[27 Pa.B. 5683]
[Continued from previous Web Page] (II) For oil-fired turbines, the default factor is 1.2 pounds NOx 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 NOx Budget Program,'' to determine unit specific maximum potential NOx 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 NOx emissions in pounds per hour, or may perform testing consistent with the ''Guidance for Implementation of Emission Monitoring Requirements for the NOx 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 NOx CEMS to monitor NOx 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 NOx CEMS to monitor NOx 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 NOx 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 NOx 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 NOx Budget Program.''
(10) If the owner or operator determines NOx 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 NOx emissions in pounds per hour. If the owner or operator determines NOx emissions in ppm and flow in standard cubic feet per hour, the procedures in ''Guidance for Implementation of Emission Monitoring Requirements for the NOx Budget Program'' may be used to determine NOx 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 NOx CEMS reporting in accordance with § 139.101 in units of pounds of NOx 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 NOx emissions rate by 1.1), or both, shall be conducted only for reporting to the NOx 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.
§ 123.109. Source emissions reporting requirements.
(a) The authorized account representative for each NOx affected source shall submit to the NOx 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 NOx Budget Program.''
(b) Upon permanent shutdown, NOx affected sources may be exempted from this section after receiving written Department approval of a request filed by the authorized account representative for the NOx affected source which identifies the source and date of shutdown.
§ 123.110. Source compliance requirements.
(a) Each year from November 1 through December 31, inclusive, the authorized account representative shall request the NOx budget administrator to deduct, consistent with § 123.107 (relating to NOx allowance transfer procedures) a designated amount of NOx allowances by serial number, from the NOx affected source's compliance account in an amount equivalent to the NOx emitted from the NOx affected source during that year's NOx allowance control period in accordance with the following:
(1) Allowances allocated for the current NOx control period may be used without restriction.
(2) Allowances allocated for future NOx control periods may not be used.
(3) NOx allowances which were allocated for any preceding NOx 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 NOx budget. Banked allowances shall be deducted against emissions in accordance with a ratio of NOx allowances to emissions as specified by the NOx budget administrator as follows:
(i) If the total NOx allowances remaining in the NATS for all sources for preceding NOx allowance control periods are less than or equal to 10% of the total NOx allowances allocated for that NOx allowance control period, the ratio is 1:1.
(ii) If the total NOx allowances remaining in the NATS for all sources for preceding NOx allowance control periods are greater than 10% of the NOx allowances allocated for that NOx 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 NOx allowance deduction request, or a NOx allowance deduction request insufficient to meet the requirements of subsection (a), the NOx budget administrator may deduct the necessary number of NOx allowances from the NOx affected source's compliance account. The NOx budget administrator shall provide written notice to the authorized account representative that NOx allowances were deducted from the source's account. If the necessary number of NOx allowances is available, the source will be in compliance after the NOx allowance deduction is completed. If there is an insufficient number of NOx allowances available for NOx allowance deduction, § 123.111 (relating to failure to meet source compliance requirements) applies.
(c) For each NOx allowance control period, the authorized account representative for the NOx affected source shall submit an annual compliance certification to the Department.
(d) The compliance certification shall be submitted no later than the NOx allowance transfer deadline (December 31) of each year.
(e) The compliance certification shall contain, at a minimum, the following:
(1) An identification of the NOx 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 NOx affected source held sufficient NOx allowances, as determined in subsection (a), in its compliance account for the NOx allowance control period, as of the NOx allowance transfer deadline, to equal or exceed the NOx affected source's actual emissions and the emissions reported to the NETS for the NOx allowance control period.
(4) A statement indicating whether or not the monitoring plan which governs the NOx affected source was followed when monitoring the actual operation of the NOx affected source.
(5) A statement indicating that all emissions from the NOx 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 NOx affected source or the method of monitoring of the NOx 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 NOx allowance deduction and transfers from the NATS.
(3) Obtaining information on emissions from the NETS.
(4) Testing emission monitoring devices.
(5) Requiring the NOx affected source to conduct emissions testing in accordance with Chapter 139 (relating to sampling and testing).
§ 123.111. Failure to meet source compliance requirements.
