### COMMONWEALTH OF PENNSYLVANIA Department of Environmental Protection

April 15 , 201 3 814/332

- 6940 Fax: 814/332

- 6117
SUBJECT: Review of Application for Plan Approval

Hickory Run Energy, LLC North Beaver Township , Lawrence County
TO: File AQ/Fac/Permi t/ 37

- 3 37 A

APS ID: 7 9 24 06 Auth ID: 9 4 4870
FROM: Hubert Thomas Flaherty

New Source Review Air Quality Program Northwest Regional Office
THROUGH: Edward Orris , P.E. John F. Guth

Environmental Engineer Manager Regional Program Manager Air Quali ty Program Air Quality Program Northwest Regional Office Northwest Regional Office This application is for the construction of a natural gas

- fired combined

- cycle electric generation facility that is designed to generate up to 900 MW nominal, using 2 combustion turbine generators and 2 heat recovery steam generators with duct burners that will provide steam to drive a single steam turbine generator. Each steam generator will be equipped with a duct burner which may be utilized at time of peak power de mands to supplement power output. The source is subject to PSD /NSR requirements. Continuous Assurance Monitoring (CAM) will also apply. This will be a Title V facility. However, case by case MACT will not apply since the facility will be non

- major for HAP. Application Completeness: The application was administratively complete as received on October 17 , 20 1 2 , with the Completeness Letter being sent on October 17 , 201 2 . Receipt of the application was published in the PA Bulletin on Novemb er 3 , 20 1 2

. The Department has also determined the application is “complete” pursuant to the Prevention of Significant Deterioration regulations (Subchapter D of Chapter 127 of the Pennsylvania Code (25 Pa. Code 127.81

- 83) which incorporates by reference 40 CFR 52.21) on Nov ember 1 3 , 201 2

. The completeness letter was based on a complete application subject to PSD regulations must, at a minimum, contain the following information:
1. A project overview and description 

# DRAFTPA Review Memo 37

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###  The GIF contains the name, mailing address, email addr ess, and telephone number of the applicant and the designated contact for the project. The application was signed by a responsible official. Section 2 of the application contains the project location with Lat/Long coordinates; the current use of the proj ect site was submitted as part of an email on November 6, 2012. Section 3 of the application discusses location of the source in relation to Class I areas. The application contains the purpose of the project; the SIC code (4911) was submitted as part of an email on November 6, 2012, a detailed description of all processes, process equipment, emission control systems, and includes drawings that show the design and plant layout showing buildings and property lines. The application includes anticipated mile stones which include the expected commencement date of construction of January 2014, expected completion date of construction of June 2016, and anticipated date of start

- up of June 2016. 2. A PSD applicability section
 The application contains emission estimat es for all regulated NSR pollutants and how they were derived. The application also contains information with regards to how the area is designated for PSD/NSR purposes and what pollutants are major. 3. A “Top

- down” BACT analysis for each regulated NSR pollu tant subject to major PSD review
 The application contains a “top down” BACT analysis. 4. An air quality analysis for the NAAQS and PSD increments, as applicable for each regulated NSR pollutant subject to major PSD review
 The application contains a Class II a ir quality analysis. Central Office (Sean Nolan) has determined that the modeling is administratively complete and the analysis contains the necessary modeling components to initiate a technical review in an email dated October 16, 2012. 5. An analysis of Cl ass I areas impacts
 Not applicable because no Class I areas within 100 km. 6. An analysis of the new source or project’s impacts on visibility, soils, vegetation, and the impact on associated growth for the project or new source
 Included in Section B of the a pplication as part of the modeling. 7. Compliance with other EPA air regulations [such as NSPS]
 Section 3 of the application contains other applicable EPA requirements. 8. Compliance with non

- Clean Air Act requirements [such as the Endangered Species Act]
 The ap plication didn’t contain non

- CAA requirements; but based on the submitted GIF, the facility will submit applications to the Department for coordination with other Departmental Programs resulting from the GIF. A PNDI Project Environmental review was run on April 13, 2012, and indicated a potential impact to a federally listed species. A response letter, from USFWS, dated June 12, 2012, was sent to the applicant concerning the potential impact. The NWRO AQ received a copy of this information on October 16, 2012. 9. Clear identification of confidential business information claims, if needed
 The application does not show any materials as being confidential.PA Review Memo 37

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### From the Permit Manual, in order to comply with the 40 CFR 52.21, a complete application subject to PSD r egulations must, at a minimum, contain the following information:
1. Description and design specifications for the source and control devices and predicted emission data.
 See 1, 2, & 3 from above. 2. Best available control technology (BACT) documentation.
 See 3 from above. 3. Ambient impact analysis (modeling).
 See 4 from above. 4. Monitoring data unless modeling shows de minimis (reference 40 CFR 52.21(i)(8)(i)) impacts.
 See 4 from above. 5. Other information determined to be necessary for the technical review by the re view personnel.
 The application contains material requested in pre

- application meeting with regards to Pennsylvania Historical & Museum Commission (PHMC) letter and PNDI letter. Also on October 16, 2012, the NWRO received a copy of the notification letter and cultural resource notice sent to the PHMC on July 24, 2012. PHMC required a Phase 1 archaeological survey in a letter dated August 14, 2012. Public Meeting /Hearing : There was a public hearing held on April 3 , 20 1 3 , at North Beaver Township VFD in N orth Beaver Township ( 969 Mount Jackson R o a d , New Castle, P A )

. Th e hearing will r u n from 6 : 0 0 PM to 9:00 PM

. This hearing was conducted as part of the public comment period for the draft plan approval. The Hearing minutes are in the file along with all public comments received during the public comment period. The comments received during the meeting, hearing, and public comment period are summarized and responded to in the Public Comment and Response Document. EPA: The United States Environmental Pro tection Agency (EPA) received the Department’s draft plan approval on March 4 , 201 3 , and was afforded the required 45 days for comment (until A pril 1 8 , 201 3 ). EPA’s submitted comments on the proposed Plan Approval on April 5 , 201 3 , and are addressed withi n a separate EPA Comment and Response Document. Other Agencies: The proposed project is located within 300 km of the Otter Creek Wilderness and the Dolly Sods Wilderness, both areas administered by the US Forest Service (USFS)

. It is also within 300 kmPA Review Memo 37

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### of Shenandoah National Park administered by the National Park Service (NPS)

. The proposed facility is over 300 km from the James River Face Wilderness (USFS) and Brigantine National Wildlife Refuge administered by the Fish and Wildlife Service (FWS). The facility sent an email to the USFS, NPS, & FWS on September 19, 2012, with regards to Class I Air Quality Related Values ( AQRV ) analysis. The FWS stated in an email dated September 24, 2012, that they are not requesting a Class I (AQRV) analysis for Brig antine National Wildlife Refuge

. The NPS stated in an email dated November 1, 2012, that they are not requesting a Class I (AQRV) analysis for Shenandoah National Park. T he USFS stated in an email dated January 3, 201 3 , that they are no t requesting a Cla ss I ( AQRV) analysis for Otter Creek Wilderness, Dolly Sods Wilderness , and James River Face Wilderness . BACKGROUND Hickory R un Energy ( H RE) project is a natural gas

- fired combined

- cycle (NGCC) electric generation facility located in North Beaver Townshi p , Lawrence County. The project is designed to generate up to 9 00 megawatts (MW) nominal , and will use consist of two (2) combustion turbine generators (CTG) and two (2) heat recovery steam generators (HRSG) that will provide steam to drive a single steam turbine generator (STG). The combined cycle unit (CCU) is a CTG and a HRSG. Each HRSG will be equipped with a natural gas

- fired duct burner which may be utilized at time of peak power demand to supplement power output by raising the heat content of the exhaust gas and thereby increasing the amount of steam generated . The proposed project will also include a natural gas

- fired auxiliary boiler; a diesel engine

- driven emergency generator; a diesel engine

- driven firewater pump; a multi

- cell evaporative cool ing tower; and associated emission control system, tanks, and piping/ductwork. The facility is proposing four (4) different supply options and will pick one option prior to construction. The CTG will be one of the following:
 General Electric 7FA (GE 7FA) (2,272 mmbtu/hr & 500 mmbtu/hr duct burner)
 Siemens SGT6

- 5000F (Siemens F) (2,352 mmbtu/hr & 500 mmbtu/hr duct burner)
 Mitsubishi 501G (Mitsubishi G) (2,954 mmbtu/hr & 500 mmbtu/hr duct burner)
 Siemens SGT6

- 8000H (Siemens H) (2,942 mmbtu/hr & 500 mmbtu/hr duct burner) PROCESS DESCRIPTION & THROUGHPUTS C CUs (Source 031 & 032) : Combustion air will be drawn in and compressed and fed to the CTG combustion sections. Natural gas will be injected into the compressed air and ignited. The hot combustion gases w ill expand through the turbine sections of the CTG, causing the turbine to rotate and drive the electric generators and CTG compressors. The hot gases exit the CTG turbine sections and enter the HRSGs, where they will transfer heat into various steam supe rheater, evaporator and feedwater heating elements prior to exiting the stack. Steam produced in the HRSGs will be delivered to the steam turbine generator for the production of additional electricity. Steam exiting the steam turbine generator will be co ndensed and heat rejection accomplished via anPA Review Memo 37

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### evaporative (wet) cooling tower system. Natural gas fired duct burners will be installed in the HRSGs , providing the capability to increase steam generation; providing greater operating flexibility; and provi ding improved steam temperature control. The duct burners will burn only natural gas. For this plan approval, startup is defined as the period beginning with ignition in the combustion turbine and lasting until either (1) the combustion process, air poll ution control equipment, and associated control systems have attained normal operating conditions for two consecutive 15

- minute averaging periods, or (2) five hours after ignition, whichever occurs first. Shutdown is defined as the period beginning with t he lowering of unit load below 60% with the intent of ceasing operation of the unit and concluding with the cessation of combustion in the turbine, limited to a maximum of one hour in duration. CCUs Controls (C031A & C031B) & (C032A & C032B) Each unit wil l be equipped with a selective catalytic reduction (SCR) system. The exact make and model will be determined at a later time. The system will be designed to handle between 1,200,000 and 1,500,000 acfm of gases. The expected operating range will be 800F to 1,100F. T he reducing agent will be ammonia (19% aqueous ammonia) at a rate of 100 to 200 gallons per hour. The system will be designed to minimize ammonia slip to 5 ppm or less. The system will monitor continuously the NO x 

### and ammonia emissions and m ake adjustments to maintain NO x 

### emissions below 2 ppm. The anticipated removal efficiency is ~ 92% (NO x 

### inlet concentration of 25 ppm to an outlet concentration of 2 ppm). Each unit will be equipped with an oxidation catalyst. The exact make and model w ill be determined at a later time. The system will be designed to handle between 1,200,000 and 1,500,000 acfm of gases at 180F and 10% moisture. The primary purpose of the oxidation catalyst will be CO reduction (less than 2 ppm) . However, it will also provide some control for VOC ( less than 1.5 ppm )

. Other sources at the facility will include : Auxiliary Boiler (Source 033) The boiler will be natural gas

- fired with a nominal heat input of 40 mmbtu/hr. The boiler will be used to provide high

- temperatur e steam during periods when the CCGU are offline in order to accommodate more rapid combined cycle startup following extended shutdowns. The boiler will typically not operate once the combined cycle units achieve steady

- state operations. However, the boi ler must be able to operate during periods when the CCU are not in steady

- state operation. The b oiler is subject to the requirements of 40 CFR 60 Subpart Dc ( Standards of Performance for Small Industrial

- Commercial

- Institutional Steam Generating Units ). It is not subject to 40 CFR 63 Subpart JJJJJJ (National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers Area Sources) because it meets the definition of gas

- fired boiler. Emergency Diesel Generator (So urce 101)PA Review Memo 37

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### The generator is rated at 1 , 135 bhp (750 kW). The generator will be used to safely shutdown the plant to prevent damage to critical auxiliary equipment in the event there is a loss of power. The generator will use ultra

- low sulfur diesel (ULSD) fuel only. Operation of the generator will be for emergency purposes a nd periodic reliability testing with an anticipated 100 hours per year of total run time. The generator is subject to the requirements of 40 CFR 60 Subpart IIII ( Standards of Performa nce for Stationary Compression Ignition Internal Combustion Engines) and has a displacement per cylinder of 2.5 liter

. Diesel Engine
- Driven Firewater Pump (Source 102) The firewater pump is rated at 450 bhp. The firewater pump will be used in case of fir e . The pump will use ultra

- low sulfur diesel (ULSD) fuel only. Operation of the pump will be for emergency purposes and periodic reliability testing with an anticipated 100 hours per year of total run time

. The firewater pump is subject to the requireme nts of 40 CFR 60 Subpart IIII ( Standards of Performance for Stationary Compression Ignition Internal Combustion Engines) and has a displacement per cylinder of less than 2.5 liter

. Cooling Tower (Source 103) The multi

- cell mechanical draft cooling tower w ill operate using fans to draw air through a cascade of recirculating water to promote evaporative cooling. The water circulation rate is 175,000 gpm (87,570,000 #/hr) with an associated drift of 0.0005%. The estimated TDS of the water will be 5,000 ppmw

. E missions are estimated to be 2

. 19 #/hr for PM, 0.66 #/hr for PM10, and 0.0039 #/hr for PM2.5

. S torage Tanks (Source 104) ULSD fuel for the emergency generator and the firewater pump will be stored in separate above

ground tanks at the site. These tan ks are less than 20,000 gallons each. The fuel storage tanks are not subject to 40 CFR 60 Subpart Kb (Standards of Performance for Volatile Organic Liquid Storage Vessels for which Construction, Reconstruction, or Modification Commenced after July 23, 198 4) because the tanks are below the 75

- cubic meter (20,000 gallon) applicability threshold in 40 CFR 60.110b(a).

EMISSION SUMMARY The primary source of emissions from this facility will be the Combined Cycle Unit s (CCU)

. Potential emissions, as proposed by the applicant, from both C CU s based on 8,760 hours of operation per year, are summarized below

. Uncontrolled Combined Cycle Units (each) Combustion Unit Mode NO x 

### CO VOC SO 2 

### H 2 

### SO 4 

### PM10/PM2.5

(#/hr) (tpy) (#/hr) (tpy) (#/hr) (tpy) (#/hr) (tpy) (#/hr) (tpy) (#/hr) (tpy) GE 7FA.05 (GE 7FA) Normal Duct 89.12 178.69 16.75 33.59 6.55 13.13 4.76 9.54 0.71 1.43 10.0 20.05PA Review Memo 37

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### Off Normal Duct On 162.63 325.26 106.75 213.49 8.52 17.04 5.8 11.6 0.87 1.74 17.5 35.0 Startup 173.2 43.3 601.4 150.35 247.9 61.98 3.49 0.87 0.52 0.13 9.68 2.42 Shutdown 142.49 17.81 348.3 43.54 137.21 17.15 2.64 0.33 0.4 0.05 11.08 1.38 Total 565.05 440.97 109.29 22.34 3.35 58.85 Siemens SGT6

- 5000F5/DLN (Siemens F) Normal Duct Off 339.51 680.71 16.48 33.04 6.8 13.64 4.92 9.86 0 .74 1.48 10.0 20.05
Normal Duct On 369.66 739.31 98.63 197.27 8.77 17.53 5.96 11.92 0.89 1.79 17.5 35.0 Startup 162.13 40.53 456.25 114.06 149.19 37.3 3.61 0.9 0.54 0.14 10.0 2.5 Shutdown 147.27 18.41 360.0 45.0 141.82 17.73 2.73 0.34 0.41 0.05 11.45 1. 43 Total 1 , 478.96 389.37 86.2 23.02 3.45 58.98 Mitsubushi M501GAC (Mitsubishi G) Normal Duct Off 191.32 383.61 20.4 40.9 8.43 16.91 6.17 12.38 0.93 1.86 12.0 24.06
Normal Duct On 254.68 509.36 122.24 244.48 9.7 19.41 7.22 14.44 1.08 2.17 19.5 39. 1 Startup 39.8 9.95 1059.2 264.8 179.62 44.91 4.28 1.07 0.68 0.17 10.12 2.53 Shutdown 37.6 4.7 562.7 70.34 161.93 20.24 3.01 0.38 0.51 0.06 10.54 1.32 Total 907.62 620.52 101.46 28.26 4.26 67.01 Siemens SGT6

- 8000H/DLN (Siemens H) Normal Duct Off 317.75 637.09 19.82 39.75 8.4 16.84 6.15 12.33 0.92 1.85 11.0 22.06
Normal Duct On 362.52 725.04 122.29 244.57 9.67 19.35 7.19 14.39 1.08 2.16 18.5 37.0 Startup 178.91 44.73 598.87 149.72 178.87 44.72 4.26 1.07 0.68 0.17 10.08 2.52 Shutdown 146.25 18.2 8 408.75 51.09 161.25 20.16 3.0 0.38 0.51 0.06 10.5 1.31 Total 1 , 425.15 485.13 101.06 28.15 4.24 62.89
Maximum Emissions 1 , 478.96 620.52 109.29 28.26 4.26 67.01
Minimum Emissions 565.05 389.37 86.2 22.34 3.35 58.85



### Notes :  Startup hours per unit

– 500 hr/yr
 Shutdown hours per unit

– 250 hr/yr
 Duct firing hours per unit

– 4,000 hr/yr
 Normal operating hours per unit

– 8, 01 0 hr/yr
 Fuel heating value

– 1,020 btu/scf
 Heat input per unit (turbine only)

– 2,954 mmbtu/hr (HHV)
 Hea t input per unit (duct burner only)

– 500 mmbtu/hr (HHV)
 Maximum fuel consumption per unit

– 27,331 mmscf/yrPA Review Memo 37

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### Controlled Combined Cycle Units (each) Combustion Unit Mode NO x 

### CO VOC SO 2 

### H 2 

### SO 4 

### PM10/PM2.5

(#/hr) (tpy) (#/hr) (tpy) (#/hr) (tpy) (#/hr) (tpy) (#/hr) (tpy) (#/hr) (tpy) GE 7FA.05 (GE 7FA) Normal Duct Off 19.76 39.62 12.03 24.12 5.17 10.36 4.76 9.54 0.71 1.43 10.0 20.05
Normal Duct On 23.65 47.3 1 4 .4 28.8 6.19 12.37 5.8 11.6 0.87 1.74 17.5 35.0 Startup 173.2 43.3 601.4 150.35 247.9 61.98 3.49 0.87 0.52 0.13 9.7 2.42 Shutdown 142.49 17.81 348.3 43.54 137.21 17.15 2.64 0.33 0.4 0.05 11.1 1.38 Total s/u s/d 61.11 193.89 79.13 1.2 0.18 3.8 Total 148.03 246.81 10 1

. 86 22.34 3.35 58.85 Siemens SGT6

- 5000F5/DLN (Siemens F) Normal Duct Off 20.53 41.17 12.5 25.06 5.37 10.77 4.92 9.86 0.74 1.48 10.0 20.05
Normal Duct On 24.45 48.9 14.89 29.77 6.39 12.79 5.96 11.92 0.89 1.79 17.5 35.0 Startup 162.13 40.53 456.25 114.06 149.19 37.3 3.61 0.9 0.54 0.14 10.0 2.5 Shutdown 147.27 18.41 360.0 4 5.0 141.82 17.73 2.73 0.34 0.41 0.05 11.5 1.43 Total s/u s/d 58.94 159.06 55.03 1.24 0.19 3.93 Total 149.0 213.9 78.58 23.02 3.45 58.98 Mitsub i shi M501GAC (Mitsubishi G) Normal Duct Off 2 5 .45 51.03 15.5 31.07 6.66 13.35 6.17 12.38 0.93 1.8 6 12.0 24.06
Normal Duct On 29.29 58.58 17.83 35.67 7.66 15.32 7.22 14.44 1.08 2.17 19.5 39.0 Startup 39.8 9.95 1059.2 264.8 179.62 44.91 4.28 1.07 0.68 0.17 10.1 2.53 Shutdown 37.6 4.7 562.7 70.34 161.93 20.24 3.01 0.38 0.51 0.06 10.5 1.32 Total s/u s/d 14.65 335.14 65.15 1.45 0.23 3.85 Total 124.26 401.88 93.81 28.26 4.26 66.91 Siemens SGT6

- 8000H/DLN (Siemens H) Normal Duct Off 25.36 50.84 15.44 30.95 6.63 13.3 6.15 12.33 0.92 1.85 11.0 22.06
Normal Duct On 29.2 58.4 17.78 35.55 7.64 15.27 7.19 14.39 1.08 2.16 18.5 37.0 Startup 178.91 44.73 598.87 149.72 178.87 44.72 4.26 1.07 0.68 0.17 10.1 2.52 Shutdown 146.25 18.28 408.75 51.09 161.25 20.16 3.0 0.38 0.51 0.06 10.5 1.31 Total s/u s/d 63.01 200.81 64.88 1.45 0.23 3.83 Total 172.25 267.32 93.44 28.15 4.24 62.89
Maximum Emissions 172.25 401.88 10 1

. 86 28.26 4.26 66.91
Minimum Emissions 124.26 213.9 78.58 22.34 3.35 58.85PA Review Memo 37

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### Notes:
 Startup hours per unit

– 500 hr/yr
 Shutdown hours per unit

– 250 h r/yr
 Duct firing hours per unit

– 4,000 hr/yr
 Normal operating hours per unit

– 8,0 1 0 hr/yr
 Fuel heating value

– 1,020 btu/scf
 Heat input per unit (turbine only)

– 2,954 mmbtu/hr (HHV)
 Heat input per unit (duct burner only)

– 500 mmbtu/hr (HHV)
 Maximum fue l consumption per unit

– 27,331 mmscf/yr
 For all turbine types, NO x 

### , CO , and VOC emissions for duct on and duct off are based on 2.0 ppmvd , 2.0 ppmvd , and 1.5 ppmvd respectively.
CCU (each) Ammonia Slip

(Normal Duct Off) (#/hr) Ammonia Slip

(Normal Duct O ff) (tpy) Ammonia Slip

(Normal Duct On) (#/hr) Ammonia Slip

(Normal Duct On) (tpy) Total (tpy)

GE 7FA 18.33 43.63 21.95 43.9 8 7

. 5 Siemens F 1 9

. 06 45.37 2 2 .7 2 4 5

. 44 9 0. 8 Mitsubushi G 23.61 56.20 27.19 54.38 11 0

. 6 Siemens H 23.53 56.01 27.11 54.22 1 1 0. 2 Notes: For all turbine types, ammonia slip emissions for duct on and duct off are based on 5.0 ppmvd. For duct off it is based on 4,760 hr/yr and for duct on it is based on 4,000 hr/yr. Auxiliary Boiler Pollutant Emission Factor Units Notes #/hr tpy PM /PM10/PM2.5 0.005 #/mmbtu A 0.2 0.46 NO x 

### 0.011 #/mmbtu A 0.44 1.01 SO 2 

### S/7000*10 4 

### *64/32 #/mmscf B 0.08 0.19 H 2 

### SO 4 

### 0.49 #/mmscf C 0.02 0.04 CO 0.036 #/mmbtu A 1.44 3.31 VOC 0.0015 #/mmbtu A 0.06 0.14 Lead 0.0005 #/mmscf D 0.00002 0.00005 Notes: based on 4,600 hours per year A

– Based on vendor guarantee B

– Emission rate based on mass balance assuming all sulfur (S) converts to sulfur dioxide C

– Emission rate based on sulfur content (S) of the fuel and 15% oxidation rate D

– Emission factor from AP

- 4 2 Table 1.4

- 2 (7/98) Emergency Diesel Generator Pollutant Emission Factor Units Notes #/hr tpy PM/PM10 0.00044 #/kWh A 0.33 0.02 PM2.5 0.00044 #/kWh B 0.33 0.02PA Review Memo 37

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### NO x 

### 0.01 3 #/kWh A 9 .8 9 0. 49 CO 0.0077 #/kWh A 5.79 0.29 VOC 0.09 #/mmbtu C 0.7 0.03 SO 2 

### 0.00809S #/bhp

- hr D 0.01 0.00 069 H 2 

### SO 4 

### 0.0000024 #/bhp

- hr E 0.0028 0.00014 Notes: based on 100 hours per year A

– Emission factor reflects NSPS Subpart IIII limit B

– PM2.5 assumed to equal PM10 C

– Based on vendor guarantee D

– Emission factor from AP

- 4 2 Table 3.4

- 2 (10/96) where (S) is sulfur content E

- Emission rate based on sulfur content (S) of the fuel and 15% oxidation rate Emergency Diesel Firewater Pump Pollutant Emission Factor Units Notes #/hr tpy PM/PM10 0.00033 #/bhp

- hr A 0.15 0.01 PM2.5 0.00033 B 0.15 0.01 NO x 

### 0.00 41 A 1 .8 6 0. 09 CO 0.0057 A 2.58 0.13 VOC 0.00247 C 1.11 0.06 SO 2 

### 0.00809S C 0.0055 0.00027 H 2 

### SO 4 

### 0.0000026 D 0.0012 0.000058 Notes: based on 100 hours per year A

– Emission factor reflects NSPS Subpart IIII limit B

– PM2.5 assumed to equal PM10 C

– Emission factor from AP

- 42 Table 3.3

- 1 (10/96) where (S) is sulfur content D

- Emission rate based on sulfur content (S) of the fuel and 15% oxidation rate Cooling Tower Unit Water Circulation Rate Drift TDS (ppmw) TDS Spe cific Gravity gal/min #/hr Cooling Tower 175,000 87,570,000 0.0005 % 5,000 2.2 Note: TDS specific gravity corresponding to NaCl
Unit PM PM10 PM2.5

#/hr tpy #/hr tpy #/hr tpy Cooling Tower 2.19 9.59 0.66 2.87 0.0039 0.017 Note: PM emissions were calculated by water circulation rate (#/hr) times drift times TDS and dividing that by one million. PM10 is approximately 30% of total PM and PM2.5 is approximately 0.18% of total PM based on methodology and EPRI droplet diameter and % mass smaller values from Reisman, J. and Frisbie, G., “Calculating Realistic PM10 Emissions from Cooling Towers.”PA Review Memo 37

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### Greenhouse Gas Emissions
Emission Unit Pollutant Emission Factor (kg/mmbtu) GHG

Emissions (tpy) Global

Warming Potential Equivalent Emissions

(tons CO 2 ( e ) 

### /yr)
GE7FA (each) (2,276 mmbtu/hr) (21,937,760 mmbtu/yr) CO 2 

### 53.02 1,446,505 1 1,446,505 CH 4 

### 0.001 27.3 21 573 N 2 

### O 0.0001 2.8 310 846 Total 1, 447 , 924 Emission Unit Pollutant Emission Factor (kg/mmbtu) GHG

Emissions (tpy) Global

Warming Potential Equivale nt Emissions

(tons CO 2 ( e ) 

### /yr)
Siemens F (each) (2,3 52 mmbtu/hr) (22, 6 0 3 , 52 0 mmbtu/yr) CO 2 

### 53.02 1,4 90 ,4 03 1 1,4 90 ,4 03 CH 4 

### 0.001 28. 2 21 591 N 2 

### O 0.0001 2. 9 310 8 72 Total 1, 4 91 , 866 Emission Unit Pollutant Emission Factor (kg/mmbtu) GHG

Emissions (tpy) Global

Warming Potential Equivalent Emissions

(tons CO 2 ( e ) 

### /yr)
Mitsubishi G (each) (2,954 mmbtu/hr) (27,877,040 mmbtu/yr) CO 2 

### 53.02 1,83 8 , 121 1 1,838,121 CH 4 

### 0.001 34.7 21 729 N 2 

### O 0.0001 3.5 310 1075 Total 1,839, 925 Emission Unit Pollutant Emission Factor (kg/mmbtu) GHG

Emissions (tpy) Global

Warming Potential Equivalent Emissions

(tons CO 2 ( e ) 

### /yr)
Siemens H (each) (2,942 mmbtu/hr) (27,771,920 mmbtu/yr) CO 2 

### 53.02 1,831,190 1 1,831,190 CH 4 

### 0.001 34.6 21 726 N 2 

### O 0.0001 3.5 310 1,071 Total 1,83 2 , 9 87 Note: Emission factors based on Tables C

- 1 and C

- 2 of 40 CFR 98 and Global warming potentials based on Table A

- 1 of 40 CFR 98 . Total heat input is based on 8,760 hr/yr and operating duct burner for 4,000 hr/yr.
Emission Unit Pollutant Emission Factor (kg/mmbtu) GHG

Emissions (tpy) Global

Warming Potential Equivalent Emissions

(tons CO 2 ( e ) 

### /yr) Auxiliary Boiler CO 2 

### 53.02 12,130 1 12 , 130

CH 4 

### 0.001 0.23 21 4.8 N 2 

### O 0.0001 0.023 310 7.1 Total 13,696PA Review Memo 37

- 3 37 A PSD 12 April 15 , 201 3 DRAFT 

### Note: Emission factors based on Tables C

- 1 and C

- 2 of 40 CFR 98 and Global warming potentials based on Table A

- 1 of 40 CFR 98
Emission Unit Pollutant Emission Factor (kg/mmbtu) GHG

Emissions (tpy) Global

Warming Potential Equivalent Emissions

(tons CO 2 ( e ) 

### /yr) Emergency Generator CO 2 

### 73.96 71.1 1 71.1

C H 4 

### 0.003 0.0029 21 0.061 N 2 

### O 0.0006 0.00058 310 0.18 Total 80.5 Note: Emission factors based on Tables C

- 1 and C

- 2 of 40 CFR 98 and Global warming potentials based on Table A

- 1 of 40 CFR 98
Emission Unit Pollutant Emission Factor (kg/mmbtu) GHG

Emissi ons (tpy) Global

Warming Potential Equivalent Emissions

(tons CO 2 ( e ) 

### /yr) Firewater Pump CO 2 

### 73.96 29.9 1 29.9

CH 4 

### 0.003 0.0012 21 0.025 N 2 

### O 0.0006 0.00024 310 0.075 Total 33.8 Note: Emission factors based on Tables C

- 1 and C

- 2 of 40 CFR 98 and Globa l warming potentials based on Table A

- 1 of 40 CFR 98
F acility

- wide Potential E missions (based on worst case turbine selection scenario)
Pollutant 2 CCU (tpy) Auxiliary Boiler (tpy) Emergency

Generator (tpy) Emergency Fire

Pump (tpy) Cooling

Tower (tpy) T otal Facility

PTE (tpy) CO 803.8 3.31 0.29 0.13 807.53 GHG (CO 2(e) 

### ) 3 , 679 ,8 50 13,696 80.5 33.8 3 ,6 9 3, 660 .3 H 2 

### SO 4 

### 8.52 0.04 0.0001 0.0001 8.57 Lead 0.001 4.5E

- 05 0.001 NO 2 

### 344.5 1.01 0. 49 0. 09 346.0 9 PM2.5 133.9 0.46 0.02 0.01 0.02 134.41 PM10 133.9 0.46 0.02 0.01 2.87 137.26 PM 133.9 0.46 0.02 0.01 9.59 143.98 SO 2 

### 56.5 0.19 0.001 56.70 VOC 2 03.72 0.14 0.03 0.06 203.95 Ammonia 2 21

. 2 2 21

. 2 HAPs 15.0 0.17 6.6E

- 04 6.4E

- 04 15. 3 

### Note: Formaldehyde is the largest HAP PTE of 6.88 tpyPA Review Memo 37

- 3 37 A PSD 13 April 15 , 201 3 DRAFT 

### R EGULATORY ANALYSIS The proposed facilit y is subject to New Source Review which includes Prevention of Significa n t Deterioration (PSD) regulations including a demonstration of compliance with the National Ambient Air Quality Standards (NAAQS) and the non

- at tainment provisions developed in response to the Federal Clean Air Act. Prevention of Significant Deterioration (PSD ) Title 25 PA Code Section 127.83 adopts by reference the PSD requirements promulgated in 40 CFR Part 52. The PSD regulations apply to air emission sources which satisfy the regulatory definitions of a “major stationary source” and/or which undergo a “major modification” located in areas designated as attainment or unclassified for the relevant NAAQS. The proposed f acility will be a major s ource (CO , NO x 

### , PM, PM10, PM2.5, VOC, and GHG ) a nd will emit significant amounts, as defined in 40 CFR Part 52.21, for the following pollutants : CO , NO 2 , 

### VOC, SO 2 

### , PM, PM10, PM2.5, sulfuric acid mist, and greenhouse gases (GHG). Paragraphs (j) through (r ) of the PSD regulations require a control technology review, various analyses of source impact, ambient air quality, additional vicinity impacts such as those on visibility, soils and vegetation, visibility in nearby Federal Class I areas and other source obligations. Also, t he G reenhouse G as (GHG) T ailoring R ule requires a BACT analysis to be performed for CO 2(e) 

### . The proposed facility is located is in North Beaver Township , Lawrence County , which is part of the Upper Beaver Valley Air basin and meets t he regulatory definition of a major source. The area is designated as follows:

 Lawrence County is designated as Attainment ( does not meet secondary standards ) for TSP.
 Lawrence County is designated as Attainment ( cannot be classified ) for SO 2 

### .  Lawrence C ounty is designated as Unclassifiable/Attainment for CO.
 Lawrence County is designated as nonattainment (incomplete data) for Ozone (1

- hr standard revoked June 15, 2005).
 Lawrence County is designated as Unclassifiable for PM10.
 Lawrence County is designat ed as c annot be classified or better than national standards for NO 2 

### (1971 annual standard).
 Lawrence County is designated as Unclassifiable/Attainment for NO 2 

### (1

- hr standard 2010).
 Lawrence County is designated as Unclassifiable/Attainment for Ozone (8

- hr standard NAAQS 1997).
 Lawrence County is designated as Unclassifiable/Attainment for Ozone (8

- hr standard NAAQS 2008).
 Lawrence County is designated as Unclassifiable/Attainment for PM2.5 (annual NAAQS).
 Lawrence County is designated as Unclassifiable/Att ainment for PM2.5 (24

- hr NAAQS for both 1997 & 2006).
 Lawrence County is designated as Unclassifiable/Attainment for Lead (2008 NAAQS). PSD Increment ConsumptionPA Review Memo 37

- 3 37 A PSD 14 April 15 , 201 3 DRAFT 

### An ambient air quality analysis must be conducted to demonstrate that the PSD ambient air qua lity increments are not exceeded . This facility will be located in a Class II area, increments for CO, PM

- 10, PM

- 2.5, NO 2 

### , and SO 2 

### apply. There are t hree Class I areas between 2 3 5 and 300 km from the facility. The facility has i nformed the applicable Fe deral Land Managers of the project as discussed in “Other Agencies” section of the memo . The Federal Land Managers have waived their analysis because of the low emissions and im pacts from the proposed facility. Since the modeling indicates that the Signi ficant Impact Levels (SILs) were not exceeded for any pollutants, other increment consuming sources need not be evaluated. D ispersion modeling was conducted for the proposed facility with representative emission source data, terrain data, and meteorologic al data. The impacts of the emissions of carbon monoxide, nitrogen dioxide, particulate matter less than 10 micrometers, and sulfur dioxide from the proposed facility are estimated by modeling to be less than the significant impact levels established by t he U.S. EPA; therefore, it is estimated by modeling that these emissions from the proposed facility will not cause or significantly contribute to air pollution in violation of the National Ambient Air Quality Standards or PSD increment standards. Modeling also demonstrated that emissions from the proposed facility of particulate matter less than 2.5 micrometers (PM2.5) in conjunction with existing ambient concentrations, do not cause or contribute to a violation of either the National Ambient Air Quality S tandards or PSD increment for PM2.5. The degree of PSD air quality increment consumption expected to result from operations of the proposed facility is as follows, based on the dispersion modeling analysis for the facility (all values given in micrograms per cubic meter):

 NO 2 

### /NO x 

### (annual average): 0.80 vs. standard of 25
 PM2.5 (annual average): 0.04 vs. standard of 4
 PM2.5 (24

- hour average): 0.63 vs. standard of 9
 PM10 (annual average): 0.53 vs. standard of 17
 PM10 (24

- hour average): 2.26 vs. standard of 30
 SO 2 

### (3

- hour average): 0.91 vs. standard of 512
 SO 2 

### (24

- hour average): 0.26 vs. standard of 91
 SO 2 

### (annual average): 0.018 vs. standard of 20 Additional Impact Analysis The owner or operator shall provide an analysis of the impairment to visibility, soi ls and vegetation that would occur as a result of the source or modification and general commercial, residential, industrial and other growth associated with the source or modification. The owner or operator need not provide an analysis of the impact on v egetation having no significant commercial or recreational value. The owner or operator shall provide an analysis of the air quality impact projected for the area as a result of general commercial, residential, industrial and other growth associated with the source or modification. The facility provided an analysis (see Appendix B ) o f any potential adverse impacts. Modeling has demonstrated that the facility will not have a significant impact for criteria pollutants as discussed later in the Modeling Sec tion of the memo

.PA Review Memo 37

- 3 37 A PSD 15 April 15 , 201 3 DRAFT 

### PSD Applicability Determination Step 1: Projected Emission Increases
Pollutant Baseline

Actual Emissions (tpy) Projected

Actual Emissions (tpy) PAE

minus BAE (tpy) Could Have

Accommodated Emissions (tpy) Emission

Increase (tpy) Signific ant

Emission Threshold (tpy) Applicable

New Source Program NO x 

### 346.0 9 346. 0 9 346. 0 9 40 PSD/NSR CO 807.53 807.53 807.53 100 PSD VOC 2 03.95 2 03

. 95 2 03

. 95 40 PSD/NSR PM 143.98 143.98 143.98 25 PSD PM10 137.26 137.26 137.26 15 PSD PM2.5 134.41 134.41 134.41 10 PSD SO 2 

### 56.7 56.7 56.7 40 PSD H 2 

### SO 4 

### 8.57 8.57 8.57 7 PSD CO 2(e) 

### 3,693,66 1 3,693,66 1 3,693,66 1 

### 100 ,000 new 75,000 existing PSD
Pb 0.001 0.001 0.001 0.6 PSD Fluorides 3 PSD T RS Compounds including H 2 

### S 10 PSD

Notes:
 If PAE minus BAE is greater than the SET, then CHAE were calculated
 The emission increase is the projected actual emissions minus the baseline minus the could have accommodated emissions.
 There are no baseline emissions because this is a new facility.
P SD Applicability Determination Step 2: Contemporaneous Emissions Because Step 1 Emission Increase is greater than the significant threshold, an increase or decrease is contemporaneou s if it occurs between the date 5 years before construction on the project commences and the date that construction on the project is completed. Because this is a new facility, there are no contemp oraneous emissions.
NSR Pollutant Step 1 Project

Emissions Increase (tpy) Contemporaneous

Emission Increases (tpy) Net Emission

Inc rease or Decrease (tpy) Significant

Emissions Threshold (tpy) NO x 

### 346.0 9 346. 0 9 40 CO 807.53 807.53 100 VOC 2 03

. 95 2 03

. 95 40 PM 143.98 143.98 25 PM10 137.26 137.26 15PA Review Memo 37

- 3 37 A PSD 16 April 15 , 201 3 DRAFT 

### PM2.5 134.41 134.41 10 SO 2 

### 56.7 56.7 40 H 2 

### SO 4 

### 8.57 8.57 7 CO 2(e) 

### 3,693,6 6 1 3,693,66 1 

### 100,000 new 75,000 existing Pb 0.001 0.001 0.6 Fluorides 3 TRS Compounds including H 2 

### S 10
PSD Applicability Summary Based on all pollutants (except lead) being above the significant emission thresholds, PSD is triggered requiring a BACT analysis for each pollutant

. NNSR Analysis 25 PA Code 127.201 addresses sources subject to special permit conditions that are located in a designated non

- attainment region for criteria pollutants. Lawrence County is designated as being in attainme nt (or unclassifiable) with the NAAQS for all criteria pollutants. However, the site is also located in the Northeast Ozone Transport Region and is therefore treated as an ozone moderate non

- attainment area. Because of the current designations and since this proposed s ite has potential emissions equal to or greater than 100 tpy for NO x 

### and 50 tpy for VOC it is subject to the special permit conditions specified in Title 25 PA Code Subchapter E for New Source Review. 25 PA Code 127.205 requires the facilit y must demonstrate the NO x 

### and VOC emissions are controlled with LAER (Lowest Achievable Emission Rate) technology . Section 127.205 also requires each new facility shall offset the potential to emit of that facility with ERCs in accordance with Section 12 7.210. Section 127.210 specifies that NO x 

### emission offsets for the Transport Area shall be at a ratio of 1.15:1 for flue emissions and 1.15:1 for NO x 

### fugitive emissions. Section 127.205 also requires the facility to perform an alternative site analysis w hich is discussed later in the memo

. Section 127.205 also allows the Department to determine that BAT requirements are equivalent to BACT or LAER. Based on the offsets required , the plan approval contains the following condition:

 The permittee shall sec ure NO x 

### and VOC ERCs. ERCs shall be properly generated and certified by the Department. Upon transfer, the permittee shall provide the Department with documentation clearly specifying the details of the ERC transaction. The facility NO x 

### PTE is based on 1.01 tpy for the Auxiliary Boiler, 0.49 tpy for the Emergency Generator, 0.09 tpy for the Emergency Fire Pump, and the NO x 

### PTE for the Combined Cycle Units. The facility VOC PTE is based on 0.14 tpy for the Auxiliary Boiler, 0.03 tpy for the Emergency Gen erator, 0.06 tpy for the Emergency Fire Pump, and the VOC PTE for the Combined Cycle Units. The NO x 

### and VOC PTE for the GE 7FA is 296.06 tpy and 203.72 tpy resulting in a facility NO x 

### and VOC PTE of 297.65 tpy and 203.95 tpy. The NO x 

### and VOC PTE for the Siemens F is 298.0 tpy and 157.16 tpy resulting in aPA Review Memo 37

- 3 37 A PSD 17 April 15 , 201 3 DRAFT 

### facility NO x 

### and VOC PTE of 299.59 tpy and 157.39 tpy. The NO x 

### and VOC PTE for the Mitsubishi G is 248.52 tpy and 187.62 tpy resulting in a facility NO x 

### and VOC PTE of 250.11 tpy and 187.85 tpy. The NO x 

### and VOC PTE for the Siemens H is 344.5 tpy and 186.88 tpy resulting in a facility NO x 

### and VOC PTE of 346.09 tpy and 187.11 tpy. The permittee shall obtain the following NO x 

### and VOC ERCs based on the facility NO x 

### and VOC PTE times the offset of 1.15:

 GE 7FA: NO x 

### - 342.3 tons and VOC

- 234.6 tons
 Siemens F: NO x 

### - 344.6 tons and VOC 181.0 tons
 Mitsubishi G: NO x 

### - 287.7 tons and VOC 216.1 tons
 Siemens H: NO x 

### - 398.1 tons and VOC 215.2 tons NNSR Applicability Determination Step 1: Projected Emission Increas es Pollutant Baseline

Actual Emissions (tpy) Projected

Actual Emissions (tpy) Could have

accommodated Emissions (tpy) Emission

Increase (tpy) Significant

Emission Threshold (tpy) Applicable

New Source Program NO x 

### 346.0 9 346. 0 9 40 NSR VOC 2 03

. 95 2 03

. 95 40 NSR Note: the emission increase is the projected actual emissions minus the baseline minus the could have accommodated emissions. There are no baseline emissions because this is a new facility. NNSR Applicability Determination Step 2: Contemporane ous Emissions Because Step 1 Emission Increase is greater than the significant threshold, an increase or decrease is contemporaneous if it occur s between the date 5 years before construction on the project commences and the date that construction on the pr oject is completed. Because this is a new facility, there are no contemporaneous emissions.
NSR Pollutant Step 1 Project

Emissions Increase (tpy) Contemporaneous

Emission Increases (tpy) Net Emission

Increase or Decrease (tpy) Significant

Emissions Thres hold (tpy) NO x 

### 346.0 9 346. 0 9 40 VOC 2 03

. 95 2 03

. 95 40 NNSR Applicability Summary Based on the projected emission increase for NO x 

### and VOC being greater than the significant emission threshold, NSR is triggered requiring a LAER analysis for each pollut ant. BACT /LAER Analysis A best available control technology (BACT) analysis is required for PSD pollutants and a lowest achievable emission rate (LAER) is required for NSR pollutants (NO x 

### and VOC )

. BACT isPA Review Memo 37

- 3 37 A PSD 18 April 15 , 201 3 DRAFT 

### defined in 25 PA Code 121 as an emissions limita tion (including a visible emissions standard) based on the maximum degree of reduction for each regulated NSR pollutant which would be emitted from any proposed major facility or major modification which the Department, on a case - by

