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   (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

CombustionPointBaseline NOxBaseline
CountyFacilitySource NameIDAllowancelb/MMBtuMMBtu
AdamsMet Edison Hamilton03140.5918,716
AdamsMet Edison Ortanna03130.5913,130
AdamsMetropolitan Edison CompanyG. E. N Frame Turbine #1031170.4589,908
AdamsMetropolitan Edison CompanyG. E. N Frame Turbine #203260.4529,243
AdamsMetropolitan Edison CompanyG. E. N Frame Turbine #3033140.4574,249
AlleghenyDuquesne Light Company, CheswickBoiler0012,1140.6115,025,580
ArmstrongPenelec--KeystoneBoiler No. 10314,3420.8025,149,236
ArmstrongPenelec--KeystoneBoiler No. 20323,4460.7922,657,898
ArmstrongWest Penn Power Co.Foster Wheeler0311,1400.955,355,101
ArmstrongWest Penn Power Co.Foster Wheeler0321,0661.025,007,467
BeaverAES Beaver Valley Partners, Inc.Babcock and Wilcox0323020.831,747,462
BeaverAES Beaver Valley Partners, Inc.Babcock and Wilcox0332470.831,431,342
BeaverAES Beaver Valley Partners, Inc.Babcock and Wilcox0342860.831,655,847
BeaverAES Beaver Valley Partners, Inc.Babcock and Wilcox0351540.81683,951
BeaverPenn Power Co.--Bruce MansfieldBoiler Unit 10312,9930.9016,618,929
BeaverPenn Power Co.--Bruce MansfieldFoster Wheeler Unit No. 20323,8660.9021,464,786
BeaverPenn Power Co.--Bruce MansfieldFoster Wheeler Unit 30333,5040.7019,455,843
BeaverZinc Corporation Of AmericaCoal Boiler 10342410.801,380,627
BeaverZinc Corporation Of AmericaCoal Boiler 20352040.801,168,776
BerksMetropolitan Edison Co.--TitusUnit 10312020.651,836,587
BerksMetropolitan Edison Co.--TitusUnit 20321860.681,632,072
BerksMetropolitan Edison Co.--TitusUnit 30332010.661,805,003
BerksMetropolitan Edison Co.--TitusNo. 4 Combustion Turbine03420.4420,010
BerksMetropolitan Edison Co.--TitusNo. 5 Combustion Turbine03520.4415,484
BlairPenelec--WilliamsburgNo. 11 Boiler--Rily031380.87200,874
BucksPECO Energy--CroydenCroyden--Turbine #11031110.7042,451
BucksPECO Energy--CroydenCroyden--Turbine #1203270.7026,382
BucksPECO Energy--CroydenCroyden--Turbine #21033440.70175,640
BucksPECO Energy--CroydenCroyden--Turbine #22034200.7081,649
BucksPECO Energy--CroydenCroyden--Turbine #31035110.7042,534
BucksPECO Energy--CroydenCroyden--Turbine #32036140.7054,905
BucksPECO Energy--CroydenCroyden--Turbine #4103780.7030,191
BucksPECO Energy--CroydenCroyden--Turbine #42038380.70152,094
BucksUnited States Steel Corp., ThePower House Boiler
No. 3
043630.26655,625
BucksUnited States Steel Corp., ThePower House Boiler
No. 4
044140.27147,330
BucksUnited States Steel Corp., ThePower House Boiler
No. 5
045730.26756,980
BucksUnited States Steel Corp., ThePower House Boiler
No. 6
046840.26871,810
CambriaCambria CoGen CompanyA Boiler0312000.242,003,177
CambriaCambria CoGen CompanyB Boiler0322120.232,116,233
CambriaColver Power Project4110.204,112,640
CambriaEbensburg Power CompanyCFB Boiler2060.082,058,858
CarbonPanther Creek Energy FacilityBoiler 11190.121,592,491
CarbonPanther Creek Energy FacilityBoiler 21170.121,555,673
ChesterPECO Energy--CrombyBoiler No 10312470.821,660,770
ChesterPECO Energy--CrombyBoiler No 20321870.281,257,120
ClarionPiney Creek ProjectCFB Boiler1220.181,217,989
ClearfieldPenelec--ShawvilleBabcock Wilcox Boiler0319811.223,737,976