(a) Failure by the NOx affected source to hold in its compliance account, for a NOx allowance control period, as of the NOx allowance transfer deadline, sufficient NOx allowances equal to or exceeding actual emissions for the NOx allowance control period as specified under § 123.102 (relating to source allowance requirements and NOx allowance control period) shall result in NOx allowance deduction from the NOx affected source's compliance account at the rate of 3 NOx 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 NOx allowance control period, otherwise the source may not operate during subsequent control periods.
(b) In addition to the NOx 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 NOx allowance control period shall presume that each day in the NOx allowance control period constitutes a day in violation (153 days) unless the NOx 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.
§ 123.112. Source operating permit provision requirements.
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 NOx allowance requirements). The NATS compliance account number and the authorized account representative shall be listed on the permit.
§ 123.113. Source recordkeeping requirements.
The owner or operator of a NOx affected source shall maintain for each NOx affected source and for 5 years, or any other period consistent with the terms of the NOx 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.
§ 123.114. General NOx allocation provisions.
(a) NOx allocations to NOx affected sources may only be made by the Department.
(b) Except as provided in § 123.116 (relating to source opt-in provisions), for NOx affected sources identified in Appendix A which shutdown or curtail operations, the source account will continue to receive NOx allowances for each NOx allowance control period.
§ 123.115. Initial NOx allowance NOx allocations.
(a) The sources contained in Appendix A are subject to the requirements of §§ 123.101--123.114, 123.116--123.120 and this section. These sources are allocated NOx allowances for the 1999--2002 NOx allowance control periods as listed in Appendix A. Except as provided in § 123.120 (relating to audit), if no allocation is specified for the NOx allowance control periods beyond 2002, the current allocations continue indefinitely.
(b) The Washington Power Company and Colver Power Project sources identified in Appendix A shall receive the allocation identified in Appendix A upon operation of the source.
(c) 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.
§ 123.116. Source opt-in provisions.
(a) A person who owns, operates, leases or controls a non-NOx affected source located in this Commonwealth may apply to the Department to opt-in that source to become a NOx 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 NOx affected source may become a NOx affected source under the following conditions:
(1) Submission of an opt-in application to the Department, including:
(i) Documentation of baseline NOx allowance control period emissions which shall be the average of the actual emissions for the preceding two consecutive NOx allowance control periods. The Department may approve selection of an alternative two consecutive NOx 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 NOx 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 NOx allowances established under paragraph (1)(i) or subsection (c) by the Department to the NOx budget administrator.
(c) A source which began operations with emission reduction credits from a NOx affected source may become a NOx affected source by complying with subsection (b)(1). To operate the source, NOx 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 NOx 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 NOx allowances for the current NOx 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 NOx allowance control period allowance allocation and the emissions reported in accordance with § 123.109 (relating to source emissions reporting requirements). NOx allocations for future NOx allocation control periods shall also be surrendered. NOx allowances which were allocated for any preceding NOx allowance control period which were not used (banked) may not be surrendered. Surrendered NOx allowances shall be retired from the NATS and NOx budget except that upon request by the source owner or operator, the Department may reallocate the NOx 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-NOx affected source unless it is shut down.
§ 123.117. New NOx affected source provisions.
(a) NOx allowances may not be created for new NOx affected sources. New NOx affected sources are sources which are not listed in § 123.115 (relating to initial NOx allowance NOx allocations). The owner or operator of a new NOx affected source shall establish a compliance account prior to the commencement of operations and is responsible to acquire any required NOx allowances from those available in the NATS.
(b) Newly discovered NOx 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 NOx 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 NOx MOU Budget and provide NOx 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 NOx allowance awards).
§ 123.118. Emission reduction credit provisions.
(a) NOx 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 NOx 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 NOx affected source may transfer NOx ERCs to an NOx affected source if the new or modified NOx 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 NOx ERCs.
(d) A NOx affected source may transfer NOx ERCs to a non-NOx affected source under the following conditions:
(1) The non-NOx 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 NOx ERCs.
(2) The NATS account for NOx affected sources which generated ERCs transferred to non-NOx 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 NOx allowance requirements) to the NOx nonaffected sources. The amount of annual NOx allowances deducted shall be equivalent to that portion of the nonaffected source's NOx control period allowable emissions which were provided for by the NOx ERCs from the affected source.
