one of the following methods by March 1 for the preceding control period:

   (1)  Compliance on a unit-by-unit basis.

   (2)  Compliance on a facility-wide basis.

   (3)  Compliance on a system-wide basis.

 (q)  Facility-wide compliance demonstration. The owner or operator of an EGU may demonstrate compliance with this section on a facility-wide basis. The total of the actual mercury emissions from the EGUs included in the demonstration must be less than the total of the allowable mercury emissions from all EGUs included in the demonstration on an annual basis.

 (r)  System-wide compliance demonstration. The owner or operator of two or more EGUs under common ownership or operator control in this Commonwealth may demonstrate compliance with this section as follows:

   (1)  The total of the actual mercury emissions from the EGUs at the facility and other EGUs at other facilities included in the system-wide demonstration must be less than the total of the allowable mercury emissions from all EGUs included in the demonstration on an annual basis.

   (2)  An owner or operator may not include an EGU, or a portion thereof, in more than one system-wide demonstration submitted for purposes of complying with this section and § §  123.201—123.206 and 123.208—123.215.

   The provisions of this §  123.207 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.207 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  Effective January 1, 2010, the Department will establish an annual emission limitation supplement pool to monitor annual nontradable mercury allowances that:

   (1)  Have been created as part of the new affected EGU set-aside under §  123.207(c) (relating to annual emission limitations for coal-fired EGUs).

   (2)  Are unused annual nontradable mercury allowances set aside as annual emission limitation supplements under §  123.207(j)(2).

 (b)  The annual emission limitation supplement pool of annual nontradable mercury allowances established under subsection (a) will be administered in accordance with §  123.209 (relating to petition process) by the Department.

   The provisions of this §  123.208 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.208 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  Each calendar year beginning January 1, 2010, the owner or operator of either a new EGU or an existing affected EGU that emits amounts of mercury in excess of the maximum number of annual nontradable mercury allowances set aside in accordance with §  123.207 (relating to annual emission limitations for coal-fired EGUs) or a standby affected EGU that is ready for normal operation may petition the Department, in writing, for supplemental annual nontradable mercury allowances to be set aside for the owner or operator from the annual emission limitation supplement pool established under §  123.208(a) (relating to annual emission limitation supplement pool).

 (b)  The owner or operator shall submit a separate petition for each calendar year for which the owner or operator requests supplemental annual nontradable mercury allowances to be set aside from the annual emission limitation supplement pool.

 (c)  The owner or operator with more than one affected EGU shall submit a separate petition for each EGU for which the owner or operator requests supplemental annual nontradable mercury allowances to be set aside from the annual emission limitation supplement pool.

 (d)  The owner or operator of the existing affected EGU shall submit the petition to the Department by January 31 of the year following the calendar year for which the supplemental annual nontradable mercury allowances are requested to be set aside.

 (e)  The owner or operator of the standby affected EGU shall submit the petition to the Department no later than 120 days before the date of anticipated start-up of the EGU.

 (f)  The petition must include the following:

   (1)  A brief description, including make, model and location of each affected EGU.

   (2)  A list of all air pollution control technologies and measures that have been installed on each affected EGU and are operating to control emissions of air contaminants, including mercury.

   (3)  For each of the technologies and measures listed in accordance with paragraph (2), the date of installation and original commencement of operation.

   (4)  For each of the technologies and measures listed in accordance with paragraph (2), an explanation of how the mercury control technology or measure as installed has been optimized for the maximum mercury emission reduction.

   (5)  The results of each mercury stack test and other emissions measurements for the affected EGU following installation and commencement of operation of the air pollution control technologies and measures listed in accordance with paragraph (2).

   (6)  A list of other air pollution control technologies or measures that the owner or operator proposes to install and operate on each affected EGU to control emissions of air contaminants, including mercury.

   (7)  A summary of how the owner or operator of the affected EGU intends to operate and maintain the EGU during the term of the approved plan approval or operating permit, or both, including the associated air pollution control equipment and measures that are designed to maintain compliance with all other applicable plan approval or operating permit requirements and that are designed and operated to minimize the emissions of mercury to the extent practicable.