- case basis, taking into account energy, environmental and economic impacts and other costs, determines is achievable for the facility or modification through application of production processes or available methods, systems and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of the pollutant. The application of BACT may not result in emissions of a pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR Part 60 or 61. If the Department dete rmines that technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combi nation thereof, may be prescribed instead to satisfy the requirement for the application of BACT. The standard must, to the degree possible, set forth the emissions reduction achievable by implementation of the design, equipment, work practice or operatio n, and provide for compliance by means which achieve equivalent results. LAER is defined in 25 PA Code 121 as whichever is more stringent of the following: (a) the most stringent emission limitation which is contained in the implementation plan of a state for the class or category of sources unless the owner or operator of the proposed source demonstrates that the limitations are not achievable or (b) the most stringent emission limitation which is achieved in practice by the class or category of source. For all pollutants emitted at significant levels, a BACT determination must be performed using a “top

- down” approach. This begins with the most stringent control alternative (top), which must be utilized unless it is demonstrated that technical considerat ions, or energy, environmental, or economic impacts justify infeasibility. The process continues until an alternative cannot be eliminated based on the criteria above. The Department performed a review of the RBLC database and a subsequent review of plan approvals issued in the state to determine what control technologies have been required to be installed in the past for this type of source. The Department reviewed the BACT/LAER/BAT analysis provided by the facility and determined that all relevant cont rol technologies were included in their analysis. The facility’s analysis then removed certain technologies that were determined to be technically infeasible and then ranked the remaining control technologies in order of most effective. The Department re viewed the information provided and agrees with the facility ’s determination as to which control technologies were technically infeasible. After reviewing the ranking to ensure the most effective was at the top, the facility then proposed to use the most effective control thus no further analysis was required. Section 5 of the application contains the ir complete analysis including the various control technologies for each pollutant analyzed, justifications as to what is technically feasible and what is te chnically infeasible, and the ranking of the remaining technically feasible control technologies based on effectiveness

. Because cost factors were not evaluated, this analysis can also be used for LAER. A summary of the BACT/LAER analysis is listed below

. CCU BACT for CO: The following table includes a list of potential control technologies. Control Technology Combustion or Post ControlPA Review Memo 37

- 3 37 A PSD 19 April 15 , 201 3 DRAFT 

### Good Combustion Practices (GCP) Combustion Oxidation Catalyst Post Control SCONOX Post Control
Based on the lack o f availability of SCONOX technology on projects of this size, this technology has been determined to be infeasible. The remaining two technically feasible control technologies (GCP and oxidation catalyst) are compatible and the facility has decided to use both as the control for this source. The BACT determination is use of GCP and oxidation catalyst with an emission limitation of 2.0 ppmvd corrected to 15% O 2 

### based on a 3

- hour averaging period. These limits apply regardless of the operational status of the duct burners (firing or not firing). For periods of startup and shutdown: emissions will be controlled by combustion controls and in accordance with the startup and shutdown definitions and emission will be limited to those listed for startup and shut down periods.
CCU BACT and LAER for VOC: The following table includes a list of potential control technologies. Control Technology Combustion or Post Control Good Combustion Practices (GCP) Combustion Oxidation Catalyst Post Control SCONOX Post Control
Based on the lack of availability of SCONOX technology on projects of this size, this technology has been determined to be infeasible. The remaining two technically feasible control technologies (GCP and oxidation catalyst) are compatible and the facil ity has decided to use both as the control for this source. The BACT and LAER determination is use of GCP and oxidation catalyst with an emission limitation of 1.5 ppmvd corrected to 15% O 2 

### . These limits apply regardless of the operational status of the duct burners (firing or not firing). For periods of startup and shutdown : emissions will be controlled by combustion controls and in accordance with the startup and shutdown definitions and emission will be limit ed to those listed for startup and shutdown periods.
C CU BACT and LAER for NO x 

### : The following table includes a list of potential control technologies. Control Technology Combustion or Post Control Wet Injection Combustion D LN Combustor (dry low NO x 

### ) Combustion Selective Catalytic Reduction (SCR ) Post Control SCONOX Post Control Selective Non

- Catalyst Reduction (SNCR) Post ControlPA Review Memo 37

- 3 37 A PSD 20 April 15 , 201 3 DRAFT


### SNCR has been determined to be technically infeasible because of the required operating temperature of the SNCR is much higher than the operating temperature of the exhaust gas downstream of the HRSG which is approximately 150F to 290F. SCONOX has also been determined to be technically infeasible because it has not been applied to a facility of this size , therefore it is not available . Finally Wet Injection, while technically feasible is not being considered because the DLN Combustor would provide equivalent or higher level of control. The remaining two technically feasible control technologies (DLN Combustors and SCR) are compatible and the facility has decided to use both as the control for this source. The BACT and LAER determination is DLN Combustors and SCR with an emission limitation of 2 .0 ppmvd corrected to 15% O 2 

### based on a 3

- hour averaging period

. These limits apply regardless of the operational status o f the duct burners (firing or not firing). For periods of startup and shutdown: emissions will be controlled by combustion controls and in accordance with the startup and shutdown definitions and emission will be limited to those listed for startup and sh utdown periods. CCU BACT for PM/PM10/PM2.5: The following table includes a list of potential control technologies. Control Technology Combustion or Post Control Good Combustion Practices (GCP) Combustion Low Sulfur Fuel Combustion Fabric Filter (baghou se) Post Control Electrostatic Precipitator (ESP) Post Control Wet Electrostatic Precipitator (WESP) Post Control Wet Scrubber Post Control The post combustion control technologies have been determined to be technically infeasibility. This is because of the high operating temperatures, high airflow volumes, fine particulate distribution, and inherently low uncontrolled emission rates. Also , a review of the RBLC showed no combined cycle units equipped with add

- on controls. The remaining two technical ly feasible control technologies (GCP and Low Sulfur Fuel) are compatible and the facility has decided to use both as the control for this source. The BACT determination is GCP and Low Sulfur Fuel with an emission limitation of the following:

 Normal Oper ation

– Duct Burners off
 GE 7FA: 10.0 #/hr
 Siemens F: 10 .0 #/hr
 Mitsubishi G: 12.0 #/hrPA Review Memo 37

- 3 37 A PSD 21 April 15 , 201 3 DRAFT



###  Siemens H: 11.0 #/hr
 Normal Operation

– Duct Burners on
 GE 7FA: 17.5 #/hr
 Siemens F: 17.5 #/hr
 Mitsubishi G: 19.5 #/hr
 Siemens H: 18.5 #/hr For periods of startup and shutdown: emissions will be controlled by combustion controls and in accordance with the startup and shutdown definitions and emission will be limited to those listed for startup and shutdown periods.
C CU BACT for SO x 

### and Sulfuric Acid Mist : The following table includes a list of potential control technologies. Control Technology Combustion or Post Control Fuel Treatment Combustion Pipeline Quality Natural Gas Combustion Flue Gas Desulfurization (FGD) P ost Control
 Wet Scrubber Po st Control

 Spray Dryer Absorber (Dr y Scrubber) Post Control Fuel treatment has been determined to be technically infeasible because of the very low sulfur content of the pipeline natural gas. FGD has bee n determined to be technically infeasible because its efficiency decreas es with lower inlet SO x 

### concentrations. Also, FGD has not been used on projects of this size, therefore it would not be considered available. The only remaining control technology is the pipeline quality natural gas. The BACT determination for both SO x 

### and H 2 

### SO 4 

### is use of pipeline quality natural gas with an emission limitation of 0. 75 grains sulfur per 100 scf natural gas based on fuel monitoring

. CCU BACT for GHG : The following table includes a list of potential control technologies. Control Technolog y Carbon Capture & Storage (CCS) Energy Efficiency utilization CCS has not been demonstrated on a facility of this size, therefore it has been determined that it is infeasible. Energy efficiency utilization will include: combine cycle technology (sign ificantly higher levels of electric generation efficiency than traditional fossil fuel generating facilities); equipment maintenance; instrumentation & control systems; HRSG design consideration; and high efficiency auxiliary equipment. Energy efficiency is the only technical feasible option remaining. The energy efficiency for the various units are provided in Appendix A of the application and are as follows:PA Review Memo 37

- 3 37 A PSD 22 April 15 , 201 3 DRAFT



###  GE 7FA: net plant heat rate of 6,700 btu/kWh, HHV @ ISO conditions at 59F ambient temperature w ith no duct firing
 Siemens F: net plant heat rate of 6,842 btu/kWh, HHV @ ISO conditions at 59F ambient temperature with no duct firing
 Mitsubishi G: net plant heat rate of 6,702 btu/kWh, HHV @ ISO conditions at 59F ambient temperature with no duct firing
 Siemens H: net plant heat rate of 6,577 btu/kWh, HHV @ ISO conditions at 59F ambient temperature with no duct firing The BACT determination is use of energy efficiency with an emission limitation of 1,000 # CO 2 

### /MW

- hr (gross) on a 365

- day rolling average w hich is based on proposed NSPS

. Auxiliary Boiler BACT for CO: Based on the very low emissions, Good Combustion Practices (GCP) will be used as the control for this source. The BACT determination is use of GCP with an emission limitation of 0 .0 36 #/mmbtu

. Auxiliary Boiler BA C T and LAER for VOC: Based on the very low emissions, Good Combustion Practices (GCP) will be used as the control for this source. The LAER and BACT determination is use of GCP with an emission limitation of 0.015 #/mmbtu. Auxiliary Boiler BACT and LAER for NO x 

### : Based on the very low emissions, Ultra

- low NO x 

### burners (ULNB) will be used as the control for this source. The LAER and BACT determination is use of ULNB with an emission limitation of 0.011 #/mmbtu. Auxiliary Boiler BACT fo r PM/ PM10/PM2.5: Based on very low emissions, GCP and pipeline quality natural gas will be the control for this source. The BACT determination is use of GCP and pipeline quality natural gas wi th an emission limitation of 0.005 #/mmbtu. Auxiliary Boiler B

ACT for SO x 

### and Sulfuric Acid Mist : Based on very low emissions, pipeline quality natural gas will be the control for this source. The BACT determination is use of pipeline quality natural gas with an emission limitation of 0.0021 #/mmbtu for SO x 

### and 0.00 048 #/mmbtu for H 2 

### SO 4 

### . Emergency Engines (Generator and Fire Water Pump) BACT for CO: Based on the very low emissions, Good Combustion Practices (GCP) will be used as the control for this source. The BACT determination is use of GCP with an emission limi tation of 3

. 5 g / kW

- hr (0.0057 #/bhp

- hr)

.PA Review Memo 37

- 3 37 A PSD 23 April 15 , 201 3 DRAFT


### Emergency Engines (Generator and Fire Water Pump) BA C T and LAER for VOC: Based on the very low emissions, Good Combustion Practices (GCP) will be used as the control for this sour ce. The LAER and BACT determinatio n is use of GCP with an emission limitation of 0.0 9 #/mmbtu for emergency generator and 0.00247 #/bhp

- hr for fire water pump . Emergency Engines (Generator and Fire Water Pump) BACT and LAER for NO x 

### : Based on the very low emissions, Good Combustion Practic es (GCP) will be used as the control for this source. The LAER and BACT determination is use of GCP with an emission limitation of 5.9 g/kW

- hr (3.9 g/bhp

- hr) for emergency generator and 1.87 g/bhp

- hr for fire water pump

. Emergency Engines (Generator and Fire Water Pump) BACT for PM/ PM10/PM2.5: Based on very low emissions, GCP and pipeline quality natural gas will be the control for this source. The BACT determination is use of GCP and pipeline quality natural gas with an emission limitation of 0.15 g/bhp

- hr (0.23 g/KW

- hr). Emergency Engines (Generator and Fire Water Pump) BACT for SO x 

### and Sulfuric Acid Mist : Based on very low emissions, ultra

- low sulfur diesel (ULSD) will be the control for this source. The BACT determination is use of ULSD with an emis sion limitation of 0.0018 #/mmbtu (0.0055 g/bhp

- hr) for SO x 

### for both the emergency generator and fire water pump and 0.00036 #/mmbtu (0.0012 g/bhp

- hr) for H 2 

### SO 4 

### for both the emergency generator and fire water pump

. Cooling Tower BACT for PM/ PM10/PM2.5: Th e use of high

- efficiency drift eliminating media to de

- entrain droplets from the air flow exiting the cooling tower is a commercially proven technique to reduce PM/PM10/PM2.5 emissions. A review of the RBLC shows this as the only available control. The B ACT determination is drift rate of 0.0005%. Fuel Storage Tanks BA C T and LAER for VOC: Due to the low vapor pressure of ultra

- low sulfur diesel (ULSD), low tank throughput, and very low emissions, conservation vent valves will be the control for this sourc e. The conservation vent valves include both pressure

- relief valves (to keep vapors at a safe pressure) and vacuum

relief valves (to allow outside air to enter to avoid a significant vacuum). The LAER and BACT determination is use of conservation vent va lves. BAT Analysis Per Title 25 PA Code Section 127.1; all new sources are required to control the emission of air pollutants to the maximum extent consistent with the best available technology (BAT) as determined by the Department. Th e s e source s meet th e definition of a new source as defined by Title 25 PA Code Section 121.1. BAT is defined in 25 PA Code 121 as e quipment, devices, methods or techniques as determined by the Department which will prevent, reduce or control emissions of air contaminants to the maximum degree possible and which are available or may be made available.PA Review Memo 37

- 3 37 A PSD 24 April 15 , 201 3 DRAFT



### C CU BAT for Ammonia : Ammonia is used as a reagent in the SCR for NO x 

### control. Ammonia slip is the ammonia that doesn’t react in the SCR and exhausts into the atmosphere. The higher the NO x 

### control efficiency usually requires greater amounts of ammonia which results in higher levels of ammonia slip. For optimum SCR efficiency, NO x 

### and ammonia slip concentrations are measured continuously and adjusted by automated control syste ms. The BAT emission limit for ammonia slip is 5.0 ppmvd at 15% O 2 

### on a rolling 3

- hour average period . This limit includes all periods of operations.
C CU BAT for H

APs : Formaldehyde is the largest HAP emission and will be used as a surrogate for all orga nic HAP emissions. The BAT limit is as follows:

 GE 7FA: 2.67 tpy for each CCU
 Siemens F: 2.75 tpy for each CCU
 Mitsubishi M501G: 3.44 tpy for each CCU
 Siemens H: 3.42 tpy for each CCU Compliance will be shown by testing. Summary of BACT/LAER/BAT Determi nations
Pollutant Source Criteria Control Device selected Emission limit CO C CU BACT GCP and oxidation catalyst 2.0 ppmvd corrected to 15% O 2



### based on a 3

- hour averaging period VOC C CU LAER GCP and oxidation catalyst 1. 5 ppmvd corrected to 15% O 2 

### NO x 

### C CU LAER DLN Combustors and SCR 2.0 ppmvd corrected to 15% O 2



### based on a 3

- hour averaging period PM/ PM 10/PM2.5 C CU BACT GCP and Low Sulfur Fuel Normal Operation

– Duct Burners off
 GE 7FA: 10.0 #/hr
 Siemens F: 10.0 #/hr
 Mitsubishi M501G: 12.0 #/hr
 Siemens H : 11.0 #/hr Normal Operation

– Duct Burners on  GE 7FA: 17.5 #/hr
 Siemens F: 17.5 #/hr
 Mitsubishi M501G: 19.5PA Review Memo 37

- 3 37 A PSD 25 April 15 , 201 3 DRAFT 

### #/hr
 Siemens H: 18.5 #/hr SO 2 

### C CU BACT pipeline quality natural gas 0.75 grains sulfur per 100 scf natural

gas based on fuel monitoring H 2 

### SO 4 

### Mis t C CU BACT pipeline quality natural gas 0.75 grains sulfur per 100 scf natural

gas based on fuel monitoring GHG CCU BACT energy efficiency 1,000 # CO 2 

### /MWhr (gross) on a 365

- day rolling average Ammonia Slip C CU BAT optimum SCR efficiency 5.0 ppmvd at 15% O 2 

### on a rolling 12

- month average basis HAPs C CU BAT oxidation catalyst  GE 7FA.05: 2.67 tpy for each CCU
 Siemens SGT6

- 5000F5/DLN: 2.75 tpy for each CCU
 Mitsubishi M501GAC: 3.44 tpy for each CCU
 Siemens SGT6

- 8000H/DLN: 3.42 tpy for each CCU CO Aux Boiler B ACT GCP 0.036 #/mmbtu VOC Aux Boiler LAER GCP 0.0 0 15 #/mmbtu NO x 

### Aux Boiler LAER ULNB 0.011 #/mmbtu PM/PM10/PM2.5 Aux Boiler BACT GCP and pipeline quality natural gas 0.005 #/mmbtu
SO 2 

### Aux Boiler BACT pipeline quality natural gas 0.0021 #/mmbtu
H 2 

### SO 4 

### Mist Aux Boiler BA C T pipeline quality natural gas 0.00048 #/mmbtu
CO Emergency

Engines BACT GCP 3.5 g/kW

- hr (0.0057 #/bhp

- hr)
VOC Emergency

Engines LAER GCP 0.09 #/mmbtu for emergency generator and 0.00247 #/bhp

- hr for fire water pump NO x 

### Emergency

Engi nes LAER GCP 5

. 9 g/kW

- hr (3.9 g/bhp

- hr) for emergency generator and 1

. 87 g/bhp

- hr for fire water pump PM/PM10/PM2.5 Emergency

Engines BACT GCP and pipeline quality natural gas 0.1 5 g / bhp

- hr (0.23 g/KW

- hr)
SO 2 

### Emergency

Engines BACT ULSD 0.0018 #/mmbtu (0 .0055 g/bhp

- hr) for both the emergency generator and fire water pump H 2 

### SO 4 

### Mist Emergency BA C T ULSD 0.00036 #/mmbtu (0.0012 g/bhp

- hr)PA Review Memo 37

- 3 37 A PSD 26 April 15 , 201 3 DRAFT 

### Engines for both the emergency generator and fire water pump PM/PM10/PM2.5 Cooling

Tower BACT High efficiency drift eli minators drift rate of 0.0005%
VOC Fuel

Storage Tanks LAER conservation vent valves

New Source Performance Standards :  Th e C CU s are subject to the requirements of 40 CFR 60 Subpart KKKK ( Standards of Performance for Stationary Combustion Turbines )

. The facility has p roposed emission limitations that are more stringent than the requirements set forth in Subpart KKKK

.  The CCUs will be subject to the requirements of proposed 40 CFR 60 Subpart TTTT (Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units) if and when it becomes applicable and if no changes in the applicability requirements . The facility has proposed emission limitations that are equivalent to the proposed requirements set forth in Subpart TTTT

. If this becomes applicable prior to plan approval issuance, the requirements will be added to the plan approval prior to issuance. If this becomes applicable after the issuance of the plan approval, the sources would still be required to co mply with all the applicable requirements and those requirements will be added to the facility operating permit at a later date.
 The Auxiliary Boiler is subject to the requirements of 40 CFR 60 Subpart Dc ( Standards of Performance for Small Industrial

- Comm ercial

- Institutional Steam Generating Units ).
 The emergency generator and the emergency fire water pump are subje ct to 40 CFR 60 Subpart IIII ( Standards of Performance for Stationary Compression Ignition Internal Combustion Engines)

. The facility has p rop osed emission limitations that are as stringent as the requirements set forth in Subpart IIII. National Emission Standards for Hazardous Air Pollutants:
 The Auxiliary Boiler is not subj ect to 40 CFR 63 Subpart JJJJ JJ ( National Emission Standards for Hazar dous Air Pollutants for Industrial, Commercial, and Institutional Boilers Area Sources) because the boiler meets the definition of gas

- fired boiler

.  The Auxiliary Boiler is not subject to 40 CFR 63 Subp art DDDDD ( National Emission Standards for Hazardous A ir Pollutants for Industrial, Commercial, and Institutional Boilers and Process Heaters) b ecause the facility HAP emissions are not major. Acid Rain Regulations (Title IV Program): The purpose of the program is to reduce emissions of SO 2 

### and NO x 

### from elec tric utilities, thereby reducing the occurrence of acid rain. The program is being implemented in two phases for both SO 2 

### and NO x 

### . The acid rain regulations do apply to the proposed facility because the plant uses fossil fuel.PA Review Memo 37

- 3 37 A PSD 27 April 15 , 201 3 DRAFT



### Clean Air Interstate Rule (CAIR): The facility is subject to 40 CFR 96 with regards to the CAIR rule . This rule ha d been replaced by the Cross

- State Air Pollution Rule (CSAPR) (40 CFR 97) but that rule was stayed on August 21, 2012

. Cross
- State Air Pollution Rule (CSAPR) : This ru le was stayed on August 21, 2012. The facility is subject to 40 CFR 97 with regards to the CSAPR. The final rule does not affect any Acid Rain Program requirements. Acid Rain Program requirements are established independently in Title IV of the CAA and are not replaced by the Transport Rule. Title IV sources that are subject to final Transport Rule provisions still need to continue to comply with all Acid Rain provisions. Title IV SO 2 

### and NO x 

### requirements continue to apply independently of the Transpor t Rule provisions. For the reasons explained above, Title IV SO 2 

### allowances are not allowed to be used in the Transport Rule trading programs. Similarly, Transport Rule SO 2 

### allowances are not usable in the Acid Rain Program. Compliance Assurance Monitor ing Plan (40 CFR 64) : This is applicable because precontrol emissions of a pollutant with a control device are major. However, the facility will have CEMs for all the pollutants (NO x 

### & CO) that would be major pre

control with the exception of VOC for the GE turbine set

. Risk Management Program (40 CFR 68) : This is applicable if ammonia is present in quantities greater than 10,000 pounds (anhydrous) or 20,000 pounds (aqueous solution). At this time the facility plans on staying below the thresholds. GHG Tailoring Rule: The facility is subject to 40 CFR 51 and 52 with regards to the GHG tailoring rule. The facility submitted a GHG BACT as part of Section 5 of the application. A summary of the BACT determination is included in the PSD section. Alternat iv e Site s Analysis : Per 25 PA Code 127.205(5) the applicant is required to conduct an analysis of alternative sites, sizes, production processes and environmental control techniques for the proposed facility, which demonstrates that the benefits of the propo sed facility significantly outweigh the environmental and social costs imposed within this Commonwealth as a result of its location, construction or modification

. This is done in Section 3 of the application

.PA Review Memo 37

- 3 37 A PSD 28 April 15 , 201 3 DRAFT 

### The company looked at a site in norther n Ohio (outside the Commonwealth) and two sites in Lawrence County

. T he conclus ion is no other suitable sites were identified and the benefits of the proposed facility significantly outweigh the environmental and social costs of the project. The Departme nt concurs with this analysis. Below is a summary of the analysis.
Alternative Sites HRE evaluated alternat ive sites and chose to locate the Facility at the proposed location in North Beaver Township in Pennsylvania

. HRE identified a need for reliable e lectrical generation capacity within the PJM Interconnection, L.L.C. (PJM), American Transmission Systems Inc. (ATSI) Locational Deliverability Area (LDA). The ATSI LDA encompasses the northern portion of Ohio (primarily the Cleveland metropolitan area) a nd a portion northwestern Pennsylvania The primary driver for new generation is the pending retirement of over 3,000 MW of mostly older, coal

- fired resources within the ATSI LDA. HRE’s analysis indicated that t he operation of the facility may allow for the displacement of older, less reliable, less efficient power generation units, thus yielding net environmental benefits. In addition, the Project will help maintain the overall reliability of the PJM electrical system and its ability to meet the growing ele ctrical demands of the regional population. HRE utilized three primary scoping and screening criteria in its identification and evaluation of potential sites: (i) proximity to a location on the PJM high

- voltage transmission system sufficient to interconne ct the Project; (ii) proximity to interstate natural gas pipelines with volume and pressure capabilities sufficient to supply the Project; and (iii) availability of water supply and discharge alternatives for Project cooling and process water needs. Apply ing these scoping criteria served to focus the siting effort to the few localized areas of interest with minimized off

- site environmental and community impacts. 

### HRE’s evaluation identified three sites that meet the project definition and screening criteria : a site in northern Ohio (outside the Commonwealth) and two sites in Lawrence County (PA Site A and PA Site B)

. PA Site A is the proposed site. HRE’s analysis of the three sites determined that all three locations had developable sites, minimized wetl and and flood zone impacts, suitable zoning and compatibility with the surrounding land use. The analysis determined that the site in Ohio did not have a suitable fuel supply. The analysis also determined that the PA Site B had a suitable fuel supply and suitable transmission, but the fuel pipeline and transmission routes required to connect the Facility to interstate pipelines and the grid were longer than the routes for Site A and would result increased environmental impacts from pipeline and transmissi on infrastructure construction

. Both Site A and Site B had an adequate water supply including options for beneficial water reuse. Site B’s current land use is agricultural and Site A is a former industrial site. The analysis determined that locating th e project at Site B would involve impacts to prime farmland and higher visual impacts to the surrounding areas. Site A has adequate setbacks and surrounding forested land to avoid the visual impacts. Site B is located closer to a non - attainment area (PM 2.5 non

- attainment) than Site A. Locating the Facility at Site B also had the potential for the cooling towers to fog and ice a major adjacent roadway. HRE’s choice of Site A meets their requirements for grid connection, fuel supply and water supply/disc harge availability and minimizes off

- site environmental and community impact.PA Review Memo 37

- 3 37 A PSD 29 April 15 , 201 3 DRAFT



### Alternative Sizes
HRE selected the generating capacity of the facility (900 MW) based on the current and future needs for efficient electric generating capacity in the PJM re gion. Increased generating capacity would result in a larger site footprint. Developing a larger footprint is constrained by topography, potential wetland impacts and areas of the former industrial property that may require remediation or hazard mitigati on. Decreasing generating capacity would result in lower air emissions but other environmental impacts would remain relatively constant, and the additional generating capacity would potentially be constructed at another site and potentially be located on a greenfield area.



### NO x 

### Budget Trading Program: This has been replaced by the CAIR rule (CSAPR)

. Modeling ( Summary of Air Quality Analysis for Prevention of Significant Deterioration memo from Sean Nolan dated March 1 , 201 3 . ) The Hickory Run proposa l is subject to the Prevention of Significant Deterioration (PSD) regulations promulgated in 40 CFR § 52.21. These federal PSD regulations are adopted and incorporated by reference in their entirety in 25 Pa. Code § 127.83 and the Commonwealth’s State Imp lementation Plan (SIP) codified at 40 CFR § 52.2020. The following pollutants are subject to the PSD air quality analysis requirements: carbon monoxide (CO), nitrogen dioxide (NO 2 

### ), particulate matter less than 2.5 micrometers (PM2.5), particulate matter less than 10 micrometers (PM10), and sulfur dioxide (SO 2 

### ). The air quality analysis to support the plan approval application was prepared by Trinity Consultants. The Hickory Run air quality analysis satisfies the requirements of the PSD regulations and i s consistent with the U.S. Environmental Protection Agency’s (EPA) “Guideline on Air Quality Models” (Guideline), codified in Appendix W to 40 CFR Part 51, and the EPA’s air quality modeling policy and guidance. Furthermore, Hickory Run adequately address ed the PADEP’s comments of February 13, 2013, relating to the technical review of the air quality analysis. The Hickory Run air quality analysis adequately demonstrates that Hickory Run’s proposed emissions will not cause or significantly contribute to ai r pollution in violation of the National Ambient Air Quality Standards (NAAQS) for CO, NO 2 

### , PM2.5, PM

- 10 and SO 2 

### , and the PSD increment standards for NO 2 

### , PM2.5, PM 10, and SO 2 

### . In addition, the analysis adequatelyPA Review Memo 37

- 3 37 A PSD 30 April 15 , 201 3 DRAFT 

### demonstrates that Hickory Run’s proposed emissions, in conjunction with anticipated emissions due to general commercial, residential, industrial, and other growth associated with the Hickory Run facility, will not impair visibility, soils, and vegetation. Furthermore, the analysis adequately dem onstrates that Hickory Run’s proposed emissions will not adversely affect air quality related values (AQRVs), including visibility, in Federal Class I areas.

CONCLUSIONS & RECOMMENDATIONS : Hickory Run Energy will be a major source (Title V) based on pot ential emissions. They will not be major for HAPs. They do not have a Title V permit because this is a new facility. The construction of the natural gas

- fired combined

- cycle electric generation facility designed to generate up to 900 MW nominal, using 2 combustion turbine generators and 2 heat recovery steam generators with duct burners that will provide steam to drive a single steam turbine generator will result in PSD and NSR requirements. Also Federal NSPS and NESHAP requirements will apply to this c onstruction

. This application shows that this facility will meet the applicable requirements of 40 CFR Part 52.21 (related to Prevention of Significant Deterioration), Title 25 PA Code Subchapter E (related to Non

- attainment New Source Review), and Pennsy lvania Best Available Technology. I recommend that a Plan Approval with conditions be granted

.

cc: AQ Central Office, New Source Review

- Hrsbg. AQ Central Office, Division of Permits (K. Ramamurthy and V. Trivedi) AQ Central Office, Air Quality Model ing Section (S. Nolan) New Castle District Office

– thru L. Vogel37-337A

Page 1 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: PLAN APPROVAL Issue Date: Effective Date:
In accordance with the provisions of the Air Pollution Control Act, the Act of January 8, 1960, P.L. 2119, as amended, and 25 Pa. Code Chapter 127, the Owner, [and Operator if noted] (hereinafter referred to as permittee) identified below is authorized by the Department of Environmental Protection (Department) to construct, install, modify or reactivate the air emission source(s) more fully described in the site inventory list. This Facility is subject to all terms and conditions specified in this plan approval. Nothing in this plan approval relieves the permittee from its obligations to comply with all applicable Federal, State and Local laws and regulations. The regulatory or statutory authority for each plan approval condition is set forth in brackets. All terms and conditions in this permit are federally enforceable unless otherwise designated as "State-Only" requirements. Plan Approval No. 37-337A

Mailing Address:

Plant: HICKORY RUN ENERGY STATION

400 CHESTERFIELD CTR STE 110 CHESTERFIELD, MO 63017-4800

Location: 37 Lawrence County

HICKORY RUN ENERGY LLC

Responsible Official Name: Title:

Name: Title: Phone:
[Signature] _________________________________________

ROBERT COLOZZA SENIOR VICE PRESIDENT

DAVID K WILSON SR ENVIRONMENTAL ENG (636) 532 - 2200 SIC Code: 4911 Trans. & Utilities - Electric Services 37912 North Beaver Township

JOHN F. GUTH, NORTHWEST REGION AIR PROGRAM MANAGER Owner Information

Plant Information Name:

Phone: (636) 532 - 2200 Expiration Date:

Plan Approval Contact Person Federal Tax Id - Plant Code: 45-5096863-1 COMMONWEALTH OF PENNSYLVANIA DEPARTMENT OF ENVIRONMENTAL PROTECTION

AIR QUALITY PROGRAM37-337A

Page 2 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: Plan Approval Description This application is for the construction of a natural gas-fired combined-cycle electric generation facility that is designed to generate up to 900 MW nominal, using 2 combustion turbine generators and 2 heat recovery steam generators that will provide steam to drive a single steam turbine generator. Each heat recovery steam generator will be equipped with a duct burner which may be utilized at time of peak power demands to supplement power output. The source is subject to PSD/NSR requirements.Compliance Assurance Monitoring (CAM) will be applicable to the facility. The proposed project will also include a natural gasfired auxiliary boiler; a diesel engine-driven emergency generator; a diesel engine-driven firewater pump; a multi-cell evaporative cooling tower; and associated emission control systems, tanks, and other balance of plant equipment. This will be a Title V facility.37-337A

Page 3 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: SECTION A. Table of Contents Section A. Facility/Source Identification

Section B. General Plan Approval Requirements

Section C. Site Level Plan Approval Requirements

Section D. Source Level Plan Approval Requirements

Section E. Alternative Operating Scenario(s)

Section F. Emission Restriction Summary #001 #002 #003 #004 #005 #006 #007 #008 #009 #010 #011 #012 #013 Definitions

Future Adoption of Requirements Plan Approval Temporary Operation Content of Applications Public Records and Confidential Information Plan Approval terms and conditions. Transfer of Plan Approvals Inspection and Entry Plan Approval Changes for Cause Circumvention Submissions Risk Management Compliance Requirement Table of Contents Plan Approval Inventory List

C-I: Restrictions C-II: Testing Requirements C-III: Monitoring Requirements C-IV: Recordkeeping Requirements C-V: Reporting Requirements C-VI: Work Practice Standards C-VII: Additional Requirements C-VIII: Compliance Certification C-IX: Compliance Schedule

D-I: Restrictions D-II: Testing Requirements D-III: Monitoring Requirements D-IV: Recordkeeping Requirements D-V: Reporting Requirements D-VI: Work Practice Standards D-VII: Additional Requirements Note: These same sub-sections are repeated for each source!

E-I: Restrictions E-II: Testing Requirements E-III: Monitoring Requirements E-IV: Recordkeeping Requirements E-V: Reporting Requirements E-VI: Work Practice Standards E-VII: Additional Requirements37-337A

Page 4 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: SECTION A. Table of Contents

Section G. Miscellaneous37-337A

Page 5 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: 

### PERMIT MAPS CU 031

CU 032

CU 033 CNTL

C031A

CNTL C032A

STAC S033 CNTL

C031B

CNTL C032B STAC

S031

STAC S032 FML FML01

FML FML01

FML FML01 SECTION A. Plan Approval Inventory List

031 032 033

101

102

103 104 C031A C031B C032A C032B COMBINED CYCLE UNIT #1

COMBINED CYCLE UNIT #2 AUXILIARY BOILER
EMERGENCY GENERATOR (1,135 BHP - 750 KW)
EMERGENCY FIREWATER PUMP (450 BHP)

COOLING WATER TOWER FUEL STORAGE TANKS SCR #1 OXIDATION CATALYST #1 SCR #2 OXIDATION CATALYST #2 40.000

7.800

3.250 MMBTU/HR

MMBTU/HR

MMBTU/HR 3.400 3.400

39.300

55.000

24.000 10.500 79.000 MMCF/HR

MMCF/HR

MCF/HR

Gal/HR

Gal/HR M Gal/HR Gal/HR Natural Gas

Natural Gas

Natural Gas

ULTRA LOW SULFUR DISTI

ULTRA LOW SULFUR DISTI COOLING WATER ULSD Source ID Source Name Capacity/Throughput Fuel/Material

FML01 FML02 NATURAL GAS

DIESEL FUEL S031 S032 S033 S101 S102 Z01 COMBINED CYCLE UNIT #1 STACK

COMBINED CYCLE UNIT #2 STACK AUXILIARY BOILER STACK EMERGENCY GENERATOR STACK EMERGENCY FIREWATER PUMP STACK FUGITIVE EMISSIONS37-337A

Page 6 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: 

### PERMIT MAPS PROC 101

PROC 102

PROC 103

PROC 104 STAC

S101

STAC S102

STAC Z01

STAC Z01 FML FML02

FML FML0237-337A

Page 7 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: #001

#002

#003

#004

#005 Definitions

Future Adoption of Requirements

Plan Approval Temporary Operation

Content of Applications

Public Records and Confidential Information

Words and terms that are not otherwise defined in this plan approval shall have the meanings set forth in Section 3 of the Air Pollution Control Act (35 P.S. § 4003) and 25 Pa. Code § 121.1.

The issuance of this plan approval does not prevent the future adoption by the Department of any rules, regulations or standards, or the issuance of orders necessary to comply with the requirements of the Federal Clean Air Act or the Pennsylvania Air Pollution Control Act, or to achieve or maintain ambient air quality standards. The issuance of this plan approval shall not be construed to limit the Department's enforcement authority.

This plan approval authorizes temporary operation of the source(s) covered by this plan approval provided the following conditions are met. (a) When construction, installation, modification, or reactivation is being conducted, the permittee shall provide written notice to the Department of the completion of the activity approved by this plan approval and the permittee's intent to commence operation at least five (5) working days prior to the completion of said activity. The notice shall state when the activity will be completed and when the permittee expects to commence operation. When the activity involves multiple sources on different time schedules, notice is required for the commencement of operation of each source. (b) Pursuant to 25 Pa. Code § 127.12b (d), temporary operation of the source(s) is authorized to facilitate the shakedown of sources and air cleaning devices, to permit operations pending the issuance of a permit under 25 Pa. Code Chapter 127, Subchapter F (relating to operating permits) or Subchapter G (relating to Title V operating permits) or to permit the evaluation of the air contaminant aspects of the source. (c) This plan approval authorizes a temporary operation period not to exceed 180 days from the date of commencement of operation, provided the Department receives notice from the permittee pursuant to paragraph (a), above. (d) The permittee may request an extension of the 180-day shakedown period if further evaluation of the air contamination aspects of the source(s) is necessary. The request for an extension shall be submitted, in writing, to the Department at least 15 days prior to the end of the initial 180-day shakedown period and shall provide a description of the compliance status of the source, a detailed schedule for establishing compliance, and the reasons compliance has not been established. This temporary operation period will be valid for a limited time and may be extended for additional limited periods, each not to exceed 180 days. (e) The notice submitted by the permittee pursuant to subpart (a) above, prior to the expiration of the plan approval, shall modify the plan approval expiration date on Page 1 of this plan approval. The new plan approval expiration date shall be 180 days from the date of commencement of operation.

The permittee shall maintain and operate the sources and associated air cleaning devices in accordance with good engineering practice as described in the plan approval application submitted to the Department.

(a) The records, reports or information obtained by the Department or referred to at public hearings shall be available to the public, except as provided in paragraph (b) of this condition. (b) Upon cause shown by the permittee that the records, reports or information, or a particular portion thereof, but not emission data, to which the Department has access under the act, if made public, would divulge production or sales figures or methods, processes or production unique to that person or would otherwise tend to affect adversely the SECTION B. General Plan Approval Requirements
[25 Pa. Code § 121.1]

[25 Pa. Code § 127.12b (a) (b)]

[25 Pa. Code § 127.12b]

[25 Pa. Code § 127.12(a) (10)]

[25 Pa. Code §§ 127.12(c) and (d) & 35 P.S. § 4013.2]37-337A

Page 8 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: #006

#007

#008 Plan Approval terms and conditions.

Transfer of Plan Approvals

Inspection and Entry

competitive position of that person by revealing trade secrets, including intellectual property rights, the Department will consider the record, report or information, or particular portion thereof confidential in the administration of the act. The Department will implement this section consistent with sections 112(d) and 114(c) of the Clean Air Act (42 U.S.C.A. § § 7412(d) and 7414(c)). Nothing in this section prevents disclosure of the report, record or information to Federal, State or local representatives as necessary for purposes of administration of Federal, State or local air pollution control laws, or when relevant in a proceeding under the act.

[Additional authority for this condition is derived from 25 Pa. Code Section 127.13] (a) This plan approval will be valid for a limited time, as specified by the expiration date contained on Page 1 of this plan approval. Except as provided in § § 127.11a and 127.215 (relating to reactivation of sources; and reactivation), at the end of the time, if the construction, modification, reactivation or installation has not been completed, a new plan approval application or an extension of the previous approval will be required. (b) If construction has commenced, but cannot be completed before the expiration of this plan approval, an extension of the plan approval must be obtained to continue construction. To allow adequate time for departmental action, a request for the extension shall be postmarked at least thirty (30) days prior to the expiration date. The request for an extension shall include the following: (i) A justification for the extension, (ii) A schedule for the completion of the construction If construction has not commenced before the expiration of this plan approval, then a new plan approval application must be submitted and approval obtained before construction can commence. (c) If the construction, modification or installation is not commenced within 18 months of the issuance of this plan approval or if there is more than an 18-month lapse in construction, modification or installation, a new plan approval application that meets the requirements of 25 Pa. Code Chapter 127, Subchapter B (related to plan approval requirements), Subchapter D (related to prevention of significant deterioration of air quality), and Subchapter E (related to new source review) shall be submitted. The Department may extend the 18-month period upon a satisfactory showing that an extension is justified.

(a) This plan approval may not be transferred from one person to another except when a change of ownership is demonstrated to the satisfaction of the Department and the Department approves the transfer of the plan approval in writing. (b) Section 127.12a (relating to compliance review) applies to a request for transfer of a plan approval. A compliance review form shall accompany the request. (c) This plan approval is valid only for the specific source and the specific location of the source as described in the application.

(a) Pursuant to 35 P.S. § 4008, no person shall hinder, obstruct, prevent or interfere with the Department or its personnel in the performance of any duty authorized under the Air Pollution Control Act. (b) The permittee shall also allow the Department to have access at reasonable times to said sources and associated air cleaning devices with such measuring and recording equipment, including equipment recording visual observations, as the Department deems necessary and proper for performing its duties and for the effective enforcement of the Air Pollution Control Act and regulations adopted under the act. SECTION B. General Plan Approval Requirements

[25 Pa. Code § 127.12b]

[25 Pa. Code § 127.32]

[25 Pa. Code § 127.12(4) & 35 P.S. § 4008 & § 114 of the CAA]37-337A

Page 9 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: #009

#010

#011

#012 Plan Approval Changes for Cause

Circumvention

Submissions

Risk Management

(c) Nothing in this plan approval condition shall limit the ability of the Environmental Protection Agency to inspect or enter the premises of the permittee in accordance with Section 114 or other applicable provisions of the Clean Air Act.

This plan approval may be terminated, modified, suspended or revoked and reissued if one or more of the following applies: (a) The permittee constructs or operates the source subject to the plan approval in violation of the act, the Clean Air Act, the regulations promulgated under the act or the Clean Air Act, a plan approval or permit or in a manner that causes air pollution. (b) The permittee fails to properly or adequately maintain or repair an air pollution control device or equipment attached to or otherwise made a part of the source. (c) The permittee fails to submit a report required by this plan approval. (d) The Environmental Protection Agency determines that this plan approval is not in compliance with the Clean Air Act or the regulations thereunder.

(a) The permittee, or any other person, may not circumvent the new source review requirements of 25 Pa. Code Chapter 127, Subchapter E by causing or allowing a pattern of ownership or development, including the phasing, staging, delaying or engaging in incremental construction, over a geographic area of a facility which, except for the pattern of ownership or development, would otherwise require a permit or submission of a plan approval application. (b) No person may permit the use of a device, stack height which exceeds good engineering practice stack height, dispersion technique or other technique which, without resulting in reduction of the total amount of air contaminants emitted, conceals or dilutes an emission of air contaminants which would otherwise be in violation of this plan approval, the Air Pollution Control Act or the regulations promulgated thereunder, except that with prior approval of the Department, the device or technique may be used for control of malodors.

Reports, test data, monitoring data, notifications shall be submitted to the: Regional Air Program Manager PA Department of Environmental Protection (At the address given on the plan approval transmittal letter or otherwise notified)

(a) If required by Section 112(r) of the Clean Air Act, the permittee shall develop and implement an accidental release program consistent with requirements of the Clean Air Act, 40 CFR Part 68 (relating to chemical accident prevention provisions) and the Federal Chemical Safety Information, Site Security and Fuels Regulatory Relief Act (P.L. 106-40). (b) The permittee shall prepare and implement a Risk Management Plan (RMP) which meets the requirements of Section 112(r) of the Clean Air Act, 40 CFR Part 68 and the Federal Chemical Safety Information, Site Security and Fuels Regulatory Relief Act when a regulated substance listed in 40 CFR § 68.130 is present in a process in more than the listed threshold quantity at the facility. The permittee shall submit the RMP to the Environmental Protection Agency according to the following schedule and requirements: (1) The permittee shall submit the first RMP to a central point specified by the Environmental Protection Agency no later than the latest of the following: SECTION B. General Plan Approval Requirements

[25 Pa. Code 127.13a]

[25 Pa. Code §§ 121.9 & 127.216]

[25 Pa. Code § 127.12c]

[25 Pa. Code § 127.12(9) & 40 CFR Part 68]37-337A

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## PROPOSED 944870 DEP Auth ID: #013 Compliance Requirement

(i) Three years after the date on which a regulated substance is first listed under § 68.130; or, (ii) The date on which a regulated substance is first present above a threshold quantity in a process. (2) The permittee shall submit any additional relevant information requested by the Department or the Environmental Protection Agency concerning the RMP and shall make subsequent submissions of RMPs in accordance with 40 CFR § 68.190. (3) The permittee shall certify that the RMP is accurate and complete in accordance with the requirements of 40 CFR Part 68, including a checklist addressing the required elements of a complete RMP. (c) As used in this plan approval condition, the term "process" shall be as defined in 40 CFR § 68.3. The term "process" means any activity involving a regulated substance including any use, storage, manufacturing, handling, or on-site movement of such substances or any combination of these activities. For purposes of this definition, any group of vessels that are interconnected, or separate vessels that are located such that a regulated substance could be involved in a potential release, shall be considered a single process.

A person may not cause or permit the operation of a source subject to § 127.11 (relating to plan approval requirements), unless the source and air cleaning devices identified in the application for the plan approval and the plan approval issued to the source, are operated and maintained in accordance with specifications in the application and conditions in the plan approval issued by the Department. A person may not cause or permit the operation of an air contamination source subject to this chapter in a manner inconsistent with good operating practices. SECTION B. General Plan Approval Requirements

[25 Pa. Code § 127.25]37-337A

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## PROPOSED 944870 DEP Auth ID: I. RESTRICTIONS. Emission Restriction(s). # 001

# 002 [25 Pa. Code §121.7]

[25 Pa. Code §123.1] Prohibition of air pollution.