ClearfieldPenelec--ShawvilleBabcock Wilcox Boiler0329471.213,624,416
ClearfieldPenelec--ShawvilleCombustion Engineering0338520.864,558,942
ClearfieldPenelec-ShawvilleCombustion Engineering0346930.873,697,889
ClintonInternational Paper Co.1 Riley Stoker Vo-Sp0331450.551,220,703
ClintonInternational Paper Co.2 Riley Stoker Vo-Sp0341450.551,218,878
ClintonPP&L--Lock HanveCT 10.4914,818
ColumbiaPenelec--Benton00212.332,661
ColumbiaPenelec--Benton00312.932,330
CumberlandMetropolitan Edison CompanyG.E. N Frame Turbine03190.4546,665
CumberlandMetropolitan Edison CompanyG.E. N Frame Turbine #1032110.4555,480
CumberlandPP&L-West ShoreCT 130.4912,402
CumberlandPP&L-West ShoreCT 230.4913,231
DauphinPP&L-HarrisburgCT 140.4916,282
DauphinPP&L-HarrisburgCT 240.4915,884
DauphinPP&L-HarrisburgCT 340.4915,446
DauphinPP&L-HarrisburgCT 440.4915,386
DelawareBP Oil, Inc.7 Boiler032350.37331,917
DelawareBP Oil, Inc.8 Boiler033560.48535,337
DelawareBP Oil, Inc.0381870.551,789,455
DelawarePECO Energy-EddystoneNo. 1 Boiler0316630.545,571,014
DelawarePECO Energy-EddystoneNo. 2 Boiler0324320.553,629,294
DelawarePECO Energy-EddystoneNo. 3 Boiler0332570.282,153,713
DelawarePECO Energy-EddystoneNo. 10 Gas Turbine03710.499,464
DelawarePECO Energy-EddystoneNo. 20 Gas Turbine03810.487,560
DelawarePECO Energy-EddystoneNo. 30 Gas Turbine03920.4819,502
DelawarePECO Energy-EddystoneNo. 40 Gas Turbine04010.499,450
DelawarePECO Energy-EddystoneNo. 4 Boiler0412490.282,089,539
DelawareKimberly-ClarkBoiler No. 9034120.52264,600
DelawareKimberly-Clark10 Culm Cogen. Fbc Plant035850.081,602,169
DelawareSun Refining & Marketing089860.091,211,002
DelawareSun Refining & Marketing0901450.084,927,837
ElkPenntech Papers, Inc.B&W Model Pm106 Boiler #603800.000
ElkPenntech Papers, Inc.B&W #81 Boiler0401030.83570,989
ElkPenntech Papers, Inc.B&W #82 Boiler0411090.83603,471
ErieGeneral Electric Co.B&W Boiler No. 2032261.01587,180
ErieInternational Paper CompanyCoal Fired Boiler No. 21037680.58321,958
ErieNorcon Power PartnersTurbine 1001500.071,483,488
ErieNorcon Power PartnersTurbine 2002500.071,483,488
EriePenelec-Front StreetErie City Iron Works No. 703150.9238,964
EriePenelec--Front StreetErie City Iron Works No. 803250.9039,881
EriePenelec--Front StreetComb. Eng. Boiler
No. 9
0331340.571,033,388
EriePenelec--Front StreetComb. Eng. Boiler
No. 10
0341340.571,033,528
GreeneWest Penn Power--Hatfield's FerryBabcock & Wilcox0313,9781.0415,502,912
GreeneWest Penn Power--Hatfield's FerryBabcock & Wilcox0323,7031.0414,429,251
GreeneWest Penn Power--Hatfield's FerryBabcock & Wilcox0332,1601.048,416,290
IndianaPenelec--ConemaughBoiler No. 10313,2950.7620,130,686
IndianaPenelec--ConemaughBoiler No. 20324,1970.7625,543,024
IndianaPenelec--Homer CityBoiler No. 1-Foster Whelr0313,1671.2011,325,278
IndianaPenelec--Homer CityBoiler No. 2-Foster Whelr0323,9871.2015,382,211
IndianaPenelec--Homer CityBoiler No. 3-B&W0332,9310.6221,951,003
IndianaPenelec--SewardBoiler No. 12 (B&W)0321450.84849,307
IndianaPenelec--SewardBoiler No. 14 (B&W)0331460.83809,011
IndianaPenelec--SewardBoiler No. 15 (Comb. Eng.)9316730.754,155,275
LackawannaArchbald Power CorporationCogen820.05818,013
LancasterPP&L--HoltwoodUnit 17 Foster Wheeler9348071.203,116,786
LawrencePenn Power Co.--New CastleFoster Wheeler0311080.91553,994