 (g)  Each calendar year beginning January 1, 2010, the Department may allocate supplemental annual nontradable mercury allowances from the annual emission limitation supplement pool established under §  123.208(a) for the owners or operators of new and existing affected EGUs. If a petition is approved by the Department in accordance with the requirements of this section, the allowances will be distributed to the following:

   (1)  Each owner or operator of a standby unit as defined under §  123.202 (relating to definitions) which meets the requirements of this section and § §  123.205—123.208 and 123.210—123.215.

   (2)  Each owner or operator of an EGU that enters into an enforceable agreement with the Department by December 31, 2007, for the shut down and replacement of the unit with IGCC technology by December 31, 2012.

   (3)  Each owner or operator of a new EGU.

   (4)  Each owner or operator of an existing affected EGU based on the performance of the air pollution control technologies and measures that have been installed and are operating to control mercury emissions.

 (h)  If the petition for supplemental annual nontradable mercury allowances is approved by the Department, the supplemental annual nontradable mercury allowances set aside for the owner or operator of the existing affected EGU will be added to the maximum number of annual nontradable mercury allowances set aside for the owner or operator of the EGU in accordance with §  123.207 only for the calendar year of the request.

 (i)  The Department’s approval of supplemental annual nontradable mercury allowances will be based on the information provided in the petition submitted by the owner or operator of an EGU in accordance with subsection (f).

 (j)  The supplemental annual nontradable mercury allowances set aside under subsection (h) may not be added to the maximum number of annual nontradable mercury allowances set aside for the owner or operator of the EGU for subsequent years.

   The provisions of this §  123.209 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.209 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  The owner or operator of a new EGU subject to the requirements of this section and § §  123.201—123.209 and 123.211—123.215 shall demonstrate compliance with § §  123.205 and 123.207 (relating to emission standards for coal-fired EGUs; and annual emission limitations for coal-fired EGUs) by installing and operating continuous emissions monitoring systems to measure, record and report mercury emissions from each EGU. The monitoring, recordkeeping and reporting requirements provided in this section, § §  123.211—123.215 and 139.101 (relating to general requirements), 40 CFR Part 75, Subpart I (relating to Hg mass emission provisions) and the applicable provisions of the Continuous Source Monitoring Manual (DEP 274-0300-001) shall apply. For the purpose of complying with this section, the provisions in 40 CFR 60.4110—60.4114 are adopted in their entirety and incorporated herein by reference.

 (b)  Except as provided in subsection (c), the owner or operator of an existing EGU subject to this section, § §  123.201—123.209 and 123.211—123.215 shall demonstrate compliance with § §  123.205 and 123.207 (relating to emission standards for coal-fired EGUs; and annual emission limitations for coal-fired EGUs) by installing and operating continuous emissions monitoring systems to measure, record and report mercury emissions from each EGU. The monitoring, recordkeeping and reporting requirements as provided in this section, § §  123.211—123.215 and 139.101, 40 CFR Part 75, Subpart I (relating to Hg mass emission provisions) and the applicable provisions of the Continuous Source Monitoring Manual (DEP 274-0300-001) shall apply. In addition, for purposes of complying with these requirements, the definitions in §  123.202 (relating to definitions) and in 40 CFR 72.2 (relating to definitions) shall apply. For the purpose of complying with the requirements of this section, the provisions in 40 CFR 60.4110—60.4114 are adopted in their entirety and incorporated herein by reference.

 (c)  For an affected EGU that emits 464 ounces (29 lbs.) or less of mercury per year, the owner or operator of the affected EGU shall either:

   (1)  Meet the requirements in subsections (a) and (b) for demonstrating compliance with § §  123.205 and 123.207 and 40 CFR Part 75, Subpart I.

   (2)  Implement the excepted monitoring methodology for an EGU meeting the requirements in 40 CFR 75.81(b)—(e) (relating to monitoring of Hg mass emissions and heat input at the unit level).