Prohibition of certain fugitive emissions No person may permit air pollution as that term is defined in the act.

(a) No person may permit the emission into the outdoor atmosphere of 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) Not applicable (8) Not applicable (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; and (ii) the emissions are not preventing or interfering with the attainment or maintenance of any 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, characteristics of emissions, quantity of emissions, and ambient air quality data and analysis showing the impact of the source on ambient air quality. The applicant shall be 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 shall 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. SECTION C. Site Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: # 003

# 004

# 005

# 006

# 007 [25 Pa. Code §123.2]

[25 Pa. Code §123.31]

[25 Pa. Code §123.41]

[25 Pa. Code §123.42]

[25 Pa. Code §127.12b] Fugitive particulate matter

Limitations

Limitations

Exceptions

Plan approval terms and conditions. (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) Not applicable

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 such emissions are visible at the point the emissions pass outside the person's property.

(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 1200F for at least 0.3 seconds 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) Not applicable

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 three minutes in any 1 hour. (2) Equal to or greater than 60% at any time.

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) Not applicable

[Plan Approval 37-337A] (a) The facility shall not permit the emission into the outdoor atmosphere of any single HAP (formaldehyde) in excess of 6.9 tpy based on a 12-month rolling total. [Compliance with the formaldehyde limit will show compliance with the total facility HAP limit based on EPA stating it is appropriate to use formaldehyde as a surrogate for all organic HAP emissions.] SECTION C. Site Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [Plan Approval 37-337A] (b) The facility shall not permit the emission into the outdoor atmosphere of total HAP in excess of 15.3 tpy based on a 12- month rolling total. [Plan Approval 37-337A] (c) The facility shall not permit the emission into the outdoor atmosphere of CO2(e) (including SF6) in excess of the following: 1. If GE7FA option is chosen: 2,909,658 tpy based on a 12-month rolling total 2. If Siemens F option is chosen: 2,997,542 tpy based on a 12-month rolling total 3. If Mitsubishi G option is chosen: 3,693,660 tpy based on a 12-month rolling total 4. If Siemens H option is chosen: 3,679,784 tpy based on a 12-month rolling total

# 008

# 009

# 010

# 011 [25 Pa. Code §123.43]

[25 Pa. Code §127.12b]

[25 Pa. Code §127.12b]

[25 Pa. Code §135.5] Measuring techniques

Plan approval terms and conditions.

Plan approval terms and conditions.

Recordkeeping 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 any devices approved by the Department.

[Plan Approval 37-337A] The permittee shall perform monitoring of the facility at least once per operating day for the presence of visible emissions, fugitive emissions, and malodors. The permittee shall take immediate corrective action to eliminate any emissions that are out of compliance. For determining visible emissions, a visual observation of the stack shall be used to determine whether or not there is a visible emission. If during this observation a visible emission is detected, a Method 9 reading shall be performed to determine compliance. Method 22 shall be used for determining fugitive emissions.

[Plan Approval 37-337A] (a) The facility shall keep adequate records to show compliance with the facility HAP emission limitations. Records shall be kept on a monthly basis and a 12-month rolling total basis. [Plan Approval 37-337A] (b) The facility shall keep records of the daily facility monitoring indicating, at a minimum, that required monitoring was performed. II.

III.

IV. TESTING REQUIREMENTS.

MONITORING REQUIREMENTS.

RECORDKEEPING REQUIREMENTS. No additional testing requirements exist except as provided in other sections of this plan approval including Section B (Plan Approval General Requirements). SECTION C. Site Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: # 012

# 013

# 014 [25 Pa. Code §127.12b]

[25 Pa. Code §135.21]

[25 Pa. Code §135.3] Plan approval terms and conditions.

Emission statements

Reporting Source owners or operators shall maintain and make available upon request by the Department records including computerized records that may be necessary to comply with § § 135.3 and 135.21 (relating to reporting; and emission statements). These may include records of production, fuel usage, maintenance of production or pollution control equipment or other information determined by the Department to be necessary for identification and quantification of potential and actual air contaminant emissions. If direct recordkeeping is not possible or practical, sufficient records shall be kept to provide the needed information by indirect means.

[Plan Approval 37-337A] The permittee shall report, within 24 hours, each malfunction that poses an imminent and substantial danger to the public health and safety or the environment or which it should reasonably believe may result in citizen complaints to the Department that occurs at this facility. For purposes of this condition, a malfunction is defined as any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, process equipment or a process to operate in a normal or usual manner that may result in an increase in the emissions of air contaminants.

(a) Except as provided in subsection (d), this section applies to stationary sources or facilities: (1) Located in an area designated by the Clean Air Act as a marginal, moderate, serious, severe or extreme ozone nonattainment area and which emit oxides of nitrogen or VOC. (2) Not located in an area described in subparagraph (1) and included in the Northeast Ozone Transport Region which emit or have the potential to emit 100 tons or more oxides of nitrogen or 50 tons or more of VOC per year. (b) The owner or operator of each stationary source emitting oxides of nitrogen or VOCs shall provide the Department with a statement, in a form as the Department may prescribe, for classes or categories of sources, showing the actual emissions of oxides of nitrogen and VOCs from that source for each reporting period, a description of the method used to calculate the emissions and the time period over which the calculation is based. The statement shall contain a certification by a company officer or the plant manager that the information contained in the statement is accurate. (c) Annual emission statements are due by March 1 for the preceding calendar year and shall provide data consistent with requirements and guidance developed by the EPA. The guidance document is available from: United States Environmental Protection Agency, 401 M. Street, S.W., Washington, D.C. 20460. The Department may require more frequent submittals if the Department determines that one or more of the following applies: (1) A more frequent submission is required by the EPA. (2) Analysis of the data on a more frequent basis is necessary to implement the requirements of the act. (d) Subsection (a) does not apply to a class or category of stationary sources which emits less than 25 tons per year of VOCs or oxides of nitrogen, if the Department in its submissions to the Administrator of the EPA under section 182(a)(1) or (3)(B)(ii) of the Clean Air Act (42 U.S.C.A. 7511a(a)(1) or (3)(B)(ii)) provides an inventory of emissions from the class or category of sources based on the use of the emission factors established by the Administrator or other methods acceptable to the Administrator. The Department will publish in the Pennsylvania Bulletin a notice of the lists of classes or categories of sources which are exempt from the emission statement requirement under this subsection.

(a) A person who owns or operates a source to which this chapter applies, and who has previously been advised by the Department to submit a source report, shall submit by March 1 of each year a source report for the preceding calendar year. The report shall include information for all previously reported sources, new sources which were first operated during the preceding calendar year and sources modified during the same period which were not previously reported. V. REPORTING REQUIREMENTS. SECTION C. Site Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: # 015

# 016 [25 Pa. Code §135.4]

[25 Pa. Code §129.14] Report format

Open burning operations (b) A person who receives initial notification by the Department that a source report is necessary shall submit an initial source report within 60 days after receiving the notification or by March 1 of the year following the year for which the report is required, whichever is later. (c) A source owner or operator may request an extension of time from the Department for the filing of a source report, and the Department may grant the extension for reasonable cause.

Source reports shall contain sufficient information to enable the Department to complete its emission inventory. Source reports shall be made by the source owner or operator in a format specified by the Department.

(a) Air basins. No person may permit the open burning of material in an air basin. (b) Not applicable (c) Exceptions: The requirements of subsections (a) and (b) do not apply where the open burning operations result from: (1) A fire set to prevent or abate a fire hazard, when approved by the Department and set by or under the supervision of a public officer. (2) A fire set for the purpose of instructing personnel in fire fighting, when approved by the Department. (3) A fire set for the prevention and control of disease or pests, when approved by the Department. (4) Not applicable (5) Not applicable (6) A fire set solely for recreational or ceremonial purposes. (7) A fire set solely for cooking food. (d) Clearing and grubbing wastes. The following is applicable to clearing and grubbing wastes: (1) As used in this subsection the following terms shall have the following meanings: Air curtain destructor -- A mechanical device which forcefully projects a curtain of air across a pit in which open burning is being conducted so that combustion efficiency is increased and smoke and other particulate matter are contained. Clearing and grubbing wastes -- Trees, shrubs, and other native vegetation which are cleared from land during or prior to the process of construction. The term does not include demolition wastes and dirt laden roots. (2) Subsection (a) notwithstanding, clearing and grubbing wastes may be burned in a basin subject to the following requirements: (i) Air curtain destructors shall be used when burning clearing and grubbing wastes. (ii) Each proposed use of air curtain destructors shall be reviewed and approved by the Department in writing with respect to equipment arrangement, design and existing environmental conditions prior to commencement of burning. Proposals approved under this subparagraph need not obtain plan approval or operating permits under Chapter 127 (relating to construction modification, reactivation and operation of sources). VI. WORK PRACTICE REQUIREMENTS. SECTION C. Site Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: # 017 [25 Pa. Code §127.12b] Plan approval terms and conditions. (iii) Approval for use of an air curtain destructor at one site may be granted for a specified period not to exceed 3 months, but may be extended for additional limited periods upon further approval by the Department. (iv) The Department reserves the right to rescind approval granted if a determination by the Department indicates that an air pollution problem exists. (3) Not applicable (4) During an air pollution episode, open burning is limited by Chapter 137 (relating to air pollution episodes) and shall cease as specified in such chapter.

[Plan Approval 37-337A] (a) Nothing in this plan approval shall relieve the owner or operator from complying with any local zoning ordinances. [Plan Approval 37-337A] (b) Emission Reduction Credit Requirements 1. The permittee shall not operate the source(s) until the required emission reduction credits are provided to and processed through the ERC registry in accordance with 25 PA Code 127.206(d)(1) and the Department certifies the required emissions reductions. 2. The permittee shall secure NOx and VOC ERCs. ERCs shall be properly generated and certified by the Department. Upon transfer, the permittee shall provide the Department with documentation clearly specifying the details of the ERC transaction. The facility NOx PTE is based on 1.01 tpy for the Auxiliary Boiler, 0.49 tpy for the Emergency Generator, 0.09 tpy for the Emergency Fire Pump, and the NOx PTE for the Combined Cycle Units. The facility VOC PTE is based on 0.14 tpy for the Auxiliary Boiler, 0.03 tpy for the Emergency Generator, 0.06 tpy for the Emergency Fire Pump, and the VOC PTE for the Combined Cycle Units. The NOx and VOC PTE for the GE 7FA is 296.06 tpy and 203.72 tpy resulting in a facility NOx and VOC PTE of 297.65 tpy and 203.95 tpy. The NOx and VOC PTE for the Siemens F is 298.0 tpy and 157.16 tpy resulting in a facility NOx and VOC PTE of 299.59 tpy and 157.39 tpy. The NOx and VOC PTE for the Mitsubishi G is 248.52 tpy and 187.62 tpy resulting in a facility NOx and VOC PTE of 250.11 tpy and 187.85 tpy. The NOx and VOC PTE for the Siemens H is 344.5 tpy and 186.88 tpy resulting in a facility NOx and VOC PTE of 346.09 tpy and 187.11 tpy. The permittee shall obtain the following NOx and VOC ERCs based on the facility NOx and VOC PTE times the offset of 1.15: (a) GE 7FA: NOx - 342.3 tons and VOC - 234.6 tons (b) Siemens F: NOx - 344.6 tons and VOC 181.0 tons (c) Mitsubishi G: NOx - 287.7 tons and VOC 216.1 tons (d) Siemens H: NOx - 398.1 tons and VOC 215.2 tons 3. If the amount of required emission reduction credits increases, the company shall secure emission offsets according to a schedule determined by the Department. VIII. COMPLIANCE CERTIFICATION.

IX. COMPLIANCE SCHEDULE. No compliance milestones exist. VII. ADDITIONAL REQUIREMENTS. SECTION C. Site Level Plan Approval Requirements

No additional compliance certifications exist except as provided in other sections of this plan approval including Section B (relating to Plan Approval General Requirements).37-337A

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## PROPOSED 944870 DEP Auth ID: Source ID: Source Name:

031 COMBINED CYCLE UNIT #1

Source Capacity/Throughput:

FML FML01 CU 031 CNTL

C031A CNTL

C031B STAC

S031 3.400 MMCF/HR Natural Gas

I. RESTRICTIONS. Emission Restriction(s). # 001 [25 Pa. Code §127.12b] Plan approval terms and conditions. [Plan Approval 37-337A] (a) The Permittee shall select and install any of the turbine options listed below (or newer versions of these turbines if the Department determines that such newer versions achieve equivalent or better emissions rates and exhaust parameters) as part of the CCUs at the facility: 1. General Electric 7FA (GE 7FA) 2. Siemens SGT6-5000F (Siemens F) 3. Mitsubishi M501G (Mitsubishi G) 4. Siemens SGT6-8000H (Siemens H) [Plan Approval 37-337A] (b) No person may permit the emission from each CCU into the outdoor atmosphere of the following in a manner that exceeds the following: 1. GE 7FA (a) Nitrogen Oxides (NOx): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4320)] (ii) Normal operation with duct burner: 23.65 #/hr (iii) Normal operation without duct burner: 19.76 #/hr (iv) Total normal operation: 86.92 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 148.03 tpy based on a 12-month rolling total (b) Carbon Monoxide (CO): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 14.4 #/hr (iii) Normal operation without duct burner: 12.03 #/hr (iv) Total normal operation: 52.92 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 246.81 tpy based on a 12-month rolling total (c) Volatile Organic Compounds (VOC): (i) Normal operation with or without duct burner: 1.5 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 6.19 #/hr (iii) Normal operation without duct burner: 5.17 #/hr (iv) Total normal operation: 22.73 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 101.86 tpy based on a 12-month rolling total (d) Sulfur Oxides (SOx): (i) Normal operation with duct burner: 5.8 #/hr SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (ii) Normal operation without duct burner: 4.76 #/hr (iii) Total normal operation: 21.14 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 22.34 tpy based on a 12-month rolling total (v) Total per calendar day: 139.1 #/day (e) Sulfuric Acid (H2SO4): (i) Normal operation with duct burner: 0.87 #/hr (ii) Normal operation without duct burner: 0.71 #/hr (iii) Total normal operation: 3.17 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 3.35 tpy based on a 12-month rolling total (f) Particulate Matter (PM)/Particulate Matter 10 (PM10)/Particulate Matter 2.5 (PM2.5): (i) Normal operation with duct burner: 17.5 #/hr (ii) Normal operation without duct burner: 10.0 #/hr (iii) Total normal operation: 55.05 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 58.85 tpy based on a 12-month rolling total (v) Total per calendar day: 329.7 #/day for PM10/PM2.5 (g) Ammonia Slip (NH3): (i) Total normal operation: 87.5 tpy based on a 12-month rolling total 2. Siemens F (a) Nitrogen Oxides (NOx): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4320)] (ii) Normal operation with duct burner: 24.45 #/hr (iii) Normal operation without duct burner: 20.53 #/hr (iv) Total normal operation: 90.07 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 149.0 tpy based on a 12-month rolling total (b) Carbon Monoxide (CO): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 14.89 #/hr (iii) Normal operation without duct burner: 12.5 #/hr (iv) Total normal operation: 54.83 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 213.9 tpy based on a 12-month rolling total (c) Volatile Organic Compounds (VOC): (i) Normal operation with or without duct burner: 1.5 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 6.39 #/hr (iii) Normal operation without duct burner: 5.37 #/hr (iv) Total normal operation: 23.56 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 78.58 tpy based on a 12-month rolling total (d) Sulfur Oxides (SOx): (i) Normal operation with duct burner: 5.96 #/hr (ii) Normal operation without duct burner: 4.92 #/hr (iii) Total normal operation: 21.78 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 23.02 tpy based on a 12-month rolling total (v) Total per calendar day: 142.9 #/day (e) Sulfuric Acid (H2SO4): (i) Normal operation with duct burner: 0.89 #/hr (ii) Normal operation without duct burner: 0.74 #/hr (iii) Total normal operation: 3.27 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 3.45 tpy based on a 12-month rolling total (f) Particulate Matter (PM)/Particulate Matter 10 (PM10)/Particulate Matter 2.5 (PM2.5): (i) Normal operation with duct burner: 17.5 #/hr (ii) Normal operation without duct burner: 10.0 #/hr (iii) Total normal operation: 55.05 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 58.98 tpy based on a 12-month rolling total (v) Total per calendar day: 331.1 #/day for PM10/PM2.5 SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (g) Ammonia Slip (NH3): (i) Total normal operation: 90.8 tpy based on a 12-month rolling total 3. Mitsubushi G (a) Nitrogen Oxides (NOx): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4320)] (ii) Normal operation with duct burner: 29.29 #/hr (iii) Normal operation without duct burner: 25.45 #/hr (iv) Total normal operation: 109.61 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 124.26 tpy based on a 12-month rolling total (b) Carbon Monoxide (CO): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 17.83 #/hr (iii) Normal operation without duct burner: 15.5 #/hr (iv) Total normal operation: 66.74 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 401.88 tpy based on a 12-month rolling total (c) Volatile Organic Compounds (VOC): (i) Normal operation with or without duct burner: 1.5 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 7.66 #/hr (iii) Normal operation without duct burner: 6.66 #/hr (iv) Total normal operation: 28.67 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 93.81 tpy based on a 12-month rolling total (d) Sulfur Oxides (SOx): (i) Normal operation with duct burner: 7.22 #/hr (ii) Normal operation without duct burner: 6.17 #/hr (iii) Total normal operation: 26.82 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 28.26 tpy based on a 12-month rolling total (v) Total per calendar day: 173.1 #/day (e) Sulfuric Acid (H2SO4): (i) Normal operation with duct burner: 1.08 #/hr (ii) Normal operation without duct burner: 0.93 #/hr (iii) Total normal operation: 4.03 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 4.26 tpy based on a 12-month rolling total (f) Particulate Matter (PM)/Particulate Matter 10 (PM10)/Particulate Matter 2.5 (PM2.5): (i) Normal operation with duct burner: 19.5 #/hr (ii) Normal operation without duct burner: 12.0 #/hr (iii) Total normal operation: 63.06 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 66.91 tpy based on a 12-month rolling total (v) Total per calendar day: 377.7 #/day for PM10/PM2.5 (g) Ammonia Slip (NH3): (i) Total normal operation: 110.6 tpy based on a 12-month rolling total 4. Siemens H (a) Nitrogen Oxides (NOx): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4320)] (ii) Normal operation with duct burner: 29.2 #/hr (iii) Normal operation without duct burner: 25.36 #/hr (iv) Total normal operation: 109.24 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 172.25 tpy based on a 12-month rolling total (b) Carbon Monoxide (CO): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 17.78 #/hr SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: # 002 [25 Pa. Code §127.12b] Plan approval terms and conditions. (iii) Normal operation without duct burner: 15.44 #/hr (iv) Total normal operation: 66.5 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 267.32 tpy based on a 12-month rolling total (c) Volatile Organic Compounds (VOC): (i) Normal operation with or without duct burner: 1.5 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 7.64 #/hr (iii) Normal operation without duct burner: 6.63 #/hr (iv) Total normal operation: 28.57 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 93.44 tpy based on a 12-month rolling total (d) Sulfur Oxides (SOx): (i) Normal operation with duct burner: 7.19 #/hr (ii) Normal operation without duct burner: 6.15 #/hr (iii) Total normal operation: 26.72 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 28.15 tpy based on a 12-month rolling total (v) Total per calendar day: 172.4 #/day (e) Sulfuric Acid (H2SO4): (i) Normal operation with duct burner: 1.08 #/hr (ii) Normal operation without duct burner: 0.92 #/hr (iii) Total normal operation: 4.01 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 4.24 tpy based on a 12-month rolling total (f) Particulate Matter (PM)/Particulate Matter 10 (PM10)/Particulate Matter 2.5 (PM2.5): (i) Normal operation with duct burner: 18.5 #/hr (ii) Normal operation without duct burner: 11.0 #/hr (iii) Total normal operation: 59.06 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 62.89 tpy based on a 12-month rolling total (v) Total per calendar day: 353.7 #/day for PM10/PM2.5 (g) Ammonia Slip (NH3): (i) Total normal operation: 110.2 tpy based on a 12-month rolling total [Plan Approval 37-337A] (c) The emission limitations for NOx and CO are 3-hour rolling averages calculated once per hour and verified by CEMS. The emission limitations for VOC, SOx, H2SO4, and PM/PM10/PM2.5 are 1-hour based on the average of three stack test runs. [Plan Approval 37-337A] (d) No person may permit the emission into the outdoor atmosphere of the following in a manner that exceeds the following: 1. Ammonia Slip (NH3 Slip) - 5 ppmv, on a dry basis corrected @ 15% oxygen, 3-hour rolling averages calculated once per hour and verified by CEMS or as determined by USEPA Conditional Test Method (CTM-027), 'Procedure for Collection and Analysis of Ammonia in Stationary Sources' or other procedure approved by the Department. 2. 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: (a) Equal to or greater than 10% for a period or periods aggregating more than 3 minutes in any 1 hour. (b) Equal to or greater than 10% for a period or periods aggregating more than 6 minutes during startup and shutdown. [This condition also assures compliance with 25 PA Code 123.41]

The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: # 003 [25 Pa. Code §127.12b] Plan approval terms and conditions. (a) No person may permit the emission into the outdoor atmosphere of the following in a manner that exceeds the following: 1. CO2 emission rate of 1,000 # / MW-hr (gross) on a 12-operating month annual average basis [Plan Approval 37-337A] (b) No person may permit the emission into the outdoor atmosphere of CO2(e) in excess of the following: 1. If GE7FA option is chosen: 2,895,848 tpy based on a 12-month rolling total for both units 2. If Siemens F option is chosen: 2,983,732 tpy based on a 12-month rolling total for both units 3. If Mitsubishi G option is chosen: 3,679,850 tpy based on a 12-month rolling total for both units 4. If Siemens H option is chosen: 3,665,974 tpy based on a 12-month rolling total for both units

[Plan Approval 37-337A] (a) The startup and shutdown emissions from each CCU shall be limited to the following: 1. GE 7FA (a) NOx: S/U: 43.3 tpy & S/D: 17.81 tpy (b) CO: S/U: 150.35 tpy & S/D: 43.54 tpy (c) VOC: S/U: 61.98 tpy & S/D: 17.15 tpy (d) SOx: S/U: 0.87 tpy & S/D: 0.33 tpy (e) H2SO4: S/U: 0.13 tpy & S/D: 0.05 tpy (f) PM/PM10/PM2.5: S/U: 2.42 tpy & S/D: 1.38 tpy 2. Siemens F (a) NOx: S/U: 40.53 tpy & S/D: 18.41 tpy (b) CO: S/U: 114.06 tpy & S/D: 45.0 tpy (c) VOC: S/U: 37.3 tpy & S/D: 17.73 tpy (d) SOx: S/U: 0.9 tpy & S/D: 0.34 tpy (e) H2SO4: S/U: 0.14 tpy & S/D: 0.05 tpy (f) PM/PM10/PM2.5: S/U: 2.5 tpy & S/D: 1.43 tpy 3. Mitsubushi G (a) NOx: S/U: 9.95 tpy & S/D: 4.7 tpy (b) CO: S/U: 264.8 tpy & S/D: 70.34 tpy (c) VOC: S/U: 44.91 tpy & S/D: 20.24 tpy (d) SOx: S/U: 1.07 tpy & S/D: 0.38 tpy (e) H2SO4: S/U: 0.17 tpy & S/D: 0.06 tpy (f) PM/PM10/PM2.5: S/U: 2.53 tpy & S/D: 1.32 tpy 4. Siemens H (a) NOx: S/U: 44.73 tpy & S/D: 18.28 tpy (b) CO: S/U: 149.72 tpy & S/D: 51.09 tpy (c) VOC: S/U: 44.72 tpy & S/D: 20.16 tpy (d) SOx: S/U: 1.07 tpy & S/D: 0.38 tpy (e) H2SO4: S/U: 0.17 tpy & S/D: 0.06 tpy (f) PM/PM10/PM2.5: S/U: 2.52 tpy & S/D: 1.31 tpy SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: Fuel Restriction(s).

Operation Hours Restriction(s). # 004

# 005

# 006

# 007

# 008 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4320]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4325]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4330]

[25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines What emission limits must I meet for nitrogen oxides (NOX)?

What emission limits must I meet for NOX if my turbine burns both natural gas and distillate oil (or some other combination of fuels)?

What emission limits must I meet for sulfur dioxide (SO2)?

Plan approval terms and conditions.

Plan approval terms and conditions. [Compliance with the NOx limit of 2.0 ppmvd @ 15% oxygen for the CCU under 127.12b will show compliance with this requirement] (a) You must meet the emission limits for NOX specified in Table 1 to this subpart. [From Table 1: For new turbine firing natural gas and > 850 mmbtu/hr: 15 ppm at 15% O2 or 54 ng/J of useful output (0.43 #/MWh) and For heat recovery units operating independent of the combustion turbine: 54 ppm @ 15% O2 or 110 ng/J of useful output (0.86 #/MWh)] (b) If you have two or more turbines that are connected to a single generator, each turbine must meet the emission limits for NOX .

Not applicable

[Compliance with the sulfur limit in the fuel of 0.75 gr / 100 scf natural gas under 127.12b will show compliance with this requirement] (a) If your turbine is located in a continental area, you must comply with either paragraph (a)(1), (a)(2), or (a)(3) of this section. If your turbine is located in Alaska, you do not have to comply with the requirements in paragraph (a) of this section until January 1, 2008. (1) You must not cause to be discharged into the atmosphere from the subject stationary combustion turbine any gases which contain SO2 in excess of 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour (lb/MWh)) gross output; (2) You must not burn in the subject stationary combustion turbine any fuel which contains total potential sulfur emissions in excess of 26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input. If your turbine simultaneously fires multiple fuels, each fuel must meet this requirement; or (3) Not applicable (b) Not applicable

[Plan Approval 37-337A] The source shall fire only natural gas that has a sulfur content not to exceed 0.75 gr / 100 scf natural gas. [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4330) and 25 PA Code 123.22(c)]

[Plan Approval 37-337A] (a) Startup is defined as the period beginning with ignition in the combustion turbine and lasting until either: 1. The combustion process, air pollution control equipment, and associated control systems have attained normal operating conditions for two consecutive 15-minute averaging periods, or SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b] # 009 Plan approval terms and conditions. [Plan Approval 37-337A] (a) Within 60 days after achieving the normal production rate at which the affected source will be operated, but not later than 180 days after initial start-up of the source/control device, a stack test for PM (filterable & condensable), PM10 (filterable & condensable), PM2.5 (filterable & condensable), NOx, SOx, CO, VOC, ammonia slip, sulfuric acid, and HAPs (Formaldehyde) shall be performed in accordance with the provisions of Chapter 139 of the Rules and Regulations of the Department of Environmental Protection. The stack test shall be performed while the aforementioned source is operating at greater than 90% of the rated capacity. Any testing performed at less than 90% of the rated capacity may subject the facility to a production limit of the production rate during the compliant testing. The stack test shall be conducted at the outlet of the control device. 1. [25 Pa. Code § 139.53(a)(3)] At least 60 calendar days prior to commencing an emissions testing program, a test protocol shall be submitted to the Department's Division of Source Testing and Monitoring and two copies to the appropriate Regional Office Department for review and approval. The test protocol shall meet all applicable requirements specified in the most current version of the Department's Source Testing Manual. 2. [25 Pa. Code § 139.53(a)(3)] At least 15 calendar days prior to commencing an emission testing program, notification as to the date and time of testing shall be given to the appropriate Regional Office. Notification shall also be sent to the Division of Source Testing and Monitoring. Notification shall not be made without prior receipt of a protocol acceptance letter from the Department. 3. [25 Pa. Code § 139.53(a)(3)] Within 15 calendar days after completion of the on-site testing portion of an emission test program, if a complete test report has not yet been submitted, an electronic mail notification shall be sent to the Department's Division of Source Testing and Monitoring and the appropriate Regional Office indicating the completion date of the on-site testing. 4. [40 CFR Part 60.8(a), 40 CFR Part 61.13(f) and 40 CFR Part 63.7(g)] A complete test report shall be submitted to the Department no later than 60 calendar days after completion of the on-site testing portion of an emission test program. For those tests being conducted pursuant to 40 CFR Part 61, a complete test report shall be submitted within 31 days after completion of the test. 5. [25 Pa. Code Section 139.53(b)] A complete test report shall include a summary of the emission results on the first pageof the report indicating if each pollutant measured is within permitted limits and a statement of compliance or noncompliance with all applicable permit conditions. The summary results will include, at a minimum, the following information: II. TESTING REQUIREMENTS. 2. Five hours after ignition, whichever occurs first. [Plan Approval 37-337A] (b) Startup shall be limited to 500 total hours in any consecutive 12-month period. [Plan Approval 37-337A] (c) Shutdown is defined as the period beginning with the lowering of unit load below 60% with the intent of ceasing operation of the unit and concluding with the cessation of combustion in the turbine, limited to a maximum of one hour in duration. [Plan Approval 37-337A] (d) Shutdown shall be limited to 250 total hours in any consecutive 12-month period. [Plan Approval 37-337A] (e) Malfunction is defined as any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner that may result in an increase in the emissions of air contaminants. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (a) A statement that the owner or operator has reviewed the report from the emissions testing body and agrees with the findings. (b) Permit number(s) and condition(s) which are the basis for the evaluation. (c) Summary of results with respect to each applicable permit condition. (d) Statement of compliance or non-compliance with each applicable permit condition. 6. [25 Pa. Code § 139.3] All submittals shall meet all applicable requirements specified in the most current version of the Department's Source Testing Manual. 7. All testing shall be performed in accordance with the provisions of Chapter 139 of the Rules and Regulations of the Department of Environmental Protection. 8. [25 Pa. Code Section 139.53(a)(1) and 139.53(a)(3)] All submittals, besides notifications, shall be accomplished through PSIMS*Online available through https://www.depgreenport.state.pa.us/ecomm/Login.jsp when it becomes available. If internet submittal cannot be accomplished, one copy of the submittal shall be sent to the Pennsylvania Department of Environmental Protection, Bureau of Air Quality, Division of Source Testing and Monitoring, 400 Market Street, 12th Floor Rachael Carson State Office Building, Harrisburg, PA 17105-8468 with deadlines verified through document postmarks. In a like manner, two copies of the submittal shall be sent to the appropriate Regional Office. 9. The permittee shall ensure all federal reporting requirements contained in the applicable subpart of 40 CFR are followed, including timelines more stringent than those contained herein. In the event of an inconsistency or any conflicting requirements between state and the federal, the most stringent provision, term, condition, method or rule shall be used by default. 10. Actions Related to Noncompliance Demonstrated by a Stack Test: (a) If the results of a stack test, performed as required by this approval, exceed the level specified in any condition of this approval, the Permittee shall take appropriate corrective actions. Within 30 days of the Permittee receiving the stack test results, a written description of the corrective actions shall be submitted to the Department. The Permittee shall take appropriate action to minimize emissions from the affected facility while the corrective actions are being implemented. The Department shall notify the Permittee within 30 days, if the corrective actions taken are deficient. Within 30 days of receipt of the notice of deficiency, the Permittee shall submit a description of additional corrective actions to the Department. The Department reserves the authority to use enforcement activities to resolve noncompliant stack tests. (b) If the results of the required stack test exceed any limit defined in this plan approval, the test was not performed in accordance with the stack test protocol or the source and/or air cleaning device was not operated in accordance with the plan approval, then another stack test shall be performed to determine compliance. Within 120 days of the Permittee receiving the original stack test results, a retest shall be performed. The Department may extend the retesting deadline if the Permittee demonstrates, to the Department's satisfaction, that retesting within 120 days is not practicable. Failure of the second test to demonstrate compliance with the limits in the plan approval, not performing the test in accordance with the stack test protocol or not operating the source and/or air cleaning device in accordance with the plan approval may be grounds for immediate revocation of the plan approval to operate the affected source. [Plan Approval 37-337A] (b) The facility shall perform subsequent stack test for PM (filterable & condensable), PM10 (filterable & condensable), PM2.5 (filterable & condensable), VOC, sulfuric acid, and HAPs (Formaldehyde) in accordance with the provisions in part (a) every two years (22 to 26 months after the date of the previous test). The stack test shall be performed while the aforementioned source is operating at greater than 90% of the rated capacity. Any testing performed at less than 90% of the rated capacity may subject the facility to a production limit of the production rate during the compliant testing. The stack test shall be conducted at the outlet of the control device. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4400] # 010

# 011 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines Plan approval terms and conditions.

How do I conduct the initial and subsequent performance tests, regarding NOX ? [Plan Approval 37-337A] (a) Initial Application (Phase I): Proposal[s] containing information as listed in the Phase I section of the Department's Continuous Source Monitoring Manual for the CEMS[s] must be submitted at least 180 days prior to the planned initial source startup date. [Plan Approval 37-337A] (b) Performance Testing (Phase II): Testing as listed in the Phase II section of the Department's Continuous Source Monitoring Manual must be completed for the CEMS[s] no later than 180 days after initial source startup date and no later than 60 days after source achieves normal process capacity. [Plan Approval 37-337A] (c) Final Approval (Phase III): The final report of testing as listed in the Phase III section of the Department's Continuous Source Monitoring Manual must be submitted to the Bureau no later than 60 days after completion of testing. [Plan Approval 37-337A] (d) The owner or operator of the source shall not be issued an operating permit until the CEMS has received Phase III approval, in writing from the Department, when installation of a CEMS is made a condition of the plan approval. Until Phase III Department approval is obtained, operation shall be covered solely under condition of a plan approval.

(a) You must conduct an initial performance test, as required in § 60.8. Subsequent NOX performance tests shall be conducted on an annual basis (no more than 14 calendar months following the previous performance test). (1) There are two general methodologies that you may use to conduct the performance tests. For each test run: (i) Not applicable (ii) Measure the NOX and diluent gas concentrations, using either EPA Methods 7E and 3A, or EPA Method 20 in appendix A of this part. Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), and measure the electrical and thermal output of the unit. Use EPA Method 19 in appendix A of this part to calculate the NOX emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in § 60.4350(f) to calculate the NOX emission rate in lb/MWh. (2) Sampling traverse points for NOX and (if applicable) diluent gas are to be selected following EPA Method 20 or EPA Method 1 (non-particulate procedures), and sampled for equal time intervals. The sampling must be performed with a traversing single-hole probe, or, if feasible, with a stationary multi-hole probe that samples each of the points sequentially. Alternatively, a multi-hole probe designed and documented to sample equal volumes from each hole may be used to sample simultaneously at the required points. (3) Notwithstanding paragraph (a)(2) of this section, you may test at fewer points than are specified in EPA Method 1 or EPA Method 20 in appendix A of this part if the following conditions are met: (i) You may perform a stratification test for NOX and diluent pursuant to (A) [Reserved], or (B) The procedures specified in section 6.5.6.1(a) through (e) of appendix A of part 75 of this chapter. (ii) Once the stratification sampling is completed, you may use the following alternative sample point selection criteria for the performance test: (A) If each of the individual traverse point NOX concentrations is within ±10 percent of the mean concentration for all traverse SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4405]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4410] # 012

# 013 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I perform the initial performance test if I have chosen to install a NOX-diluent CEMS?

How do I establish a valid parameter range if I have chosen to continuously monitor parameters? points, or the individual traverse point diluent concentrations differs by no more than ±5ppm or ±0.5 percent CO2 (or O2 ) from the mean for all traverse points, then you may use three points (located either 16.7, 50.0 and 83.3 percent of the way across the stack or duct, or, for circular stacks or ducts greater than 2.4 meters (7.8 feet) in diameter, at 0.4, 1.2, and 2.0 meters from the wall). The three points must be located along the measurement line that exhibited the highest average NOX concentration during the stratification test; or (B) Not applicable (C) For turbines with a NOX standard less than or equal to 15 ppm @ 15% O2, you may sample at a single point, located at least 1 meter from the stack wall or at the stack centroid if each of the individual traverse point NOX concentrations is within ±2.5 percent of the mean concentration for all traverse points, or the individual traverse point diluent concentrations differs by no more than ±1ppm or ±0.15 percent CO2 (or O2) from the mean for all traverse points. (b) The performance test must be done at any load condition within plus or minus 25 percent of 100 percent of peak load. You may perform testing at the highest achievable load point, if at least 75 percent of peak load cannot be achieved in practice. You must conduct three separate test runs for each performance test. The minimum time per run is 20 minutes. (1) Not applicable (2) For a combined cycle and CHP turbine systems with supplemental heat (duct burner), you must measure the total NOx emissions after the duct burner rather than directly after the turbine. The duct burner must be in operation during the performance test. (3) Not applicable (4) Compliance with the applicable emission limit in § 60.4320 must be demonstrated at each tested load level. Compliance is achieved if the three-run arithmetic average NOx emission rate at each tested level meets the applicable emission limit in § 60.4320. (5) If you elect to install a CEMS, the performance evaluation of the CEMS may either be conducted separately or (as described in § 60.4405) as part of the initial performance test of the affected unit. (6) The ambient temperature must be greater than 0°F during the performance test.

If you elect to install and certify a NOX - diluent CEMS under § 60.4345, then the initial performance test required under § 60.8 may be performed in the following alternative manner: (a) Perform a minimum of nine RATA reference method runs, with a minimum time per run of 21 minutes, at a single load level, within plus or minus 25 percent of 100 percent of peak load. The ambient temperature must be greater than 0°F during the RATA runs. (b) For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) and measure the electrical and thermal output from the unit. (c) Use the test data both to demonstrate compliance with the applicable NOX emission limit under § 60.4320 and to provide the required reference method data for the RATA of the CEMS described under § 60.4335. (d) Compliance with the applicable emission limit in § 60.4320 is achieved if the arithmetic average of all of the NOX emission rates for the RATA runs, expressed in units of ppm or lb/MWh, does not exceed the emission limit. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4415]

[25 Pa. Code §123.51] # 014

# 015 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I conduct the initial and subsequent performance tests for sulfur?

Monitoring requirements Not applicable

(a) You must conduct an initial performance test, as required in § 60.8. Subsequent SO2 performance tests shall be conducted on an annual basis (no more than 14 calendar months following the previous performance test). There are three methodologies that you may use to conduct the performance tests. (1) If you choose to periodically determine the sulfur content of the fuel combusted in the turbine, a representative fuel sample would be collected following ASTM D5287 (incorporated by reference, see § 60.17) for natural gas or ASTM D4177 (incorporated by reference, see § 60.17) for oil. Alternatively, for oil, you may follow the procedures for manual pipeline sampling in section 14 of ASTM D4057 (incorporated by reference, see § 60.17). The fuel analyses of this section may be performed either by you, a service contractor retained by you, the fuel vendor, or any other qualified agency. Analyze the samples for the total sulfur content of the fuel using: (i) Not applicable (ii) For gaseous fuels, ASTM D1072, or alternatively D3246, D4084, D4468, D4810, D6228, D6667, or Gas Processors Association Standard 2377 (all of which are incorporated by reference, see § 60.17). (2) Measure the SO2 concentration (in parts per million (ppm)), using EPA Methods 6, 6C, 8, or 20 in appendix A of this part. In addition, the American Society of Mechanical Engineers (ASME) standard, ASME PTC 19-10-1981-Part 10, “Flue and Exhaust Gas Analyses,” manual methods for sulfur dioxide (incorporated by reference, see § 60.17) can be used instead of EPA Methods 6 or 20. For units complying with the output based standard, concurrently measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix A of this part, and measure and record the electrical and thermal output from the unit. Then use the following equation from 40 CFR 60.4415(a)(2) to calculate the SO2 emission rate. (3) Measure the SO2 and diluent gas concentrations, using either EPA Methods 6, 6C, or 8 and 3A, or 20 in appendix A of this part. In addition, you may use the manual methods for sulfur dioxide ASME PTC 19-10-1981-Part 10 (incorporated by reference, see 60.17). Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), and measure the electrical and thermal output of the unit. Use EPA Method 19 in appendix A of this part to calculate the SO2 emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in 60.4350(f) to calculate the SO2 emission rate in lb/MWh. (b) [Reserved]

(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 statutory 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. III. MONITORING REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 016

# 017 Plan approval terms and conditions.

Plan approval terms and conditions. (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.

[Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.6 & §64.3] (a) The permittee shall use the approved process parameter(s) or indicator(s) to obtain data and monitor the emission control equipment performance. 1. Oxidation Catalyst (a) Catalyst Temperature [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.6 & §64.3] (b) The permittee shall use the approved mean(s) or device(s) to measure the applicable indicator(s). 1. Oxidation Catalyst (a) Thermocouple or equivalent [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.3 & §64.6] (c) The permittee shall use the approved frequency for conducting monitoring of indicators. 1. Oxidation Catalyst (a) Catalyst Temperature - continuously meaning a reading at least once every 15-minutes [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.3] (d) The permittee shall use the approved period over which discrete data points for approved indicators will be collected and averaged for the purpose of determining an excursion. 1. Oxidation Catalyst (a) Catalyst Temperature - averaged over a 3-hour period

[Plan Approval 37-337A] (a) The following continuous emission monitoring system[s] (CEMS[s]) must be installed, approved by the Department, operated and maintained in accordance with the requirements of 25 Pa. Code Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources), and the 'Submittal and Approval', 'Record Keeping and Reporting', and 'Quality Assurance' requirements of Revision No. 8 of the Department's Continuous Source Monitoring Manual, 274-0300-001. 1. CEMS #1 SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (a) Source Combination to be Monitored: Combined Cycle Unit #1 (b) Parameter to be Reported: CO (c) Units of Measurement to be Reported: ppmvd (d) Moisture Basis of Measurement to be Reported: dry (e) Correction basis of Measurements to be Reported: 15% O2 (f) Data Substitution Required: No (g) Emission Standards (1) Emission Standard # 1: (a) Emission Standard Averaging Period Description: 3-hour rolling average, calculated once per hour (b) Emission Standard Value: 2.0 ppmvd corrected to 15% O2 (c) Emission Standard Direction: Violation if greater than emission standard value (d) Variable Emission Standard: No 2. CEMS #2 (a) Source Combination to be Monitored: Combined Cycle Unit #1 (b) Parameter to be Reported: NOx (c) Units of Measurement to be Reported: ppmvd (d) Moisture Basis of Measurement to be Reported: dry (e) Correction basis of Measurements to be Reported: 15% O2 (f) Data Substitution Required: No (g) Emission Standards (1) Emission Standard # 1 (a) Emission Standard Averaging Period Description: 3-hour rolling average, calculated once per hour (b) Emission Standard Value: 2.0 ppmvd corrected to 15% O2 (c) Emission Standard Direction: Violation if greater than emission standard value (d) Variable Emission Standard: No 3. CEMS #3 [This will consist of continuous measurement of CO2 in the exhaust of each CCU and calculation of combined mass emission rate from CCU #1 and CCU#2; continuous measurement of gross electrical output of the facility; and calculation of pounds of CO2 per gross MW-hour on a 12-month rolling average, calculated monthly] (a) Source Combination to be Monitored: Combined Cycle Unit #1 & #2 SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (b) Parameter to be Reported: CO2 (c) Units of Measurement to be Reported: lbs per hr (d) Moisture Basis of Measurement to be Reported: NA (e) Correction basis of Measurements to be Reported: None (f) Data Substitution Required: Yes (g) Emission Standards (1) Emission Standard # 1 (a) Emission Standard Averaging Period Description: 12-month sum, calculated monthly (b) Emission Standard Value: None (c) Emission Standard Direction: Not applicable (d) Variable Emission Standard: No 4. CEMS #4 [This will consist of continuous measurement of CO2 in the exhaust of each CCU and calculation of combined mass emission rate from CCU #1 and CCU#2; continuous measurement of gross electrical output of the facility; and calculation of pounds of CO2 per gross MW-hour on a 12-month rolling average, calculated monthly] (a) Source Combination to be Monitored: Combined Cycle Unit #1 & #2 (b) Parameter to be Reported: Gross Electrical Outlet (GEO) (c) Units of Measurement to be Reported: MW-hr (gross) (d) Moisture Basis of Measurement to be Reported: NA (e) Correction basis of Measurements to be Reported: None (f) Data Substitution Required: Yes (g) Emission Standards (1) Emission Standard # 1 (a) Emission Standard Averaging Period Description: 12-month sum, calculated monthly (b) Emission Standard Value: None (c) Emission Standard Direction: Not applicable (d) Variable Emission Standard: No 5. CEMS #5 (a) Source Combination to be Monitored: Combined Cycle Unit #1 (b) Parameter to be Reported: Ammonia SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §139.101] # 018 General requirements. (c) Units of Measurement to be Reported: ppmvd (d) Moisture Basis of Measurement to be Reported: dry (e) Correction basis of Measurements to be Reported: 15% O2 (f) Data Substitution Required: No (g) Emission Standards (1) Emission Standard # 1 (a) Emission Standard Averaging Period Description: 3-hour rolling average, calculated once per hour (b) Emission Standard Value: 5.0 (c) Emission Standard Direction: Violation if greater than emission standard value (d) Variable Emission Standard: No [Plan Approval 37-337A] (b) Compliance with any subsequently issued revisions to the Continuous Source Monitoring Manual will constitute compliance with the regulations. [Plan Approval 37-337A] (c) The facility shall show compliance with the CO2 limit by 1. Determining Monthly CO2 emission Rate, R(i) R(i) = (Monthly Sum, CO2 [lbs]) / (Monthly Sum, GEO [MW-h]) 2. Determining 12-month rolling average, CO2[lbs/MW-h] CO2[lbs/MW-h] = (1/12) * Sum (R(i))
where: R(i) is monthly CO2 emission rate and "i" is from 1 to 12 (current month to previous 11 months)

This section applies to monitoring systems as defined in the manual referenced at 139.102(3) (relating to references), installations required or approved under Chapters 122, 124, 127 and 129 or in an order issued under section 4 of the act (35 P. S. 4004). (1) The submittal procedures specified in the publication entitled "Continuous Source Monitoring Manual," available from the Department shall be utilized to obtain Department approval. This publication includes: (i) Installation requirements. (ii) Performance specifications. (iii) Test procedures. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (iv) Reporting requirements. (v) Quality assurance requirements. (vi) Administrative procedures for obtaining Department approval. (2) The monitoring system installation, certification and operation shall be conducted under the direct supervision of persons qualified by training and experience. (3) The monitoring systems may be designed to monitor source emissions or stack emissions if the representativeness of emissions can be verified. The method of conversion of monitoring results to source or stack emissions shall be approved by the Department. (4) The location of monitoring devices shall be approved by the Department prior to installation. The selection of the monitoring location shall utilize applicable criteria in the manual referenced in 139.102(3). The Department has the authority to determine which of the criteria are applicable. The representativeness of the measurements at the chosen monitoring location shall be verified. (5) The owner of a monitored source shall maintain records containing monitoring information and report data to the Department as specified in the manual referenced in 139.102(3). The records shall be maintained for 5 years and be available for inspection by Department personnel. (6) The owner of a monitored source shall provide permanent sampling facilities as specified in 139.1 (relating to sampling facilities) to permit verification testing by the Department. For extractive monitors, calibration gas inlets shall be available as near as possible to the monitor probe inlet to permit the Department to verify calibration of the monitoring system. Facilities shall be approved by the Department prior to construction. (7) Verification testing for monitoring systems shall be in accordance with Subchapter B (relating to monitoring duties of certain sources), and of the manual referenced in 139.102(3). (8) A quality assurance program shall be established and maintained by the owner of the monitored source. This program shall be in accordance with the criteria in the sources listed in 139.102. (9) The Department's approval will be based on the criteria specified in the manual referenced in 139.102(3). Failure to utilize the specified procedures or to conduct the quality assurance program could result in denying or rescinding the Department's approval. (10) The owner of a monitored source shall notify the Department when the monitoring system is inoperative for more than 1 hour during an air pollution episode as specified in Chapter 137 (relating to air pollution episodes). The notice shall be given within 2 hours of the malfunction. (11) Manual sampling conducted under Subchapter B may be required if the Department determines that the monitoring system data is not accurate or that the owner of the monitored source does not conduct the quality assurance program specified in the manual referenced in 139.102(3). (12) Required monitoring shall meet at least one of the following minimum data availability requirements unless other data availability requirements are stipulated elsewhere in this title, in a plan approval or permit condition under Chapter 127 (relating to construction, modification, reactivation and operation of sources), or in an order issued under section 4 of the act. For purposes of calculating data availability, "process down" time, as specified in the manual referenced in 139.102(3), shall be considered valid time. (i) In each calendar month, at least 90% of the time periods for which an emission standard or an operational parameter applies shall be valid as set forth in the quality assurance section of the manual referenced in 139.102(3). (ii) In each calendar quarter, at least 95% of the hours during which the monitored source is operating shall be valid as set forth in the quality assurance section of the manual referenced in 139.102(3). SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4335]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4340]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4345] # 019

# 020

# 021 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I demonstrate compliance for NOX if I use water or steam injection?