(3) Allocations for NOx allowance control periods following 2002 to the NOx ERC generating source may not include the allowances identified in paragraph (2).
§ 123.119. Bonus NOx allowance awards.
(a) The Department will, upon receipt of a complete application by November 1, 1998, award a NOx affected source with bonus NOx 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 NOx 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 NOx allowance control.
(ii) The lower of the source's applicable emission rate for NOx expressed in pounds of NOx 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 NOx allowances awarded.
§ 123.120. Audit.
(a) The Department will complete an audit of the program established by §§ 123.101--123.119 and this section (relating to NOx 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 NOx allowance CEMS and data acquisition systems at the NOx affected source.
(3) If emissions in excess of the NOx allowances allocated occurred in any NOx allowance control period, as a result of banking provisions, a determination whether or not the NOx allowance banking provisions require modification or deletion.
(4) NOx allowance banking privileges will be examined to determine whether they adversely influenced market availability and price of NOx 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.
Appendix A
Combustion Point Baseline NOx Baseline County Facility Source Name ID Allowance lb/MMBtu MMBtu Adams Met Edison Hamilton 031 4 0.59 18,716 Adams Met Edison Ortanna 031 3 0.59 13,130 Adams Metropolitan Edison Company G. E. N Frame Turbine #1 031 17 0.45 89,908 Adams Metropolitan Edison Company G. E. N Frame Turbine #2 032 6 0.45 29,243 Adams Metropolitan Edison Company G. E. N Frame Turbine #3 033 14 0.45 74,249 Allegheny Duquesne Light Company, Cheswick Boiler 001 2,114 0.61 15,025,580 Armstrong Penelec--Keystone Boiler No. 1 031 4,342 0.80 25,149,236 Armstrong Penelec--Keystone Boiler No. 2 032 3,446 0.79 22,657,898 Armstrong West Penn Power Co. Foster Wheeler 031 1,140 0.95 5,355,101 Armstrong West Penn Power Co. Foster Wheeler 032 1,066 1.02 5,007,467 Beaver AES Beaver Valley Partners, Inc. Babcock and Wilcox 032 302 0.83 1,747,462 Beaver AES Beaver Valley Partners, Inc. Babcock and Wilcox 033 247 0.83 1,431,342 Beaver AES Beaver Valley Partners, Inc. Babcock and Wilcox 034 286 0.83 1,655,847 Beaver AES Beaver Valley Partners, Inc. Babcock and Wilcox 035 154 0.81 683,951 Beaver Penn Power Co.--Bruce Mansfield Boiler Unit 1 031 2,993 0.90 16,618,929 Beaver Penn Power Co.--Bruce Mansfield Foster Wheeler Unit No. 2 032 3,866 0.90 21,464,786 Beaver Penn Power Co.--Bruce Mansfield Foster Wheeler Unit 3 033 3,504 0.70 19,455,843 Beaver Zinc Corporation Of America Coal Boiler 1 034 241 0.80 1,380,627 Beaver Zinc Corporation Of America Coal Boiler 2 035 204 0.80 1,168,776 Berks Metropolitan Edison Co.--Titus Unit 1 031 202 0.65 1,836,587 Berks Metropolitan Edison Co.--Titus Unit 2 032 186 0.68 1,632,072 Berks Metropolitan Edison Co.--Titus Unit 3 033 201 0.66 1,805,003 Berks Metropolitan Edison Co.