 (d)  The owner or operator of an EGU that emits 464 ounces (29 lbs.) or less of mercury per year, may demonstrate compliance with the percent control requirements by averaging the coal mercury content and stack emission data collected during the control period.

 (e)  The owner or operator of each EGU shall:

   (1)  Install all monitoring systems required under this section and § §  123.211—123.215 and the applicable provisions of Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources) for monitoring mercury emissions, including all systems required to monitor mercury concentration, stack gas moisture content, stack gas flow rate and CO₂ or O₂ concentration, as applicable, in accordance with 40 CFR 75.81 and 75.82 (relating to monitoring of Hg mass emissions and heat input at common and multiple stacks).

   (2)  Successfully complete the certification tests required under §  123.211 (relating to initial certification and recertification procedures for emissions monitoring) and meet the other requirements of this section and § §  123.211—123.215 that are applicable to the monitoring systems required under paragraph (1).

 (f)  The owner or operator of each EGU shall comply with the monitoring system certification and other requirements of subsection (e) on or before the later of:

   (1)  January 1, 2009.

   (2)  Ninety EGU operating days or 180 calendar days, whichever occurs first, after the date on which the EGU commences commercial operation.

 (g)  The owner or operator of each EGU shall record, report and quality-assure the data from the monitoring systems required under subsection (e)(1) on and after the later of:

   (1)  January 1, 2009.

   (2)  Ninety EGU operating days or 180 calendar days, whichever occurs first, after the date on which the EGU commences commercial operation.

 (h)  The owner or operator of an EGU for which construction of a new stack or flue, installation of add-on mercury emission controls, a flue gas desulfurization system, an SCR system or a compact hybrid particulate collector system is completed after the applicable deadlines of subsections (f) and (g), shall:

   (1)  Comply with the monitoring system certification and other requirements of subsection (e).

   (2)  Record, report and quality assure the data from the monitoring systems required under subsection (e)(1).

   (3)  Comply with this section within 90 EGU operating days or 180 calendar days, whichever occurs first, after the date on which emissions first exit to the atmosphere through the new stack or flue, add-on mercury emission controls, flue gas desulfurization system, SCR system or compact hybrid particulate collector system.

 (i)  The owner or operator of an EGU that does not meet the applicable monitoring date in subsections (f)—(h) for any monitoring system required under subsection (e)(1) shall, for each monitoring system, determine, record and report maximum potential (or, as appropriate, minimum potential) values for:

   (1)  Mercury concentration.

   (2)  Stack gas flow rate.

   (3)  Stack gas moisture content.

   (4)  Other parameters required to determine mercury mass emissions in accordance with 40 CFR 75.80(g) (relating to general provisions).

 (j)  The owner or operator of an EGU that does not meet the applicable monitoring date in subsections (f)—(h) for a monitoring system required under subsection (e)(1) shall, for each monitoring system, determine, record and report substitute data using the applicable missing data procedures in 40 CFR 75.80(f) instead of the maximum potential (or, as appropriate, minimum potential) values for a parameter if the owner or operator demonstrates that there is continuity between the data streams for that parameter before and after the construction or installation of the monitoring systems required under subsection (e)(1).

 (k)  An owner or operator of an EGU may not use any alternative monitoring system, alternative reference method or any other alternative to any requirement of 40 CFR Part 75 (relating to continuous emission monitoring) unless the alternative system, method or requirement is approved, in writing, by the Administrator in accordance with 40 CFR Part 75, Subpart E (relating to alternative monitoring systems).

 (l)  An owner or operator of an affected EGU may not operate the EGU so as to discharge or allow to be discharged mercury emissions to the atmosphere without accounting for all of the emissions in accordance with the applicable provisions of this section, § §  123.211—123.215 and Chapter 139, Subchapter C.