How do I demonstrate continuous compliance for NOX if I do not use water or steam injection?

What are the requirements for the continuous emission monitoring system equipment, if I choose to use this option? (13) The monitor results shall be expressed in terms of the applicable standard or criteria required. The method used to convert monitor data shall be approved by the Department. (14) Monitoring systems shall comply with the applicable performance specifications section of the manual referenced in 139.102(3). The Department has the authority to determine which of the performance specifications are applicable. (15) Verification of calibration standards shall be conducted in accordance with the applicable sampling methods in the Department's "Source Testing Manual" or as otherwise approved by the Department. The "Source Testing Manual" may be obtained from the Department. (16) The requirements of this section apply to monitoring to demonstrate compliance with emissions standards and process operational parameter criteria.

Not applicable

(a) If you are not using water or steam injection to control NOX emissions, you must perform annual performance tests in accordance with § 60.4400 to demonstrate continuous compliance. If the NOX emission result from the performance test is less than or equal to 75 percent of the NOX emission limit for the turbine, you may reduce the frequency of subsequent performance tests to once every 2 years (no more than 26 calendar months following the previous performance test). If the results of any subsequent performance test exceed 75 percent of the NOX emission limit for the turbine, you must resume annual performance tests. (b) As an alternative, you may install, calibrate, maintain and operate one of the following continuous monitoring systems: (1) Continuous emission monitoring as described in §§ 60.4335(b) and 60.4345, or (2) Not applicable

If the option to use a NOX CEMS is chosen: (a) Each NOX diluent CEMS must be installed and certified according to Performance Specification 2 (PS 2) in appendix B to this part, except the 7-day calibration drift is based on unit operating days, not calendar days. With state approval, Procedure 1 in appendix F to this part is not required. Alternatively, a NOX diluent CEMS that is installed and certified according to appendix A of part 75 of this chapter is acceptable for use under this subpart. The relative accuracy test audit (RATA) of the CEMS shall be performed on a lb/MMBtu basis. (b) As specified in § 60.13(e)(2), during each full unit operating hour, both the NOX monitor and the diluent monitor must complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each 15-minute quadrant of the hour, to validate the hour. For partial unit operating hours, at least one valid data point must be obtained with each monitor for each quadrant of the hour in which the unit operates. For unit operating hours in which required quality assurance and maintenance activities are performed on the CEMS, a minimum of two valid data points (one in each of two quadrants) are required for each monitor to validate the NOX emission rate for the hour. (c) Each fuel flowmeter shall be installed, calibrated, maintained, and operated according to the manufacturer's instructions. Alternatively, with state approval, fuel flowmeters that meet the installation, certification, and quality assurance requirements of appendix D to part 75 of this chapter are acceptable for use under this subpart. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4350]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4355] # 022

# 023 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I use data from the continuous emission monitoring equipment to identify excess emissions?

How do I establish and document a proper parameter monitoring plan? (d) Each watt meter, steam flow meter, and each pressure or temperature measurement device shall be installed, calibrated, maintained, and operated according to manufacturer's instructions. (e) The owner or operator shall develop and keep on-site a quality assurance (QA) plan for all of the continuous monitoring equipment described in paragraphs (a), (c), and (d) of this section. For the CEMS and fuel flow meters, the owner or operator may, with state approval, satisfy the requirements of this paragraph by implementing the QA program and plan described in section 1 of appendix B to part 75 of this chapter.

For purposes of identifying excess emissions: (a) All CEMS data must be reduced to hourly averages as specified in § 60.13(h). (b) For each unit operating hour in which a valid hourly average, as described in § 60.4345(b), is obtained for both NOX and diluent monitors, the data acquisition and handling system must calculate and record the hourly NOX emission rate in units of ppm or lb/MMBtu, using the appropriate equation from method 19 in appendix A of this part. For any hour in which the hourly average O2 concentration exceeds 19.0 percent O2 (or the hourly average CO2 concentration is less than 1.0 percent CO2 ), a diluent cap value of 19.0 percent O2 or 1.0 percent CO2 (as applicable) may be used in the emission calculations. (c) Correction of measured NOX concentrations to 15 percent O2 is not allowed. (d) If you have installed and certified a NOX diluent CEMS to meet the requirements of part 75 of this chapter, states can approve that only quality assured data from the CEMS shall be used to identify excess emissions under this subpart. Periods where the missing data substitution procedures in subpart D of part 75 are applied are to be reported as monitor downtime in the excess emissions and monitoring performance report required under § 60.7(c). (e) All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data must be reduced to hourly averages. (f) Calculate the hourly average NOX emission rates, in units of the emission standards under § 60.4320, using either ppm for units complying with the concentration limit or the following equation for units complying with the output based standard: (1) Not applicable (2) For combined-cycle and combined heat and power complying with the output-based standard, use Equation 1 of this subpart, except that the gross energy output is calculated as the sum of the total electrical and mechanical energy generated by the combustion turbine, the additional electrical or mechanical energy (if any) generated by the steam turbine following the heat recovery steam generator, and 100 percent of the total useful thermal energy output that is not used to generate additional electricity or mechanical output, expressed in equivalent MW, as in the following equations in 40 CFR 60.4350(f)(2). (3) Not applicable (g) Not applicable (h) For combined cycle and combined heat and power units with heat recovery, use the calculated hourly average emission rates from paragraph (f) of this section to assess excess emissions on a 30 unit operating day rolling average basis, as described in § 60.4380(b)(1).

Not applicable SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4360]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4365]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4370] # 024

# 025

# 026 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I determine the total sulfur content of the turbine's combustion fuel?

How can I be exempted from monitoring the total sulfur content of the fuel?

How often must I determine the sulfur content of the fuel? You must monitor the total sulfur content of the fuel being fired in the turbine, except as provided in § 60.4365. The sulfur content of the fuel must be determined using total sulfur methods described in § 60.4415. Alternatively, if the total sulfur content of the gaseous fuel during the most recent performance test was less than half the applicable limit, ASTM D4084, D4810, D5504, or D6228, or Gas Processors Association Standard 2377 (all of which are incorporated by reference, see § 60.17), which measure the major sulfur compounds, may be used.

You may elect not to monitor the total sulfur content of the fuel combusted in the turbine, if the fuel is demonstrated not to exceed potential sulfur emissions of 26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input for units located in continental areas and 180 ng SO2 /J (0.42 lb SO2 /MMBtu) heat input for units located in noncontinental areas or a continental area that the Administrator determines does not have access to natural gas and that the removal of sulfur compounds would cause more environmental harm than benefit. You must use one of the following sources of information to make the required demonstration: (a) The fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel, specifying that the maximum total sulfur content for oil use in continental areas is 0.05 weight percent (500 ppmw) or less and 0.4 weight percent (4,000 ppmw) or less for noncontinental areas, the total sulfur content for natural gas use in continental areas is 20 grains of sulfur or less per 100 standard cubic feet and 140 grains of sulfur or less per 100 standard cubic feet for noncontinental areas, has potential sulfur emissions of less than less than 26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input for continental areas and has potential sulfur emissions of less than less than 180 ng SO2 /J (0.42 lb SO2 /MMBtu) heat input for noncontinental areas; or (b) Representative fuel sampling data which show that the sulfur content of the fuel does not exceed 26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input for continental areas or 180 ng SO2 /J (0.42 lb SO2 /MMBtu) heat input for noncontinental areas. At a minimum, the amount of fuel sampling data specified in section 2.3.1.4 or 2.3.2.4 of appendix D to part 75 of this chapter is required.

The frequency of determining the sulfur content of the fuel must be as follows: (a) Not applicable (b) Gaseous fuel. If you elect not to demonstrate sulfur content using options in § 60.4365, and the fuel is supplied without intermediate bulk storage, the sulfur content value of the gaseous fuel must be determined and recorded once per unit operating day. (c) Custom schedules. Notwithstanding the requirements of paragraph (b) of this section, operators or fuel vendors may develop custom schedules for determination of the total sulfur content of gaseous fuels, based on the design and operation of the affected facility and the characteristics of the fuel supply. Except as provided in paragraphs (c)(1) and (c)(2) of this section, custom schedules shall be substantiated with data and shall be approved by the Administrator before they can be used to comply with the standard in § 60.4330. (1) The two custom sulfur monitoring schedules set forth in paragraphs (c)(1)(i) through (iv) and in paragraph (c)(2) of this section are acceptable, without prior Administrative approval: (i) The owner or operator shall obtain daily total sulfur content measurements for 30 consecutive unit operating days, using the applicable methods specified in this subpart. Based on the results of the 30 daily samples, the required frequency for subsequent monitoring of the fuel's total sulfur content shall be as specified in paragraph (c)(1)(ii), (iii), or (iv) of this section, SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b] # 027 Plan approval terms and conditions. as applicable. (ii) If none of the 30 daily measurements of the fuel's total sulfur content exceeds half the applicable standard, subsequent sulfur content monitoring may be performed at 12-month intervals. If any of the samples taken at 12-month intervals has a total sulfur content greater than half but less than the applicable limit, follow the procedures in paragraph (c)(1)(iii) of this section. If any measurement exceeds the applicable limit, follow the procedures in paragraph (c)(1)(iv) of this section. (iii) If at least one of the 30 daily measurements of the fuel's total sulfur content is greater than half but less than the applicable limit, but none exceeds the applicable limit, then: (A) Collect and analyze a sample every 30 days for 3 months. If any sulfur content measurement exceeds the applicable limit, follow the procedures in paragraph (c)(1)(iv) of this section. Otherwise, follow the procedures in paragraph (c)(1)(iii)(B) of this section. (B) Begin monitoring at 6-month intervals for 12 months. If any sulfur content measurement exceeds the applicable limit, follow the procedures in paragraph (c)(1)(iv) of this section. Otherwise, follow the procedures in paragraph (c)(1)(iii)(C) of this section. (C) Begin monitoring at 12-month intervals. If any sulfur content measurement exceeds the applicable limit, follow the procedures in paragraph (c)(1)(iv) of this section. Otherwise, continue to monitor at this frequency. (iv) If a sulfur content measurement exceeds the applicable limit, immediately begin daily monitoring according to paragraph (c)(1)(i) of this section. Daily monitoring shall continue until 30 consecutive daily samples, each having a sulfur content no greater than the applicable limit, are obtained. At that point, the applicable procedures of paragraph (c)(1)(ii) or (iii) of this section shall be followed. (2) The owner or operator may use the data collected from the 720-hour sulfur sampling demonstration described in section 2.3.6 of appendix D to part 75 of this chapter to determine a custom sulfur sampling schedule, as follows: (i) If the maximum fuel sulfur content obtained from the 720 hourly samples does not exceed 20 grains/100 scf, no additional monitoring of the sulfur content of the gas is required, for the purposes of this subpart. (ii) If the maximum fuel sulfur content obtained from any of the 720 hourly samples exceeds 20 grains/100 scf, but none of the sulfur content values (when converted to weight percent sulfur) exceeds half the applicable limit, then the minimum required sampling frequency shall be one sample at 12 month intervals. (iii) If any sample result exceeds half the applicable limit, but none exceeds the applicable limit, follow the provisions of paragraph (c)(1)(iii) of this section. (iv) If the sulfur content of any of the 720 hourly samples exceeds the applicable limit, follow the provisions of paragraph (c)(1)(iv) of this section.

[Plan Approval 37-337A] (a) All recordkeeping shall commence upon commencement of operation of the source and shall be kept for a period of 5 years and made available to the Department upon request. [Plan Approval 37-337A] (b) The permittee shall submit the turbine option chosen to the Department, with emission values if newer models are chosen, for final approval prior to construction. [Plan Approval 37-337A] (c) The company shall maintain a log of all preventative maintenance inspections of the source and control device(s). The IV. RECORDKEEPING REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 028

# 029

# 030 Plan approval terms and conditions.

Plan approval terms and conditions. inspection logs, at a minimum, shall contain the dates of the inspections, the name of the person performing the inspection, any mechanical repairs and/or adjustments, any potential problems or defects that were encountered, and the steps taken to correct them. [Plan Approval 37-337A] (d) The company shall maintain a log of the following, at a minimum, from the operational inspections: 1. Visible emission of the stack - daily defined as at least once per calendar day, while the plant is operating or as approved by the Department in the work practice inspection protocol. [Plan Approval 37-337A] (e) The company shall keep records (12-month rolling totals) of the following: 1. Fuel usage (natural gas)

[Plan Approval 37-337A] [Additional authority for this permit condition is derived from 25 Pa. Code Sections 139.101(5) and 139.101(12), 139.103, 139.108 or 139.111)] (a) The permittee shall comply with the recordkeeping requirements established in 25 Pa. Code Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources), (and) the 'Record Keeping and Reporting' requirements in the Department's Continuous Source Monitoring Manual, Revision No. 8, 274-0300-001. [Plan Approval 37-337A] (b) Records shall be retained for at least 5 years and shall be made available to the Department upon request. [Plan Approval 37-337A] (c) Compliance with any subsequently issued revision to the Continuous Source Monitoring Manual will constitute compliance with this permit condition.

[Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (a) The permittee shall record (continuously) the approved indicator(s) using approved data collecting device(s). (Examples of approved data collecting devices may include: strip chart recorders, data acquisition systems, manual log entries based on gauge readings, or EPA Method 9 observations.) [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (b) The permittee shall record all excursions and corrective actions taken in response to an excursion and the time elapsed until the corrective actions have been taken. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (c) The permittee shall record all inspections, repair and maintenance performed on the monitoring equipment. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (d) The permittee shall maintain records of all monitoring downtime incidents (other than downtime associated with zero and span or other daily calibration checks, if applicable). The permittee shall also record the dates, times and durations, possible causes and corrective actions taken for the incidents. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §70.6(a)(3)(ii)(B)] (e) The permittee shall keep all records for a period of five (5) years and make the records available to the Department upon request. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 031

# 032 Plan approval terms and conditions.

Plan approval terms and conditions.

Plan approval terms and conditions. The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] (a) The facility shall maintain sufficient records to adequately demonstrate compliance with the emission limitations associated with the GHG rule. [Plan Approval 37-337A] (b) The facility shall keep accurate and comprehensive records of: 1. The amount of SF6 dielectric fluid added to each circuit breaker unit each month. 2. The date and time that each alarm associated with the circuit breaker is activated, the corrective action taken to remedy the problem associated with each alarm, and the date corrective action remedied the problem.

[Plan Approval 37-337A] [Additional authority for this permit condition is derived from 25 Pa. Code Sections 139.101(1)(iv), 139.101(10) and 139.101(12), 139.103, 139.108 or 139.111)] (a) The permittee shall submit quarterly reports of continuous emission monitoring to the Department in accordance with the requirements established in 25 Pa. Code Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources), (and) the "Record Keeping and Reporting" requirements as established in the Department's Continuous Source Monitoring Manual, Revision No. 8, 274-0300-001. [Plan Approval 37-337A] (b) The permittee shall report emissions for all periods of unit operation, including startup, shutdown and malfunction. [Plan Approval 37-337A] (c) Initial quarterly reports following system certification shall be submitted to the Department within 35 days following the date upon which the Department notifies the owner or operator, in writing, of the approval of the continuous source monitoring system for use in determining compliance with applicable emission standards. [Plan Approval 37-337A] (d) Subsequent quarterly reports shall be submitted to the Department within 30 days after the end of each calendar quarter. [Plan Approval 37-337A] (e) Failure to submit required reports of continuous emission monitoring within the time periods specified in this Condition, shall constitute violations of this Permit, unless approved in advance by the Department in writing. [Plan Approval 37-337A] (f) Compliance with any subsequently issued revision to the Continuous Source Monitoring Manual will constitute compliance with this permit condition.

[Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9 & §70.6(a)(3)(iii)(A)] (a) The permittee shall report all excursions and corrective actions taken, the dates, times, durations and possible causes, every six (6) months. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (b) The permittee shall report all monitoring downtime incidents (other than downtime associated with zero and span or other daily calibration checks, if applicable), their dates, times and durations, possible causes and corrective actions taken, every six (6) months. V. REPORTING REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

Page 39 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4375]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4390]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4395]

[25 Pa. Code §127.12b] # 033

# 034

# 035

# 036

# 037 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines Plan approval terms and conditions.

What reports must I submit?

What are my reporting requirements if I operate an emergency combustion turbine or a research and development turbine?

When must I submit my reports?

Plan approval terms and conditions. [Plan Approval 37-337A] The facility shall submit semi-annual reports no later than March 1 for the January 1 thru December 31 of the previous year period and by September 1 for the July 1 of the previous year thru June 30 of the concurrent year period. The report shall include: 1. The greenhouse gas and SF6 emissions including emission calculations from all air-contaminant sources, on a monthly basis, in order to demonstrate compliance with the emission limitations for all sources at the facility. 2. The amount of SF6 dielectric fluid added to each circuit breaker unit each month. 3. The date and time that each alarm associated with the circuit breaker is activated, the corrective action taken to remedy the problem associated with each alarm, and the date corrective action remedied the problem.

(a) For each affected unit required to continuously monitor parameters or emissions, or to periodically determine the fuel sulfur content under this subpart, you must submit reports of excess emissions and monitor downtime, in accordance with § 60.7(c). Excess emissions must be reported for all periods of unit operation, including start-up, shutdown, and malfunction. (b) For each affected unit that performs annual performance tests in accordance with § 60.4340(a), you must submit a written report of the results of each performance test before the close of business on the 60th day following the completion of the performance test.

Not applicable

All reports required under § 60.7(c) must be postmarked by the 30th day following the end of each 6-month period.

[Plan Approval 37-337A] (a) The permittee shall perform a daily operational inspection of the source until such time as the Department approves a work practice inspection protocol submitted by the permittee. After Departmental approval, the permittee shall perform periodic inspections of the significant source equipment and emission controls in accordance with the approved work practice inspection protocol. [Plan Approval 37-337A] (b) All gauges employed by the permittee to monitor the required control device operating parameters shall have a scale such that the expected normal reading shall be no less than twenty percent (20%) of full scale and be accurate within plus or minus two percent (+/- 2%) of full scale reading. [Plan Approval 37-337A] (c) The permittee shall operate the control device(s) at all times this source is in operation once operating parameters VI. WORK PRACTICE REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b] # 038 Plan approval terms and conditions. (temperature, flow, etc.) are sufficient for proper control device operation. [Plan Approval 37-337A] (d) The permittee shall maintain and operate this source and the control device(s) in accordance with the manufacturer's specifications, the manufacturer's preventative maintenance schedule, and good air pollution control practices. The facility shall maintain a copy of the manufacturer's preventative maintenance schedule on-site. [Plan Approval 37-337A] (e) The SCR system shall be designed so it will not inject ammonia into the system when the inlet temperature to the catalyst is less than the minimum catalyst temperature to be established as part of the O&M plan. [Plan Approval 37-337A] (f) Prior to commencement of operations, the permittee shall develop and submit to the Department for approval a Risk Management Plan (RMP) meeting the requirements of Clean Air Act Section 112(r) and 40 CFR 68 Subpart G, with respect to the storage of aqueous ammonia if the permittee intends to store aqueous ammonia with a concentration of 20% or greater such that the quantity of ammonia present at the facility at any time exceeds 20,000 pounds, and the permittee shall implement the Department approved RMP.

[Plan Approval 37-337A] [Additional authority for this permit condition is derived from 25 Pa. Code Sections 139.101(1)(iv), 139.101(2), 139.101(3), 139.101(4), 139.101(6), 139.101(7), 139.101(8), 139.101(12), 139.101(14) and 139.101(15))] (a) Continuous Emission Monitoring Systems and components must be operated and maintained in accordance with the requirements established in 25 Pa. Code Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources) and the "Quality Assurance" requirements in the Department's Continuous Source Monitoring Manual, Revision No. 8, 274-0300-001. [Plan Approval 37-337A] (b) Compliance with any subsequently issued revision to the Continuous Source Monitoring Manual will constitute compliance with this permit condition. [Plan Approval 37-337A] (c) Data Availability Standards: Continuous emission monitoring shall meet the following minimum data availability requirements: 1. In accordance with 25 Pa. Code Section 139.101(12), required monitoring shall, at a minimum, meet one of the following data availability requirements unless otherwise stipulated in this permit, a plan approval, Title 25 or an order issued under Section 4 of the Air Pollution Control Act: (a) In each calendar month, at least 90% of the time periods for which an emission standard or an operational parameter applies, shall be valid as set forth in the Quality Assurance section of Revision No. 8 of the Department's Continuous Source Monitoring Manual, 274-0300-001; or (b) In each calendar quarter, at least 95% of the hours shall be valid as set forth in the Quality Assurance section of Revision No. 8 of the Department's Continuous Source Monitoring Manual, 274-0300-001. 2. Compliance with any subsequently issued revisions to the Continuous Source Monitoring Manual will constitute compliance with the regulations. 3. Emission Standard(s) To Which Data Availability Standard applies: (a) CO (ppmvd) (b) NOx (ppmvd) SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 039

# 040 Plan approval terms and conditions.

Plan approval terms and conditions. (c) CO2 (lbs per hr) (d) GEO (MW-hr gross) (e) Ammonia (ppmvd)

[Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.3 & §64.6] (a) Within 180-days of commencement of operation, or by the date of the initial operating permit inspection, whichever is sooner, the permittee shall submit the proposed indicator ranges for the following: 1. Oxidation Catalyst (a) Catalyst Temperature The proposed indicator ranges, as approved by the Department, shall be incorporated into the operating permit. The permittee shall adhere to the approved indicator ranges so that operation within the range shall provide reasonable assurance of compliance. A departure from the specified indicator range over the specified averaging period shall be defined as an excursion. Within 24-hours of discovery of an indicator being out of range, the permittee shall perform a maintenance inspection on the control device and take corrective action. [Plan Approval 37-337A] [Additional authority for the following permit conditions are also derived from 40 CFR §64.3] (b) The permittee shall utilize approved QA/QC practices that are adequate to ensure continuing validity of data and proper performance of the devices. 1. The permittee shall, for an approved device(s), install detectors or sensors at a location approved by the Department for obtaining data that are representative of the monitored indicator. 2. The permittee shall develop verification procedures to confirm the operational status of new or modified monitoring equipment prior to commencement of the monitoring process. (The operational status pertains to the first time calibration of new or modified equipment. The permittee may compare the data with any Department approved standardized data. For example, permittee might calibrate a new pH sensor by comparison with laboratory measurement of the scrubber recirculation fluid.) (The operational status pertains to the first time calibration of new or modified equipment. The permittee may compare the data with any Department approved standardized data. For example, you might compare a pressure gauge at a controlled pressure to that of a pressure standard of a known accuracy, or thermal couple temperature accuracy measured against a known reference temperature traceable to a National Institute for Standards and Technology (NIST)). 3. The permittee shall calibrate and check the accuracy of monitoring equipment taking into account the manufacturer's specifications at approved time intervals. (a) Oxidation Catalyst (i) Thermocouple or equivalent - calibrated and checked for accuracy annually [Plan Approval 37-337A] (c) The permittee shall maintain all monitoring equipment and stock parts necessary for routine repairs onsite. [Plan Approval 37-337A] (d) The permittee shall ensure that at least 90% of the monitoring data has been properly and accurately collected.

The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4333]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4380] # 041

# 042 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines What are my general requirements for complying with this subpart?

How are excess emissions and monitor downtime defined for NOX ? [Plan Approval 37-337A] (a) The permittee shall incorporate instrumentation and control systems that will allow plant efficiency to be optimized to the maximum extent practicable. To maintain efficient operating characteristics, these systems shall be periodically maintained in accordance with the permittee's Preventative maintenance Program. [Plan Approval 37-337A] (c) Facility shall implement a sulfur hexafluoride (SF6) leak detection program to minimize SF6 leaks as follows. Circuit breakers are to be state-of-the-art sealed enclosed-pressure circuit breakers equipped with low-pressure alarms that are triggered when 10% of the SF6 by weight has escaped. When alarms are triggered, the facility will take corrective action as soon as practicable to fix the circuit breaker units to a like-new state to prevent the emission of SF6 to the maximum extent practicable. [Plan Approval 37-337A] (e) Facility shall develop a site Preventative Maintenance Program to maintain plant operating efficiency.

(a) You must operate and maintain your stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown, and malfunction. (b) When an affected unit with heat recovery utilizes a common steam header with one or more combustion turbines, the owner or operator shall either: (1) Determine compliance with the applicable NOX emissions limits by measuring the emissions combined with the emissions from the other unit(s) utilizing the common heat recovery unit; or (2) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined gross energy output from the heat recovery unit for each of the affected combustion turbines. The Administrator may approve such demonstrated substitute methods for apportioning the combined gross energy output measured at the steam turbine whenever the demonstration ensures accurate estimation of emissions related under this part.

For the purpose of reports required under § 60.7(c), periods of excess emissions and monitor downtime that must be reported are defined as follows: (a) Not applicable (b) For turbines using continuous emission monitoring, as described in §§ 60.4335(b) and 60.4345: (1) An excess emissions is any unit operating period in which the 4-hour or 30-day rolling average NOX emission rate exceeds the applicable emission limit in § 60.4320. For the purposes of this subpart, a “4-hour rolling average NOX emission rate” is the arithmetic average of the average NOX emission rate in ppm or ng/J (lb/MWh) measured by the continuous emission monitoring equipment for a given hour and the three unit operating hour average NOX emission rates immediately preceding that unit operating hour. Calculate the rolling average if a valid NOX emission rate is obtained for at least 3 of the 4 hours. For the purposes of this subpart, a “30-day rolling average NOX emission rate” is the arithmetic average of all hourly NOX emission data in ppm or ng/J (lb/MWh) measured by the continuous emission monitoring equipment for a given day and the twenty-nine unit operating days immediately preceding that unit operating day. A new 30- day average is calculated each unit operating day as the average of all hourly NOX emissions rates for the preceding 30 unit operating days if a valid NOX emission rate is obtained for at least 75 percent of all operating hours. (2) A period of monitor downtime is any unit operating hour in which the data for any of the following parameters are either missing or invalid: NOX concentration, CO2 or O2 concentration, fuel flow rate, steam flow rate, steam temperature, steam SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4385]

[25 Pa. Code §127.12b] # 043

# 044 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How are excess emissions and monitoring downtime defined for SO2?

Plan approval terms and conditions. pressure, or megawatts. The steam flow rate, steam temperature, and steam pressure are only required if you will use this information for compliance purposes. (3) For operating periods during which multiple emissions standards apply, the applicable standard is the average of the applicable standards during each hour. For hours with multiple emissions standards, the applicable limit for that hour is determined based on the condition that corresponded to the highest emissions standard. (c) Not applicable

If you choose the option to monitor the sulfur content of the fuel, excess emissions and monitoring downtime are defined as follows: (a) For samples of gaseous fuel and for oil samples obtained using daily sampling, flow proportional sampling, or sampling from the unit's storage tank, an excess emission occurs each unit operating hour included in the period beginning on the date and hour of any sample for which the sulfur content of the fuel being fired in the combustion turbine exceeds the applicable limit and ending on the date and hour that a subsequent sample is taken that demonstrates compliance with the sulfur limit. (b) Not applicable (c) A period of monitor downtime begins when a required sample is not taken by its due date. A period of monitor downtime also begins on the date and hour of a required sample, if invalid results are obtained. The period of monitor downtime ends on the date and hour of the next valid sample.

[Plan Approval 37-337A] (a) The source is subject to the following: 1. 40 CFR 60 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines 2. Acid Rain Regulations (40 CFR 72-78) (Applicable) 3. CAIR (40 CFR 96) (Applicable - was replaced by CSAPR but CSAPR was stayed) 4. Cross State Air Pollution Rule (CSAPR) (40 CFR 97) (Not applicable - stayed 8-21-12) 5. Risk Management Program (40 CFR 68) (Applicable if greater than 20,000 lbs of aqueous ammonia at concentrations of 20% or greater is stored at facility) 6. CAM (40 CFR 64) (Applicable for pollutants being controlled and not having CEM) [Plan Approval 37-337A] (b) Any information required to be submitted as part of the above conditions should be submitted to the New Source Review Section Chief, Air Quality Program, Northwest Regional Office, 230 Chestnut Street, Meadville, PA 16335-3481. [Plan Approval 37-337A] (c) In accordance with 40 CFR 60.4 copies of all requests, reports, applications submittals and other communications shall be forwarded to both EPA and the Department at the addresses listed below unless otherwise noted. Air Quality Program Manager VII. ADDITIONAL REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 045

# 046 Plan approval terms and conditions.

Plan approval terms and conditions. Pa DEP Air Quality 230 Chestnut Street Meadville, PA 16335 Director Air Toxics and Radiation US EPA, Region III 1650 Arch Street Philadelphia, PA 19103-2029 [Plan Approval 37-337A] (d) Issuance of an operating permit is contingent upon satisfactory compliance with conditions numbered above, upon the source being constructed and operating as stated on the application, and upon the satisfactory demonstration that the emissions from the source will not be in violation of applicable Rules & Regulations of the Department of Environmental Protection.

[Plan Approval 37-337A] [25 Pa. Code §127.441(c) & Chapter 139; §§114(a)(3), 504(b) of the CAA] Sampling, Testing and Monitoring Procedures 1. The permittee shall perform the emissions monitoring analysis procedures or test methods required under an applicable requirement including procedures and methods under Sections 114(a)(3) ( 42 U.S.C.A.§§ 7414 (a)(3)) or 504(b) ( 42 U.S.C.A.§§ 7661c(b)) of the Clean Air Act. 2. Unless otherwise required by this permit, the permittee shall comply with applicable monitoring, quality assurance, recordkeeping and reporting requirements of the Air Pollution Control Act, 25 Pa. Code, Subpart C, Article III (relating to air resources), including Chapter 139 (relating to sampling and testing). The permittee shall also comply with applicable requirements related to monitoring, quality assurance, reporting and recordkeeping required by the Clean Air Act including §§ 114(a)(3) and 504(b) and regulations adopted thereunder, unless otherwise required by this permit.

Quality Improvement Plan Requirements [Plan Approval 37-337A] [Additional authority for the following permit conditions are also derived from 40 CFR §64.8] (a) The permittee shall develop and implement a quality improvement plan (QIP) as expeditiously as practicable if any of the following occurs: (1) Six excursions occur in a six-month reporting period. (2) The Department determines after review of all reported information that the permittee has not responded acceptably to an excursion. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.8] (b) In general, the QIP plan should be developed within 60 days and the permittee shall provide a copy of the QIP to the Department. Furthermore, the permittee shall notify the Department if the period for completing the improvements contained in the QIP exceeds 180 days from the date on which the need to implement the QIP was determined. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (c) The permittee shall record actions taken to implement a QIP during a reporting period and all related actions including, but not limited to inspections, repairs and maintenance performed on the monitoring equipment. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.8] (d) In accordance with § 64.8, the QIP shall include procedures for evaluating the control performance problems. Based on SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4300]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4305]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4310]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4315] # 047

# 048

# 049

# 050 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines What is the purpose of this subpart?

Does this subpart apply to my stationary combustion turbine?

What types of operations are exempt from these standards of performance?

What pollutants are regulated by this subpart? the results of the evaluation procedures, the permittee shall modify the QIP, and provide a copy to the Department, to include procedures for conducting more frequent or improved monitoring in conjunction with one or more of the following: (1) Improved preventive maintenance practices (2) Process operation changes (3) Appropriate improvements to control methods (4) Other steps appropriate to correct performance. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.8] (e) Following implementation of a QIP, the Department will require reasonable revisions to the QIP if the plan has failed to either: (1) Address the cause of the control device performance problem. (2) Provide adequate procedures for correcting control device performance problems in as expeditiously as practicable in accordance with good air pollution control practices for minimizing emissions. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.8] (f) Implementation of a QIP, shall not excuse the owner or operator of a source from compliance with any existing emission limitation or standard or any existing monitoring, testing, reporting or recordkeeping requirement that may apply under any federal, state, or local laws or any other applicable requirements under the Clean Air Act.

This subpart establishes emission standards and compliance schedules for the control of emissions from stationary combustion turbines that commenced construction, modification or reconstruction after February 18, 2005.

(a) If you are the owner or operator of a stationary combustion turbine with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005, your turbine is subject to this subpart. Only heat input to the combustion turbine should be included when determining whether or not this subpart is applicable to your turbine. Any additional heat input to associated heat recovery steam generators (HRSG) or duct burners should not be included when determining your peak heat input. However, this subpart does apply to emissions from any associated HRSG and duct burners. (b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part. Heat recovery steam generators and duct burners regulated under this subpart are exempted from the requirements of subparts Da, Db, and Dc of this part.

Not applicable

The pollutants regulated by this subpart are nitrogen oxide (NOX) and sulfur dioxide (SO2). SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4420] # 051 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines What definitions apply to this subpart? As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (General Provisions) of this part. Biogas means gas produced by the anaerobic digestion or fermentation of organic matter including manure, sewage sludge, municipal solid waste, biodegradable waste, or any other biodegradable feedstock, under anaerobic conditions. Biogas is comprised primarily of methane and CO2. Combined cycle combustion turbine means any stationary combustion turbine which recovers heat from the combustion turbine exhaust gases to generate steam that is only used to create additional power output in a steam turbine. Combined heat and power combustion turbine means any stationary combustion turbine which recovers heat from the exhaust gases to heat water or another medium, generate steam for useful purposes other than additional electric generation, or directly uses the heat in the exhaust gases for a useful purpose. Combustion turbine model means a group of combustion turbines having the same nominal air flow, combustor inlet pressure, combustor inlet temperature, firing temperature, turbine inlet temperature and turbine inlet pressure. Combustion turbine test cell/stand means any apparatus used for testing uninstalled stationary or uninstalled mobile (motive) combustion turbines. Diffusion flame stationary combustion turbine means any stationary combustion turbine where fuel and air are injected at the combustor and are mixed only by diffusion prior to ignition. Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary combustion turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit. Efficiency means the combustion turbine manufacturer's rated heat rate at peak load in terms of heat input per unit of power output—based on the higher heating value of the fuel. Emergency combustion turbine means any stationary combustion turbine which operates in an emergency situation. Examples include stationary combustion turbines used to produce power for critical networks or equipment, including power supplied to portions of a facility, when electric power from the local utility is interrupted, or stationary combustion turbines used to pump water in the case of fire or flood, etc. Emergency stationary combustion turbines do not include stationary combustion turbines used as peaking units at electric utilities or stationary combustion turbines at industrial facilities that typically operate at low capacity factors. Emergency combustion turbines may be operated for the purpose of maintenance checks and readiness testing, provided that the tests are required by the manufacturer, the vendor, or the insurance company associated with the turbine. Required testing of such units should be minimized, but there is no time limit on the use of emergency combustion turbines. Excess emissions means a specified averaging period over which either (1) the NOX emissions are higher than the applicable emission limit in § 60.4320; (2) the total sulfur content of the fuel being combusted in the affected facility exceeds the limit specified in § 60.4330; or (3) the recorded value of a particular monitored parameter is outside the acceptable range specified in the parameter monitoring plan for the affected unit. Gross useful output means the gross useful work performed by the stationary combustion turbine system. For units using the mechanical energy directly or generating only electricity, the gross useful work performed is the gross electrical or mechanical output from the turbine/generator set. For combined heat and power units, the gross useful work performed is the gross electrical or mechanical output plus the useful thermal output (i.e., thermal energy delivered to a process). Heat recovery steam generating unit means a unit where the hot exhaust gases from the combustion turbine are routed in order to extract heat from the gases and generate steam, for use in a steam turbine or other device that utilizes steam. Heat SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 72 Regulations on Permits §40 CFR 72.30] # 052 Subpart C--Acid Rain Permit Application Requirements to apply. recovery steam generating units can be used with or without duct burners. Integrated gasification combined cycle electric utility steam generating unit means a coal-fired electric utility steam generating unit that burns a synthetic gas derived from coal in a combined-cycle gas turbine. No solid coal is directly burned in the unit during operation. ISO conditions means 288 Kelvin, 60 percent relative humidity and 101.3 kilopascals pressure. Lean premix stationary combustion turbine means any stationary combustion turbine where the air and fuel are thoroughly mixed to form a lean mixture before delivery to the combustor. Mixing may occur before or in the combustion chamber. A lean premixed turbine may operate in diffusion flame mode during operating conditions such as startup and shutdown, extreme ambient temperature, or low or transient load. Natural gas means a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) produced in geological formations beneath the Earth's surface that maintains a gaseous state at standard atmospheric temperature and pressure under ordinary conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 950 and 1,100 British thermal units (Btu) per standard cubic foot. Naturalgas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value. Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, the Northern Mariana Islands, or offshore platforms. Peak load means 100 percent of the manufacturer's design capacity of the combustion turbine at ISO conditions. Regenerative cycle combustion turbine means any stationary combustion turbine which recovers heat from the combustion turbine exhaust gases to preheat the inlet combustion air to the combustion turbine. Simple cycle combustion turbine means any stationary combustion turbine which does not recover heat from the combustion turbine exhaust gases to preheat the inlet combustion air to the combustion turbine, or which does not recover heat from the combustion turbine exhaust gases for purposes other than enhancing the performance of the combustion turbine itself. Stationary combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any regenerative/recuperative cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. Unit operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period. Unit operating hour means a clock hour during which any fuel is combusted in the affected unit. If the unit combusts fuel for the entire clock hour, it is considered to be a full unit operating hour. If the unit combusts fuel for only part of the clock hour, it is considered to be a partial unit operating hour. Useful thermal output means the thermal energy made available for use in any industrial or commercial process, or used in any heating or cooling application, i.e., total thermal energy made available for processes and applications other than electrical or mechanical generation. Thermal output for this subpart means the energy in recovered thermal output measured against the energy in the thermal output at 15 degrees Celsius and 101.325 kilopascals of pressure. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.106] # 053 Subpart AA - CAIR NOX Annual Trading Program General Provisions Standard requirements. (a) Duty to apply. The designated representative of any source with an affected unit shall submit a complete Acid Rain permit application by the applicable deadline in paragraphs (b) and (c) of this section, and the owners and operators of such source and any affected unit at the source shall not operate the source or unit without a permit that states its Acid Rain program requirements. (b) Deadlines. (1) Not applicable (2) Phase II. (i) Not applicable (ii) For any source with a new unit under 72.6(a)(3)(i), the designated representative shall submit a complete Acid Rain permit application governing such unit to the permitting authority at least 24 months before the later of January 1, 2000 or the date on which the unit commences operation. (iii) Not applicable (iv) Not applicable (v) Not applicable (vi) Not applicable (vii) Not applicable (viii) Not applicable (3) Acid Rain Compliance Option Deadlines. The deadlines for applying for approval of any Acid Rain compliance options shall be the deadlines specified in the relevant section of subpart D of this part and in section 407 of the Act and regulations implementing section 407 of the Act. (c) Duty to Reapply. The designated representative shall submit a complete Acid Rain permit application for each source with an affected unit at least 6 months prior to the expiration of an existing Acid Rain permit governing the unit during Phase II or such longer time as may be approved under part 70 of this chapter that ensures that the term of the existing permit will not expire before the effective date of the permit for which the application is submitted. (d) The original and three copies of all permit applications for Phase I and where the Administrator is the permitting authority, for Phase II, shall be submitted to the EPA Regional Office for the Region where the affected source is located. The original and three copies of all permit applications for Phase II, where the Administrator is not the permitting authority, shall be submitted to the State permitting authority for the State where the affected source is located.