--Titus No. 4 Combustion Turbine 034 2 0.44 20,010 Berks Metropolitan Edison Co.--Titus No. 5 Combustion Turbine 035 2 0.44 15,484 Blair Penelec--Williamsburg No. 11 Boiler--Rily 031 38 0.87 200,874 Bucks PECO Energy--Croyden Croyden--Turbine #11 031 11 0.70 42,451 Bucks PECO Energy--Croyden Croyden--Turbine #12 032 7 0.70 26,382 Bucks PECO Energy--Croyden Croyden--Turbine #21 033 44 0.70 175,640 Bucks PECO Energy--Croyden Croyden--Turbine #22 034 20 0.70 81,649 Bucks PECO Energy--Croyden Croyden--Turbine #31 035 11 0.70 42,534 Bucks PECO Energy--Croyden Croyden--Turbine #32 036 14 0.70 54,905 Bucks PECO Energy--Croyden Croyden--Turbine #41 037 8 0.70 30,191 Bucks PECO Energy--Croyden Croyden--Turbine #42 038 38 0.70 152,094 Bucks United States Steel Corp., The Power House Boiler
No. 3043 63 0.26 655,625 Bucks United States Steel Corp., The Power House Boiler
No. 4044 14 0.27 147,330 Bucks United States Steel Corp., The Power House Boiler
No. 5045 73 0.26 756,980 Bucks United States Steel Corp., The Power House Boiler
No. 6046 84 0.26 871,810 Cambria Cambria CoGen Company A Boiler 031 200 0.24 2,003,177 Cambria Cambria CoGen Company B Boiler 032 212 0.23 2,116,233 Cambria Colver Power Project 411 0.20 4,112,640 Cambria Ebensburg Power Company CFB Boiler 206 0.08 2,058,858 Carbon Panther Creek Energy Facility Boiler 1 119 0.12 1,592,491 Carbon Panther Creek Energy Facility Boiler 2 117 0.12 1,555,673 Chester PECO Energy--Cromby Boiler No 1 031 247 0.82 1,660,770 Chester PECO Energy--Cromby Boiler No 2 032 187 0.28 1,257,120 Clarion Piney Creek Project CFB Boiler 122 0.18 1,217,989 Clearfield Penelec--Shawville Babcock Wilcox Boiler 031 981 1.22 3,737,976 Clearfield Penelec--Shawville Babcock Wilcox Boiler 032 947 1.21 3,624,416 Clearfield Penelec--Shawville Combustion Engineering 033 852 0.86 4,558,942 Clearfield Penelec-Shawville Combustion Engineering 034 693 0.87 3,697,889 Clinton International Paper Co. 1 Riley Stoker Vo-Sp 033 145 0.55 1,220,703 Clinton International Paper Co. 2 Riley Stoker Vo-Sp 034 145 0.55 1,218,878 Clinton PP&L--Lock Hanve CT 1 0.49 14,818 Columbia Penelec--Benton 002 1 2.33 2,661 Columbia Penelec--Benton 003 1 2.93 2,330 Cumberland Metropolitan Edison Company G.E. N Frame Turbine 031 9 0.45 46,665 Cumberland Metropolitan Edison Company G.E. N Frame Turbine #1 032 11 0.45 55,480 Cumberland PP&L-West Shore CT 1 3 0.49 12,402 Cumberland PP&L-West Shore CT 2 3 0.49 13,231 Dauphin PP&L-Harrisburg CT 1 4 0.49 16,282 Dauphin PP&L-Harrisburg CT 2 4 0.49 15,884 Dauphin PP&L-Harrisburg CT 3 4 0.49 15,446 Dauphin PP&L-Harrisburg CT 4 4 0.49 15,386 Delaware BP Oil, Inc. 7 Boiler 032 35 0.37 331,917 Delaware BP Oil, Inc. 8 Boiler 033 56 0.48 535,337 Delaware BP Oil, Inc. 038 187 0.55 1,789,455 Delaware PECO Energy-Eddystone No. 1 Boiler 031 663 0.54 5,571,014 Delaware PECO Energy-Eddystone No. 2 Boiler 032 432 0.55 3,629,294 Delaware PECO Energy-Eddystone No. 3 Boiler 033 257 0.28 2,153,713 Delaware PECO Energy-Eddystone No. 10 Gas Turbine 037 1 0.49 9,464 Delaware PECO Energy-Eddystone No. 20 Gas Turbine 038 1 0.48 7,560 Delaware PECO Energy-Eddystone