 (m)  An owner or operator of an affected EGU may not disrupt the continuous emission monitoring system or portion of it or other approved emission monitoring method to avoid monitoring and recording mercury mass emissions discharged into the atmosphere, except for periods of recertification or periods when calibration, quality assurance testing or maintenance is performed in accordance with the applicable provisions of this section, § §  123.211—123.215 and Chapter 139, Subchapter C.

 (n)  An owner or operator of an affected EGU may not retire or permanently discontinue use of the continuous emission monitoring system or component of it or other approved monitoring system required under this section and § §  123.211—123.215, except under either of the following circumstances:

   (1)  The owner or operator is monitoring emissions from the affected EGU with another certified monitoring system that has been approved by the Department, in writing, for use at that EGU and that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system, in accordance with the applicable provisions of this section, § §  123.211—123.215 and Chapter 139, Subchapter C.

   (2)  The owner or operator submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with §  123.211(a)(5)(i) and a complete certification application in accordance with §  123.211(a)(5)(ii).

   (3)  The owner or operator of an EGU that is using a continuous emission monitoring system or a sorbent trap system to continuously monitor mercury emissions under §  123.210(c)(1) (relating to general monitoring and reporting requirements) and 40 CFR 75.81(a), may elect to comply with the methodology specified in §  123.210(c)(2) and 40 CFR 75.81(b)—(f).

   The provisions of this §  123.210 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.210 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  By the applicable deadline specified in §  123.210 (f)—(h) (relating to general monitoring and reporting requirements), the owner or operator of an affected EGU shall comply with the following initial certification and recertification procedures for a continuous monitoring system (continuous emission monitoring system) and an excepted monitoring system (sorbent trap monitoring system) as required under 40 CFR 75.15 (relating to special provisions for measuring Hg mass emissions using the excepted sorbent trap monitoring methodology) and Chapter 139 (relating to sampling and testing):

   (1)  The owner or operator of the EGU shall ensure that each continuous monitoring system required by the applicable provisions of §  123.210 successfully completes all of the initial certification testing required under 40 CFR 75.80(d) (relating to general provisions) and Chapter 139.

   (2)  If the owner or operator of the EGU installs a monitoring system to meet the requirements of this section and § §  123.210 and 123.212—123.215 in a location where no monitoring system was previously installed, initial certification testing is required in accordance with the applicable provisions of 40 CFR 75.80(d) and Chapter 139.

   (3)  If the owner or operator of the EGU makes a replacement, modification or change to a certified continuous emission monitoring system or excepted monitoring system (sorbent trap monitoring system) required by §  123.210 that may significantly affect the ability of the system to accurately measure or record mercury mass emissions or heat input rate or to meet the quality-assurance and quality-control requirements of 40 CFR 75.81 (relating to monitoring of Hg mass emissions and heat input at the unit level) or 40 CFR Part 75, Appendix B (relating to quality assurance and quality control procedures), the monitoring system for the EGU shall be recertified in accordance with 40 CFR 75.20(b) (relating to initial certification and recertification procedures) and Chapter 139.

   (4)  If the owner or operator of the EGU makes a replacement, modification or change to the flue gas handling system or the operation of the EGU that may significantly change the stack gas flow or concentration profile, the owner or operator shall recertify each continuous emission monitoring system and each excepted monitoring system (sorbent trap monitoring system) whose accuracy is potentially affected by the change in accordance with 40 CFR 75.20(b) and Chapter 139.

   (5)  This subsection applies to both the initial certification and recertification procedures of a continuous monitoring system required by §  123.210. For recertifications, replace the words ‘‘certification’’ and ‘‘initial certification’’ with the word ‘‘recertification,’’ replace the word ‘‘certified’’ with the word ‘‘recertified,’’ and follow the procedures required under 40 CFR 75.20(b)(5) or Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources) as directed by the Department instead of the following procedures:

     (i)   The owner or operator shall submit to the Department written notice of the dates of certification testing.

     (ii)   The owner or operator shall submit to the Department a certification application for each monitoring system. A complete certification application must include the information specified in Chapter 139, Subchapter C.