(a) Permit requirements. (1) The CAIR designated representative of each CAIR NOX source required to have a title V operating permit and each CAIR NOX unit required to have a title V operating permit at the source shall: (i) Submit to the permitting authority a complete CAIR permit application under § 97.122 in accordance with the deadlines specified in § 97.121; and (ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit. (2) The owners and operators of each CAIR NOX source required to have a title V operating permit and each CAIR NOX unit SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: required to have a title V operating permit at the source shall have a CAIR permit issued by the permitting authority under subpart CC of this part for the source and operate the source and the unit in compliance with such CAIR permit. (3) Except as provided in subpart II of this part, the owners and operators of a CAIR NOX source that is not otherwise required to have a title V operating permit and each CAIR NOX unit that is not otherwise required to have a title V operating permit are not required to submit a CAIR permit application, and to have a CAIR permit, under subpart CC of this part for such CAIR NOX source and such CAIR NOX unit. (b) Monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the CAIR designated representative, of each CAIR NOX source and each CAIR NOX unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of subpart HH of this part. (2) The emissions measurements recorded and reported in accordance with subpart HH of this part shall be used to determine compliance by each CAIR NOX source with the CAIR NOX emissions limitation under paragraph (c) of this section. (c) Nitrogen oxides emission requirements. (1) As of the allowance transfer deadline for a control period, the owners and operators of each CAIR NOX source and each CAIR NOX unit at the source shall hold, in the source's compliance account, CAIR NOX allowances available for compliance deductions for the control period under § 97.154(a) in an amount not less than the tons of total nitrogen oxides emissions for the control period from all CAIR NOX units at the source, as determined in accordance with subpart HH of this part. (2) A CAIR NOX unit shall be subject to the requirements under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2009 or the deadline for meeting the unit's monitor certification requirements under § 97.170(b)(1), (2), or (5) and for each control period thereafter. (3) A CAIR NOX allowance shall not be deducted, for compliance with the requirements under paragraph (c)(1) of this section, for a control period in a calendar year before the year for which the CAIR NOX allowance was allocated. (4) CAIR NOX allowances shall be held in, deducted from, or transferred into or among CAIR NOX Allowance Tracking System accounts in accordance with subparts EE, FF, GG, and II of this part. (5) A CAIR NOX allowance is a limited authorization to emit one ton of nitrogen oxides in accordance with the CAIR NOX Annual Trading Program. No provision of the CAIR NOX Annual Trading Program, the CAIR permit application, the CAIR permit, or an exemption under § 97.105 and no provision of law shall be construed to limit the authority of the United States to terminate or limit such authorization. (6) A CAIR NOX allowance does not constitute a property right. (7) Upon recordation by the Administrator under subpart EE, FF, GG, or II of this part, every allocation, transfer, or deduction of a CAIR NOX allowance to or from a CAIR NOX source's compliance account is incorporated automatically in any CAIR permit of the source. (d) Excess emissions requirements. If a CAIR NOX source emits nitrogen oxides during any control period in excess of the CAIR NOX emissions limitation, then: (1) The owners and operators of the source and each CAIR NOX unit at the source shall surrender the CAIR NOX allowances required for deduction under § 97.154(d)(1) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act or applicable State law; and (2) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law. (e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the CAIR NOX source and each CAIR NOX unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time before the end of 5 SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.206] # 054 Subpart AAA - CAIR SO2 Trading Program General Provisions Standard requirements. years, in writing by the permitting authority or the Administrator. (i) The certificate of representation under § 97.113 for the CAIR designated representative for the source and each CAIR NOX unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation under § 97.113 changing the CAIR designated representative. (ii) All emissions monitoring information, in accordance with subpart HH of this part, provided that to the extent that subpart HH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply. (iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR NOX Annual Trading Program. (iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR NOX Annual Trading Program or to demonstrate compliance with the requirements of the CAIR NOX Annual Trading Program. (2) The CAIR designated representative of a CAIR NOX source and each CAIR NOX unit at the source shall submit the reports required under the CAIR NOX Annual Trading Program, including those under subpart HH of this part. (f) Liability. (1) Each CAIR NOX source and each CAIR NOX unit shall meet the requirements of the CAIR NOX Annual Trading Program. (2) Any provision of the CAIR NOX Annual Trading Program that applies to a CAIR NOX source or the CAIR designated representative of a CAIR NOX source shall also apply to the owners and operators of such source and of the CAIR NOX units at the source. (3) Any provision of the CAIR NOX Annual Trading Program that applies to a CAIR NOX unit or the CAIR designated representative of a CAIR NOX unit shall also apply to the owners and operators of such unit. (g) Effect on other authorities. No provision of the CAIR NOX Annual Trading Program, a CAIR permit application, a CAIR permit, or an exemption under § 97.105 shall be construed as exempting or excluding the owners and operators, and the CAIR designated representative, of a CAIR NOX source or CAIR NOX unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

(a) Permit requirements. (1) The CAIR designated representative of each CAIR SO2 source required to have a title V operating permit and each CAIR SO2 unit required to have a title V operating permit at the source shall: (i) Submit to the permitting authority a complete CAIR permit application under § 97.222 in accordance with the deadlines specified in § 97.221; and (ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit. (2) The owners and operators of each CAIR SO2 source required to have a title V operating permit and each CAIR SO2 unit required to have a title V operating permit at the source shall have a CAIR permit issued by the permitting authority under subpart CCC of this part for the source and operate the source and the unit in compliance with such CAIR permit. (3) Except as provided in subpart III of this part, the owners and operators of a CAIR SO2 source that is not otherwise required to have a title V operating permit and each CAIR SO2 unit that is not otherwise required to have a title V operating permit are not required to submit a CAIR permit application, and to have a CAIR permit, under subpart CCC of this part for such CAIR SO2 source and such CAIR SO2 unit. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (b) Monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the CAIR designated representative, of each CAIR SO2 source and each CAIR SO2 unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of subpart HHH of this part. (2) The emissions measurements recorded and reported in accordance with subpart HHH of this part shall be used to determine compliance by each CAIR SO2 source with the CAIR SO2 emissions limitation under paragraph (c) of this section. (c) Sulfur dioxide emission requirements. (1) As of the allowance transfer deadline for a control period, the owners and operators of each CAIR SO2 source and each CAIR SO2 unit at the source shall hold, in the source's compliance account, a tonnage equivalent in CAIR SO2 allowances available for compliance deductions for the control period, as determined in accordance with § 97.254(a) and (b), not less than the tons of total sulfur dioxide emissions for the control period from all CAIR SO2 units at the source, as determined in accordance with subpart HHH of this part. (2) A CAIR SO2 unit shall be subject to the requirements under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2010 or the deadline for meeting the unit(s monitor certification requirements under § 97.270(b)(1),(2), or (5) and for each control period thereafter. (3) A CAIR SO2 allowance shall not be deducted, for compliance with the requirements under paragraph (c)(1) of this section, for a control period in a calendar year before the year for which the CAIR SO2 allowance was allocated. (4) CAIR SO2 allowances shall be held in, deducted from, or transferred into or among CAIR SO2 Allowance Tracking System accounts in accordance with subparts FFF, GGG, and III of this part. (5) A CAIR SO2 allowance is a limited authorization to emit sulfur dioxide in accordance with the CAIR SO2 Trading Program. No provision of the CAIR SO2 Trading Program, the CAIR permit application, the CAIR permit, or an exemption under § 97.205 and no provision of law shall be construed to limit the authority of the United States to terminate or limit such authorization. (6) A CAIR SO2 allowance does not constitute a property right. (7) Upon recordation by the Administrator under subpart FFF, GGG, or III of this part, every allocation, transfer, or deduction of a CAIR SO2 allowance to or from a CAIR SO2 source's compliance account is incorporated automatically in any CAIR permit of the source. (d) Excess emissions requirements. If a CAIR SO2 source emits sulfur dioxide during any control period in excess of the CAIR SO2 emissions limitation, then: (1) The owners and operators of the source and each CAIR SO2 unit at the source shall surrender the CAIR SO2 allowances required for deduction under § 97.254(d)(1) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act or applicable State law; and (2) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law. (e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the CAIR SO2 source and each CAIR SO2 unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time before the end of 5 years, in writing by the permitting authority or the Administrator. (i) The certificate of representation under § 97.213 for the CAIR designated representative for the source and each CAIR SO2 unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation under § 97.213 changing the CAIR designated representative. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.306] # 055 Subpart AAAA - CAIR NOX Ozone Season Trading Program General Provisions Standard requirements. (ii) All emissions monitoring information, in accordance with subpart HHH of this part, provided that to the extent that subpart HHH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply. (iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR SO2 Trading Program. (iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR SO2 Trading Program or to demonstrate compliance with the requirements of the CAIR SO2 Trading Program. (2) The CAIR designated representative of a CAIR SO2 source and each CAIR SO2 unit at the source shall submit the reports required under the CAIR SO2 Trading Program, including those under subpart HHH of this part. (f) Liability. (1) Each CAIR SO2 source and each CAIR SO2 unit shall meet the requirements of the CAIR SO2 Trading Program. (2) Any provision of the CAIR SO2 Trading Program that applies to a CAIR SO2 source or the CAIR designated representative of a CAIR SO2 source shall also apply to the owners and operators of such source and of the CAIR SO2 units at the source. (3) Any provision of the CAIR SO2 Trading Program that applies to a CAIR SO2 unit or the CAIR designated representative of a CAIR SO2 unit shall also apply to the owners and operators of such unit. (g) Effect on other authorities. No provision of the CAIR SO2 Trading Program, a CAIR permit application, a CAIR permit, or an exemption under § 97.205 shall be construed as exempting or excluding the owners and operators, and the CAIR designated representative, of a CAIR SO2 source or CAIR SO2 unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

(a) Permit requirements. (1) The CAIR designated representative of each CAIR NOX Ozone Season source required to have a title V operating permit and each CAIR NOX Ozone Season unit required to have a title V operating permit at the source shall: (i) Submit to the permitting authority a complete CAIR permit application under § 97.322 in accordance with the deadlines specified in § 97.321; and (ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit. (2) The owners and operators of each CAIR NOX Ozone Season source required to have a title V operating permit and each CAIR NOX Ozone Season unit required to have a title V operating permit at the source shall have a CAIR permit issued by the permitting authority under subpart CCCC of this part for the source and operate the source and the unit in compliance with such CAIR permit. (3) Except as provided in subpart IIII of this part, the owners and operators of a CAIR NOX Ozone Season source that is not otherwise required to have a title V operating permit and each CAIR NOX Ozone Season unit that is not otherwise required to have a title V operating permit are not required to submit a CAIR permit application, and to have a CAIR permit, under subpart CCCC of this part for such CAIR NOX Ozone Season source and such CAIR NOX Ozone Season unit. (b) Monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the CAIR designated representative, of each CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of subpart HHHH of this part. (2) The emissions measurements recorded and reported in accordance with subpart HHHH of this part shall be used to determine compliance by each CAIR NOX Ozone Season source with the CAIR NOX Ozone Season emissions limitation SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: under paragraph (c) of this section. (c) Nitrogen oxides ozone season emission requirements. (1) As of the allowance transfer deadline for a control period, the owners and operators of each CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit at the source shall hold, in the source's compliance account, CAIR NOX Ozone Season allowances available for compliance deductions for the control period under § 97.354(a) in an amount not less than the tons of total nitrogen oxides emissions for the control period from all CAIR NOX Ozone Season units at the source, as determined in accordance with subpart HHHH of this part. (2) A CAIR NOX Ozone Season unit shall be subject to the requirements under paragraph (c)(1) of this section for the control period starting on the later of May 1, 2009 or the deadline for meeting the unit's monitor certification requirements under § 97.370(b)(1), (2), (3), or (7) and for each control period thereafter. (3) A CAIR NOX Ozone Season allowance shall not be deducted, for compliance with the requirements under paragraph (c)(1) of this section, for a control period in a calendar year before the year for which the CAIR NOX Ozone Season allowance was allocated. (4) CAIR NOX Ozone Season allowances shall be held in, deducted from, or transferred into or among CAIR NOX Ozone Season Allowance Tracking System accounts in accordance with subparts EEEE, FFFF, GGGG, and IIII of this part. (5) A CAIR NOX Ozone Season allowance is a limited authorization to emit one ton of nitrogen oxides in accordance with the CAIR NOX Ozone Season Trading Program. No provision of the CAIR NOX Ozone Season Trading Program, the CAIR permit application, the CAIR permit, or an exemption under § 97.305 and no provision of law shall be construed to limit the authority of the United States to terminate or limit such authorization. (6) A CAIR NOX Ozone Season allowance does not constitute a property right. (7) Upon recordation by the Administrator under subpart EEEE, FFFF, GGGG, or IIII of this part, every allocation, transfer, or deduction of a CAIR NOX Ozone Season allowance to or from a CAIR NOX Ozone Season source's compliance account is incorporated automatically in any CAIR permit of the source. (d) Excess emissions requirements. If a CAIR NOX Ozone Season source emits nitrogen oxides during any control period in excess of the CAIR NOX Ozone Season emissions limitation, then: (1) The owners and operators of the source and each CAIR NOX Ozone Season unit at the source shall surrender the CAIR NOX Ozone Season allowances required for deduction under § 97.354(d)(1) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act or applicable State law; and (2) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law. (e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time before the end of 5 years, in writing by the permitting authority or the Administrator. (i) The certificate of representation under § 97.313 for the CAIR designated representative for the source and each CAIR NOX Ozone Season unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation under § 97.313 changing the CAIR designated representative. (ii) All emissions monitoring information, in accordance with subpart HHHH of this part, provided that to the extent that subpart HHHH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply. (iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR NOX Ozone Season Trading Program. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR NOX Ozone Season Trading Program or to demonstrate compliance with the requirements of the CAIR NOX Ozone Season Trading Program. (2) The CAIR designated representative of a CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit at the source shall submit the reports required under the CAIR NOX Ozone Season Trading Program, including those under subpart HHHH of this part. (f) Liability. (1) Each CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit shall meet the requirements of the CAIR NOX Ozone Season Trading Program. (2) Any provision of the CAIR NOX Ozone Season Trading Program that applies to a CAIR NOX Ozone Season source or the CAIR designated representative of a CAIR NOX Ozone Season source shall also apply to the owners and operators of such source and of the CAIR NOX Ozone Season units at the source. (3) Any provision of the CAIR NOX Ozone Season Trading Program that applies to a CAIR NOX Ozone Season unit or the CAIR designated representative of a CAIR NOX Ozone Season unit shall also apply to the owners and operators of such unit. (g) Effect on other authorities. No provision of the CAIR NOX Ozone Season Trading Program, a CAIR permit application, a CAIR permit, or an exemption under § 97.305 shall be construed as exempting or excluding the owners and operators, and the CAIR designated representative, of a CAIR NOX Ozone Season source or CAIR NOX Ozone Season unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: Source ID: Source Name:

032 COMBINED CYCLE UNIT #2

Source Capacity/Throughput:

FML FML01 CU 032 CNTL

C032A CNTL

C032B STAC

S032 3.400 MMCF/HR Natural Gas

I. RESTRICTIONS. Emission Restriction(s). # 001 [25 Pa. Code §127.12b] Plan approval terms and conditions. [Plan Approval 37-337A] (a) The Permittee shall select and install any of the turbine options listed below (or newer versions of these turbines if the Department determines that such newer versions achieve equivalent or better emissions rates and exhaust parameters) as part of the CCUs at the facility: 1. General Electric 7FA (GE 7FA) 2. Siemens SGT6-5000F (Siemens F) 3. Mitsubishi M501G (Mitsubishi G) 4. Siemens SGT6-8000H (Siemens H) [Plan Approval 37-337A] (b) No person may permit the emission from each CCU into the outdoor atmosphere of the following in a manner that exceeds the following: 1. GE 7FA (a) Nitrogen Oxides (NOx): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4320)] (ii) Normal operation with duct burner: 23.65 #/hr (iii) Normal operation without duct burner: 19.76 #/hr (iv) Total normal operation: 86.92 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 148.03 tpy based on a 12-month rolling total (b) Carbon Monoxide (CO): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 14.4 #/hr (iii) Normal operation without duct burner: 12.03 #/hr (iv) Total normal operation: 52.92 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 246.81 tpy based on a 12-month rolling total (c) Volatile Organic Compounds (VOC): (i) Normal operation with or without duct burner: 1.5 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 6.19 #/hr (iii) Normal operation without duct burner: 5.17 #/hr (iv) Total normal operation: 22.73 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 101.86 tpy based on a 12-month rolling total (d) Sulfur Oxides (SOx): (i) Normal operation with duct burner: 5.8 #/hr SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (ii) Normal operation without duct burner: 4.76 #/hr (iii) Total normal operation: 21.14 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 22.34 tpy based on a 12-month rolling total (v) Total per calendar day: 139.1 #/day (e) Sulfuric Acid (H2SO4): (i) Normal operation with duct burner: 0.87 #/hr (ii) Normal operation without duct burner: 0.71 #/hr (iii) Total normal operation: 3.17 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 3.35 tpy based on a 12-month rolling total (f) Particulate Matter (PM)/Particulate Matter 10 (PM10)/Particulate Matter 2.5 (PM2.5): (i) Normal operation with duct burner: 17.5 #/hr (ii) Normal operation without duct burner: 10.0 #/hr (iii) Total normal operation: 55.05 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 58.85 tpy based on a 12-month rolling total (v) Total per calendar day: 329.7 #/day for PM10/PM2.5 (g) Ammonia Slip (NH3): (i) Total normal operation: 87.5 tpy based on a 12-month rolling total 2. Siemens F (a) Nitrogen Oxides (NOx): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4320)] (ii) Normal operation with duct burner: 24.45 #/hr (iii) Normal operation without duct burner: 20.53 #/hr (iv) Total normal operation: 90.07 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 149.0 tpy based on a 12-month rolling total (b) Carbon Monoxide (CO): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 14.89 #/hr (iii) Normal operation without duct burner: 12.5 #/hr (iv) Total normal operation: 54.83 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 213.9 tpy based on a 12-month rolling total (c) Volatile Organic Compounds (VOC): (i) Normal operation with or without duct burner: 1.5 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 6.39 #/hr (iii) Normal operation without duct burner: 5.37 #/hr (iv) Total normal operation: 23.56 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 78.58 tpy based on a 12-month rolling total (d) Sulfur Oxides (SOx): (i) Normal operation with duct burner: 5.96 #/hr (ii) Normal operation without duct burner: 4.92 #/hr (iii) Total normal operation: 21.78 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 23.02 tpy based on a 12-month rolling total (v) Total per calendar day: 142.9 #/day (e) Sulfuric Acid (H2SO4): (i) Normal operation with duct burner: 0.89 #/hr (ii) Normal operation without duct burner: 0.74 #/hr (iii) Total normal operation: 3.27 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 3.45 tpy based on a 12-month rolling total (f) Particulate Matter (PM)/Particulate Matter 10 (PM10)/Particulate Matter 2.5 (PM2.5): (i) Normal operation with duct burner: 17.5 #/hr (ii) Normal operation without duct burner: 10.0 #/hr (iii) Total normal operation: 55.05 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 58.98 tpy based on a 12-month rolling total (v) Total per calendar day: 331.1 #/day for PM10/PM2.5 SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (g) Ammonia Slip (NH3): (i) Total normal operation: 90.8 tpy based on a 12-month rolling total 3. Mitsubushi G (a) Nitrogen Oxides (NOx): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4320)] (ii) Normal operation with duct burner: 29.29 #/hr (iii) Normal operation without duct burner: 25.45 #/hr (iv) Total normal operation: 109.61 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 124.26 tpy based on a 12-month rolling total (b) Carbon Monoxide (CO): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 17.83 #/hr (iii) Normal operation without duct burner: 15.5 #/hr (iv) Total normal operation: 66.74 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 401.88 tpy based on a 12-month rolling total (c) Volatile Organic Compounds (VOC): (i) Normal operation with or without duct burner: 1.5 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 7.66 #/hr (iii) Normal operation without duct burner: 6.66 #/hr (iv) Total normal operation: 28.67 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 93.81 tpy based on a 12-month rolling total (d) Sulfur Oxides (SOx): (i) Normal operation with duct burner: 7.22 #/hr (ii) Normal operation without duct burner: 6.17 #/hr (iii) Total normal operation: 26.82 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 28.26 tpy based on a 12-month rolling total (v) Total per calendar day: 173.1 #/day (e) Sulfuric Acid (H2SO4): (i) Normal operation with duct burner: 1.08 #/hr (ii) Normal operation without duct burner: 0.93 #/hr (iii) Total normal operation: 4.03 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 4.26 tpy based on a 12-month rolling total (f) Particulate Matter (PM)/Particulate Matter 10 (PM10)/Particulate Matter 2.5 (PM2.5): (i) Normal operation with duct burner: 19.5 #/hr (ii) Normal operation without duct burner: 12.0 #/hr (iii) Total normal operation: 63.06 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 66.91 tpy based on a 12-month rolling total (v) Total per calendar day: 377.7 #/day for PM10/PM2.5 (g) Ammonia Slip (NH3): (i) Total normal operation: 110.6 tpy based on a 12-month rolling total 4. Siemens H (a) Nitrogen Oxides (NOx): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4320)] (ii) Normal operation with duct burner: 29.2 #/hr (iii) Normal operation without duct burner: 25.36 #/hr (iv) Total normal operation: 109.24 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 172.25 tpy based on a 12-month rolling total (b) Carbon Monoxide (CO): (i) Normal operation with or without duct burner: 2.0 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 17.78 #/hr SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: # 002 [25 Pa. Code §127.12b] Plan approval terms and conditions. (iii) Normal operation without duct burner: 15.44 #/hr (iv) Total normal operation: 66.5 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 267.32 tpy based on a 12-month rolling total (c) Volatile Organic Compounds (VOC): (i) Normal operation with or without duct burner: 1.5 ppmvd @ 15% oxygen (ii) Normal operation with duct burner: 7.64 #/hr (iii) Normal operation without duct burner: 6.63 #/hr (iv) Total normal operation: 28.57 tpy based on a 12-month rolling total (v) Total including startup and shutdown: 93.44 tpy based on a 12-month rolling total (d) Sulfur Oxides (SOx): (i) Normal operation with duct burner: 7.19 #/hr (ii) Normal operation without duct burner: 6.15 #/hr (iii) Total normal operation: 26.72 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 28.15 tpy based on a 12-month rolling total (v) Total per calendar day: 172.4 #/day (e) Sulfuric Acid (H2SO4): (i) Normal operation with duct burner: 1.08 #/hr (ii) Normal operation without duct burner: 0.92 #/hr (iii) Total normal operation: 4.01 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 4.24 tpy based on a 12-month rolling total (f) Particulate Matter (PM)/Particulate Matter 10 (PM10)/Particulate Matter 2.5 (PM2.5): (i) Normal operation with duct burner: 18.5 #/hr (ii) Normal operation without duct burner: 11.0 #/hr (iii) Total normal operation: 59.06 tpy based on a 12-month rolling total (iv) Total including startup and shutdown: 62.89 tpy based on a 12-month rolling total (v) Total per calendar day: 353.7 #/day for PM10/PM2.5 (g) Ammonia Slip (NH3): (i) Total normal operation: 110.2 tpy based on a 12-month rolling total [Plan Approval 37-337A] (c) The emission limitations for NOx and CO are 3-hour rolling averages calculated once per hour and verified by CEMS. The emission limitations for VOC, SOx, H2SO4, and PM/PM10/PM2.5 are 1-hour based on the average of three stack test runs. [Plan Approval 37-337A] (d) No person may permit the emission into the outdoor atmosphere of the following in a manner that exceeds the following: 1. Ammonia Slip (NH3 Slip) - 5 ppmv, on a dry basis corrected @ 15% oxygen, 3-hour rolling averages calculated once per hour and verified by CEMS or as determined by USEPA Conditional Test Method (CTM-027), 'Procedure for Collection and Analysis of Ammonia in Stationary Sources' or other procedure approved by the Department. 2. 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: (a) Equal to or greater than 10% for a period or periods aggregating more than 3 minutes in any 1 hour. (b) Equal to or greater than 10% for a period or periods aggregating more than 6 minutes during startup and shutdown. [This condition also assures compliance with 25 PA Code 123.41]

The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: # 003 [25 Pa. Code §127.12b] Plan approval terms and conditions. (a) No person may permit the emission into the outdoor atmosphere of the following in a manner that exceeds the following: 1. CO2 emission rate of 1,000 # / MW-hr (gross) on a 12-operating month annual average basis [Plan Approval 37-337A] (b) No person may permit the emission into the outdoor atmosphere of CO2(e) in excess of the following: 1. If GE7FA option is chosen: 2,895,848 tpy based on a 12-month rolling total for both units 2. If Siemens F option is chosen: 2,983,732 tpy based on a 12-month rolling total for both units 3. If Mitsubishi G option is chosen: 3,679,850 tpy based on a 12-month rolling total for both units 4. If Siemens H option is chosen: 3,665,974 tpy based on a 12-month rolling total for both units

[Plan Approval 37-337A] (a) The startup and shutdown emissions from each CCU shall be limited to the following: 1. GE 7FA (a) NOx: S/U: 43.3 tpy & S/D: 17.81 tpy (b) CO: S/U: 150.35 tpy & S/D: 43.54 tpy (c) VOC: S/U: 61.98 tpy & S/D: 17.15 tpy (d) SOx: S/U: 0.87 tpy & S/D: 0.33 tpy (e) H2SO4: S/U: 0.13 tpy & S/D: 0.05 tpy (f) PM/PM10/PM2.5: S/U: 2.42 tpy & S/D: 1.38 tpy 2. Siemens F (a) NOx: S/U: 40.53 tpy & S/D: 18.41 tpy (b) CO: S/U: 114.06 tpy & S/D: 45.0 tpy (c) VOC: S/U: 37.3 tpy & S/D: 17.73 tpy (d) SOx: S/U: 0.9 tpy & S/D: 0.34 tpy (e) H2SO4: S/U: 0.14 tpy & S/D: 0.05 tpy (f) PM/PM10/PM2.5: S/U: 2.5 tpy & S/D: 1.43 tpy 3. Mitsubushi G (a) NOx: S/U: 9.95 tpy & S/D: 4.7 tpy (b) CO: S/U: 264.8 tpy & S/D: 70.34 tpy (c) VOC: S/U: 44.91 tpy & S/D: 20.24 tpy (d) SOx: S/U: 1.07 tpy & S/D: 0.38 tpy (e) H2SO4: S/U: 0.17 tpy & S/D: 0.06 tpy (f) PM/PM10/PM2.5: S/U: 2.53 tpy & S/D: 1.32 tpy 4. Siemens H (a) NOx: S/U: 44.73 tpy & S/D: 18.28 tpy (b) CO: S/U: 149.72 tpy & S/D: 51.09 tpy (c) VOC: S/U: 44.72 tpy & S/D: 20.16 tpy (d) SOx: S/U: 1.07 tpy & S/D: 0.38 tpy (e) H2SO4: S/U: 0.17 tpy & S/D: 0.06 tpy (f) PM/PM10/PM2.5: S/U: 2.52 tpy & S/D: 1.31 tpy SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: Fuel Restriction(s).

Operation Hours Restriction(s). # 004

# 005

# 006

# 007

# 008 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4320]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4325]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4330]

[25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines What emission limits must I meet for nitrogen oxides (NOX)?

What emission limits must I meet for NOX if my turbine burns both natural gas and distillate oil (or some other combination of fuels)?

What emission limits must I meet for sulfur dioxide (SO2)?

Plan approval terms and conditions.

Plan approval terms and conditions. [Compliance with the NOx limit of 2.0 ppmvd @ 15% oxygen for the CCU under 127.12b will show compliance with this requirement] (a) You must meet the emission limits for NOX specified in Table 1 to this subpart. [From Table 1: For new turbine firing natural gas and > 850 mmbtu/hr: 15 ppm at 15% O2 or 54 ng/J of useful output (0.43 #/MWh) and For heat recovery units operating independent of the combustion turbine: 54 ppm @ 15% O2 or 110 ng/J of useful output (0.86 #/MWh)] (b) If you have two or more turbines that are connected to a single generator, each turbine must meet the emission limits for NOX .

Not applicable

[Compliance with the sulfur limit in the fuel of 0.75 gr / 100 scf natural gas under 127.12b will show compliance with this requirement] (a) If your turbine is located in a continental area, you must comply with either paragraph (a)(1), (a)(2), or (a)(3) of this section. If your turbine is located in Alaska, you do not have to comply with the requirements in paragraph (a) of this section until January 1, 2008. (1) You must not cause to be discharged into the atmosphere from the subject stationary combustion turbine any gases which contain SO2 in excess of 110 nanograms per Joule (ng/J) (0.90 pounds per megawatt-hour (lb/MWh)) gross output; (2) You must not burn in the subject stationary combustion turbine any fuel which contains total potential sulfur emissions in excess of 26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input. If your turbine simultaneously fires multiple fuels, each fuel must meet this requirement; or (3) Not applicable (b) Not applicable

[Plan Approval 37-337A] The source shall fire only natural gas that has a sulfur content not to exceed 0.75 gr / 100 scf natural gas. [This condition also assures compliance with 40 CFR 60 Subpart KKKK (60.4330) and 25 PA Code 123.22(c)]

[Plan Approval 37-337A] (a) Startup is defined as the period beginning with ignition in the combustion turbine and lasting until either: 1. The combustion process, air pollution control equipment, and associated control systems have attained normal operating conditions for two consecutive 15-minute averaging periods, or SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b] # 009 Plan approval terms and conditions. [Plan Approval 37-337A] (a) Within 60 days after achieving the normal production rate at which the affected source will be operated, but not later than 180 days after initial start-up of the source/control device, a stack test for PM (filterable & condensable), PM10 (filterable & condensable), PM2.5 (filterable & condensable), NOx, SOx, CO, VOC, ammonia slip, sulfuric acid, and HAPs (Formaldehyde) shall be performed in accordance with the provisions of Chapter 139 of the Rules and Regulations of the Department of Environmental Protection. The stack test shall be performed while the aforementioned source is operating at greater than 90% of the rated capacity. Any testing performed at less than 90% of the rated capacity may subject the facility to a production limit of the production rate during the compliant testing. The stack test shall be conducted at the outlet of the control device. 1. [25 Pa. Code § 139.53(a)(3)] At least 60 calendar days prior to commencing an emissions testing program, a test protocol shall be submitted to the Department's Division of Source Testing and Monitoring and two copies to the appropriate Regional Office Department for review and approval. The test protocol shall meet all applicable requirements specified in the most current version of the Department's Source Testing Manual. 2. [25 Pa. Code § 139.53(a)(3)] At least 15 calendar days prior to commencing an emission testing program, notification as to the date and time of testing shall be given to the appropriate Regional Office. Notification shall also be sent to the Division of Source Testing and Monitoring. Notification shall not be made without prior receipt of a protocol acceptance letter from the Department. 3. [25 Pa. Code § 139.53(a)(3)] Within 15 calendar days after completion of the on-site testing portion of an emission test program, if a complete test report has not yet been submitted, an electronic mail notification shall be sent to the Department's Division of Source Testing and Monitoring and the appropriate Regional Office indicating the completion date of the on-site testing. 4. [40 CFR Part 60.8(a), 40 CFR Part 61.13(f) and 40 CFR Part 63.7(g)] A complete test report shall be submitted to the Department no later than 60 calendar days after completion of the on-site testing portion of an emission test program. For those tests being conducted pursuant to 40 CFR Part 61, a complete test report shall be submitted within 31 days after completion of the test. 5. [25 Pa. Code Section 139.53(b)] A complete test report shall include a summary of the emission results on the first pageof the report indicating if each pollutant measured is within permitted limits and a statement of compliance or noncompliance with all applicable permit conditions. The summary results will include, at a minimum, the following information: II. TESTING REQUIREMENTS. 2. Five hours after ignition, whichever occurs first. [Plan Approval 37-337A] (b) Startup shall be limited to 500 total hours in any consecutive 12-month period. [Plan Approval 37-337A] (c) Shutdown is defined as the period beginning with the lowering of unit load below 60% with the intent of ceasing operation of the unit and concluding with the cessation of combustion in the turbine, limited to a maximum of one hour in duration. [Plan Approval 37-337A] (d) Shutdown shall be limited to 250 total hours in any consecutive 12-month period. [Plan Approval 37-337A] (e) Malfunction is defined as any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment, process equipment, or a process to operate in a normal or usual manner that may result in an increase in the emissions of air contaminants. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (a) A statement that the owner or operator has reviewed the report from the emissions testing body and agrees with the findings. (b) Permit number(s) and condition(s) which are the basis for the evaluation. (c) Summary of results with respect to each applicable permit condition. (d) Statement of compliance or non-compliance with each applicable permit condition. 6. [25 Pa. Code § 139.3] All submittals shall meet all applicable requirements specified in the most current version of the Department's Source Testing Manual. 7. All testing shall be performed in accordance with the provisions of Chapter 139 of the Rules and Regulations of the Department of Environmental Protection. 8. [25 Pa. Code Section 139.53(a)(1) and 139.53(a)(3)] All submittals, besides notifications, shall be accomplished through PSIMS*Online available through https://www.depgreenport.state.pa.us/ecomm/Login.jsp when it becomes available. If internet submittal cannot be accomplished, one copy of the submittal shall be sent to the Pennsylvania Department of Environmental Protection, Bureau of Air Quality, Division of Source Testing and Monitoring, 400 Market Street, 12th Floor Rachael Carson State Office Building, Harrisburg, PA 17105-8468 with deadlines verified through document postmarks. In a like manner, two copies of the submittal shall be sent to the appropriate Regional Office. 9. The permittee shall ensure all federal reporting requirements contained in the applicable subpart of 40 CFR are followed, including timelines more stringent than those contained herein. In the event of an inconsistency or any conflicting requirements between state and the federal, the most stringent provision, term, condition, method or rule shall be used by default. 10. Actions Related to Noncompliance Demonstrated by a Stack Test: (a) If the results of a stack test, performed as required by this approval, exceed the level specified in any condition of this approval, the Permittee shall take appropriate corrective actions. Within 30 days of the Permittee receiving the stack test results, a written description of the corrective actions shall be submitted to the Department. The Permittee shall take appropriate action to minimize emissions from the affected facility while the corrective actions are being implemented. The Department shall notify the Permittee within 30 days, if the corrective actions taken are deficient. Within 30 days of receipt of the notice of deficiency, the Permittee shall submit a description of additional corrective actions to the Department. The Department reserves the authority to use enforcement activities to resolve noncompliant stack tests. (b) If the results of the required stack test exceed any limit defined in this plan approval, the test was not performed in accordance with the stack test protocol or the source and/or air cleaning device was not operated in accordance with the plan approval, then another stack test shall be performed to determine compliance. Within 120 days of the Permittee receiving the original stack test results, a retest shall be performed. The Department may extend the retesting deadline if the Permittee demonstrates, to the Department's satisfaction, that retesting within 120 days is not practicable. Failure of the second test to demonstrate compliance with the limits in the plan approval, not performing the test in accordance with the stack test protocol or not operating the source and/or air cleaning device in accordance with the plan approval may be grounds for immediate revocation of the plan approval to operate the affected source. [Plan Approval 37-337A] (b) The facility shall perform subsequent stack test for PM (filterable & condensable), PM10 (filterable & condensable), PM2.5 (filterable & condensable), VOC, sulfuric acid, and HAPs (Formaldehyde) in accordance with the provisions in part (a) every two years (22 to 26 months after the date of the previous test). The stack test shall be performed while the aforementioned source is operating at greater than 90% of the rated capacity. Any testing performed at less than 90% of the rated capacity may subject the facility to a production limit of the production rate during the compliant testing. The stack test shall be conducted at the outlet of the control device. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4400] # 010

# 011 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines Plan approval terms and conditions.

How do I conduct the initial and subsequent performance tests, regarding NOX ? [Plan Approval 37-337A] (a) Initial Application (Phase I): Proposal[s] containing information as listed in the Phase I section of the Department's Continuous Source Monitoring Manual for the CEMS[s] must be submitted at least 180 days prior to the planned initial source startup date. [Plan Approval 37-337A] (b) Performance Testing (Phase II): Testing as listed in the Phase II section of the Department's Continuous Source Monitoring Manual must be completed for the CEMS[s] no later than 180 days after initial source startup date and no later than 60 days after source achieves normal process capacity. [Plan Approval 37-337A] (c) Final Approval (Phase III): The final report of testing as listed in the Phase III section of the Department's Continuous Source Monitoring Manual must be submitted to the Bureau no later than 60 days after completion of testing. [Plan Approval 37-337A] (d) The owner or operator of the source shall not be issued an operating permit until the CEMS has received Phase III approval, in writing from the Department, when installation of a CEMS is made a condition of the plan approval. Until Phase III Department approval is obtained, operation shall be covered solely under condition of a plan approval.

(a) You must conduct an initial performance test, as required in § 60.8. Subsequent NOX performance tests shall be conducted on an annual basis (no more than 14 calendar months following the previous performance test). (1) There are two general methodologies that you may use to conduct the performance tests. For each test run: (i) Not applicable (ii) Measure the NOX and diluent gas concentrations, using either EPA Methods 7E and 3A, or EPA Method 20 in appendix A of this part. Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), and measure the electrical and thermal output of the unit. Use EPA Method 19 in appendix A of this part to calculate the NOX emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in § 60.4350(f) to calculate the NOX emission rate in lb/MWh. (2) Sampling traverse points for NOX and (if applicable) diluent gas are to be selected following EPA Method 20 or EPA Method 1 (non-particulate procedures), and sampled for equal time intervals. The sampling must be performed with a traversing single-hole probe, or, if feasible, with a stationary multi-hole probe that samples each of the points sequentially. Alternatively, a multi-hole probe designed and documented to sample equal volumes from each hole may be used to sample simultaneously at the required points. (3) Notwithstanding paragraph (a)(2) of this section, you may test at fewer points than are specified in EPA Method 1 or EPA Method 20 in appendix A of this part if the following conditions are met: (i) You may perform a stratification test for NOX and diluent pursuant to (A) [Reserved], or (B) The procedures specified in section 6.5.6.1(a) through (e) of appendix A of part 75 of this chapter. (ii) Once the stratification sampling is completed, you may use the following alternative sample point selection criteria for the performance test: (A) If each of the individual traverse point NOX concentrations is within ±10 percent of the mean concentration for all traverse SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4405]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4410] # 012

# 013 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I perform the initial performance test if I have chosen to install a NOX-diluent CEMS?

How do I establish a valid parameter range if I have chosen to continuously monitor parameters? points, or the individual traverse point diluent concentrations differs by no more than ±5ppm or ±0.5 percent CO2 (or O2 ) from the mean for all traverse points, then you may use three points (located either 16.7, 50.0 and 83.3 percent of the way across the stack or duct, or, for circular stacks or ducts greater than 2.4 meters (7.8 feet) in diameter, at 0.4, 1.2, and 2.0 meters from the wall). The three points must be located along the measurement line that exhibited the highest average NOX concentration during the stratification test; or (B) Not applicable (C) For turbines with a NOX standard less than or equal to 15 ppm @ 15% O2, you may sample at a single point, located at least 1 meter from the stack wall or at the stack centroid if each of the individual traverse point NOX concentrations is within ±2.5 percent of the mean concentration for all traverse points, or the individual traverse point diluent concentrations differs by no more than ±1ppm or ±0.15 percent CO2 (or O2) from the mean for all traverse points. (b) The performance test must be done at any load condition within plus or minus 25 percent of 100 percent of peak load. You may perform testing at the highest achievable load point, if at least 75 percent of peak load cannot be achieved in practice. You must conduct three separate test runs for each performance test. The minimum time per run is 20 minutes. (1) Not applicable (2) For a combined cycle and CHP turbine systems with supplemental heat (duct burner), you must measure the total NOx emissions after the duct burner rather than directly after the turbine. The duct burner must be in operation during the performance test. (3) Not applicable (4) Compliance with the applicable emission limit in § 60.4320 must be demonstrated at each tested load level. Compliance is achieved if the three-run arithmetic average NOx emission rate at each tested level meets the applicable emission limit in § 60.4320. (5) If you elect to install a CEMS, the performance evaluation of the CEMS may either be conducted separately or (as described in § 60.4405) as part of the initial performance test of the affected unit. (6) The ambient temperature must be greater than 0°F during the performance test.

If you elect to install and certify a NOX - diluent CEMS under § 60.4345, then the initial performance test required under § 60.8 may be performed in the following alternative manner: (a) Perform a minimum of nine RATA reference method runs, with a minimum time per run of 21 minutes, at a single load level, within plus or minus 25 percent of 100 percent of peak load. The ambient temperature must be greater than 0°F during the RATA runs. (b) For each RATA run, concurrently measure the heat input to the unit using a fuel flow meter (or flow meters) and measure the electrical and thermal output from the unit. (c) Use the test data both to demonstrate compliance with the applicable NOX emission limit under § 60.4320 and to provide the required reference method data for the RATA of the CEMS described under § 60.4335. (d) Compliance with the applicable emission limit in § 60.4320 is achieved if the arithmetic average of all of the NOX emission rates for the RATA runs, expressed in units of ppm or lb/MWh, does not exceed the emission limit. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4415]

[25 Pa. Code §123.51] # 014

# 015 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I conduct the initial and subsequent performance tests for sulfur?

Monitoring requirements Not applicable

(a) You must conduct an initial performance test, as required in § 60.8. Subsequent SO2 performance tests shall be conducted on an annual basis (no more than 14 calendar months following the previous performance test). There are three methodologies that you may use to conduct the performance tests. (1) If you choose to periodically determine the sulfur content of the fuel combusted in the turbine, a representative fuel sample would be collected following ASTM D5287 (incorporated by reference, see § 60.17) for natural gas or ASTM D4177 (incorporated by reference, see § 60.17) for oil. Alternatively, for oil, you may follow the procedures for manual pipeline sampling in section 14 of ASTM D4057 (incorporated by reference, see § 60.17). The fuel analyses of this section may be performed either by you, a service contractor retained by you, the fuel vendor, or any other qualified agency. Analyze the samples for the total sulfur content of the fuel using: (i) Not applicable (ii) For gaseous fuels, ASTM D1072, or alternatively D3246, D4084, D4468, D4810, D6228, D6667, or Gas Processors Association Standard 2377 (all of which are incorporated by reference, see § 60.17). (2) Measure the SO2 concentration (in parts per million (ppm)), using EPA Methods 6, 6C, 8, or 20 in appendix A of this part. In addition, the American Society of Mechanical Engineers (ASME) standard, ASME PTC 19-10-1981-Part 10, “Flue and Exhaust Gas Analyses,” manual methods for sulfur dioxide (incorporated by reference, see § 60.17) can be used instead of EPA Methods 6 or 20. For units complying with the output based standard, concurrently measure the stack gas flow rate, using EPA Methods 1 and 2 in appendix A of this part, and measure and record the electrical and thermal output from the unit. Then use the following equation from 40 CFR 60.4415(a)(2) to calculate the SO2 emission rate. (3) Measure the SO2 and diluent gas concentrations, using either EPA Methods 6, 6C, or 8 and 3A, or 20 in appendix A of this part. In addition, you may use the manual methods for sulfur dioxide ASME PTC 19-10-1981-Part 10 (incorporated by reference, see 60.17). Concurrently measure the heat input to the unit, using a fuel flowmeter (or flowmeters), and measure the electrical and thermal output of the unit. Use EPA Method 19 in appendix A of this part to calculate the SO2 emission rate in lb/MMBtu. Then, use Equations 1 and, if necessary, 2 and 3 in 60.4350(f) to calculate the SO2 emission rate in lb/MWh. (b) [Reserved]

(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 statutory 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. III. MONITORING REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 016

# 017 Plan approval terms and conditions.

Plan approval terms and conditions. (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.

[Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.6 & §64.3] (a) The permittee shall use the approved process parameter(s) or indicator(s) to obtain data and monitor the emission control equipment performance. 1. Oxidation Catalyst (a) Catalyst Temperature [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.6 & §64.3] (b) The permittee shall use the approved mean(s) or device(s) to measure the applicable indicator(s). 1. Oxidation Catalyst (a) Thermocouple or equivalent [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.3 & §64.6] (c) The permittee shall use the approved frequency for conducting monitoring of indicators. 1. Oxidation Catalyst (a) Catalyst Temperature - continuously meaning a reading at least once every 15-minutes [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.3] (d) The permittee shall use the approved period over which discrete data points for approved indicators will be collected and averaged for the purpose of determining an excursion. 1. Oxidation Catalyst (a) Catalyst Temperature - averaged over a 3-hour period

[Plan Approval 37-337A] (a) The following continuous emission monitoring system[s] (CEMS[s]) must be installed, approved by the Department, operated and maintained in accordance with the requirements of 25 Pa. Code Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources), and the 'Submittal and Approval', 'Record Keeping and Reporting', and 'Quality Assurance' requirements of Revision No. 8 of the Department's Continuous Source Monitoring Manual, 274-0300-001. 1. CEMS #6 SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (a) Source Combination to be Monitored: Combined Cycle Unit #2 (b) Parameter to be Reported: CO (c) Units of Measurement to be Reported: ppmvd (d) Moisture Basis of Measurement to be Reported: dry (e) Correction basis of Measurements to be Reported: 15% O2 (f) Data Substitution Required: No (g) Emission Standards (1) Emission Standard # 1: (a) Emission Standard Averaging Period Description: 3-hour rolling average, calculated once per hour (b) Emission Standard Value: 2.0 ppmvd corrected to 15% O2 (c) Emission Standard Direction: Violation if greater than emission standard value (d) Variable Emission Standard: No 2. CEMS #7 (a) Source Combination to be Monitored: Combined Cycle Unit #2 (b) Parameter to be Reported: NOx (c) Units of Measurement to be Reported: ppmvd (d) Moisture Basis of Measurement to be Reported: dry (e) Correction basis of Measurements to be Reported: 15% O2 (f) Data Substitution Required: No (g) Emission Standards (1) Emission Standard # 1 (a) Emission Standard Averaging Period Description: 3-hour rolling average, calculated once per hour (b) Emission Standard Value: 2.0 ppmvd corrected to 15% O2 (c) Emission Standard Direction: Violation if greater than emission standard value (d) Variable Emission Standard: No 3. CEMS #8 [This will consist of continuous measurement of CO2 in the exhaust of each CCU and calculation of combined mass emission rate from CCU #1 and CCU#2; continuous measurement of gross electrical output of the facility; and calculation of pounds of CO2 per gross MW-hour on a 12-month rolling average, calculated monthly] (a) Source Combination to be Monitored: Combined Cycle Unit #1 & #2 SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (b) Parameter to be Reported: CO2 (c) Units of Measurement to be Reported: lbs per hr (d) Moisture Basis of Measurement to be Reported: NA (e) Correction basis of Measurements to be Reported: None (f) Data Substitution Required: Yes (g) Emission Standards (1) Emission Standard # 1 (a) Emission Standard Averaging Period Description: 12-month sum, calculated monthly (b) Emission Standard Value: None (c) Emission Standard Direction: Not applicable (d) Variable Emission Standard: No 4. CEMS #9 [This will consist of continuous measurement of CO2 in the exhaust of each CCU and calculation of combined mass emission rate from CCU #1 and CCU#2; continuous measurement of gross electrical output of the facility; and calculation of pounds of CO2 per gross MW-hour on a 12-month rolling average, calculated monthly] (a) Source Combination to be Monitored: Combined Cycle Unit #1 & #2 (b) Parameter to be Reported: Gross Electrical Outlet (GEO) (c) Units of Measurement to be Reported: MW-hr (gross) (d) Moisture Basis of Measurement to be Reported: NA (e) Correction basis of Measurements to be Reported: None (f) Data Substitution Required: Yes (g) Emission Standards (1) Emission Standard # 1 (a) Emission Standard Averaging Period Description: 12-month sum, calculated monthly (b) Emission Standard Value: None (c) Emission Standard Direction: Not applicable (d) Variable Emission Standard: No 5. CEMS #10 (a) Source Combination to be Monitored: Combined Cycle Unit #1 (b) Parameter to be Reported: Ammonia SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §139.101] # 018 General requirements. (c) Units of Measurement to be Reported: ppmvd (d) Moisture Basis of Measurement to be Reported: dry (e) Correction basis of Measurements to be Reported: 15% O2 (f) Data Substitution Required: No (g) Emission Standards (1) Emission Standard # 1 (a) Emission Standard Averaging Period Description: 3-hour rolling average, calculated once per hour (b) Emission Standard Value: 5.0 (c) Emission Standard Direction: Violation if greater than emission standard value (d) Variable Emission Standard: No [Plan Approval 37-337A] (b) Compliance with any subsequently issued revisions to the Continuous Source Monitoring Manual will constitute compliance with the regulations. [Plan Approval 37-337A] (c) The facility shall show compliance with the CO2 limit by 1. Determining Monthly CO2 emission Rate, R(i) R(i) = (Monthly Sum, CO2 [lbs]) / (Monthly Sum, GEO [MW-h]) 2. Determining 12-month rolling average, CO2[lbs/MW-h] CO2[lbs/MW-h] = (1/12) * Sum (R(i))
where: R(i) is monthly CO2 emission rate and "i" is from 1 to 12 (current month to previous 11 months)

This section applies to monitoring systems as defined in the manual referenced at 139.102(3) (relating to references), installations required or approved under Chapters 122, 124, 127 and 129 or in an order issued under section 4 of the act (35 P. S. 4004). (1) The submittal procedures specified in the publication entitled "Continuous Source Monitoring Manual," available from the Department shall be utilized to obtain Department approval. This publication includes: (i) Installation requirements. (ii) Performance specifications. (iii) Test procedures. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (iv) Reporting requirements. (v) Quality assurance requirements. (vi) Administrative procedures for obtaining Department approval. (2) The monitoring system installation, certification and operation shall be conducted under the direct supervision of persons qualified by training and experience. (3) The monitoring systems may be designed to monitor source emissions or stack emissions if the representativeness of emissions can be verified. The method of conversion of monitoring results to source or stack emissions shall be approved by the Department. (4) The location of monitoring devices shall be approved by the Department prior to installation. The selection of the monitoring location shall utilize applicable criteria in the manual referenced in 139.102(3). The Department has the authority to determine which of the criteria are applicable. The representativeness of the measurements at the chosen monitoring location shall be verified. (5) The owner of a monitored source shall maintain records containing monitoring information and report data to the Department as specified in the manual referenced in 139.102(3). The records shall be maintained for 5 years and be available for inspection by Department personnel. (6) The owner of a monitored source shall provide permanent sampling facilities as specified in 139.1 (relating to sampling facilities) to permit verification testing by the Department. For extractive monitors, calibration gas inlets shall be available as near as possible to the monitor probe inlet to permit the Department to verify calibration of the monitoring system. Facilities shall be approved by the Department prior to construction. (7) Verification testing for monitoring systems shall be in accordance with Subchapter B (relating to monitoring duties of certain sources), and of the manual referenced in 139.102(3). (8) A quality assurance program shall be established and maintained by the owner of the monitored source. This program shall be in accordance with the criteria in the sources listed in 139.102. (9) The Department's approval will be based on the criteria specified in the manual referenced in 139.102(3). Failure to utilize the specified procedures or to conduct the quality assurance program could result in denying or rescinding the Department's approval. (10) The owner of a monitored source shall notify the Department when the monitoring system is inoperative for more than 1 hour during an air pollution episode as specified in Chapter 137 (relating to air pollution episodes). The notice shall be given within 2 hours of the malfunction. (11) Manual sampling conducted under Subchapter B may be required if the Department determines that the monitoring system data is not accurate or that the owner of the monitored source does not conduct the quality assurance program specified in the manual referenced in 139.102(3). (12) Required monitoring shall meet at least one of the following minimum data availability requirements unless other data availability requirements are stipulated elsewhere in this title, in a plan approval or permit condition under Chapter 127 (relating to construction, modification, reactivation and operation of sources), or in an order issued under section 4 of the act. For purposes of calculating data availability, "process down" time, as specified in the manual referenced in 139.102(3), shall be considered valid time. (i) In each calendar month, at least 90% of the time periods for which an emission standard or an operational parameter applies shall be valid as set forth in the quality assurance section of the manual referenced in 139.102(3). (ii) In each calendar quarter, at least 95% of the hours during which the monitored source is operating shall be valid as set forth in the quality assurance section of the manual referenced in 139.102(3). SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4335]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4340]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4345] # 019

# 020

# 021 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I demonstrate compliance for NOX if I use water or steam injection?

How do I demonstrate continuous compliance for NOX if I do not use water or steam injection?

What are the requirements for the continuous emission monitoring system equipment, if I choose to use this option? (13) The monitor results shall be expressed in terms of the applicable standard or criteria required. The method used to convert monitor data shall be approved by the Department. (14) Monitoring systems shall comply with the applicable performance specifications section of the manual referenced in 139.102(3). The Department has the authority to determine which of the performance specifications are applicable. (15) Verification of calibration standards shall be conducted in accordance with the applicable sampling methods in the Department's "Source Testing Manual" or as otherwise approved by the Department. The "Source Testing Manual" may be obtained from the Department. (16) The requirements of this section apply to monitoring to demonstrate compliance with emissions standards and process operational parameter criteria.

Not applicable

(a) If you are not using water or steam injection to control NOX emissions, you must perform annual performance tests in accordance with § 60.4400 to demonstrate continuous compliance. If the NOX emission result from the performance test is less than or equal to 75 percent of the NOX emission limit for the turbine, you may reduce the frequency of subsequent performance tests to once every 2 years (no more than 26 calendar months following the previous performance test). If the results of any subsequent performance test exceed 75 percent of the NOX emission limit for the turbine, you must resume annual performance tests. (b) As an alternative, you may install, calibrate, maintain and operate one of the following continuous monitoring systems: (1) Continuous emission monitoring as described in §§ 60.4335(b) and 60.4345, or (2) Not applicable

If the option to use a NOX CEMS is chosen: (a) Each NOX diluent CEMS must be installed and certified according to Performance Specification 2 (PS 2) in appendix B to this part, except the 7-day calibration drift is based on unit operating days, not calendar days. With state approval, Procedure 1 in appendix F to this part is not required. Alternatively, a NOX diluent CEMS that is installed and certified according to appendix A of part 75 of this chapter is acceptable for use under this subpart. The relative accuracy test audit (RATA) of the CEMS shall be performed on a lb/MMBtu basis. (b) As specified in § 60.13(e)(2), during each full unit operating hour, both the NOX monitor and the diluent monitor must complete a minimum of one cycle of operation (sampling, analyzing, and data recording) for each 15-minute quadrant of the hour, to validate the hour. For partial unit operating hours, at least one valid data point must be obtained with each monitor for each quadrant of the hour in which the unit operates. For unit operating hours in which required quality assurance and maintenance activities are performed on the CEMS, a minimum of two valid data points (one in each of two quadrants) are required for each monitor to validate the NOX emission rate for the hour. (c) Each fuel flowmeter shall be installed, calibrated, maintained, and operated according to the manufacturer's instructions. Alternatively, with state approval, fuel flowmeters that meet the installation, certification, and quality assurance requirements of appendix D to part 75 of this chapter are acceptable for use under this subpart. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4350]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4355] # 022

# 023 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I use data from the continuous emission monitoring equipment to identify excess emissions?

How do I establish and document a proper parameter monitoring plan? (d) Each watt meter, steam flow meter, and each pressure or temperature measurement device shall be installed, calibrated, maintained, and operated according to manufacturer's instructions. (e) The owner or operator shall develop and keep on-site a quality assurance (QA) plan for all of the continuous monitoring equipment described in paragraphs (a), (c), and (d) of this section. For the CEMS and fuel flow meters, the owner or operator may, with state approval, satisfy the requirements of this paragraph by implementing the QA program and plan described in section 1 of appendix B to part 75 of this chapter.

For purposes of identifying excess emissions: (a) All CEMS data must be reduced to hourly averages as specified in § 60.13(h). (b) For each unit operating hour in which a valid hourly average, as described in § 60.4345(b), is obtained for both NOX and diluent monitors, the data acquisition and handling system must calculate and record the hourly NOX emission rate in units of ppm or lb/MMBtu, using the appropriate equation from method 19 in appendix A of this part. For any hour in which the hourly average O2 concentration exceeds 19.0 percent O2 (or the hourly average CO2 concentration is less than 1.0 percent CO2 ), a diluent cap value of 19.0 percent O2 or 1.0 percent CO2 (as applicable) may be used in the emission calculations. (c) Correction of measured NOX concentrations to 15 percent O2 is not allowed. (d) If you have installed and certified a NOX diluent CEMS to meet the requirements of part 75 of this chapter, states can approve that only quality assured data from the CEMS shall be used to identify excess emissions under this subpart. Periods where the missing data substitution procedures in subpart D of part 75 are applied are to be reported as monitor downtime in the excess emissions and monitoring performance report required under § 60.7(c). (e) All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data must be reduced to hourly averages. (f) Calculate the hourly average NOX emission rates, in units of the emission standards under § 60.4320, using either ppm for units complying with the concentration limit or the following equation for units complying with the output based standard: (1) Not applicable (2) For combined-cycle and combined heat and power complying with the output-based standard, use Equation 1 of this subpart, except that the gross energy output is calculated as the sum of the total electrical and mechanical energy generated by the combustion turbine, the additional electrical or mechanical energy (if any) generated by the steam turbine following the heat recovery steam generator, and 100 percent of the total useful thermal energy output that is not used to generate additional electricity or mechanical output, expressed in equivalent MW, as in the following equations in 40 CFR 60.4350(f)(2). (3) Not applicable (g) Not applicable (h) For combined cycle and combined heat and power units with heat recovery, use the calculated hourly average emission rates from paragraph (f) of this section to assess excess emissions on a 30 unit operating day rolling average basis, as described in § 60.4380(b)(1).

Not applicable SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4360]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4365]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4370] # 024

# 025

# 026 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How do I determine the total sulfur content of the turbine's combustion fuel?

How can I be exempted from monitoring the total sulfur content of the fuel?

How often must I determine the sulfur content of the fuel? You must monitor the total sulfur content of the fuel being fired in the turbine, except as provided in § 60.4365. The sulfur content of the fuel must be determined using total sulfur methods described in § 60.4415. Alternatively, if the total sulfur content of the gaseous fuel during the most recent performance test was less than half the applicable limit, ASTM D4084, D4810, D5504, or D6228, or Gas Processors Association Standard 2377 (all of which are incorporated by reference, see § 60.17), which measure the major sulfur compounds, may be used.

You may elect not to monitor the total sulfur content of the fuel combusted in the turbine, if the fuel is demonstrated not to exceed potential sulfur emissions of 26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input for units located in continental areas and 180 ng SO2 /J (0.42 lb SO2 /MMBtu) heat input for units located in noncontinental areas or a continental area that the Administrator determines does not have access to natural gas and that the removal of sulfur compounds would cause more environmental harm than benefit. You must use one of the following sources of information to make the required demonstration: (a) The fuel quality characteristics in a current, valid purchase contract, tariff sheet or transportation contract for the fuel, specifying that the maximum total sulfur content for oil use in continental areas is 0.05 weight percent (500 ppmw) or less and 0.4 weight percent (4,000 ppmw) or less for noncontinental areas, the total sulfur content for natural gas use in continental areas is 20 grains of sulfur or less per 100 standard cubic feet and 140 grains of sulfur or less per 100 standard cubic feet for noncontinental areas, has potential sulfur emissions of less than less than 26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input for continental areas and has potential sulfur emissions of less than less than 180 ng SO2 /J (0.42 lb SO2 /MMBtu) heat input for noncontinental areas; or (b) Representative fuel sampling data which show that the sulfur content of the fuel does not exceed 26 ng SO2 /J (0.060 lb SO2 /MMBtu) heat input for continental areas or 180 ng SO2 /J (0.42 lb SO2 /MMBtu) heat input for noncontinental areas. At a minimum, the amount of fuel sampling data specified in section 2.3.1.4 or 2.3.2.4 of appendix D to part 75 of this chapter is required.

The frequency of determining the sulfur content of the fuel must be as follows: (a) Not applicable (b) Gaseous fuel. If you elect not to demonstrate sulfur content using options in § 60.4365, and the fuel is supplied without intermediate bulk storage, the sulfur content value of the gaseous fuel must be determined and recorded once per unit operating day. (c) Custom schedules. Notwithstanding the requirements of paragraph (b) of this section, operators or fuel vendors may develop custom schedules for determination of the total sulfur content of gaseous fuels, based on the design and operation of the affected facility and the characteristics of the fuel supply. Except as provided in paragraphs (c)(1) and (c)(2) of this section, custom schedules shall be substantiated with data and shall be approved by the Administrator before they can be used to comply with the standard in § 60.4330. (1) The two custom sulfur monitoring schedules set forth in paragraphs (c)(1)(i) through (iv) and in paragraph (c)(2) of this section are acceptable, without prior Administrative approval: (i) The owner or operator shall obtain daily total sulfur content measurements for 30 consecutive unit operating days, using the applicable methods specified in this subpart. Based on the results of the 30 daily samples, the required frequency for subsequent monitoring of the fuel's total sulfur content shall be as specified in paragraph (c)(1)(ii), (iii), or (iv) of this section, SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b] # 027 Plan approval terms and conditions. as applicable. (ii) If none of the 30 daily measurements of the fuel's total sulfur content exceeds half the applicable standard, subsequent sulfur content monitoring may be performed at 12-month intervals. If any of the samples taken at 12-month intervals has a total sulfur content greater than half but less than the applicable limit, follow the procedures in paragraph (c)(1)(iii) of this section. If any measurement exceeds the applicable limit, follow the procedures in paragraph (c)(1)(iv) of this section. (iii) If at least one of the 30 daily measurements of the fuel's total sulfur content is greater than half but less than the applicable limit, but none exceeds the applicable limit, then: (A) Collect and analyze a sample every 30 days for 3 months. If any sulfur content measurement exceeds the applicable limit, follow the procedures in paragraph (c)(1)(iv) of this section. Otherwise, follow the procedures in paragraph (c)(1)(iii)(B) of this section. (B) Begin monitoring at 6-month intervals for 12 months. If any sulfur content measurement exceeds the applicable limit, follow the procedures in paragraph (c)(1)(iv) of this section. Otherwise, follow the procedures in paragraph (c)(1)(iii)(C) of this section. (C) Begin monitoring at 12-month intervals. If any sulfur content measurement exceeds the applicable limit, follow the procedures in paragraph (c)(1)(iv) of this section. Otherwise, continue to monitor at this frequency. (iv) If a sulfur content measurement exceeds the applicable limit, immediately begin daily monitoring according to paragraph (c)(1)(i) of this section. Daily monitoring shall continue until 30 consecutive daily samples, each having a sulfur content no greater than the applicable limit, are obtained. At that point, the applicable procedures of paragraph (c)(1)(ii) or (iii) of this section shall be followed. (2) The owner or operator may use the data collected from the 720-hour sulfur sampling demonstration described in section 2.3.6 of appendix D to part 75 of this chapter to determine a custom sulfur sampling schedule, as follows: (i) If the maximum fuel sulfur content obtained from the 720 hourly samples does not exceed 20 grains/100 scf, no additional monitoring of the sulfur content of the gas is required, for the purposes of this subpart. (ii) If the maximum fuel sulfur content obtained from any of the 720 hourly samples exceeds 20 grains/100 scf, but none of the sulfur content values (when converted to weight percent sulfur) exceeds half the applicable limit, then the minimum required sampling frequency shall be one sample at 12 month intervals. (iii) If any sample result exceeds half the applicable limit, but none exceeds the applicable limit, follow the provisions of paragraph (c)(1)(iii) of this section. (iv) If the sulfur content of any of the 720 hourly samples exceeds the applicable limit, follow the provisions of paragraph (c)(1)(iv) of this section.

[Plan Approval 37-337A] (a) All recordkeeping shall commence upon commencement of operation of the source and shall be kept for a period of 5 years and made available to the Department upon request. [Plan Approval 37-337A] (b) The permittee shall submit the turbine option chosen to the Department, with emission values if newer models are chosen, for final approval prior to construction. [Plan Approval 37-337A] (c) The company shall maintain a log of all preventative maintenance inspections of the source and control device(s). The IV. RECORDKEEPING REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 028

# 029

# 030 Plan approval terms and conditions.

Plan approval terms and conditions. inspection logs, at a minimum, shall contain the dates of the inspections, the name of the person performing the inspection, any mechanical repairs and/or adjustments, any potential problems or defects that were encountered, and the steps taken to correct them. [Plan Approval 37-337A] (d) The company shall maintain a log of the following, at a minimum, from the operational inspections: 1. Visible emission of the stack - daily defined as at least once per calendar day, while the plant is operating or as approved by the Department in the work practice inspection protocol. [Plan Approval 37-337A] (e) The company shall keep records (12-month rolling totals) of the following: 1. Fuel usage (natural gas)

[Plan Approval 37-337A] [Additional authority for this permit condition is derived from 25 Pa. Code Sections 139.101(5) and 139.101(12), 139.103, 139.108 or 139.111)] (a) The permittee shall comply with the recordkeeping requirements established in 25 Pa. Code Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources), (and) the 'Record Keeping and Reporting' requirements in the Department's Continuous Source Monitoring Manual, Revision No. 8, 274-0300-001. [Plan Approval 37-337A] (b) Records shall be retained for at least 5 years and shall be made available to the Department upon request. [Plan Approval 37-337A] (c) Compliance with any subsequently issued revision to the Continuous Source Monitoring Manual will constitute compliance with this permit condition.

[Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (a) The permittee shall record (continuously) the approved indicator(s) using approved data collecting device(s). (Examples of approved data collecting devices may include: strip chart recorders, data acquisition systems, manual log entries based on gauge readings, or EPA Method 9 observations.) [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (b) The permittee shall record all excursions and corrective actions taken in response to an excursion and the time elapsed until the corrective actions have been taken. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (c) The permittee shall record all inspections, repair and maintenance performed on the monitoring equipment. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (d) The permittee shall maintain records of all monitoring downtime incidents (other than downtime associated with zero and span or other daily calibration checks, if applicable). The permittee shall also record the dates, times and durations, possible causes and corrective actions taken for the incidents. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §70.6(a)(3)(ii)(B)] (e) The permittee shall keep all records for a period of five (5) years and make the records available to the Department upon request. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 031

# 032 Plan approval terms and conditions.

Plan approval terms and conditions.

Plan approval terms and conditions. The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] (a) The facility shall maintain sufficient records to adequately demonstrate compliance with the emission limitations associated with the GHG rule. [Plan Approval 37-337A] (b) The facility shall keep accurate and comprehensive records of: 1. The amount of SF6 dielectric fluid added to each circuit breaker unit each month. 2. The date and time that each alarm associated with the circuit breaker is activated, the corrective action taken to remedy the problem associated with each alarm, and the date corrective action remedied the problem.

[Plan Approval 37-337A] [Additional authority for this permit condition is derived from 25 Pa. Code Sections 139.101(1)(iv), 139.101(10) and 139.101(12), 139.103, 139.108 or 139.111)] (a) The permittee shall submit quarterly reports of continuous emission monitoring to the Department in accordance with the requirements established in 25 Pa. Code Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources), (and) the "Record Keeping and Reporting" requirements as established in the Department's Continuous Source Monitoring Manual, Revision No. 8, 274-0300-001. [Plan Approval 37-337A] (b) The permittee shall report emissions for all periods of unit operation, including startup, shutdown and malfunction. [Plan Approval 37-337A] (c) Initial quarterly reports following system certification shall be submitted to the Department within 35 days following the date upon which the Department notifies the owner or operator, in writing, of the approval of the continuous source monitoring system for use in determining compliance with applicable emission standards. [Plan Approval 37-337A] (d) Subsequent quarterly reports shall be submitted to the Department within 30 days after the end of each calendar quarter. [Plan Approval 37-337A] (e) Failure to submit required reports of continuous emission monitoring within the time periods specified in this Condition, shall constitute violations of this Permit, unless approved in advance by the Department in writing. [Plan Approval 37-337A] (f) Compliance with any subsequently issued revision to the Continuous Source Monitoring Manual will constitute compliance with this permit condition.

[Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9 & §70.6(a)(3)(iii)(A)] (a) The permittee shall report all excursions and corrective actions taken, the dates, times, durations and possible causes, every six (6) months. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (b) The permittee shall report all monitoring downtime incidents (other than downtime associated with zero and span or other daily calibration checks, if applicable), their dates, times and durations, possible causes and corrective actions taken, every six (6) months. V. REPORTING REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4375]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4390]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4395]

[25 Pa. Code §127.12b] # 033

# 034

# 035

# 036

# 037 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines Plan approval terms and conditions.

What reports must I submit?

What are my reporting requirements if I operate an emergency combustion turbine or a research and development turbine?

When must I submit my reports?

Plan approval terms and conditions. [Plan Approval 37-337A] The facility shall submit semi-annual reports no later than March 1 for the January 1 thru December 31 of the previous year period and by September 1 for the July 1 of the previous year thru June 30 of the concurrent year period. The report shall include: 1. The greenhouse gas and SF6 emissions including emission calculations from all air-contaminant sources, on a monthly basis, in order to demonstrate compliance with the emission limitations for all sources at the facility. 2. The amount of SF6 dielectric fluid added to each circuit breaker unit each month. 3. The date and time that each alarm associated with the circuit breaker is activated, the corrective action taken to remedy the problem associated with each alarm, and the date corrective action remedied the problem.

(a) For each affected unit required to continuously monitor parameters or emissions, or to periodically determine the fuel sulfur content under this subpart, you must submit reports of excess emissions and monitor downtime, in accordance with § 60.7(c). Excess emissions must be reported for all periods of unit operation, including start-up, shutdown, and malfunction. (b) For each affected unit that performs annual performance tests in accordance with § 60.4340(a), you must submit a written report of the results of each performance test before the close of business on the 60th day following the completion of the performance test.

Not applicable

All reports required under § 60.7(c) must be postmarked by the 30th day following the end of each 6-month period.

[Plan Approval 37-337A] (a) The permittee shall perform a daily operational inspection of the source until such time as the Department approves a work practice inspection protocol submitted by the permittee. After Departmental approval, the permittee shall perform periodic inspections of the significant source equipment and emission controls in accordance with the approved work practice inspection protocol. [Plan Approval 37-337A] (b) All gauges employed by the permittee to monitor the required control device operating parameters shall have a scale such that the expected normal reading shall be no less than twenty percent (20%) of full scale and be accurate within plus or minus two percent (+/- 2%) of full scale reading. [Plan Approval 37-337A] (c) The permittee shall operate the control device(s) at all times this source is in operation once operating parameters VI. WORK PRACTICE REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b] # 038 Plan approval terms and conditions. (temperature, flow, etc.) are sufficient for proper control device operation. [Plan Approval 37-337A] (d) The permittee shall maintain and operate this source and the control device(s) in accordance with the manufacturer's specifications, the manufacturer's preventative maintenance schedule, and good air pollution control practices. The facility shall maintain a copy of the manufacturer's preventative maintenance schedule on-site. [Plan Approval 37-337A] (e) The SCR system shall be designed so it will not inject ammonia into the system when the inlet temperature to the catalyst is less than the minimum catalyst temperature to be established as part of the O&M plan. [Plan Approval 37-337A] (f) Prior to commencement of operations, the permittee shall develop and submit to the Department for approval a Risk Management Plan (RMP) meeting the requirements of Clean Air Act Section 112(r) and 40 CFR 68 Subpart G, with respect to the storage of aqueous ammonia if the permittee intends to store aqueous ammonia with a concentration of 20% or greater such that the quantity of ammonia present at the facility at any time exceeds 20,000 pounds, and the permittee shall implement the Department approved RMP.

[Plan Approval 37-337A] [Additional authority for this permit condition is derived from 25 Pa. Code Sections 139.101(1)(iv), 139.101(2), 139.101(3), 139.101(4), 139.101(6), 139.101(7), 139.101(8), 139.101(12), 139.101(14) and 139.101(15))] (a) Continuous Emission Monitoring Systems and components must be operated and maintained in accordance with the requirements established in 25 Pa. Code Chapter 139, Subchapter C (relating to requirements for source monitoring for stationary sources) and the "Quality Assurance" requirements in the Department's Continuous Source Monitoring Manual, Revision No. 8, 274-0300-001. [Plan Approval 37-337A] (b) Compliance with any subsequently issued revision to the Continuous Source Monitoring Manual will constitute compliance with this permit condition. [Plan Approval 37-337A] (c) Data Availability Standards: Continuous emission monitoring shall meet the following minimum data availability requirements: 1. In accordance with 25 Pa. Code Section 139.101(12), required monitoring shall, at a minimum, meet one of the following data availability requirements unless otherwise stipulated in this permit, a plan approval, Title 25 or an order issued under Section 4 of the Air Pollution Control Act: (a) In each calendar month, at least 90% of the time periods for which an emission standard or an operational parameter applies, shall be valid as set forth in the Quality Assurance section of Revision No. 8 of the Department's Continuous Source Monitoring Manual, 274-0300-001; or (b) In each calendar quarter, at least 95% of the hours shall be valid as set forth in the Quality Assurance section of Revision No. 8 of the Department's Continuous Source Monitoring Manual, 274-0300-001. 2. Compliance with any subsequently issued revisions to the Continuous Source Monitoring Manual will constitute compliance with the regulations. 3. Emission Standard(s) To Which Data Availability Standard applies: (a) CO (ppmvd) (b) NOx (ppmvd) SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 039

# 040 Plan approval terms and conditions.

Plan approval terms and conditions. (c) CO2 (lbs per hr) (d) GEO (MW-hr gross) (e) Ammonia (ppmvd)

[Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.3 & §64.6] (a) Within 180-days of commencement of operation, or by the date of the initial operating permit inspection, whichever is sooner, the permittee shall submit the proposed indicator ranges for the following: 1. Oxidation Catalyst (a) Catalyst Temperature The proposed indicator ranges, as approved by the Department, shall be incorporated into the operating permit. The permittee shall adhere to the approved indicator ranges so that operation within the range shall provide reasonable assurance of compliance. A departure from the specified indicator range over the specified averaging period shall be defined as an excursion. Within 24-hours of discovery of an indicator being out of range, the permittee shall perform a maintenance inspection on the control device and take corrective action. [Plan Approval 37-337A] [Additional authority for the following permit conditions are also derived from 40 CFR §64.3] (b) The permittee shall utilize approved QA/QC practices that are adequate to ensure continuing validity of data and proper performance of the devices. 1. The permittee shall, for an approved device(s), install detectors or sensors at a location approved by the Department for obtaining data that are representative of the monitored indicator. 2. The permittee shall develop verification procedures to confirm the operational status of new or modified monitoring equipment prior to commencement of the monitoring process. (The operational status pertains to the first time calibration of new or modified equipment. The permittee may compare the data with any Department approved standardized data. For example, permittee might calibrate a new pH sensor by comparison with laboratory measurement of the scrubber recirculation fluid.) (The operational status pertains to the first time calibration of new or modified equipment. The permittee may compare the data with any Department approved standardized data. For example, you might compare a pressure gauge at a controlled pressure to that of a pressure standard of a known accuracy, or thermal couple temperature accuracy measured against a known reference temperature traceable to a National Institute for Standards and Technology (NIST)). 3. The permittee shall calibrate and check the accuracy of monitoring equipment taking into account the manufacturer's specifications at approved time intervals. (a) Oxidation Catalyst (i) Thermocouple or equivalent - calibrated and checked for accuracy annually [Plan Approval 37-337A] (c) The permittee shall maintain all monitoring equipment and stock parts necessary for routine repairs onsite. [Plan Approval 37-337A] (d) The permittee shall ensure that at least 90% of the monitoring data has been properly and accurately collected.

The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4333]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4380] # 041

# 042 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines What are my general requirements for complying with this subpart?

How are excess emissions and monitor downtime defined for NOX ? [Plan Approval 37-337A] (a) The permittee shall incorporate instrumentation and control systems that will allow plant efficiency to be optimized to the maximum extent practicable. To maintain efficient operating characteristics, these systems shall be periodically maintained in accordance with the permittee's Preventative maintenance Program. [Plan Approval 37-337A] (c) Facility shall implement a sulfur hexafluoride (SF6) leak detection program to minimize SF6 leaks as follows. Circuit breakers are to be state-of-the-art sealed enclosed-pressure circuit breakers equipped with low-pressure alarms that are triggered when 10% of the SF6 by weight has escaped. When alarms are triggered, the facility will take corrective action as soon as practicable to fix the circuit breaker units to a like-new state to prevent the emission of SF6 to the maximum extent practicable. [Plan Approval 37-337A] (e) Facility shall develop a site Preventative Maintenance Program to maintain plant operating efficiency.

(a) You must operate and maintain your stationary combustion turbine, air pollution control equipment, and monitoring equipment in a manner consistent with good air pollution control practices for minimizing emissions at all times including during startup, shutdown, and malfunction. (b) When an affected unit with heat recovery utilizes a common steam header with one or more combustion turbines, the owner or operator shall either: (1) Determine compliance with the applicable NOX emissions limits by measuring the emissions combined with the emissions from the other unit(s) utilizing the common heat recovery unit; or (2) Develop, demonstrate, and provide information satisfactory to the Administrator on methods for apportioning the combined gross energy output from the heat recovery unit for each of the affected combustion turbines. The Administrator may approve such demonstrated substitute methods for apportioning the combined gross energy output measured at the steam turbine whenever the demonstration ensures accurate estimation of emissions related under this part.

For the purpose of reports required under § 60.7(c), periods of excess emissions and monitor downtime that must be reported are defined as follows: (a) Not applicable (b) For turbines using continuous emission monitoring, as described in §§ 60.4335(b) and 60.4345: (1) An excess emissions is any unit operating period in which the 4-hour or 30-day rolling average NOX emission rate exceeds the applicable emission limit in § 60.4320. For the purposes of this subpart, a “4-hour rolling average NOX emission rate” is the arithmetic average of the average NOX emission rate in ppm or ng/J (lb/MWh) measured by the continuous emission monitoring equipment for a given hour and the three unit operating hour average NOX emission rates immediately preceding that unit operating hour. Calculate the rolling average if a valid NOX emission rate is obtained for at least 3 of the 4 hours. For the purposes of this subpart, a “30-day rolling average NOX emission rate” is the arithmetic average of all hourly NOX emission data in ppm or ng/J (lb/MWh) measured by the continuous emission monitoring equipment for a given day and the twenty-nine unit operating days immediately preceding that unit operating day. A new 30- day average is calculated each unit operating day as the average of all hourly NOX emissions rates for the preceding 30 unit operating days if a valid NOX emission rate is obtained for at least 75 percent of all operating hours. (2) A period of monitor downtime is any unit operating hour in which the data for any of the following parameters are either missing or invalid: NOX concentration, CO2 or O2 concentration, fuel flow rate, steam flow rate, steam temperature, steam SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4385]

[25 Pa. Code §127.12b] # 043

# 044 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines How are excess emissions and monitoring downtime defined for SO2?

Plan approval terms and conditions. pressure, or megawatts. The steam flow rate, steam temperature, and steam pressure are only required if you will use this information for compliance purposes. (3) For operating periods during which multiple emissions standards apply, the applicable standard is the average of the applicable standards during each hour. For hours with multiple emissions standards, the applicable limit for that hour is determined based on the condition that corresponded to the highest emissions standard. (c) Not applicable

If you choose the option to monitor the sulfur content of the fuel, excess emissions and monitoring downtime are defined as follows: (a) For samples of gaseous fuel and for oil samples obtained using daily sampling, flow proportional sampling, or sampling from the unit's storage tank, an excess emission occurs each unit operating hour included in the period beginning on the date and hour of any sample for which the sulfur content of the fuel being fired in the combustion turbine exceeds the applicable limit and ending on the date and hour that a subsequent sample is taken that demonstrates compliance with the sulfur limit. (b) Not applicable (c) A period of monitor downtime begins when a required sample is not taken by its due date. A period of monitor downtime also begins on the date and hour of a required sample, if invalid results are obtained. The period of monitor downtime ends on the date and hour of the next valid sample.

[Plan Approval 37-337A] (a) The source is subject to the following: 1. 40 CFR 60 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines 2. Acid Rain Regulations (40 CFR 72-78) (Applicable) 3. CAIR (40 CFR 96) (Applicable - was replaced by CSAPR but CSAPR was stayed) 4. Cross State Air Pollution Rule (CSAPR) (40 CFR 97) (Not applicable - stayed 8-21-12) 5. Risk Management Program (40 CFR 68) (Applicable if greater than 20,000 lbs of aqueous ammonia at concentrations of 20% or greater is stored at facility) 6. CAM (40 CFR 64) (Applicable for pollutants being controlled and not having CEM) [Plan Approval 37-337A] (b) Any information required to be submitted as part of the above conditions should be submitted to the New Source Review Section Chief, Air Quality Program, Northwest Regional Office, 230 Chestnut Street, Meadville, PA 16335-3481. [Plan Approval 37-337A] (c) In accordance with 40 CFR 60.4 copies of all requests, reports, applications submittals and other communications shall be forwarded to both EPA and the Department at the addresses listed below unless otherwise noted. Air Quality Program Manager VII. ADDITIONAL REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 045

# 046 Plan approval terms and conditions.

Plan approval terms and conditions. Pa DEP Air Quality 230 Chestnut Street Meadville, PA 16335 Director Air Toxics and Radiation US EPA, Region III 1650 Arch Street Philadelphia, PA 19103-2029 [Plan Approval 37-337A] (d) Issuance of an operating permit is contingent upon satisfactory compliance with conditions numbered above, upon the source being constructed and operating as stated on the application, and upon the satisfactory demonstration that the emissions from the source will not be in violation of applicable Rules & Regulations of the Department of Environmental Protection.

[Plan Approval 37-337A] [25 Pa. Code §127.441(c) & Chapter 139; §§114(a)(3), 504(b) of the CAA] Sampling, Testing and Monitoring Procedures 1. The permittee shall perform the emissions monitoring analysis procedures or test methods required under an applicable requirement including procedures and methods under Sections 114(a)(3) ( 42 U.S.C.A.§§ 7414 (a)(3)) or 504(b) ( 42 U.S.C.A.§§ 7661c(b)) of the Clean Air Act. 2. Unless otherwise required by this permit, the permittee shall comply with applicable monitoring, quality assurance, recordkeeping and reporting requirements of the Air Pollution Control Act, 25 Pa. Code, Subpart C, Article III (relating to air resources), including Chapter 139 (relating to sampling and testing). The permittee shall also comply with applicable requirements related to monitoring, quality assurance, reporting and recordkeeping required by the Clean Air Act including §§ 114(a)(3) and 504(b) and regulations adopted thereunder, unless otherwise required by this permit.

Quality Improvement Plan Requirements [Plan Approval 37-337A] [Additional authority for the following permit conditions are also derived from 40 CFR §64.8] (a) The permittee shall develop and implement a quality improvement plan (QIP) as expeditiously as practicable if any of the following occurs: (1) Six excursions occur in a six-month reporting period. (2) The Department determines after review of all reported information that the permittee has not responded acceptably to an excursion. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.8] (b) In general, the QIP plan should be developed within 60 days and the permittee shall provide a copy of the QIP to the Department. Furthermore, the permittee shall notify the Department if the period for completing the improvements contained in the QIP exceeds 180 days from the date on which the need to implement the QIP was determined. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.9] (c) The permittee shall record actions taken to implement a QIP during a reporting period and all related actions including, but not limited to inspections, repairs and maintenance performed on the monitoring equipment. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.8] (d) In accordance with § 64.8, the QIP shall include procedures for evaluating the control performance problems. Based on SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4300]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4305]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4310]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4315] # 047

# 048

# 049

# 050 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines What is the purpose of this subpart?

Does this subpart apply to my stationary combustion turbine?

What types of operations are exempt from these standards of performance?

What pollutants are regulated by this subpart? the results of the evaluation procedures, the permittee shall modify the QIP, and provide a copy to the Department, to include procedures for conducting more frequent or improved monitoring in conjunction with one or more of the following: (1) Improved preventive maintenance practices (2) Process operation changes (3) Appropriate improvements to control methods (4) Other steps appropriate to correct performance. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.8] (e) Following implementation of a QIP, the Department will require reasonable revisions to the QIP if the plan has failed to either: (1) Address the cause of the control device performance problem. (2) Provide adequate procedures for correcting control device performance problems in as expeditiously as practicable in accordance with good air pollution control practices for minimizing emissions. [Plan Approval 37-337A] [Additional authority for this permit condition is also derived from 40 CFR §64.8] (f) Implementation of a QIP, shall not excuse the owner or operator of a source from compliance with any existing emission limitation or standard or any existing monitoring, testing, reporting or recordkeeping requirement that may apply under any federal, state, or local laws or any other applicable requirements under the Clean Air Act.

This subpart establishes emission standards and compliance schedules for the control of emissions from stationary combustion turbines that commenced construction, modification or reconstruction after February 18, 2005.

(a) If you are the owner or operator of a stationary combustion turbine with a heat input at peak load equal to or greater than 10.7 gigajoules (10 MMBtu) per hour, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005, your turbine is subject to this subpart. Only heat input to the combustion turbine should be included when determining whether or not this subpart is applicable to your turbine. Any additional heat input to associated heat recovery steam generators (HRSG) or duct burners should not be included when determining your peak heat input. However, this subpart does apply to emissions from any associated HRSG and duct burners. (b) Stationary combustion turbines regulated under this subpart are exempt from the requirements of subpart GG of this part. Heat recovery steam generators and duct burners regulated under this subpart are exempted from the requirements of subparts Da, Db, and Dc of this part.

Not applicable

The pollutants regulated by this subpart are nitrogen oxide (NOX) and sulfur dioxide (SO2). SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4420] # 051 Subpart KKKK - Standards of Performance for Stationary Combustion Turbines What definitions apply to this subpart? As used in this subpart, all terms not defined herein will have the meaning given them in the Clean Air Act and in subpart A (General Provisions) of this part. Biogas means gas produced by the anaerobic digestion or fermentation of organic matter including manure, sewage sludge, municipal solid waste, biodegradable waste, or any other biodegradable feedstock, under anaerobic conditions. Biogas is comprised primarily of methane and CO2. Combined cycle combustion turbine means any stationary combustion turbine which recovers heat from the combustion turbine exhaust gases to generate steam that is only used to create additional power output in a steam turbine. Combined heat and power combustion turbine means any stationary combustion turbine which recovers heat from the exhaust gases to heat water or another medium, generate steam for useful purposes other than additional electric generation, or directly uses the heat in the exhaust gases for a useful purpose. Combustion turbine model means a group of combustion turbines having the same nominal air flow, combustor inlet pressure, combustor inlet temperature, firing temperature, turbine inlet temperature and turbine inlet pressure. Combustion turbine test cell/stand means any apparatus used for testing uninstalled stationary or uninstalled mobile (motive) combustion turbines. Diffusion flame stationary combustion turbine means any stationary combustion turbine where fuel and air are injected at the combustor and are mixed only by diffusion prior to ignition. Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source, such as a stationary combustion turbine, internal combustion engine, kiln, etc., to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a heat recovery steam generating unit. Efficiency means the combustion turbine manufacturer's rated heat rate at peak load in terms of heat input per unit of power output—based on the higher heating value of the fuel. Emergency combustion turbine means any stationary combustion turbine which operates in an emergency situation. Examples include stationary combustion turbines used to produce power for critical networks or equipment, including power supplied to portions of a facility, when electric power from the local utility is interrupted, or stationary combustion turbines used to pump water in the case of fire or flood, etc. Emergency stationary combustion turbines do not include stationary combustion turbines used as peaking units at electric utilities or stationary combustion turbines at industrial facilities that typically operate at low capacity factors. Emergency combustion turbines may be operated for the purpose of maintenance checks and readiness testing, provided that the tests are required by the manufacturer, the vendor, or the insurance company associated with the turbine. Required testing of such units should be minimized, but there is no time limit on the use of emergency combustion turbines. Excess emissions means a specified averaging period over which either (1) the NOX emissions are higher than the applicable emission limit in § 60.4320; (2) the total sulfur content of the fuel being combusted in the affected facility exceeds the limit specified in § 60.4330; or (3) the recorded value of a particular monitored parameter is outside the acceptable range specified in the parameter monitoring plan for the affected unit. Gross useful output means the gross useful work performed by the stationary combustion turbine system. For units using the mechanical energy directly or generating only electricity, the gross useful work performed is the gross electrical or mechanical output from the turbine/generator set. For combined heat and power units, the gross useful work performed is the gross electrical or mechanical output plus the useful thermal output (i.e., thermal energy delivered to a process). Heat recovery steam generating unit means a unit where the hot exhaust gases from the combustion turbine are routed in order to extract heat from the gases and generate steam, for use in a steam turbine or other device that utilizes steam. Heat SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 72 Regulations on Permits §40 CFR 72.30] # 052 Subpart C--Acid Rain Permit Application Requirements to apply. recovery steam generating units can be used with or without duct burners. Integrated gasification combined cycle electric utility steam generating unit means a coal-fired electric utility steam generating unit that burns a synthetic gas derived from coal in a combined-cycle gas turbine. No solid coal is directly burned in the unit during operation. ISO conditions means 288 Kelvin, 60 percent relative humidity and 101.3 kilopascals pressure. Lean premix stationary combustion turbine means any stationary combustion turbine where the air and fuel are thoroughly mixed to form a lean mixture before delivery to the combustor. Mixing may occur before or in the combustion chamber. A lean premixed turbine may operate in diffusion flame mode during operating conditions such as startup and shutdown, extreme ambient temperature, or low or transient load. Natural gas means a naturally occurring fluid mixture of hydrocarbons (e.g., methane, ethane, or propane) produced in geological formations beneath the Earth's surface that maintains a gaseous state at standard atmospheric temperature and pressure under ordinary conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 950 and 1,100 British thermal units (Btu) per standard cubic foot. Naturalgas does not include the following gaseous fuels: landfill gas, digester gas, refinery gas, sour gas, blast furnace gas, coalderived gas, producer gas, coke oven gas, or any gaseous fuel produced in a process which might result in highly variable sulfur content or heating value. Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, the Northern Mariana Islands, or offshore platforms. Peak load means 100 percent of the manufacturer's design capacity of the combustion turbine at ISO conditions. Regenerative cycle combustion turbine means any stationary combustion turbine which recovers heat from the combustion turbine exhaust gases to preheat the inlet combustion air to the combustion turbine. Simple cycle combustion turbine means any stationary combustion turbine which does not recover heat from the combustion turbine exhaust gases to preheat the inlet combustion air to the combustion turbine, or which does not recover heat from the combustion turbine exhaust gases for purposes other than enhancing the performance of the combustion turbine itself. Stationary combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), heat recovery system, and any ancillary components and sub-components comprising any simple cycle stationary combustion turbine, any regenerative/recuperative cycle stationary combustion turbine, any combined cycle combustion turbine, and any combined heat and power combustion turbine based system. Stationary means that the combustion turbine is not self propelled or intended to be propelled while performing its function. It may, however, be mounted on a vehicle for portability. Unit operating day means a 24-hour period between 12 midnight and the following midnight during which any fuel is combusted at any time in the unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period. Unit operating hour means a clock hour during which any fuel is combusted in the affected unit. If the unit combusts fuel for the entire clock hour, it is considered to be a full unit operating hour. If the unit combusts fuel for only part of the clock hour, it is considered to be a partial unit operating hour. Useful thermal output means the thermal energy made available for use in any industrial or commercial process, or used in any heating or cooling application, i.e., total thermal energy made available for processes and applications other than electrical or mechanical generation. Thermal output for this subpart means the energy in recovered thermal output measured against the energy in the thermal output at 15 degrees Celsius and 101.325 kilopascals of pressure. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.106] # 053 Subpart AA - CAIR NOX Annual Trading Program General Provisions Standard requirements. (a) Duty to apply. The designated representative of any source with an affected unit shall submit a complete Acid Rain permit application by the applicable deadline in paragraphs (b) and (c) of this section, and the owners and operators of such source and any affected unit at the source shall not operate the source or unit without a permit that states its Acid Rain program requirements. (b) Deadlines. (1) Not applicable (2) Phase II. (i) Not applicable (ii) For any source with a new unit under 72.6(a)(3)(i), the designated representative shall submit a complete Acid Rain permit application governing such unit to the permitting authority at least 24 months before the later of January 1, 2000 or the date on which the unit commences operation. (iii) Not applicable (iv) Not applicable (v) Not applicable (vi) Not applicable (vii) Not applicable (viii) Not applicable (3) Acid Rain Compliance Option Deadlines. The deadlines for applying for approval of any Acid Rain compliance options shall be the deadlines specified in the relevant section of subpart D of this part and in section 407 of the Act and regulations implementing section 407 of the Act. (c) Duty to Reapply. The designated representative shall submit a complete Acid Rain permit application for each source with an affected unit at least 6 months prior to the expiration of an existing Acid Rain permit governing the unit during Phase II or such longer time as may be approved under part 70 of this chapter that ensures that the term of the existing permit will not expire before the effective date of the permit for which the application is submitted. (d) The original and three copies of all permit applications for Phase I and where the Administrator is the permitting authority, for Phase II, shall be submitted to the EPA Regional Office for the Region where the affected source is located. The original and three copies of all permit applications for Phase II, where the Administrator is not the permitting authority, shall be submitted to the State permitting authority for the State where the affected source is located.