LawrencePenn Power Co.--New CastleB.W. Boiler032970.91498,559
LawrencePenn Power Co.--New CastleBabcock And Wilcox0331850.91947,292
LawrencePenn Power Co.--New CastleBabcock And Wilcox0343390.911,737,996
LawrencePenn Power Co.--New CastleBabcock And Wilcox0356220.913,183,091
LehighPP&L--AllentownCT 120.4910,329
LehighPP&L--AllentownCT 230.4913,752
LehighPP&L--AllentownCT 330.4914,215
LehighPP&L--AllentownCT 430.4912,745
LycomingPP&L--WilliamsportCT 130.4914,633
LycomingPP&L--WilliamsportCT 230.4914,083
LuzerneContinental Energy AssociatesTurbine2690.132,687,577
LuzerneContinental Energy AssociatesHRSG1290.201,288,248
LuzerneUGI Corp.--Hunlock PowerFoster Wheeler0313750.951,821,127
LuzernePP&L--JenkinsCT 130.4912,942
LuzernePP&L--JenkinsCT 220.496,885
LuzernePP&L--HarwoodCT 130.4914,194
LuzernePP&L--HarwoodCT 230.4914,049
MonroeMet Edison Shawnee03130.5915,285
MontgomeryMerck Sharp & DohmeCogen II Gas Turbine039790.161,028,875
MontourPP&L--MontourMontour No. 10313,5760.8517,029,683
MontourPP&L--MontourMontour No. 20324,7061.0722,409,322
MontourPP&L--MontourAux. Start-Up Boiler No. 103390.1744,436
MontourPP&L--MontourAux. Start-Up Boiler No. 203470.1734,076
NorthamptonBethlehem Steel Corp.Boiler 1 Boiler House 2041900.23Confidential
NorthamptonBethlehem Steel Corp.Boiler 2 Boiler House 2042900.23Confidential
NorthamptonBethlehem Steel Corp.Boiler 3 Boiler House 2067910.23Confidential
NorthamptonMet Edison Co.--PortlandUnit No. 10314630.593,593,611
NorthamptonMet Edison Co.--PortlandUnit No. 20326580.664,578,297
NorthamptonMet Edison Co.--PortlandCombustion Turbine No. 303310.539,795
NorthamptonMet Edison Co.--PortlandCombustion Turbine No. 403460.5340,931
NorthamptonNorthampton Generating CompanyBoiler0012100.104,208,112
NorthamptonPP&L--Martins CreekFoster-Wheeler Unit No. 10314931.013,329,831
NorthamptonPP&L--Martins CreekFoster-Wheeler Unit No. 20324610.913,112,136
NorthamptonPP&L--Martins CreekC-E Unit No. 30338370.515,652,924
NorthamptonPP&L--Martins CreekC-E Unit No. 40347410.515,003,663
NorthamptonPP&L--Martins CreekNo. 4b Auxiliary Boiler03600.172,394
NorthamptonPP&L--Martins CreekCombustion Turbine No. 103730.02206,640
NorthamptonPP&L--Martins CreekCombustion Turbine No. 203830.02206,640
NorthamptonPP&L--Martins CreekCombustion Turbine No. 303930.02206,640
NorthamptonPP&L--Martins CreekCombustion Turbine No. 404030.02206,640
NorthumberlandFoster Wheeler Mt. Carmel CogenCogen0311960.101,814,911
PhiladelphiaPECO Energy037280.60117,455
PhiladelphiaPECO Energy038370.60156,375
PhiladelphiaPECO Energy--Delware0131110.45918,037
PhiladelphiaPECO Energy--Delware0141290.451,066,091
PhiladelphiaPECO Energy--Delware01510.677,089
PhiladelphiaPECO Energy--Delaware01610.679,452
PhiladelphiaPECO Energy--Delaware01710.6711,259
PhiladelphiaPECO Energy--Delaware01820.6715,012
PhiladelphiaPECO Energy--Schuylkill0031740.281,459,923
PhiladelphiaPECO Energy--Schuylkill00710.679,285
PhiladelphiaPECO Energy--Schuylkill00800.671,946
PhiladelphiaTrigen Energy Co--Sansom001310.45318,459
PhiladelphiaTrigen Energy Co--Sansom002270.45280,748
PhiladelphiaTrigen Energy Co--Sansom003120.45126,824
PhiladelphiaTrigen Energy Co--Sansom004150.45155,123
PhiladelphiaTrigen Energy Co--Schuylkill00100.28511,191