     (iii)   If the Department issues a notice of disapproval of a certification application or a notice of disapproval of certification status, the owner or operator shall:

       (A)   Substitute, for each disapproved monitoring system, for each hour of EGU operation during the period of invalid data specified under 40 CFR 75.20(a)(4)(iii) or 75.21(e) (relating to quality assurance and quality control requirements) and continuing until the applicable date and hour specified under 40 CFR 75.20(a)(5)(i), either the following values or, if approved by the Department in writing, an alternative emission value that is more representative of actual emissions that occurred during the period:

         (I)   For a disapproved mercury pollutant concentration monitor and disapproved flow monitor, respectively, the maximum potential concentration of mercury and the maximum potential flow rate, as defined in 40 CFR Part 75, Appendix A, Sections 2.1.4.1 and 2.1.7.1 (relating to specifications and test procedures).

         (II)   For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO₂ concentration or the minimum potential O₂ concentration (as applicable), as defined in 40 CFR Part 75, Appendix A, Sections 2.1.3.1, 2.1.3.2 and 2.1.5.

         (III)   For a disapproved excepted monitoring system (sorbent trap monitoring system) under 40 CFR 75.15 and disapproved flow monitor, respectively, the maximum potential concentration of mercury and maximum potential flow rate, as defined in 40 CFR Part 75, Appendix A, Sections 2.1.4.1 and 2.1.7.1.

       (B)   Submit a notification of certification retest dates and a new certification application in accordance with subparagraphs (i) and (ii).

       (C)   Repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Department’s notice of disapproval, within the time period specified by the Department in the notice of disapproval.

 (b)  The owner or operator shall submit a certification application to the Department within 45 calendar days after completing all initial certification or recertification tests required under this section.

   The provisions of this §  123.211 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.211 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  If an emissions monitoring system fails to meet the quality-assurance and quality-control requirements or data-validation requirements of Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources), data for the demonstration of compliance with §  123.207 (relating to annual emission limitations for coal-fired EGUs) shall be substituted using the applicable missing data procedures in the Continuous Source Monitoring Manual (DEP 274-0300-001). If a mass emissions monitoring system fails to meet a quality-assurance or quality-control requirement, mass emissions data shall be substituted using the missing data procedures in 40 CFR Part 75, Subpart I (relating to Hg mass emission provisions).

 (b)  If both an audit of a monitoring system and a review of the initial certification or recertification application reveal that a monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under §  123.210 (relating to general monitoring and reporting requirements) or the applicable provisions of 40 CFR Part 75 (relating to continuous emission monitoring), both at the time of the initial certification or recertification application submission and at the time of the audit, the Department will issue a notice of disapproval of the certification status of the monitoring system.

   (1)  For the purposes of this subsection, an audit must be either a field audit or an audit of information submitted to the Department.

   (2)  By issuing the notice of disapproval, the Department revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system will not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system.

   (3)  The owner or operator shall follow the applicable initial certification or recertification procedures in §  123.210 for each disapproved monitoring system.

   The provisions of this §  123.212 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.212 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 The owner or operator of an EGU complying with the requirements of §  123.206(d) (relating to compliance requirements for the emission standards for coal-fired EGUs) using electrical output (Oi) shall monitor gross Oi of the associated generators and report in watt-hours per hour.

   The provisions of this §  123.213 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.213 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  Except as provided in §  123.210(c) (relating to general monitoring and reporting requirements), the owner or operator of an EGU complying with this section and § §  123.201—123.213 and 123.215 shall:

   (1)  Perform daily sampling of the coal combusted in the EGU for mercury content, in pounds per trillion Btu, as follows:

     (i)   Collect coal samples from the feeders or other representative location in accordance with 40 CFR 63.7521(c) (relating to what fuel analyses and procedures must I use?).

     (ii)   Composite coal samples in accordance with the requirements of 40 CFR 63.7521(d).

   (2)  Analyze each of the composited coal samples for mercury content in accordance with the procedures of ASTM D 6414-01 or the current revision of this method, or other alternative as approved by the Department.