(a) Permit requirements. (1) The CAIR designated representative of each CAIR NOX source required to have a title V operating permit and each CAIR NOX unit required to have a title V operating permit at the source shall: (i) Submit to the permitting authority a complete CAIR permit application under § 97.122 in accordance with the deadlines specified in § 97.121; and (ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit. (2) The owners and operators of each CAIR NOX source required to have a title V operating permit and each CAIR NOX unit SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: required to have a title V operating permit at the source shall have a CAIR permit issued by the permitting authority under subpart CC of this part for the source and operate the source and the unit in compliance with such CAIR permit. (3) Except as provided in subpart II of this part, the owners and operators of a CAIR NOX source that is not otherwise required to have a title V operating permit and each CAIR NOX unit that is not otherwise required to have a title V operating permit are not required to submit a CAIR permit application, and to have a CAIR permit, under subpart CC of this part for such CAIR NOX source and such CAIR NOX unit. (b) Monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the CAIR designated representative, of each CAIR NOX source and each CAIR NOX unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of subpart HH of this part. (2) The emissions measurements recorded and reported in accordance with subpart HH of this part shall be used to determine compliance by each CAIR NOX source with the CAIR NOX emissions limitation under paragraph (c) of this section. (c) Nitrogen oxides emission requirements. (1) As of the allowance transfer deadline for a control period, the owners and operators of each CAIR NOX source and each CAIR NOX unit at the source shall hold, in the source's compliance account, CAIR NOX allowances available for compliance deductions for the control period under § 97.154(a) in an amount not less than the tons of total nitrogen oxides emissions for the control period from all CAIR NOX units at the source, as determined in accordance with subpart HH of this part. (2) A CAIR NOX unit shall be subject to the requirements under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2009 or the deadline for meeting the unit's monitor certification requirements under § 97.170(b)(1), (2), or (5) and for each control period thereafter. (3) A CAIR NOX allowance shall not be deducted, for compliance with the requirements under paragraph (c)(1) of this section, for a control period in a calendar year before the year for which the CAIR NOX allowance was allocated. (4) CAIR NOX allowances shall be held in, deducted from, or transferred into or among CAIR NOX Allowance Tracking System accounts in accordance with subparts EE, FF, GG, and II of this part. (5) A CAIR NOX allowance is a limited authorization to emit one ton of nitrogen oxides in accordance with the CAIR NOX Annual Trading Program. No provision of the CAIR NOX Annual Trading Program, the CAIR permit application, the CAIR permit, or an exemption under § 97.105 and no provision of law shall be construed to limit the authority of the United States to terminate or limit such authorization. (6) A CAIR NOX allowance does not constitute a property right. (7) Upon recordation by the Administrator under subpart EE, FF, GG, or II of this part, every allocation, transfer, or deduction of a CAIR NOX allowance to or from a CAIR NOX source's compliance account is incorporated automatically in any CAIR permit of the source. (d) Excess emissions requirements. If a CAIR NOX source emits nitrogen oxides during any control period in excess of the CAIR NOX emissions limitation, then: (1) The owners and operators of the source and each CAIR NOX unit at the source shall surrender the CAIR NOX allowances required for deduction under § 97.154(d)(1) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act or applicable State law; and (2) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law. (e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the CAIR NOX source and each CAIR NOX unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time before the end of 5 SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.206] # 054 Subpart AAA - CAIR SO2 Trading Program General Provisions Standard requirements. years, in writing by the permitting authority or the Administrator. (i) The certificate of representation under § 97.113 for the CAIR designated representative for the source and each CAIR NOX unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation under § 97.113 changing the CAIR designated representative. (ii) All emissions monitoring information, in accordance with subpart HH of this part, provided that to the extent that subpart HH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply. (iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR NOX Annual Trading Program. (iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR NOX Annual Trading Program or to demonstrate compliance with the requirements of the CAIR NOX Annual Trading Program. (2) The CAIR designated representative of a CAIR NOX source and each CAIR NOX unit at the source shall submit the reports required under the CAIR NOX Annual Trading Program, including those under subpart HH of this part. (f) Liability. (1) Each CAIR NOX source and each CAIR NOX unit shall meet the requirements of the CAIR NOX Annual Trading Program. (2) Any provision of the CAIR NOX Annual Trading Program that applies to a CAIR NOX source or the CAIR designated representative of a CAIR NOX source shall also apply to the owners and operators of such source and of the CAIR NOX units at the source. (3) Any provision of the CAIR NOX Annual Trading Program that applies to a CAIR NOX unit or the CAIR designated representative of a CAIR NOX unit shall also apply to the owners and operators of such unit. (g) Effect on other authorities. No provision of the CAIR NOX Annual Trading Program, a CAIR permit application, a CAIR permit, or an exemption under § 97.105 shall be construed as exempting or excluding the owners and operators, and the CAIR designated representative, of a CAIR NOX source or CAIR NOX unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

(a) Permit requirements. (1) The CAIR designated representative of each CAIR SO2 source required to have a title V operating permit and each CAIR SO2 unit required to have a title V operating permit at the source shall: (i) Submit to the permitting authority a complete CAIR permit application under § 97.222 in accordance with the deadlines specified in § 97.221; and (ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit. (2) The owners and operators of each CAIR SO2 source required to have a title V operating permit and each CAIR SO2 unit required to have a title V operating permit at the source shall have a CAIR permit issued by the permitting authority under subpart CCC of this part for the source and operate the source and the unit in compliance with such CAIR permit. (3) Except as provided in subpart III of this part, the owners and operators of a CAIR SO2 source that is not otherwise required to have a title V operating permit and each CAIR SO2 unit that is not otherwise required to have a title V operating permit are not required to submit a CAIR permit application, and to have a CAIR permit, under subpart CCC of this part for such CAIR SO2 source and such CAIR SO2 unit. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (b) Monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the CAIR designated representative, of each CAIR SO2 source and each CAIR SO2 unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of subpart HHH of this part. (2) The emissions measurements recorded and reported in accordance with subpart HHH of this part shall be used to determine compliance by each CAIR SO2 source with the CAIR SO2 emissions limitation under paragraph (c) of this section. (c) Sulfur dioxide emission requirements. (1) As of the allowance transfer deadline for a control period, the owners and operators of each CAIR SO2 source and each CAIR SO2 unit at the source shall hold, in the source's compliance account, a tonnage equivalent in CAIR SO2 allowances available for compliance deductions for the control period, as determined in accordance with § 97.254(a) and (b), not less than the tons of total sulfur dioxide emissions for the control period from all CAIR SO2 units at the source, as determined in accordance with subpart HHH of this part. (2) A CAIR SO2 unit shall be subject to the requirements under paragraph (c)(1) of this section for the control period starting on the later of January 1, 2010 or the deadline for meeting the unit(s monitor certification requirements under § 97.270(b)(1),(2), or (5) and for each control period thereafter. (3) A CAIR SO2 allowance shall not be deducted, for compliance with the requirements under paragraph (c)(1) of this section, for a control period in a calendar year before the year for which the CAIR SO2 allowance was allocated. (4) CAIR SO2 allowances shall be held in, deducted from, or transferred into or among CAIR SO2 Allowance Tracking System accounts in accordance with subparts FFF, GGG, and III of this part. (5) A CAIR SO2 allowance is a limited authorization to emit sulfur dioxide in accordance with the CAIR SO2 Trading Program. No provision of the CAIR SO2 Trading Program, the CAIR permit application, the CAIR permit, or an exemption under § 97.205 and no provision of law shall be construed to limit the authority of the United States to terminate or limit such authorization. (6) A CAIR SO2 allowance does not constitute a property right. (7) Upon recordation by the Administrator under subpart FFF, GGG, or III of this part, every allocation, transfer, or deduction of a CAIR SO2 allowance to or from a CAIR SO2 source's compliance account is incorporated automatically in any CAIR permit of the source. (d) Excess emissions requirements. If a CAIR SO2 source emits sulfur dioxide during any control period in excess of the CAIR SO2 emissions limitation, then: (1) The owners and operators of the source and each CAIR SO2 unit at the source shall surrender the CAIR SO2 allowances required for deduction under § 97.254(d)(1) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act or applicable State law; and (2) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law. (e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the CAIR SO2 source and each CAIR SO2 unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time before the end of 5 years, in writing by the permitting authority or the Administrator. (i) The certificate of representation under § 97.213 for the CAIR designated representative for the source and each CAIR SO2 unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation under § 97.213 changing the CAIR designated representative. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.306] # 055 Subpart AAAA - CAIR NOX Ozone Season Trading Program General Provisions Standard requirements. (ii) All emissions monitoring information, in accordance with subpart HHH of this part, provided that to the extent that subpart HHH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply. (iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR SO2 Trading Program. (iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR SO2 Trading Program or to demonstrate compliance with the requirements of the CAIR SO2 Trading Program. (2) The CAIR designated representative of a CAIR SO2 source and each CAIR SO2 unit at the source shall submit the reports required under the CAIR SO2 Trading Program, including those under subpart HHH of this part. (f) Liability. (1) Each CAIR SO2 source and each CAIR SO2 unit shall meet the requirements of the CAIR SO2 Trading Program. (2) Any provision of the CAIR SO2 Trading Program that applies to a CAIR SO2 source or the CAIR designated representative of a CAIR SO2 source shall also apply to the owners and operators of such source and of the CAIR SO2 units at the source. (3) Any provision of the CAIR SO2 Trading Program that applies to a CAIR SO2 unit or the CAIR designated representative of a CAIR SO2 unit shall also apply to the owners and operators of such unit. (g) Effect on other authorities. No provision of the CAIR SO2 Trading Program, a CAIR permit application, a CAIR permit, or an exemption under § 97.205 shall be construed as exempting or excluding the owners and operators, and the CAIR designated representative, of a CAIR SO2 source or CAIR SO2 unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act.

(a) Permit requirements. (1) The CAIR designated representative of each CAIR NOX Ozone Season source required to have a title V operating permit and each CAIR NOX Ozone Season unit required to have a title V operating permit at the source shall: (i) Submit to the permitting authority a complete CAIR permit application under § 97.322 in accordance with the deadlines specified in § 97.321; and (ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit. (2) The owners and operators of each CAIR NOX Ozone Season source required to have a title V operating permit and each CAIR NOX Ozone Season unit required to have a title V operating permit at the source shall have a CAIR permit issued by the permitting authority under subpart CCCC of this part for the source and operate the source and the unit in compliance with such CAIR permit. (3) Except as provided in subpart IIII of this part, the owners and operators of a CAIR NOX Ozone Season source that is not otherwise required to have a title V operating permit and each CAIR NOX Ozone Season unit that is not otherwise required to have a title V operating permit are not required to submit a CAIR permit application, and to have a CAIR permit, under subpart CCCC of this part for such CAIR NOX Ozone Season source and such CAIR NOX Ozone Season unit. (b) Monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the CAIR designated representative, of each CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit at the source shall comply with the monitoring, reporting, and recordkeeping requirements of subpart HHHH of this part. (2) The emissions measurements recorded and reported in accordance with subpart HHHH of this part shall be used to determine compliance by each CAIR NOX Ozone Season source with the CAIR NOX Ozone Season emissions limitation SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: under paragraph (c) of this section. (c) Nitrogen oxides ozone season emission requirements. (1) As of the allowance transfer deadline for a control period, the owners and operators of each CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit at the source shall hold, in the source's compliance account, CAIR NOX Ozone Season allowances available for compliance deductions for the control period under § 97.354(a) in an amount not less than the tons of total nitrogen oxides emissions for the control period from all CAIR NOX Ozone Season units at the source, as determined in accordance with subpart HHHH of this part. (2) A CAIR NOX Ozone Season unit shall be subject to the requirements under paragraph (c)(1) of this section for the control period starting on the later of May 1, 2009 or the deadline for meeting the unit's monitor certification requirements under § 97.370(b)(1), (2), (3), or (7) and for each control period thereafter. (3) A CAIR NOX Ozone Season allowance shall not be deducted, for compliance with the requirements under paragraph (c)(1) of this section, for a control period in a calendar year before the year for which the CAIR NOX Ozone Season allowance was allocated. (4) CAIR NOX Ozone Season allowances shall be held in, deducted from, or transferred into or among CAIR NOX Ozone Season Allowance Tracking System accounts in accordance with subparts EEEE, FFFF, GGGG, and IIII of this part. (5) A CAIR NOX Ozone Season allowance is a limited authorization to emit one ton of nitrogen oxides in accordance with the CAIR NOX Ozone Season Trading Program. No provision of the CAIR NOX Ozone Season Trading Program, the CAIR permit application, the CAIR permit, or an exemption under § 97.305 and no provision of law shall be construed to limit the authority of the United States to terminate or limit such authorization. (6) A CAIR NOX Ozone Season allowance does not constitute a property right. (7) Upon recordation by the Administrator under subpart EEEE, FFFF, GGGG, or IIII of this part, every allocation, transfer, or deduction of a CAIR NOX Ozone Season allowance to or from a CAIR NOX Ozone Season source's compliance account is incorporated automatically in any CAIR permit of the source. (d) Excess emissions requirements. If a CAIR NOX Ozone Season source emits nitrogen oxides during any control period in excess of the CAIR NOX Ozone Season emissions limitation, then: (1) The owners and operators of the source and each CAIR NOX Ozone Season unit at the source shall surrender the CAIR NOX Ozone Season allowances required for deduction under § 97.354(d)(1) and pay any fine, penalty, or assessment or comply with any other remedy imposed, for the same violations, under the Clean Air Act or applicable State law; and (2) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law. (e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time before the end of 5 years, in writing by the permitting authority or the Administrator. (i) The certificate of representation under § 97.313 for the CAIR designated representative for the source and each CAIR NOX Ozone Season unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation under § 97.313 changing the CAIR designated representative. (ii) All emissions monitoring information, in accordance with subpart HHHH of this part, provided that to the extent that subpart HHHH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply. (iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR NOX Ozone Season Trading Program. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR NOX Ozone Season Trading Program or to demonstrate compliance with the requirements of the CAIR NOX Ozone Season Trading Program. (2) The CAIR designated representative of a CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit at the source shall submit the reports required under the CAIR NOX Ozone Season Trading Program, including those under subpart HHHH of this part. (f) Liability. (1) Each CAIR NOX Ozone Season source and each CAIR NOX Ozone Season unit shall meet the requirements of the CAIR NOX Ozone Season Trading Program. (2) Any provision of the CAIR NOX Ozone Season Trading Program that applies to a CAIR NOX Ozone Season source or the CAIR designated representative of a CAIR NOX Ozone Season source shall also apply to the owners and operators of such source and of the CAIR NOX Ozone Season units at the source. (3) Any provision of the CAIR NOX Ozone Season Trading Program that applies to a CAIR NOX Ozone Season unit or the CAIR designated representative of a CAIR NOX Ozone Season unit shall also apply to the owners and operators of such unit. (g) Effect on other authorities. No provision of the CAIR NOX Ozone Season Trading Program, a CAIR permit application, a CAIR permit, or an exemption under § 97.305 shall be construed as exempting or excluding the owners and operators, and the CAIR designated representative, of a CAIR NOX Ozone Season source or CAIR NOX Ozone Season unit from compliance with any other provision of the applicable, approved State implementation plan, a federally enforceable permit, or the Clean Air Act. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: Source ID: Source Name:

033 AUXILIARY BOILER

Source Capacity/Throughput:

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.44c]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.45c] # 004

# 005 Subpart Dc - Standards of Performance for Small Industrial- Commercial-Institutional Steam Generating Units

Subpart Dc - Standards of Performance for Small Industrial- Commercial-Institutional Steam Generating Units Compliance and performance test methods and procedures for sulfur dioxide.

Compliance and performance test methods and procedures for particulate matter. Not applicable FML FML01 CU 033 STAC

S033 40.000 MMBTU/HR 39.300 MCF/HR Natural Gas

II. TESTING REQUIREMENTS. I. RESTRICTIONS. Emission Restriction(s). # 001

# 002

# 003 [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.42c]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.43c] Subpart Dc - Standards of Performance for Small Industrial- Commercial-Institutional Steam Generating Units

Subpart Dc - Standards of Performance for Small Industrial- Commercial-Institutional Steam Generating Units Plan approval terms and conditions.

Standard for sulfur dioxide.

Standard for particulate matter. [Plan Approval 37-337A] (a) The emissions shall not exceed the following: 1. PM/PM10/PM2.5: 0.005 #/mmbtu or 0.46 tpy based on a 12-month rolling total 2. NOx: 0.011 #/mmbtu or 1.01 tpy based on a 12-month rolling total 3. CO: 0.036 #/mmbtu or 3.31 tpy based on a 12-month rolling total 4. VOC: 0.0015 #/mmbtu or 0.14 tpy based on a 12-month rolling total 5. SOx: 0.0021 #/mmbtu or 0.19 tpy based on a 12-month rolling total 6. H2SO4: 0.00048 #/mmbtu or 0.04 tpy based on a 12-month rolling total
The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] (b) No person may permit the emission into the outdoor atmosphere of the following in a manner that exceeds the following: 1. CO2(e): 13,696 tpy based on a 12-month rolling basis

Not applicable

Not applicable SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.46c]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.47c]

[25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.48c] # 006

# 007

# 008

# 009 Subpart Dc - Standards of Performance for Small Industrial- Commercial-Institutional Steam Generating Units

Subpart Dc - Standards of Performance for Small Industrial- Commercial-Institutional Steam Generating Units

Subpart Dc - Standards of Performance for Small Industrial- Commercial-Institutional Steam Generating Units Emission monitoring for sulfur dioxide

Emission monitoring for particulate matter.

Plan approval terms and conditions.

Reporting and recordkeeping requirements. Not applicable

Not applicable

Not applicable

[Plan Approval 37-337A] (a) All recordkeeping shall commence upon startup of the source and shall be kept for a period of 5 years and made available to the Department upon request. [Plan Approval 37-337A] (b) The company shall maintain a log of all preventative maintenance inspections of the source. The inspection logs, at a minimum, shall contain the dates of the inspections, the name of the person performing the inspection, any mechanical repairs and/or adjustments, any potential problems or defects that were encountered, and the steps taken to correct them. [Plan Approval 37-337A] (c) The company shall maintain a log of the following, at a minimum, from the operational inspections: 1. Completion of inspection - daily defined as at least once per calendar day, while the source is operating or as approved by the Department in the work practice inspection protocol. [Plan Approval 37-337A] (d) The permittee shall comply with the recordkeeping and certification requirements in accordance with 40 CFR §§60.46c(e), 60.42c(h) and 60.48c(f)(1). Reports shall be submitted on a semi-annual basis unless no excess emissions occurred. If there are no excess emissions, the permittee shall semi-annually report that no excess emissions occurred during the semi-annual reporting period (this does not apply to gas-fired units). [Plan Approval 37-337A] (e) The permittee shall maintain daily fuel consumption records in accordance with 40 CFR §60.48c(g).
The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] (f) The facility shall maintain sufficient records to adequately demonstrate compliance with the emission limitations associated with the GHG rule.

(a) The owner or operator of each affected facility shall submit notification of the date of construction or reconstruction and actual startup, as provided by § 60.7 of this part. This notification shall include: III.

IV.

V. MONITORING REQUIREMENTS.

RECORDKEEPING REQUIREMENTS.

REPORTING REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (1) The design heat input capacity of the affected facility and identification of fuels to be combusted in the affected facility. (2) If applicable, a copy of any federally enforceable requirement that limits the annual capacity factor for any fuel or mixture of fuels under § 60.42c, or § 60.43c. (3) The annual capacity factor at which the owner or operator anticipates operating the affected facility based on all fuels fired and based on each individual fuel fired. (4) Notification if an emerging technology will be used for controlling SO2 emissions. The Administrator will examine the description of the control device and will determine whether the technology qualifies as an emerging technology. In making this determination, the Administrator may require the owner or operator of the affected facility to submit additional information concerning the control device. The affected facility is subject to the provisions of § 60.42c(a) or (b)(1), unless and until this determination is made by the Administrator. (b) Not applicable (c) Not applicable (d) Not applicable (e) Not applicable (f) Fuel supplier certification shall include the following information: (1) Not applicable (2) Not applicable (3) Not applicable (4) For other fuels: (i) The name of the supplier of the fuel; (ii) The potential sulfur emissions rate or maximum potential sulfur emissions rate of the fuel in ng/J heat input; and (iii) The method used to determine the potential sulfur emissions rate of the fuel. (g)(1) Except as provided under paragraphs (g)(2) and (g)(3) of this section, the owner or operator of each affected facility shall record and maintain records of the amount of each fuel combusted during each operating day. (2) As an alternative to meeting the requirements of paragraph (g)(1) of this section, the owner or operator of an affected facility that combusts only natural gas, wood, fuels using fuel certification in § 60.48c(f) to demonstrate compliance with the SO2 standard, fuels not subject to an emissions standard (excluding opacity), or a mixture of these fuels may elect to record and maintain records of the amount of each fuel combusted during each calendar month. (3) Not applicable (h) Not applicable (i) All records required under this section shall be maintained by the owner or operator of the affected facility for a period of two years following the date of such record. (j) The reporting period for the reports required under this subpart is each six-month period. All reports shall be submitted to the Administrator and shall be postmarked by the 30th day following the end of the reporting period. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.40c] # 010

# 011

# 012 Subpart Dc - Standards of Performance for Small Industrial- Commercial-Institutional Steam Generating Units Plan approval terms and conditions.

Plan approval terms and conditions.

Applicability and delegation of authority. [Plan Approval 37-337A] (a) The permittee shall perform a daily operational inspection of the source until such time as the Department approves a work practice inspection protocol submitted by the permittee. After Departmental approval, the permittee shall perform periodic inspections of the significant source equipment and emission controls in accordance with the approved work practice inspection protocol. [Plan Approval 37-337A] (b) The permittee shall install and maintain the necessary meter(s) to determine and to record amount of fuel usage. [Plan Approval 37-337A] (c) The permittee shall maintain and operate the source in accordance with the manufacturer's specifications, the manufacturer's preventative maintenance schedule, and good air pollution control practices. The facility shall maintain a copy of the manufacturer's preventative maintenance schedule on-site.

[Plan Approval 37-337A] (a) The source is subject to 40 CFR 60 Subpart Dc Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units. [Plan Approval 37-337A] (b) Any information required to be submitted as part of this plan approval should be submitted to the attention of Chief, New Source Review Section, Air Quality Control, Northwest Regional Office, 230 Chestnut Street, Meadville, PA 16335. [Plan Approval 37-337A] (c) In accordance with 40 CFR 60.4 copies of all requests, reports, applications submittals and other communications shall be forwarded to both EPA and the Department at the addresses listed below unless otherwise noted. Air Quality Program Manager Pa DEP Air Quality 230 Chestnut Street Meadville, PA 16335 Director Air Toxics and Radiation US EPA, Region III 1650 Arch Street Philadelphia, PA 19103-2029 [Plan Approval 37-337A] (d) Issuance of an Operating Permit is contingent upon satisfactory compliance with the plan approval conditions, upon the control device being installed, tested, and operated as stated within the application, and upon satisfactory demonstration that the emissions from the source will not be in violation of applicable Rules and Regulations of the Department.

(a) Except as provided in paragraphs (d), (e), (f), and (g) of this section, the affected facility to which this subpart applies is each steam generating unit for which construction, modification, or reconstruction is commenced after June 9, 1989 and that has a maximum design heat input capacity of 29 megawatts (MW) (100 million British thermal units per hour (MMBtu/h)) or less, but greater than or equal to 2.9 MW (10 MMBtu/h). VI.

VII. WORK PRACTICE REQUIREMENTS.

ADDITIONAL REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.41c] # 013 Subpart Dc - Standards of Performance for Small Industrial- Commercial-Institutional Steam Generating Units Definitions. (b) In delegating implementation and enforcement authority to a State under section 111(c) of the Clean Air Act, § 60.48c(a)(4) shall be retained by the Administrator and not transferred to a State. (c) Steam generating units that meet the applicability requirements in paragraph (a) of this section are not subject to the sulfur dioxide (SO2 ) or particulate matter (PM) emission limits, performance testing requirements, or monitoring requirements under this subpart (§§ 60.42c, 60.43c, 60.44c, 60.45c, 60.46c, or 60.47c) during periods of combustion research, as defined in § 60.41c. (d) Any temporary change to an existing steam generating unit for the purpose of conducting combustion research is not considered a modification under § 60.14. (e) Affected facilities ( i.e. heat recovery steam generators and fuel heaters) that are associated with stationary combustion turbines and meet the applicability requirements of subpart KKKK of this part are not subject to this subpart. This subpart will continue to apply to all other heat recovery steam generators, fuel heaters, and other affected facilities that are capable of combusting more than or equal to 2.9 MW (10 MMBtu/h) heat input of fossil fuel but less than or equal to 29 MW (100 MMBtu/h) heat input of fossil fuel. If the heat recovery steam generator, fuel heater, or other affected facility is subject to this subpart, only emissions resulting from combustion of fuels in the steam generating unit are subject to this subpart. (The stationary combustion turbine emissions are subject to subpart GG or KKKK, as applicable, of this part.) (f) Any affected facility that meets the applicability requirements of and is subject to subpart AAAA or subpart CCCC of this part is not subject to this subpart. (g) Any facility that meets the applicability requirements and is subject to an EPA approved State or Federal section 111(d)/129 plan implementing subpart BBBB of this part is not subject to this subpart. (h) Affected facilities that also meet the applicability requirements under subpart J or subpart Ja of this part are subject to the PM and NOX standards under this subpart and the SO2 standards under subpart J or subpart Ja of this part, as applicable. (i) Temporary boilers are not subject to this subpart.

As used in this subpart, all terms not defined herein shall have the meaning given them in the Clean Air Act and in subpart A of this part. Annual capacity factor means the ratio between the actual heat input to a steam generating unit from an individual fuel or combination of fuels during a period of 12 consecutive calendar months and the potential heat input to the steam generating unit from all fuels had the steam generating unit been operated for 8,760 hours during that 12-month period at the maximum design heat input capacity. In the case of steam generating units that are rented or leased, the actual heat input shall be determined based on the combined heat input from all operations of the affected facility during a period of 12 consecutive calendar months. Coal means all solid fuels classified as anthracite, bituminous, subbituminous, or lignite by the American Society of Testing and Materials in ASTM D388 (incorporated by reference, see § 60.17), coal refuse, and petroleum coke. Coal-derived synthetic fuels derived from coal for the purposes of creating useful heat, including but not limited to solvent refined coal, gasified coal not meeting the definition of natural gas, coal-oil mixtures, and coal-water mixtures, are also included in this definition for the purposes of this subpart. Coal refuse means any by-product of coal mining or coal cleaning operations with an ash content greater than 50 percent (by weight) and a heating value less than 13,900 kilojoules per kilogram (kJ/kg) (6,000 Btu per pound (Btu/lb) on a dry basis. Combined cycle system means a system in which a separate source (such as a stationary gas turbine, internal combustion engine, or kiln) provides exhaust gas to a steam generating unit. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: Combustion research means the experimental firing of any fuel or combination of fuels in a steam generating unit for the purpose of conducting research and development of more efficient combustion or more effective prevention or control of air pollutant emissions from combustion, provided that, during these periods of research and development, the heat generated is not used for any purpose other than preheating combustion air for use by that steam generating unit ( i.e. , the heat generated is released to the atmosphere without being used for space heating, process heating, driving pumps, preheating combustion air for other units, generating electricity, or any other purpose). Conventional technology means wet flue gas desulfurization technology, dry flue gas desulfurization technology, atmospheric fluidized bed combustion technology, and oil hydrodesulfurization technology. Distillate oil means fuel oil that complies with the specifications for fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17), diesel fuel oil numbers 1 or 2, as defined by the American Society for Testing and Materials in ASTM D975 (incorporated by reference, see § 60.17), kerosine, as defined by the American Society of Testing and Materials in ASTM D3699 (incorporated by reference, see § 60.17), biodiesel as defined by the American Society of Testing and Materials in ASTM D6751 (incorporated by reference, see § 60.17), or biodiesel blends as defined by the American Society of Testing and Materials in ASTM D7467 (incorporated by reference, see § 60.17). Dry flue gas desulfurization technology means a SO2 control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline reagent and water, whether introduced separately or as a premixed slurry or solution and forming a dry powder material. This definition includes devices where the dry powder material is subsequently converted to another form. Alkaline reagents used in dry flue gas desulfurization systems include, but are not limited to, lime and sodium compounds. Duct burner means a device that combusts fuel and that is placed in the exhaust duct from another source (such as a stationary gas turbine, internal combustion engine, kiln, etc.) to allow the firing of additional fuel to heat the exhaust gases before the exhaust gases enter a steam generating unit. Emerging technology means any SO2 control system that is not defined as a conventional technology under this section, and for which the owner or operator of the affected facility has received approval from the Administrator to operate as an emerging technology under § 60.48c(a)(4). Federally enforceable means all limitations and conditions that are enforceable by the Administrator, including the requirements of 40 CFR parts 60 and 61, requirements within any applicable State implementation plan, and any permit requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 51.24. Fluidized bed combustion technology means a device wherein fuel is distributed onto a bed (or series of beds) of limestone aggregate (or other sorbent materials) for combustion; and these materials are forced upward in the device by the flow of combustion air and the gaseous products of combustion. Fluidized bed combustion technology includes, but is not limited to, bubbling bed units and circulating bed units. Fuel pretreatment means a process that removes a portion of the sulfur in a fuel before combustion of the fuel in a steam generating unit. Heat input means heat derived from combustion of fuel in a steam generating unit and does not include the heat derived from preheated combustion air, recirculated flue gases, or exhaust gases from other sources (such as stationary gas turbines, internal combustion engines, and kilns). Heat transfer medium means any material that is used to transfer heat from one point to another point. Maximum design heat input capacity means the ability of a steam generating unit to combust a stated maximum amount of fuel (or combination of fuels) on a steady state basis as determined by the physical design and characteristics of the steam generating unit. Natural gas means: SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon gases found in geologic formations beneath the earth's surface, of which the principal constituent is methane; or (2) Liquefied petroleum (LP) gas, as defined by the American Society for Testing and Materials in ASTM D1835 (incorporated by reference, see § 60.17); or (3) A mixture of hydrocarbons that maintains a gaseous state at ISO conditions. Additionally, natural gas must either be composed of at least 70 percent methane by volume or have a gross calorific value between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 1,150 Btu per dry standard cubic foot). Noncontinental area means the State of Hawaii, the Virgin Islands, Guam, American Samoa, the Commonwealth of Puerto Rico, or the Northern Mariana Islands. Oil means crude oil or petroleum, or a liquid fuel derived from crude oil or petroleum, including distillate oil and residual oil. Potential sulfur dioxide emission rate means the theoretical SO2 emissions (nanograms per joule (ng/J) or lb/MMBtu heat input) that would result from combusting fuel in an uncleaned state and without using emission control systems. Process heater means a device that is primarily used to heat a material to initiate or promote a chemical reaction in which the material participates as a reactant or catalyst. Residual oil means crude oil, fuel oil that does not comply with the specifications under the definition of distillate oil, and all fuel oil numbers 4, 5, and 6, as defined by the American Society for Testing and Materials in ASTM D396 (incorporated by reference, see § 60.17). Steam generating unit means a device that combusts any fuel and produces steam or heats water or heats any heat transfer medium. This term includes any duct burner that combusts fuel and is part of a combined cycle system. This term does not include process heaters as defined in this subpart. Steam generating unit operating day means a 24-hour period between 12:00 midnight and the following midnight during which any fuel is combusted at any time in the steam generating unit. It is not necessary for fuel to be combusted continuously for the entire 24-hour period. Temporary boiler means a steam generating unit that combusts natural gas or distillate oil with a potential SO2 emissions rate no greater than 26 ng/J (0.060 lb/MMBtu), and the unit is designed to, and is capable of, being carried or moved from one location to another by means of, for example, wheels, skids, carrying handles, dollies, trailers, or platforms. A steam generating unit is not a temporary boiler if any one of the following conditions exists: (1) The equipment is attached to a foundation. (2) The steam generating unit or a replacement remains at a location for more than 180 consecutive days. Any temporary boiler that replaces a temporary boiler at a location and performs the same or similar function will be included in calculating the consecutive time period. (3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least 2 years, and operates at that facility for at least 3 months each year. (4) The equipment is moved from one location to another in an attempt to circumvent the residence time requirements of this definition. Wet flue gas desulfurization technology means an SO2 control system that is located between the steam generating unit and the exhaust vent or stack, and that removes sulfur oxides from the combustion gases of the steam generating unit by contacting the combustion gases with an alkaline slurry or solution and forming a liquid material. This definition includes devices where the liquid material is subsequently converted to another form. Alkaline reagents used in wet flue gas desulfurization systems include, but are not limited to, lime, limestone, and sodium compounds. SECTION D. Source Level Plan Approval Requirements37-337A

Page 100 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: Wet scrubber system means any emission control device that mixes an aqueous stream or slurry with the exhaust gases from a steam generating unit to control emissions of PM or SO2 . Wood means wood, wood residue, bark, or any derivative fuel or residue thereof, in any form, including but not limited to sawdust, sanderdust, wood chips, scraps, slabs, millings, shavings, and processed pellets made from wood or other forest residues. SECTION D. Source Level Plan Approval Requirements37-337A

Page 101 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: Source ID: Source Name:

101 EMERGENCY GENERATOR (1,135 BHP - 750 KW)

Source Capacity/Throughput:

FML FML02 PROC 101 STAC

S101 7.800 MMBTU/HR 55.000 Gal/HR ULTRA LOW SULFUR DISTILLAT

I. RESTRICTIONS. Emission Restriction(s). # 001

# 002 [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4202] Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines Plan approval terms and conditions.

What emission standards must I meet for emergency engines if I am a stationary CI internal combustion engine manufacturer? [Plan Approval 37-337A] (a) The emissions shall not exceed the following: 1. PM/PM10/PM2.5: 0.33 #/hr or 0.02 tpy based on a 12-month rolling total [Compliance with this requirement will show compliance with 25 PA Code 123.13] 2. NOx: 9.89 #/hr or 0.49 tpy based on a 12-month rolling total 3. CO: 5.79 #/hr or 0.29 tpy based on a 12-month rolling total 4. VOC: 0.7 #/hr or 0.03 tpy based on a 12-month rolling total 5. SOx: 0.01 #/hr or 0.0007 tpy based on a 12-month rolling total [Compliance with this requirement will show compliance with 25 PA Code 123.21] 6. H2SO4: 0.0028 #/hr or 0.00014 tpy based on a 12-month rolling total [Plan Approval 37-337A] (b) The permittee may not allow 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 15% for a period or periods aggregating more than three (3) minutes in any hour. 2. Equal to or greater than 50% at any time.
The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] (c) No person may permit the emission into the outdoor atmosphere of the following in a manner that exceeds the following: 1. CO2(e): 80.5 tpy based on a 12-month rolling basis

(a) Stationary CI internal combustion engine manufacturers must certify their 2007 model year and later emergency stationary CI ICE with a maximum engine power less than or equal to 2,237 KW (3,000 HP) and a displacement of less than 10 liters per cylinder that are not fire pump engines to the emission standards specified in paragraphs (a)(1) through (2) of this section. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: # 003

# 004 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4204]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4205] Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What emission standards must I meet for non-emergency engines if I am an owner or operator of a stationary CI internal combustion engine?

What emission standards must I meet for emergency engines if I am an owner or operator of a stationary CI internal combustion engine? (1) Not applicable (2) For engines with a maximum engine power greater than or equal to 37 KW (50 HP), the certification emission standards for new nonroad CI engines for the same model year and maximum engine power in 40 CFR 89.112 and 40 CFR 89.113 for all pollutants beginning in model year 2007. [89.112 Table: kW > 560 Tier 2 2006: NMHC + NOx: 6.4; CO: 3.5; PM: 0.2 Emission limits are in g/kW-hr] [89.113: Opacity must not exceed: (1) 20 percent during the acceleration mode; (2) 15 percent during the lugging mode; and (3) 50 percent during the peaks in either the acceleration or lugging modes.] (b) Not applicable (c) [Reserved] (d) Not applicable (e) Not applicable (f) Not applicable (g) Not applicable (h) Notwithstanding the requirements in paragraphs (a) through (f) of this section, stationary CI internal combustion engine manufacturers are not required to certify reconstructed engines; however manufacturers may elect to do so. The reconstructed engine must be certified to the emission standards specified in paragraphs (a) through (f) of this section that are applicable to the model year, maximum engine power and displacement of the reconstructed emergency stationary CI ICE.

Not applicable

(a) Not applicable (b) Owners and operators of 2007 model year and later emergency stationary CI ICE with a displacement of less than 30 liters per cylinder that are not fire pump engines must comply with the emission standards for new nonroad CI engines in § 60.4202, for all pollutants, for the same model year and maximum engine power for their 2007 model year and later emergency stationary CI ICE. (c) Not applicable (d) Not applicable (e) Owners and operators of emergency stationary CI ICE with a displacement of less than 30 liters per cylinder who conduct performance tests in-use must meet the NTE standards as indicated in § 60.4212. (f) Not applicable SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4212] # 009 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What test methods and other procedures must I use if I am an owner or operator of a stationary CI internal combustion engine with a displacement of less than 30 liters per cylinder? Owners and operators of stationary CI ICE with a displacement of less than 30 liters per cylinder who conduct performance tests pursuant to this subpart must do so according to paragraphs (a) through (e) of this section. II. TESTING REQUIREMENTS. Fuel Restriction(s).

Operation Hours Restriction(s). # 005

# 006

# 007

# 008 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4217]

[25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4207]

[25 Pa. Code §127.12b] Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What emission standards must I meet if I am an owner or operator of a stationary internal combustion engine using special fuels?

Plan approval terms and conditions.

What fuel requirements must I meet if I am an owner or operator of a stationary CI internal combustion engine subject to this subpart?

Plan approval terms and conditions. Not applicable

[Plan Approval 37-337A] The emergency generator shall fire only ultralow sulfur diesel fuel (sulfur content less than 15 parts per million by weight).

(a) Not applicable (b) Beginning October 1, 2010, owners and operators of stationary CI ICE subject to this subpart with a displacement of less than 30 liters per cylinder that use diesel fuel must purchase diesel fuel that meets the requirements of 40 CFR 80.510(b) for nonroad diesel fuel. [From 40 CFR 80.510(b): Sulfur content: 15 parts per million (ppm) maximum for NR or 500 ppm maximum for LR; Cetane index or aromatic content, as follows: (i) A minimum cetane index of 40; or (ii) A maximum aromatic content of 35 volume percent] (c) [Reserved] (d) Not applicable (e) Not applicable

[Plan Approval 37-337A] (a) The annual operation during testing shall not exceed 100 hours per year. [Plan Approval 37-337A] (b) The duration of each test shall not exceed 30 minutes. [Plan Approval 37-337A] (c) The emergency generator and the emergency firewater pump shall not be tested simultaneously (within the same hour). [Plan Approval 37-337A] (d) The emergency generator and the emergency firewater pump shall not be tested during (within the same hour as) startup or shutdown of the combustion turbines. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4213]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4209]

[25 Pa. Code §127.12b] # 010

# 011

# 012 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What test methods and other procedures must I use if I am an owner or operator of a stationary CI internal combustion engine with a displacement of greater than or equal to 30 liters per cylinder?

What are the monitoring requirements if I am an owner or operator of a stationary CI internal combustion engine?

Plan approval terms and conditions. (a) The performance test must be conducted according to the in-use testing procedures in 40 CFR part 1039, subpart F, for stationary CI ICE with a displacement of less than 10 liters per cylinder, and according to 40 CFR part 1042, subpart F, for stationary CI ICE with a displacement of greater than or equal to 10 liters per cylinder and less than 30 liters per cylinder. (b) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR part 1039 must not exceed the not-to-exceed (NTE) standards for the same model year and maximum engine power as required in 40 CFR 1039.101(e) and 40 CFR 1039.102(g)(1), except as specified in 40 CFR 1039.104(d). This requirement starts when NTE requirements take effect for nonroad diesel engines under 40 CFR part 1039. (c) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR 89.112 or 40 CFR 94.8, as applicable, must not exceed the NTE numerical requirements, rounded to the same number of decimal places as the applicable standard in 40 CFR 89.112 or 40 CFR 94.8, as applicable, determined from the following equation in 40 CFR 60.4212(c). Alternatively, stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR 89.112 or 40 CFR 94.8 may follow the testing procedures specified in § 60.4213 of this subpart, as appropriate. (d) Not applicable (e) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR part 1042 must not exceed the NTE standards for the same model year and maximum engine power as required in 40 CFR 1042.101(c).

Not applicable

If you are an owner or operator, you must meet the monitoring requirements of this section. In addition, you must also meet the monitoring requirements specified in §60.4211. (a) If you are an owner or operator of an emergency stationary CI internal combustion engine that does not meet the standards applicable to non-emergency engines, you must install a non-resettable hour meter prior to startup of the engine. (b) Not applicable

[Plan Approval 37-337A] (a) All recordkeeping shall commence upon startup of the source and shall be kept for a period of 5 years and made available to the Department upon request. [Plan Approval 37-337A] (b) The company shall maintain a log of all preventative maintenance inspections of the source. The inspection logs, at a minimum, shall contain the dates of the inspections, the name of the person performing the inspection, any mechanical repairs and/or adjustments, any potential problems or defects that were encountered, and the steps taken to correct them. [Plan Approval 37-337A] (c) The company shall maintain a log of the following, at a minimum, from the operational inspections: III.

IV. MONITORING REQUIREMENTS.

RECORDKEEPING REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4214]

[25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4206]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4211] # 013

# 014

# 015

# 016 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What are my notification, reporting, and recordkeeping requirements if I am an owner or operator of a stationary CI internal combustion engine?

Plan approval terms and conditions.

How long must I meet the emission standards if I am an owner or operator of a stationary CI internal combustion engine?

What are my compliance requirements if I am an owner or operator of a stationary CI internal combustion engine? 1. Completion of inspection - daily defined as at least once per calendar day, while the source is operating or as approved by the Department in the work practice inspection protocol. [Plan Approval 37-337A] (d) The permittee shall keep records of the fuel certification reports for each delivery of diesel fuel to verify compliance with the fuel restriction requirements.
The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] (e) The facility shall maintain sufficient records to adequately demonstrate compliance with the emission limitations associated with the GHG rule.

(a) Not applicable (b) If the stationary CI internal combustion engine is an emergency stationary internal combustion engine, the owner or operator is not required to submit an initial notification. Starting with the model years in table 5 to this subpart, if the emergency engine does not meet the standards applicable to non-emergency engines in the applicable model year, the owner or operator must keep records of the operation of the engine in emergency and non-emergency service that are recorded through the non-resettable hour meter. The owner must record the time of operation of the engine and the reason the engine was in operation during that time. (c) Not applicable

[Plan Approval 37-337A] (a) The permittee shall perform a daily operational inspection of the source until such time as the Department approves a work practice inspection protocol submitted by the permittee. After Departmental approval, the permittee shall perform periodic inspections of the significant source equipment and emission controls in accordance with the approved work practice inspection protocol. [Plan Approval 37-337A] (b) The permittee shall maintain and operate the source in accordance with the manufacturer's specifications, the manufacturer's preventative maintenance schedule, and good air pollution control practices. The facility shall maintain a copy of the manufacturer's preventative maintenance schedule on-site.

Owners and operators of stationary CI ICE must operate and maintain stationary CI ICE that achieve the emission standards as required in §§60.4204 and 60.4205 over the entire life of the engine.

(a) If you are an owner or operator and must comply with the emission standards specified in this subpart, you must do all V.