PhiladelphiaTrigen Energy Co--Schuylkill00200.28228,162
PhiladelphiaTrigen Energy Co--Schuylkill00500.45248,138
PhiladelphiaU.S. Naval Base09810.1414,294
PhiladelphiaU.S. Naval Base09910.141,960
PhiladelphiaGrays Ferry ProjectCombustion Turbine126
PhiladelphiaGrays Ferry ProjectHeat Recovery Steam Gen21
PhiladelphiaGrays Ferry ProjectBoiler 2580
SchuylkillGilberton Power CompanyBoiler3350.173,352,372
SchuylkillNortheastern Power CompanyCFB Boiler2020.062,022,148
SchuylkillNortheastern Power CompanyAux Boiler00.271,396
SchuylkillSchuylkill Energy ResourcesBoiler0313500.204,349,117
SchuylkillWestwood Energy PropertiesBoiler1350.171,351,408
SchuylkillWheelabrator Frackville Energy CoBoiler2050.142,046,694
SchuylkillPP&L--FishbackCT 120.498,272
SchuylkillPP&L--FishbackCT 220.497,217
SnyderPP&L--SunburySunbury SES Unit 1a0312950.981,455,641
SnyderPP&L--SunburySunbury SES Unit 1b0322950.981,455,641
SnyderPP&L--SunburySunbury SES Unit 2a0332950.831,455,641
SnyderPP&L--SunburySunbury SES Boiler 2b0342950.831,455,641
SnyderPP&L--SunburySunbury SES Unit
No. 3
0356810.933,363,299
SnyderPP&L--SunburySunbury SES Unit
No. 4
0368240.994,070,181
SnyderPP&L--SunburyDiesel Generator 103703.39709
SnyderPP&L--SunburyDiesel Generator 203803.23806
SnyderPP&L--SunburyCombustion Turbine 103930.4914,581
SnyderPP&L--SunburyCombustion Turbine 204030.4914,581
TiogaPenelec--Tioga03130.4830,267
VenangoScrubgrass Power PlantUnit 10311820.141,816,817
VenangoScrubgrass Power PlantUnit 20321790.151,790,997
WarrenPenelec--WarrenBoiler No. 1031760.62569,825
WarrenPenelec--WarrenBoiler No. 2032730.64546,534
WarrenPenelec--WarrenBoiler No. 3033770.61572,007
WarrenPenelec--WarrenBoiler No. 4034800.61596,377
WarrenPenelec--Warren001100.6977,943
WashingtonDuquesne Light Co.--ElramaNo. 1 Boiler0313340.871,116,538
WashingtonDuquesne Light Co.--ElramaNo. 2 Boiler0323330.901,114,175
WashingtonDuquesne Light Co.--ElramaNo. 3 Boiler0334460.871,490,615
WashingtonDuquesne Light Co.--ElramaNo. 4 Boiler0341,0160.893,398,150
WashingtonMcGraw--Edison Co.Foster-Wheeler03200.000
WashingtonWashington Power Co.Boiler 11550.152,068,438
WashingtonWashington Power Co.Boiler 21550.152,068,438
WashingtonWest Penn Power Co.--MitchellCombustion Eng Coal Unit0349310.725,968,482
WaynePenelec--Wayne031110.8462,736
WyomingProcter & Gamble Paper Products Co.Westinghouse 251B100352460.681,654,800
YorkGlatfelter, P.H. Co.Number 4 Power Boiler0341270.80978,985
YorkGlatfelter, P.H. Co.Number 1 Power Boiler035850.80653,626
YorkGlatfelter, P.H. Co.Number 5 Power Boiler0362320.291,780,350
YorkMet Edison Tolna03140.5920,492
YorkMet Edison Tolna03240.5919,306
YorkPP&L--Brunner IslandBrunner Island 20321,4740.699,319,539
YorkPP&L--Brunner IslandBrunner Island Unit 19311,2940.678,178,891
YorkPP&L--Brunner IslandBrunner Island Unit 39332,9130.7818,411,970
YorkSolar Turbines, Inc.Turbine 1031330.19355,420
YorkSolar Turbines, Inc.Turbine 2032330.19355,248
YorkSolar Turbines, Inc.Turbine 3033330.19357,626
YorkSolar Turbines, Inc.Turbine 4034330.19360,280
YorkSolar Turbines, Inc.Turbine 5035330.19357,488
YorkSolar Turbines, Inc.Turbine 6036320.19351,077
[Pa.B. Doc. No. 97-1776. Filed for public inspection October 31, 1997, 9:00 a.m.]



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