No. 30 Gas Turbine 039 2 0.48 19,502 Delaware PECO Energy-Eddystone No. 40 Gas Turbine 040 1 0.49 9,450 Delaware PECO Energy-Eddystone No. 4 Boiler 041 249 0.28 2,089,539 Delaware Kimberly-Clark Boiler No. 9 034 12 0.52 264,600 Delaware Kimberly-Clark 10 Culm Cogen. Fbc Plant 035 85 0.08 1,602,169 Delaware Sun Refining & Marketing 089 86 0.09 1,211,002 Delaware Sun Refining & Marketing 090 145 0.08 4,927,837 Elk Penntech Papers, Inc. B&W Model Pm106 Boiler #6 038 0 0.00 0 Elk Penntech Papers, Inc. B&W #81 Boiler 040 103 0.83 570,989 Elk Penntech Papers, Inc. B&W #82 Boiler 041 109 0.83 603,471 Erie General Electric Co. B&W Boiler No. 2 032 26 1.01 587,180 Erie International Paper Company Coal Fired Boiler No. 21 037 68 0.58 321,958 Erie Norcon Power Partners Turbine 1 001 50 0.07 1,483,488 Erie Norcon Power Partners Turbine 2 002 50 0.07 1,483,488 Erie Penelec-Front Street Erie City Iron Works No. 7 031 5 0.92 38,964 Erie Penelec--Front Street Erie City Iron Works No. 8 032 5 0.90 39,881 Erie Penelec--Front Street Comb. Eng. Boiler
No. 9033 134 0.57 1,033,388 Erie Penelec--Front Street Comb. Eng. Boiler
No. 10034 134 0.57 1,033,528 Greene West Penn Power--Hatfield's Ferry Babcock & Wilcox 031 3,978 1.04 15,502,912 Greene West Penn Power--Hatfield's Ferry Babcock & Wilcox 032 3,703 1.04 14,429,251 Greene West Penn Power--Hatfield's Ferry Babcock & Wilcox 033 2,160 1.04 8,416,290 Indiana Penelec--Conemaugh Boiler No. 1 031 3,295 0.76 20,130,686 Indiana Penelec--Conemaugh Boiler No. 2 032 4,197 0.76 25,543,024 Indiana Penelec--Homer City Boiler No. 1-Foster Whelr 031 3,167 1.20 11,325,278 Indiana Penelec--Homer City Boiler No. 2-Foster Whelr 032 3,987 1.20 15,382,211 Indiana Penelec--Homer City Boiler No. 3-B&W 033 2,931 0.62 21,951,003 Indiana Penelec--Seward Boiler No. 12 (B&W) 032 145 0.84 849,307 Indiana Penelec--Seward Boiler No. 14 (B&W) 033 146 0.83 809,011 Indiana Penelec--Seward Boiler No. 15 (Comb. Eng.) 931 673 0.75 4,155,275 Lackawanna Archbald Power Corporation Cogen 82 0.05 818,013 Lancaster PP&L--Holtwood Unit 17 Foster Wheeler 934 807 1.20 3,116,786 Lawrence Penn Power Co.--New Castle Foster Wheeler 031 108 0.91 553,994 Lawrence Penn Power Co.--New Castle B.W. Boiler 032 97 0.91 498,559 Lawrence Penn Power Co.--New Castle Babcock And Wilcox 033 185 0.91 947,292 Lawrence Penn Power Co.--New Castle Babcock And Wilcox 034 339 0.91 1,737,996 Lawrence Penn Power Co.--New Castle Babcock And Wilcox 035 622 0.91 3,183,091 Lehigh PP&L--Allentown CT 1 2 0.49 10,329 Lehigh PP&L--Allentown CT 2 3 0.49 13,752 Lehigh PP&L--Allentown CT 3 3 0.49 14,215 Lehigh PP&L--Allentown CT 4 3 0.49 12,745 Lycoming PP&L--Williamsport CT 1 3 0.49 14,633 Lycoming PP&L--Williamsport CT 2 3 0.49 14,083 Luzerne Continental Energy Associates Turbine 269 0.13 2,687,577 Luzerne Continental Energy Associates HRSG 129 0.20 1,288,248 Luzerne UGI Corp.