 (b)  The owner or operator of an EGU shall use the data collected from the sampling and analysis required under subsection (a) to determine the input mercury content of the coal combusted in the EGU in terms of pounds of mercury per trillion Btu.

 (c)  The Department may change the frequency of the sampling and analysis of the coal combusted in the EGU for the input mercury level based on historical data provided by the owner or operator of the EGU. The change in the frequency will be approved by the Department as a minor modification to the Title V operating permit.

 (d)  Upon the written request of an EGU owner or operator, the Department may approve, in writing, an alternate coal sampling and analysis program submitted by the owner or operator of the EGU to demonstrate compliance with this section and § §  123.201—123.213 and 123.215.

   The provisions of this §  123.214 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.214 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

 (a)  The owner or operator of an affected EGU shall comply with the recordkeeping and reporting requirements in this section and the applicable recordkeeping and reporting requirements of 40 CFR 75.84 (relating to recordkeeping and reporting) and Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources).

 (b)  The owner or operator of an affected EGU complying with this section and § §  123.201—123.214 through the requirements of §  123.206(d) (relating to compliance requirements for the emission standards for coal-fired EGUs) by using electrical output to determine the allowable emissions of the EGU shall maintain the daily gross electrical output in GWhs in the file required under 40 CFR 75.84(a).

 (c)  The owner or operator of an affected EGU complying with this section and § §  123.201—123.214 through the requirements of §  123.206(e) by using input mercury levels to determine the allowable emissions of the EGU shall maintain the daily mercury content of coal used in pounds of mercury per trillion Btu and the daily input mercury content in pounds in the file required under 40 CFR 75.84(a).

 (d)  Except as provided in §  123.210(c) (relating to general monitoring and reporting requirements), the owner or operator of an affected EGU shall maintain records as follows:

   (1)  Record the daily outlet mercury or output mercury data using the time period appropriate to the excepted monitoring system (sorbent trap monitoring system).

   (2)  If using an averaging methodology, record all other information collected on a daily basis necessary to calculate the average.

   (3)  Record for each control period the method through which each EGU demonstrated compliance.

   (4)  For an owner or operator who uses the averaging option of §  123.206(a)(2), calculate and record:

     (i)   The monthly actual mercury emissions within 30 days of the end of each month.

     (ii)   The 12-month rolling actual emissions each month.

   (5)  Maintain the following records onsite:

     (i)   The results of quarterly assessments conducted under 40 CFR Part 75, Appendix B, Section 2.2 (relating to quality assurance and quality control procedures).

     (ii)   Daily/weekly system integrity checks under 40 CFR Part 75, Appendix B, Section 2.6.

     (iii)   Quality assurance records as required by the Continuous Source Monitoring Manual (DEP 274-0300-001).

   (6)  Make available to the Department upon request the records required under paragraph (5).

 (e)  The owner or operator shall submit quarterly reports to the Department in accordance with the Continuous Source Monitoring Manual (DEP 274-0300-001).

   The provisions of this §  123.215 issued under section 5(a)(1) of the Air Pollution Control Act (35 P. S. §  4005(a)(1)).

   The provisions of this §  123.215 adopted February 16, 2007, effective February 17, 2007, 37 Pa.B. 883.

   This section cited in 25 Pa. Code §  123.201 (relating to purpose); 25 Pa. Code §  123.202 (relating to definitions); 25 Pa. Code §  123.203 (relating to applicability); 25 Pa. Code §  123.205 (relating to emission standards for coal-fired EGUs); 25 Pa. Code §  123.206 (relating to compliance requirements for the emission standards for coal-fired EGUs); 25 Pa. Code §  123.207 (relating to annual emission limitations for coal-fired EGUs); 25 Pa. Code §  123.209 (relating to petition process); 25 Pa. Code §  123.210 (relating to general monitoring and reporting requirements); 25 Pa. Code §  123.211 (relating to initial certification and recertification procedures for emissions monitoring); and 25 Pa. Code §  123.214 (relating to coal sampling and analysis for input mercury levels).