--Hunlock Power Foster Wheeler 031 375 0.95 1,821,127 Luzerne PP&L--Jenkins CT 1 3 0.49 12,942 Luzerne PP&L--Jenkins CT 2 2 0.49 6,885 Luzerne PP&L--Harwood CT 1 3 0.49 14,194 Luzerne PP&L--Harwood CT 2 3 0.49 14,049 Monroe Met Edison Shawnee 031 3 0.59 15,285 Montgomery Merck Sharp & Dohme Cogen II Gas Turbine 039 79 0.16 1,028,875 Montour PP&L--Montour Montour No. 1 031 3,576 0.85 17,029,683 Montour PP&L--Montour Montour No. 2 032 4,706 1.07 22,409,322 Montour PP&L--Montour Aux. Start-Up Boiler No. 1 033 9 0.17 44,436 Montour PP&L--Montour Aux. Start-Up Boiler No. 2 034 7 0.17 34,076 Northampton Bethlehem Steel Corp. Boiler 1 Boiler House 2 041 90 0.23 Confidential Northampton Bethlehem Steel Corp. Boiler 2 Boiler House 2 042 90 0.23 Confidential Northampton Bethlehem Steel Corp. Boiler 3 Boiler House 2 067 91 0.23 Confidential Northampton Met Edison Co.--Portland Unit No. 1 031 463 0.59 3,593,611 Northampton Met Edison Co.--Portland Unit No. 2 032 658 0.66 4,578,297 Northampton Met Edison Co.--Portland Combustion Turbine No. 3 033 1 0.53 9,795 Northampton Met Edison Co.--Portland Combustion Turbine No. 4 034 6 0.53 40,931 Northampton Northampton Generating Company Boiler 001 210 0.10 4,208,112 Northampton PP&L--Martins Creek Foster-Wheeler Unit No. 1 031 493 1.01 3,329,831 Northampton PP&L--Martins Creek Foster-Wheeler Unit No. 2 032 461 0.91 3,112,136 Northampton PP&L--Martins Creek C-E Unit No. 3 033 837 0.51 5,652,924 Northampton PP&L--Martins Creek C-E Unit No. 4 034 741 0.51 5,003,663 Northampton PP&L--Martins Creek No. 4b Auxiliary Boiler 036 0 0.17 2,394 Northampton PP&L--Martins Creek Combustion Turbine No. 1 037 3 0.02 206,640 Northampton PP&L--Martins Creek Combustion Turbine No. 2 038 3 0.02 206,640 Northampton PP&L--Martins Creek Combustion Turbine No. 3 039 3 0.02 206,640 Northampton PP&L--Martins Creek Combustion Turbine No. 4 040 3 0.02 206,640 Northumberland Foster Wheeler Mt. Carmel Cogen Cogen 031 196 0.10 1,814,911 Philadelphia PECO Energy 037 28 0.60 117,455 Philadelphia PECO Energy 038 37 0.60 156,375 Philadelphia PECO Energy--Delware 013 111 0.45 918,037 Philadelphia PECO Energy--Delware 014 129 0.45 1,066,091 Philadelphia PECO Energy--Delware 015 1 0.67 7,089 Philadelphia PECO Energy--Delaware 016 1 0.67 9,452 Philadelphia PECO Energy--Delaware 017 1 0.67 11,259 Philadelphia PECO Energy--Delaware 018 2 0.67 15,012 Philadelphia PECO Energy--Schuylkill 003 174 0.28 1,459,923 Philadelphia PECO Energy--Schuylkill 007 1 0.67 9,285 Philadelphia PECO Energy--Schuylkill 008 0 0.67 1,946 Philadelphia Trigen Energy Co--Sansom 001 31 0.45 318,459 Philadelphia Trigen Energy Co--Sansom 002 27 0.45 280,748 Philadelphia Trigen Energy Co--Sansom 003 12 0.45 126,824 Philadelphia Trigen Energy Co--Sansom 004 15 0.45 155,123 Philadelphia Trigen Energy Co--Schuylkill 001 0 0.28 511,191 Philadelphia Trigen Energy Co--Schuylkill 002 0 0.28 228,162 Philadelphia Trigen Energy Co--Schuylkill 005 0 0.45 248,138 Philadelphia U.S. Naval Base 098 1 0.14 14,294 Philadelphia U.S. Naval Base 099 1 0.14 1,960 Philadelphia Grays Ferry Project Combustion Turbine 126 Philadelphia Grays Ferry Project Heat Recovery Steam Gen 21 Philadelphia Grays Ferry Project Boiler 25 80 Schuylkill Gilberton Power Company Boiler 335 0.17 3,352,372 Schuylkill Northeastern Power Company CFB Boiler 202 0.06 2,022,148 Schuylkill Northeastern Power Company Aux Boiler 0 0.27 1,396 Schuylkill Schuylkill Energy Resources Boiler 031 350 0.20 4,349,117 Schuylkill Westwood Energy Properties Boiler 135 0.17 1,351,408 Schuylkill Wheelabrator Frackville Energy Co Boiler 205 0.14 2,046,694 Schuylkill PP&L--Fishback CT 1 2 0.49 8,272 Schuylkill PP&L--Fishback CT 2 2 0.49 7,217 Snyder PP&L--Sunbury Sunbury SES Unit 1a 031 295 0.98 1,455,641 Snyder PP&L--Sunbury Sunbury SES Unit 1b 032 295 0.98 1,455,641 Snyder PP&L--Sunbury Sunbury SES Unit 2a 033 295 0.83 1,455,641 Snyder PP&L--Sunbury Sunbury SES Boiler 2b 034 295 0.83 1,455,641 Snyder PP&L--Sunbury Sunbury SES Unit
No. 3035 681 0.93 3,363,299 Snyder PP&L--Sunbury Sunbury SES Unit
No. 4036 824 0.99 4,070,181 Snyder PP&L--Sunbury Diesel Generator 1 037 0 3.39 709 Snyder PP&L--Sunbury Diesel Generator 2 038 0 3.23 806 Snyder PP&L--Sunbury Combustion Turbine 1 039 3 0.49 14,581 Snyder PP&L--Sunbury Combustion Turbine 2 040 3 0.49 14,581 Tioga Penelec--Tioga 031 3 0.48 30,267 Venango Scrubgrass Power Plant Unit 1 031 182 0.14 1,816,817 Venango Scrubgrass Power Plant Unit 2 032 179 0.15 1,790,997 Warren Penelec--Warren Boiler No. 1 031 76 0.62 569,825 Warren Penelec--Warren Boiler No. 2 032 73 0.64 546,534 Warren Penelec--Warren Boiler No. 3 033 77 0.61 572,007 Warren Penelec--Warren Boiler No. 4 034 80 0.61 596,377 Warren Penelec--Warren 001 10 0.69 77,943 Washington Duquesne Light Co.--Elrama No. 1 Boiler 031 334 0.87 1,116,538 Washington Duquesne Light Co.--Elrama No. 2 Boiler 032 333 0.90 1,114,175 Washington Duquesne Light Co.--Elrama No. 3 Boiler 033 446 0.87 1,490,615 Washington Duquesne Light Co.--Elrama No. 4 Boiler 034 1,016 0.89 3,398,150 Washington McGraw--Edison Co. Foster-Wheeler 032 0 0.00 0 Washington Washington Power Co. Boiler 1 155 0.15 2,068,438 Washington Washington Power Co. Boiler 2 155 0.15 2,068,438 Washington West Penn Power Co.--Mitchell Combustion Eng Coal Unit 034 931 0.72 5,968,482 Wayne Penelec--Wayne 031 11 0.84 62,736 Wyoming Procter & Gamble Paper Products Co. Westinghouse 251B10 035 246 0.68 1,654,800 York Glatfelter, P.H. Co. Number 4 Power Boiler 034 127 0.80 978,985 York Glatfelter, P.H. Co. Number 1 Power Boiler 035 85 0.80 653,626 York Glatfelter, P.H. Co. Number 5 Power Boiler 036 232 0.29 1,780,350 York Met Edison Tolna 031 4 0.59 20,492 York Met Edison Tolna 032 4 0.59 19,306 York PP&L--Brunner Island Brunner Island 2 032 1,474 0.69 9,319,539 York PP&L--Brunner Island Brunner Island Unit 1 931 1,294 0.67 8,178,891 York PP&L--Brunner Island Brunner Island Unit 3 933 2,913 0.78 18,411,970 York Solar Turbines, Inc. Turbine 1 031 33 0.19 355,420 York Solar Turbines, Inc. Turbine 2 032 33 0.19 355,248 York Solar Turbines, Inc. Turbine 3 033 33 0.19 357,626 York Solar Turbines, Inc. Turbine 4 034 33 0.19 360,280 York Solar Turbines, Inc. Turbine 5 035 33 0.19 357,488 York Solar Turbines, Inc. Turbine 6 036 32 0.19 351,077
[Pa.B. Doc. No. 97-1776. Filed for public inspection October 31, 1997, 9:00 a.m.]
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