VI. REPORTING REQUIREMENTS.

WORK PRACTICE REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: of the following, except as permitted under paragraph (g) of this section: (1) Operate and maintain the stationary CI internal combustion engine and control device according to the manufacturer's emission-related written instructions; (2) Change only those emission-related settings that are permitted by the manufacturer; and (3) Meet the requirements of 40 CFR parts 89, 94 and/or 1068, as they apply to you. (b) Not applicable (c) If you are an owner or operator of a 2007 model year and later stationary CI internal combustion engine and must comply with the emission standards specified in § 60.4204(b) or § 60.4205(b), or if you are an owner or operator of a CI fire pump engine that is manufactured during or after the model year that applies to your fire pump engine power rating in table 3 to this subpart and must comply with the emission standards specified in § 60.4205(c), you must comply by purchasing an engine certified to the emission standards in § 60.4204(b), or § 60.4205(b) or (c), as applicable, for the same model year and maximum (or in the case of fire pumps, NFPA nameplate) engine power. The engine must be installed and configured according to the manufacturer's emission-related specifications, except as permitted in paragraph (g) of this section. (d) Not applicable (e) Not applicable (f) Emergency stationary ICE may be operated for the purpose of maintenance checks and readiness testing, provided that the tests are recommended by Federal, State or local government, the manufacturer, the vendor, or the insurance company associated with the engine. Maintenance checks and readiness testing of such units is limited to 100 hours per year. There is no time limit on the use of emergency stationary ICE in emergency situations. The owner or operator may petition the Administrator for approval of additional hours to be used for maintenance checks and readiness testing, but a petition is not required if the owner or operator maintains records indicating that Federal, State, or local standards require maintenance and testing of emergency ICE beyond 100 hours per year. Emergency stationary ICE may operate up to 50 hours per year in non-emergency situations, but those 50 hours are counted towards the 100 hours per year provided for maintenance and testing. The 50 hours per year for non-emergency situations cannot be used for peak shaving or to generate income for a facility to supply power to an electric grid or otherwise supply non-emergency power as part of a financial arrangement with another entity. For owners and operators of emergency engines, any operation other than emergency operation, maintenance and testing, and operation in non-emergency situations for 50 hours per year, as permitted in this section, is prohibited. (g) If you do not install, configure, operate, and maintain your engine and control device according to the manufacturer's emission-related written instructions, or you change emission-related settings in a way that is not permitted by the manufacturer, you must demonstrate compliance as follows: (1) Not applicable (2) Not applicable (3) If you are an owner or operator of a stationary CI internal combustion engine greater than 500 HP, you must keep a maintenance plan and records of conducted maintenance and must, to the extent practicable, maintain and operate the engine in a manner consistent with good air pollution control practice for minimizing emissions. In addition, you must conduct an initial performance test to demonstrate compliance with the applicable emission standards within 1 year of startup, or within 1 year after an engine and control device is no longer installed, configured, operated, and maintained inaccordance with the manufacturer's emission-related written instructions, or within 1 year after you change emissionrelated settings in a way that is not permitted by the manufacturer. You must conduct subsequent performance testing every 8,760 hours of engine operation or 3 years, whichever comes first, thereafter to demonstrate compliance with the applicable emission standards. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4200] # 017

# 018 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines Plan approval terms and conditions.

Am I subject to this subpart? [Plan Approval 37-337A] (a) The source is subject to 40 CFR 60 Subpart IIII Standards of Performance for Stationary Compression Ignition Internal Combustion Engines. [Compliance with this requirement will assure compliance with 40 CFR 63 Subpart ZZZZ] [Plan Approval 37-337A] (b) Any information required to be submitted as part of this plan approval should be submitted to the attention of Chief, New Source Review Section, Air Quality Control, Northwest Regional Office, 230 Chestnut Street, Meadville, PA 16335. [Plan Approval 37-337A] (c) In accordance with 40 CFR 60.4 copies of all requests, reports, applications submittals and other communications shall be forwarded to both EPA and the Department at the addresses listed below unless otherwise noted. Air Quality Program Manager Pa DEP Air Quality 230 Chestnut Street Meadville, PA 16335 Director Air Toxics and Radiation US EPA, Region III 1650 Arch Street Philadelphia, PA 19103-2029 [Plan Approval 37-337A] (d) Issuance of an Operating Permit is contingent upon satisfactory compliance with the plan approval conditions, upon the control device being installed, tested, and operated as stated within the application, and upon satisfactory demonstration that the emissions from the source will not be in violation of applicable Rules and Regulations of the Department.

(a) The provisions of this subpart are applicable to manufacturers, owners, and operators of stationary compression ignition (CI) internal combustion engines (ICE) as specified in paragraphs (a)(1) through (4) of this section. For the purposes of this subpart, the date that construction commences is the date the engine is ordered by the owner or operator. (1) Not applicable (2) Owners and operators of stationary CI ICE that commence construction after July 11, 2005 where the stationary CI ICE are: (i) Manufactured after April 1, 2006 and are not fire pump engines, or (ii) Not applicable (3) Not applicable (4) The provisions of § 60.4208 of this subpart are applicable to all owners and operators of stationary CI ICE that commence construction after July 11, 2005. (b) Not applicable (c) If you are an owner or operator of an area source subject to this subpart, you are exempt from the obligation to obtain a VII. ADDITIONAL REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4208]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4218]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4219] # 019

# 020

# 021 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What is the deadline for importing or installing stationary CI ICE produced in the previous model year?

What parts of the General Provisions apply to me?

What definitions apply to this subpart? permit under 40 CFR part 70 or 40 CFR part 71, provided you are not required to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) for a reason other than your status as an area source under this subpart. Notwithstanding the previous sentence, you must continue to comply with the provisions of this subpart applicable to area sources. (d) Not applicable (e) Not applicable

(a) After December 31, 2008, owners and operators may not install stationary CI ICE (excluding fire pump engines) that do not meet the applicable requirements for 2007 model year engines. (b) Not applicable (c) Not applicable (d) Not applicable (e) Not applicable (f) Not applicable (g) Not applicable (h) In addition to the requirements specified in §§ 60.4201, 60.4202, 60.4204, and 60.4205, it is prohibited to import stationary CI ICE with a displacement of less than 30 liters per cylinder that do not meet the applicable requirements specified in paragraphs (a) through (g) of this section after the dates specified in paragraphs (a) through (g) of this section. (i) The requirements of this section do not apply to owners or operators of stationary CI ICE that have been modified, reconstructed, and do not apply to engines that were removed from one existing location and reinstalled at a new location.

Table 8 to this subpart shows which parts of the General Provisions in §§60.1 through 60.19 apply to you.

As used in this subpart, all terms not defined herein shall have the meaning given them in the CAA and in subpart A of this part. Certified emissions life means the period during which the engine is designed to properly function in terms of reliability and fuel consumption, without being remanufactured, specified as a number of hours of operation or calendar years, whichever comes first. The values for certified emissions life for stationary CI ICE with a displacement of less than 10 liters per cylinder are given in 40 CFR 1039.101(g). The values for certified emissions life for stationary CI ICE with a displacement of greater than or equal to 10 liters per cylinder and less than 30 liters per cylinder are given in 40 CFR 94.9(a). Combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), and any ancillary components and sub-components comprising any simple cycle combustion turbine, any regenerative/recuperative cycle combustion turbine, the combustion turbine portion of any cogeneration cycle combustion system, or the combustion turbine portion of any combined cycle steam/electric generating system. SECTION D. Source Level Plan Approval Requirements37-337A

Page 109 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: Compression ignition means relating to a type of stationary internal combustion engine that is not a spark ignition engine. Date of manufacture means one of the following things: (1) For freshly manufactured engines and modified engines, date of manufacture means the date the engine is originally produced. (2) For reconstructed engines, date of manufacture means the date the engine was originally produced, except as specified in paragraph (3) of this definition. (3) Reconstructed engines are assigned a new date of manufacture if the fixed capital cost of the new and refurbished components exceeds 75 percent of the fixed capital cost of a comparable entirely new facility. An engine that is produced from a previously used engine block does not retain the date of manufacture of the engine in which the engine block was previously used if the engine is produced using all new components except for the engine block. In these cases, the date of manufacture is the date of reconstruction or the date the new engine is produced. Diesel fuel means any liquid obtained from the distillation of petroleum with a boiling point of approximately 150 to 360 degrees Celsius. One commonly used form is number 2 distillate oil. Diesel particulate filter means an emission control technology that reduces PM emissions by trapping the particles in a flow filter substrate and periodically removes the collected particles by either physical action or by oxidizing (burning off) the particles in a process called regeneration. Emergency stationary internal combustion engine means any stationary internal combustion engine whose operation is limited to emergency situations and required testing and maintenance. Examples include stationary ICE used to produce power for critical networks or equipment (including power supplied to portions of a facility) when electric power from the local utility (or the normal power source, if the facility runs on its own power production) is interrupted, or stationary ICE used to pump water in the case of fire or flood, etc. Stationary CI ICE used to supply power to an electric grid or that supply power as part of a financial arrangement with another entity are not considered to be emergency engines. Engine manufacturer means the manufacturer of the engine. See the definition of “manufacturer” in this section. Fire pump engine means an emergency stationary internal combustion engine certified to NFPA requirements that is used to provide power to pump water for fire suppression or protection. Freshly manufactured engine means an engine that has not been placed into service. An engine becomes freshly manufactured when it is originally produced. Installed means the engine is placed and secured at the location where it is intended to be operated. Manufacturer has the meaning given in section 216(1) of the Act. In general, this term includes any person who manufactures a stationary engine for sale in the United States or otherwise introduces a new stationary engine into commerce in the United States. This includes importers who import stationary engines for sale or resale. Maximum engine power means maximum engine power as defined in 40 CFR 1039.801. Model year means the calendar year in which an engine is manufactured (see “date of manufacture”), except as follows: (1) Model year means the annual new model production period of the engine manufacturer in which an engine is manufactured (see “date of manufacture”), if the annual new model production period is different than the calendar year and includes January 1 of the calendar year for which the model year is named. It may not begin before January 2 of the previous calendar year and it must end by December 31 of the named calendar year. (2) For an engine that is converted to a stationary engine after being placed into service as a nonroad or other non-stationary engine, model year means the calendar year or new model production period in which the engine was manufactured (see “date of manufacture”). SECTION D. Source Level Plan Approval Requirements37-337A

Page 110 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: Other internal combustion engine means any internal combustion engine, except combustion turbines, which is not a reciprocating internal combustion engine or rotary internal combustion engine. Reciprocating internal combustion engine means any internal combustion engine which uses reciprocating motion to convert heat energy into mechanical work. Rotary internal combustion engine means any internal combustion engine which uses rotary motion to convert heat energy into mechanical work. Spark ignition means relating to a gasoline, natural gas, or liquefied petroleum gas fueled engine or any other type of engine with a spark plug (or other sparking device) and with operating characteristics significantly similar to the theoretical Otto combustion cycle. Spark ignition engines usually use a throttle to regulate intake air flow to control power during normal operation. Dual-fuel engines in which a liquid fuel (typically diesel fuel) is used for CI and gaseous fuel (typically natural gas) is used as the primary fuel at an annual average ratio of less than 2 parts diesel fuel to 100 parts total fuel on an energy equivalent basis are spark ignition engines. Stationary internal combustion engine means any internal combustion engine, except combustion turbines, that converts heat energy into mechanical work and is not mobile. Stationary ICE differ from mobile ICE in that a stationary internal combustion engine is not a nonroad engine as defined at 40 CFR 1068.30 (excluding paragraph (2)(ii) of that definition), and is not used to propel a motor vehicle, aircraft, or a vehicle used solely for competition. Stationary ICE include reciprocating ICE, rotary ICE, and other ICE, except combustion turbines. Subpart means 40 CFR part 60, subpart IIII. SECTION D. Source Level Plan Approval Requirements37-337A

Page 111 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: Source ID: Source Name:

102 EMERGENCY FIREWATER PUMP (450 BHP)

Source Capacity/Throughput:

FML FML02 PROC 102 STAC

S102 3.250 MMBTU/HR 24.000 Gal/HR ULTRA LOW SULFUR DISTILLAT

I. RESTRICTIONS. Emission Restriction(s). # 001

# 002 [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4205] Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines Plan approval terms and conditions.

What emission standards must I meet for emergency engines if I am an owner or operator of a stationary CI internal combustion engine? [Plan Approval 37-337A] (a) The emissions shall not exceed the following: 1. PM/PM10/PM2.5: 0.15 #/hr or 0.01 tpy based on a 12-month rolling total [Compliance with this requirement will show compliance with 25 PA Code 123.13] 2. NOx: 1.86 #/hr or 0.09 tpy based on a 12-month rolling total 3. CO: 2.58 #/hr or 0.13 tpy based on a 12-month rolling total 4. VOC: 1.11 #/hr or 0.06 tpy based on a 12-month rolling total 5. SOx: 0.0055 #/hr or 0.00027 tpy based on a 12-month rolling total [Compliance with this requirement will show compliance with 25 PA Code 123.21] 6. H2SO4: 0.0012 #/hr or 0.00006 tpy based on a 12-month rolling total [Plan Approval 37-337A] (b) The permittee may not allow 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 15% for a period or periods aggregating more than three (3) minutes in any hour. 2. Equal to or greater than 50% at any time.
The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] (c) No person may permit the emission into the outdoor atmosphere of the following in a manner that exceeds the following: 1. CO2(e): 33.8 tpy based on a 12-month rolling basis

(a) Not applicable (b) Not applicable (c) Owners and operators of fire pump engines with a displacement of less than 30 liters per cylinder must comply with the SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: Fuel Restriction(s).

Operation Hours Restriction(s). # 003

# 004

# 005

# 006 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4217]

[25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4207]

[25 Pa. Code §127.12b] Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What emission standards must I meet if I am an owner or operator of a stationary internal combustion engine using special fuels?

Plan approval terms and conditions.

What fuel requirements must I meet if I am an owner or operator of a stationary CI internal combustion engine subject to this subpart?

Plan approval terms and conditions. emission standards in table 4 to this subpart, for all pollutants. [From Table 4: 225<=KW<450 (300<=HP<600): Year 2009+ NMOC +NOx: 4.0 (3.0); PM: 0.2 (0.15) Emissions are in g/kW-hr (g/hp-hr)] (d) Not applicable (e) Owners and operators of emergency stationary CI ICE with a displacement of less than 30 liters per cylinder who conduct performance tests in-use must meet the NTE standards as indicated in § 60.4212. (f) Not applicable

Not applicable

[Plan Approval 37-337A] The emergency firewater pump shall fire only ultralow sulfur diesel fuel (sulfur content less than 15 parts per million by weight).

(a) Not applicable (b) Beginning October 1, 2010, owners and operators of stationary CI ICE subject to this subpart with a displacement of less than 30 liters per cylinder that use diesel fuel must purchase diesel fuel that meets the requirements of 40 CFR 80.510(b) for nonroad diesel fuel. [From 40 CFR 80.510(b): Sulfur content: 15 parts per million (ppm) maximum for NR or 500 ppm maximum for LR; Cetane index or aromatic content, as follows: (i) A minimum cetane index of 40; or (ii) A maximum aromatic content of 35 volume percent] (c) [Reserved] (d) Not applicable (e) Not applicable

[Plan Approval 37-337A] (a) The annual operation during testing shall not exceed 100 hours per year. [Plan Approval 37-337A] (b) The duration of each test shall not exceed 30 minutes. [Plan Approval 37-337A] (c) The emergency generator and the emergency firewater pump shall not be tested simultaneously (within the same hour). SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4212]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4213]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4209] # 007

# 008

# 009 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What test methods and other procedures must I use if I am an owner or operator of a stationary CI internal combustion engine with a displacement of less than 30 liters per cylinder?

What test methods and other procedures must I use if I am an owner or operator of a stationary CI internal combustion engine with a displacement of greater than or equal to 30 liters per cylinder?

What are the monitoring requirements if I am an owner or operator of a stationary CI internal combustion engine? Owners and operators of stationary CI ICE with a displacement of less than 30 liters per cylinder who conduct performance tests pursuant to this subpart must do so according to paragraphs (a) through (e) of this section. (a) The performance test must be conducted according to the in-use testing procedures in 40 CFR part 1039, subpart F, for stationary CI ICE with a displacement of less than 10 liters per cylinder, and according to 40 CFR part 1042, subpart F, for stationary CI ICE with a displacement of greater than or equal to 10 liters per cylinder and less than 30 liters per cylinder. (b) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR part 1039 must not exceed the not-to-exceed (NTE) standards for the same model year and maximum engine power as required in 40 CFR 1039.101(e) and 40 CFR 1039.102(g)(1), except as specified in 40 CFR 1039.104(d). This requirement starts when NTE requirements take effect for nonroad diesel engines under 40 CFR part 1039. (c) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR 89.112 or 40 CFR 94.8, as applicable, must not exceed the NTE numerical requirements, rounded to the same number of decimal places as the applicable standard in 40 CFR 89.112 or 40 CFR 94.8, as applicable, determined from the following equation in 40 CFR 60.4212(c). Alternatively, stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR 89.112 or 40 CFR 94.8 may follow the testing procedures specified in § 60.4213 of this subpart, as appropriate. (d) Not applicable (e) Exhaust emissions from stationary CI ICE that are complying with the emission standards for new CI engines in 40 CFR part 1042 must not exceed the NTE standards for the same model year and maximum engine power as required in 40 CFR 1042.101(c).

Not applicable

If you are an owner or operator, you must meet the monitoring requirements of this section. In addition, you must also meet the monitoring requirements specified in § 60.4211. (a) If you are an owner or operator of an emergency stationary CI internal combustion engine that does not meet the standards applicable to non-emergency engines, you must install a non-resettable hour meter prior to startup of the engine. (b) Not applicable II.

III. TESTING REQUIREMENTS.

MONITORING REQUIREMENTS. [Plan Approval 37-337A] (d) The emergency generator and the emergency firewater pump shall not be tested during (within the same hour as) startup or shutdown of the combustion turbines. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4214]

[25 Pa. Code §127.12b] # 010

# 011

# 012 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines Plan approval terms and conditions.

What are my notification, reporting, and recordkeeping requirements if I am an owner or operator of a stationary CI internal combustion engine?

Plan approval terms and conditions. [Plan Approval 37-337A] (a) All recordkeeping shall commence upon startup of the source and shall be kept for a period of 5 years and made available to the Department upon request. [Plan Approval 37-337A] (b) The company shall maintain a log of all preventative maintenance inspections of the source. The inspection logs, at a minimum, shall contain the dates of the inspections, the name of the person performing the inspection, any mechanical repairs and/or adjustments, any potential problems or defects that were encountered, and the steps taken to correct them. [Plan Approval 37-337A] (c) The company shall maintain a log of the following, at a minimum, from the operational inspections: 1. Completion of inspection - daily defined as at least once per calendar day, while the source is operating or as approved by the Department in the work practice inspection protocol. [Plan Approval 37-337A] (d) The permittee shall keep records of the fuel certification reports for each delivery of diesel fuel to verify compliance with the fuel restriction requirements.
The following conditions are related to the GHG Tailoring Rule (40 CFR 51, 52, and 98) [Plan Approval 37-337A] (e) The facility shall maintain sufficient records to adequately demonstrate compliance with the emission limitations associated with the GHG rule.

(a) Not applicable (b) If the stationary CI internal combustion engine is an emergency stationary internal combustion engine, the owner or operator is not required to submit an initial notification. Starting with the model years in table 5 to this subpart, if the emergency engine does not meet the standards applicable to non-emergency engines in the applicable model year, the owner or operator must keep records of the operation of the engine in emergency and non-emergency service that are recorded through the non-resettable hour meter. The owner must record the time of operation of the engine and the reason the engine was in operation during that time. (c) Not applicable

[Plan Approval 37-337A] (a) The permittee shall perform a daily operational inspection of the source until such time as the Department approves a work practice inspection protocol submitted by the permittee. After Departmental approval, the permittee shall perform periodic inspections of the significant source equipment and emission controls in accordance with the approved work practice inspection protocol. [Plan Approval 37-337A] (b) The permittee shall maintain and operate the source in accordance with the manufacturer's specifications, the IV.

V.

VI. RECORDKEEPING REQUIREMENTS.

REPORTING REQUIREMENTS.

WORK PRACTICE REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4206]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4211] # 013

# 014 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines How long must I meet the emission standards if I am an owner or operator of a stationary CI internal combustion engine?

What are my compliance requirements if I am an owner or operator of a stationary CI internal combustion engine? manufacturer's preventative maintenance schedule, and good air pollution control practices. The facility shall maintain a copy of the manufacturer's preventative maintenance schedule on-site.

Owners and operators of stationary CI ICE must operate and maintain stationary CI ICE that achieve the emission standards as required in §§ 60.4204 and 60.4205 over the entire life of the engine.

(a) If you are an owner or operator and must comply with the emission standards specified in this subpart, you must do all of the following, except as permitted under paragraph (g) of this section: (1) Operate and maintain the stationary CI internal combustion engine and control device according to the manufacturer's emission-related written instructions; (2) Change only those emission-related settings that are permitted by the manufacturer; and (3) Meet the requirements of 40 CFR parts 89, 94 and/or 1068, as they apply to you. (b) Not applicable (c) If you are an owner or operator of a 2007 model year and later stationary CI internal combustion engine and must comply with the emission standards specified in § 60.4204(b) or § 60.4205(b), or if you are an owner or operator of a CI fire pump engine that is manufactured during or after the model year that applies to your fire pump engine power rating in table 3 to this subpart and must comply with the emission standards specified in § 60.4205(c), you must comply by purchasing an engine certified to the emission standards in § 60.4204(b), or § 60.4205(b) or (c), as applicable, for the same model year and maximum (or in the case of fire pumps, NFPA nameplate) engine power. The engine must be installed and configured according to the manufacturer's emission-related specifications, except as permitted in paragraph (g) of this section. (d) Not applicable (e) Not applicable (f) Emergency stationary ICE may be operated for the purpose of maintenance checks and readiness testing, provided that the tests are recommended by Federal, State or local government, the manufacturer, the vendor, or the insurance company associated with the engine. Maintenance checks and readiness testing of such units is limited to 100 hours per year. There is no time limit on the use of emergency stationary ICE in emergency situations. The owner or operator may petition the Administrator for approval of additional hours to be used for maintenance checks and readiness testing, but a petition is not required if the owner or operator maintains records indicating that Federal, State, or local standards require maintenance and testing of emergency ICE beyond 100 hours per year. Emergency stationary ICE may operate up to 50 hours per year in non-emergency situations, but those 50 hours are counted towards the 100 hours per year provided for maintenance and testing. The 50 hours per year for non-emergency situations cannot be used for peak shaving or to generate income for a facility to supply power to an electric grid or otherwise supply non-emergency power as part of a financial arrangement with another entity. For owners and operators of emergency engines, any operation other than emergency operation, maintenance and testing, and operation in non-emergency situations for 50 hours per year, as permitted in this section, is prohibited. (g) If you do not install, configure, operate, and maintain your engine and control device according to the manufacturer's emission-related written instructions, or you change emission-related settings in a way that is not permitted by the manufacturer, you must demonstrate compliance as follows: SECTION D. Source Level Plan Approval Requirements37-337A

Page 116 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4200] # 015

# 016 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines Plan approval terms and conditions.

Am I subject to this subpart? (1) Not applicable (2) If you are an owner or operator of a stationary CI internal combustion engine greater than or equal to 100 HP and less than or equal to 500 HP, you must keep a maintenance plan and records of conducted maintenance and must, to the extent practicable, maintain and operate the engine in a manner consistent with good air pollution control practice for minimizing emissions. In addition, you must conduct an initial performance test to demonstrate compliance with the applicable emission standards within 1 year of startup, or within 1 year after an engine and control device is no longer installed, configured, operated, and maintained in accordance with the manufacturer's emission-related written instructions, or within 1 year after you change emission-related settings in a way that is not permitted by the manufacturer. (3) Not applicable

[Plan Approval 37-337A] (a) The source is subject to 40 CFR 60 Subpart IIII Standards of Performance for Stationary Compression Ignition Internal Combustion Engines. [Compliance with this requirement assures compliance with 40 CFR 63 Subpart ZZZZ] [Plan Approval 37-337A] (b) Any information required to be submitted as part of this plan approval should be submitted to the attention of Chief, New Source Review Section, Air Quality Control, Northwest Regional Office, 230 Chestnut Street, Meadville, PA 16335. [Plan Approval 37-337A] (c) In accordance with 40 CFR 60.4 copies of all requests, reports, applications submittals and other communications shall be forwarded to both EPA and the Department at the addresses listed below unless otherwise noted. Air Quality Program Manager Pa DEP Air Quality 230 Chestnut Street Meadville, PA 16335 Director Air Toxics and Radiation US EPA, Region III 1650 Arch Street Philadelphia, PA 19103-2029 [Plan Approval 37-337A] (d) Issuance of an Operating Permit is contingent upon satisfactory compliance with the plan approval conditions, upon the control device being installed, tested, and operated as stated within the application, and upon satisfactory demonstration that the emissions from the source will not be in violation of applicable Rules and Regulations of the Department.

(a) The provisions of this subpart are applicable to manufacturers, owners, and operators of stationary compression ignition (CI) internal combustion engines (ICE) and other persons as specified in paragraphs (a)(1) through (4) of this section. For the purposes of this subpart, the date that construction commences is the date the engine is ordered by the owner or operator. (1) Not applicable (2) Owners and operators of stationary CI ICE that commence construction after July 11, 2005, where the stationary CI ICE VII. ADDITIONAL REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4204]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4208]

[40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4218] # 017

# 018

# 019 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines

Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What emission standards must I meet for non-emergency engines if I am an owner or operator of a stationary CI internal combustion engine?

What is the deadline for importing or installing stationary CI ICE produced in the previous model year?

What parts of the General Provisions apply to me? are: (i) Manufactured after April 1, 2006, and are not fire pump engines, or (ii) Manufactured as a certified National Fire Protection Association (NFPA) fire pump engine after July 1, 2006. (3) Not applicable (4) The provisions of § 60.4208 of this subpart are applicable to all owners and operators of stationary CI ICE that commence construction after July 11, 2005. (b) Not applicable (c) If you are an owner or operator of an area source subject to this subpart, you are exempt from the obligation to obtain a permit under 40 CFR part 70 or 40 CFR part 71, provided you are not required to obtain a permit under 40 CFR 70.3(a) or 40 CFR 71.3(a) for a reason other than your status as an area source under this subpart. Notwithstanding the previous sentence, you must continue to comply with the provisions of this subpart applicable to area sources. (d) Not applicable (e) Not applicable

Not applicable

(a) After December 31, 2008, owners and operators may not install stationary CI ICE (excluding fire pump engines) that do not meet the applicable requirements for 2007 model year engines. (b) Not applicable (c) Not applicable (d) Not applicable (e) Not applicable (f) Not applicable (g) Not applicable (h) In addition to the requirements specified in §§ 60.4201, 60.4202, 60.4204, and 60.4205, it is prohibited to import stationary CI ICE with a displacement of less than 30 liters per cylinder that do not meet the applicable requirements specified in paragraphs (a) through (g) of this section after the dates specified in paragraphs (a) through (g) of this section. (i) The requirements of this section do not apply to owners or operators of stationary CI ICE that have been modified, reconstructed, and do not apply to engines that were removed from one existing location and reinstalled at a new location. SECTION D. Source Level Plan Approval Requirements37-337A

Page 118 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4219] # 020 Subpart IIII - Standards of Performance for Stationary Compression Ignition Internal Combustion Engines What definitions apply to this subpart? Table 8 to this subpart shows which parts of the General Provisions in §§60.1 through 60.19 apply to you.

As used in this subpart, all terms not defined herein shall have the meaning given them in the CAA and in subpart A of this part. Certified emissions life means the period during which the engine is designed to properly function in terms of reliability and fuel consumption, without being remanufactured, specified as a number of hours of operation or calendar years, whichever comes first. The values for certified emissions life for stationary CI ICE with a displacement of less than 10 liters per cylinder are given in 40 CFR 1039.101(g). The values for certified emissions life for stationary CI ICE with a displacement of greater than or equal to 10 liters per cylinder and less than 30 liters per cylinder are given in 40 CFR 94.9(a). Combustion turbine means all equipment, including but not limited to the turbine, the fuel, air, lubrication and exhaust gas systems, control systems (except emissions control equipment), and any ancillary components and sub-components comprising any simple cycle combustion turbine, any regenerative/recuperative cycle combustion turbine, the combustion turbine portion of any cogeneration cycle combustion system, or the combustion turbine portion of any combined cycle steam/electric generating system. Compression ignition means relating to a type of stationary internal combustion engine that is not a spark ignition engine. Date of manufacture means one of the following things: (1) For freshly manufactured engines and modified engines, date of manufacture means the date the engine is originally produced. (2) For reconstructed engines, date of manufacture means the date the engine was originally produced, except as specified in paragraph (3) of this definition. (3) Reconstructed engines are assigned a new date of manufacture if the fixed capital cost of the new and refurbished components exceeds 75 percent of the fixed capital cost of a comparable entirely new facility. An engine that is produced from a previously used engine block does not retain the date of manufacture of the engine in which the engine block was previously used if the engine is produced using all new components except for the engine block. In these cases, the date of manufacture is the date of reconstruction or the date the new engine is produced. Diesel fuel means any liquid obtained from the distillation of petroleum with a boiling point of approximately 150 to 360 degrees Celsius. One commonly used form is number 2 distillate oil. Diesel particulate filter means an emission control technology that reduces PM emissions by trapping the particles in a flow filter substrate and periodically removes the collected particles by either physical action or by oxidizing (burning off) the particles in a process called regeneration. Emergency stationary internal combustion engine means any stationary internal combustion engine whose operation is limited to emergency situations and required testing and maintenance. Examples include stationary ICE used to produce power for critical networks or equipment (including power supplied to portions of a facility) when electric power from the local utility (or the normal power source, if the facility runs on its own power production) is interrupted, or stationary ICE used to pump water in the case of fire or flood, etc. Stationary CI ICE used to supply power to an electric grid or that supply power as part of a financial arrangement with another entity are not considered to be emergency engines. Engine manufacturer means the manufacturer of the engine. See the definition of “manufacturer” in this section. Fire pump engine means an emergency stationary internal combustion engine certified to NFPA requirements that is used to provide power to pump water for fire suppression or protection. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: Freshly manufactured engine means an engine that has not been placed into service. An engine becomes freshly manufactured when it is originally produced. Installed means the engine is placed and secured at the location where it is intended to be operated. Manufacturer has the meaning given in section 216(1) of the Act. In general, this term includes any person who manufactures a stationary engine for sale in the United States or otherwise introduces a new stationary engine into commerce in the United States. This includes importers who import stationary engines for sale or resale. Maximum engine power means maximum engine power as defined in 40 CFR 1039.801. Model year means the calendar year in which an engine is manufactured (see “date of manufacture”), except as follows: (1) Model year means the annual new model production period of the engine manufacturer in which an engine is manufactured (see “date of manufacture”), if the annual new model production period is different than the calendar year and includes January 1 of the calendar year for which the model year is named. It may not begin before January 2 of the previous calendar year and it must end by December 31 of the named calendar year. (2) For an engine that is converted to a stationary engine after being placed into service as a nonroad or other non-stationary engine, model year means the calendar year or new model production period in which the engine was manufactured (see “date of manufacture”). Other internal combustion engine means any internal combustion engine, except combustion turbines, which is not a reciprocating internal combustion engine or rotary internal combustion engine. Reciprocating internal combustion engine means any internal combustion engine which uses reciprocating motion to convert heat energy into mechanical work. Rotary internal combustion engine means any internal combustion engine which uses rotary motion to convert heat energy into mechanical work. Spark ignition means relating to a gasoline, natural gas, or liquefied petroleum gas fueled engine or any other type of engine with a spark plug (or other sparking device) and with operating characteristics significantly similar to the theoretical Otto combustion cycle. Spark ignition engines usually use a throttle to regulate intake air flow to control power during normal operation. Dual-fuel engines in which a liquid fuel (typically diesel fuel) is used for CI and gaseous fuel (typically natural gas) is used as the primary fuel at an annual average ratio of less than 2 parts diesel fuel to 100 parts total fuel on an energy equivalent basis are spark ignition engines. Stationary internal combustion engine means any internal combustion engine, except combustion turbines, that converts heat energy into mechanical work and is not mobile. Stationary ICE differ from mobile ICE in that a stationary internal combustion engine is not a nonroad engine as defined at 40 CFR 1068.30 (excluding paragraph (2)(ii) of that definition), and is not used to propel a motor vehicle, aircraft, or a vehicle used solely for competition. Stationary ICE include reciprocating ICE, rotary ICE, and other ICE, except combustion turbines. Subpart means 40 CFR part 60, subpart IIII. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: Source ID: Source Name:

103 COOLING WATER TOWER

Source Capacity/Throughput:

[25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 002

# 003 Plan approval terms and conditions.

Plan approval terms and conditions. [Plan Approval 37-337A] The permittee shall, at a minimum of once per quarter, sample and analyze the cooling tower water for total dissolved solids (TDS) at a point which is representative of the water being evaporated to the atmosphere.

[Plan Approval 37-337A] (a) All recordkeeping shall commence upon commencement of operation of the source and shall be kept for a period of 5 years and made available to the Department upon request. [Plan Approval 37-337A] (b) The company shall maintain a log of all preventative maintenance inspections of the source. The inspection logs, at a minimum, shall contain the dates of the inspections, the name of the person performing the inspection, any mechanical repairs and/or adjustments, any potential problems or defects that were encountered, and the steps taken to correct them. [Plan Approval 37-337A] (c) The company shall maintain a log of the following, at a minimum, from the operational inspections: 1. Completion of inspection - daily defined as at least once per calendar day, while the source is operating or as approved PROC 103 STAC

Z01 10.500 M Gal/HR COOLING WATER

No additional testing requirements exist except as provided in other sections of this plan approval including Section B (Plan Approval General Requirements). II.

III.

IV. TESTING REQUIREMENTS.

MONITORING REQUIREMENTS.

RECORDKEEPING REQUIREMENTS. I. RESTRICTIONS. Emission Restriction(s). # 001 [25 Pa. Code §127.12b] Plan approval terms and conditions. [Plan Approval 37-337A] (a) The PM emissions shall not exceed 2.19 #/hr and 9.59 tpy based on a 12-month rolling basis. [Plan Approval 37-337A] (b) The PM10 emissions shall not exceed 0.66 #/hr and 2.87 tpy based on a 12-month rolling basis. [Plan Approval 37-337A] (c) The PM2.5 emissions shall not exceed 0.0039 #/hr and 0.017 tpy based on a 12-month rolling basis. [Plan Approval 37-337A] (d) The total dissolved solids (TDS) of the cooling tower water shall not exceed 5,000 ppmw. [Compliance with the #/hr limitations shall be demonstrated provided TDS concentrations do not exceed 5,000 ppmw.] SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 004

# 005 Plan approval terms and conditions.

Plan approval terms and conditions. by the Department in the work practice inspection protocol. [Plan Approval 37-337A] (d) The company shall maintain a daily log of the following: 1. Water circulation and makeup rates [Plan Approval 37-337A] (e) The company shall maintain records of the water sample TDS analysis.

[Plan Approval 37-337A] (a) The permittee shall perform a daily operational inspection of the source until such time as the Department approves a work practice inspection protocol submitted by the permittee. After Departmental approval, the permittee shall perform periodic inspections of the significant source equipment and emission controls in accordance with the approved work practice inspection protocol. [Plan Approval 37-337A] (b) The permittee shall maintain and operate the source in accordance with the manufacturer's specifications, the manufacturer's preventative maintenance schedule, and good air pollution control practices. The facility shall maintain a copy of the manufacturer's preventative maintenance schedule on-site.

[Plan Approval 37-337A] (a) Any information required to be submitted as part of this plan approval should be submitted to the attention of Chief, New Source Review Section, Air Quality Control, Northwest Regional Office, 230 Chestnut Street, Meadville, PA 16335. [Plan Approval 37-337A] (b) Issuance of an Operating Permit is contingent upon satisfactory compliance with the plan approval conditions, upon the control device being installed, tested, and operated as stated within the application, and upon satisfactory demonstration that the emissions from the source will not be in violation of applicable Rules and Regulations of the Department. No additional reporting requirements exist except as provided in other sections of this plan approval including Section B (Plan Approval General Requirements). V.

VI.

VII. REPORTING REQUIREMENTS.

WORK PRACTICE REQUIREMENTS.

ADDITIONAL REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: Source ID: Source Name:

104 FUEL STORAGE TANKS

Source Capacity/Throughput:

[25 Pa. Code §127.12b]

[25 Pa. Code §127.12b] # 001

# 002 Plan approval terms and conditions.

Plan approval terms and conditions. [Plan Approval 37-337A] (a) All recordkeeping shall commence upon commencement of operation of the source and shall be kept for a period of 5 years and made available to the Department upon request. [Plan Approval 37-337A] (b) The company shall maintain a log of all preventative maintenance inspections of the source. The inspection logs, at a minimum, shall contain the dates of the inspections, the name of the person performing the inspection, any mechanical repairs and/or adjustments, any potential problems or defects that were encountered, and the steps taken to correct them. [Plan Approval 37-337A] (c) The company shall maintain a log of the following, at a minimum, from the operational inspections: 1. Completion of inspection - daily defined as at least once per calendar day, while the source is operating or as approved by the Department in the work practice inspection protocol. [Plan Approval 37-337A] (d) The company shall keep a record of the vapor pressure of the contents of the tanks unless the tank is equipped with pressure relief valves that meet the requirements in 25 PA Code 129.57.

[Plan Approval 37-337A] (a) The permittee shall perform a daily operational inspection of the source until such time as the Department approves a PROC 104 STAC

Z01 79.000 Gal/HR ULSD

No additional testing requirements exist except as provided in other sections of this plan approval including Section B (Plan Approval General Requirements).

No additional monitoring requirements exist except as provided in other sections of this plan approval including Section B (Plan Approval General Requirements).

No additional reporting requirements exist except as provided in other sections of this plan approval including Section B (Plan Approval General Requirements). II.

III.

IV.

V.

VI. TESTING REQUIREMENTS.

MONITORING REQUIREMENTS.

RECORDKEEPING REQUIREMENTS.

REPORTING REQUIREMENTS.

WORK PRACTICE REQUIREMENTS. I. RESTRICTIONS. No additional requirements exist except as provided in other sections of this plan approval including Section B (Plan Approval General Requirements). SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: [25 Pa. Code §129.57]

[25 Pa. Code §127.12b] # 003

# 004 Storage tanks less than or equal to 40,000 gallons capacity containing VOCs

Plan approval terms and conditions. work practice inspection protocol submitted by the permittee. After Departmental approval, the permittee shall perform periodic inspections of the significant source equipment and emission controls in accordance with the approved work practice inspection protocol. [Plan Approval 37-337A] (b) The permittee shall maintain and operate the source in accordance with the manufacturer's specifications, the manufacturer's preventative maintenance schedule, and good air pollution control practices. The facility shall maintain a copy of the manufacturer's preventative maintenance schedule on-site. [Plan Approval 37-337A] (c) The company shall not store any liquid containing volatile organic compounds with vapor pressure greater than 1.5 psia (10.5 kilopascals) under actual storage conditions unless the tank is equipped with pressure relief valves which are maintained in good operating condition and which are set to release at no less than 0.7 psig (4.8 kilopascals) of pressure or 0.3 psig (2.1 kilopascals) of vacuum or the highest possible pressure and vacuum in accordance with state or local fire codes or the National Fire Prevention Association guidelines or other national consensus standards acceptable to the Department.

The provisions of this section shall apply to above ground stationary storage tanks with a capacity equal to or greater than 2,000 gallons which contain volatile organic compounds with vapor pressure greater than 1.5 psia (10.5 kilopascals) under actual storage conditions. Storage tanks covered under this section shall have pressure relief valves which are maintained in good operating condition and which are set to release at no less than 0.7 psig (4.8 kilopascals) of pressure or 0.3 psig (2.1 kilopascals) of vacuum or the highest possible pressure and vacuum in accordance with state or local fire codes or the National Fire Prevention Association guidelines or other national consensus standards acceptable to the Department. Section 129.56(g) (relating to storage tanks greater than 40,000 gallons capacity containing volatile organic compounds) applies to this section. Petroleum liquid storage vessels which are used to store produced crude oil and condensate prior to lease custody transfer shall be exempt from the requirements of this section.

[Plan Approval 37-337A] (a) Any information required to be submitted as part of this plan approval should be submitted to the attention of Chief, New Source Review Section, Air Quality Control, Northwest Regional Office, 230 Chestnut Street, Meadville, PA 16335. [Plan Approval 37-337A] (b) Issuance of an Operating Permit is contingent upon satisfactory compliance with the plan approval conditions, upon the control device being installed, tested, and operated as stated within the application, and upon satisfactory demonstration that the emissions from the source will not be in violation of applicable Rules and Regulations of the Department. VII. ADDITIONAL REQUIREMENTS. SECTION D. Source Level Plan Approval Requirements37-337A

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## PROPOSED 944870 DEP Auth ID: SECTION E. Alternative Operation Requirements.
No Alternative Operations exist for this Plan Approval facility.37-337A

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## PROPOSED 944870 DEP Auth ID: SECTION F. Emission Restriction Summary.

Source Id Source Description 031

032

033 COMBINED CYCLE UNIT #1

COMBINED CYCLE UNIT #2

AUXILIARY BOILER Emission Limit

Emission Limit

Emission Limit Pollutant

Pollutant

Pollutant 5.000
110.600 401.880 1,000.000 172.250 66.910 66.910 28.260 4.260 66.910 101.860

5.000
110.600 401.880 1,000.000 172.250 66.910 66.910 28.260 4.260 66.910 101.860

0.036 3.310 0.011 1.010 0.005 0.460 0.005 0.460 0.002 0.190 0.000 0.040 0.005 0.460 PPMV Tons/Yr Tons/Yr Lbs/KW-Hr Tons/Yr Tons/Yr Tons/Yr Tons/Yr Tons/Yr Tons/Yr Tons/Yr

PPMV Tons/Yr Tons/Yr Lbs/KW-Hr Tons/Yr Tons/Yr Tons/Yr Tons/Yr Tons/Yr Tons/Yr Tons/Yr

Lbs/MMBTU Tons/Yr Lbs/MMBTU Tons/Yr Lbs/MMBTU Tons/Yr Lbs/MMBTU Tons/Yr Lbs/MMBTU Tons/Yr Lbs/MMBTU Tons/Yr Lbs/MMBTU Tons/Yr dry basis corrected at 15% oxygen averaged over any rolling 3-hour period based on a 12-month rolling total based on a 12-month rolling total lbs/MW-hr (gross) not kW-hr based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total

dry basis corrected at 15% oxygen averaged over any rolling 3-hour period based on a 12-month rolling total based on a 12-month rolling total lbs/MW-hr (gross) not kW-hr based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total

based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total Ammonia Ammonia CO Carbon Dioxide NOX PM10 PM2.5 SOX Sulfuric Acid TSP VOC

Ammonia Ammonia CO Carbon Dioxide NOX PM10 PM2.5 SOX Sulfuric Acid TSP VOC

CO CO NOX NOX PM10 PM10 PM2.5 PM2.5 SOX SOX Sulfuric Acid Sulfuric Acid TSP TSP37-337A

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## PROPOSED 944870 DEP Auth ID: SECTION F. Emission Restriction Summary.

Source Id Source Description

101

102 EMERGENCY GENERATOR (1,135 BHP - 750 KW)

EMERGENCY FIREWATER PUMP (450 BHP) Emission Limit

Emission Limit Pollutant

Pollutant 0.002 0.140

0.290 5.790 0.490 9.890 0.020 0.330 0.020 0.330 0.001 0.010 0.000 0.003 0.020 0.330 0.030 0.700

0.130 2.580 0.090 1.860 0.010 0.150 0.010 0.150 0.000 0.006 0.000 0.001 0.010 0.150 0.060 1.110 Lbs/MMBTU Tons/Yr

Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr

Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr based on a 12-month rolling total

based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total

based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total VOC VOC

CO CO NOX NOX PM10 PM10 PM2.5 PM2.5 SOX SOX Sulfuric Acid Sulfuric Acid TSP TSP VOC VOC

CO CO NOX NOX PM10 PM10 PM2.5 PM2.5 SOX SOX Sulfuric Acid Sulfuric Acid TSP TSP VOC VOC37-337A

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## PROPOSED 944870 DEP Auth ID: SECTION F. Emission Restriction Summary.

Site Emission Restriction Summary Emission Limit Pollutant 15.300 6.900 Tons/Yr Tons/Yr based on a 12-month rolling total for all HAPs

based on a 12-month rolling total for formaldehyde Hazardous Air Pollutants Hazardous Air Pollutants Source Id Source Description 103 COOLING WATER TOWER Emission Limit Pollutant 0.660 2.870 0.004 0.017 2.190 9.590 Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr Lbs/Hr Tons/Yr based on a 12-month rolling total based on a 12-month rolling total based on a 12-month rolling total PM10 PM10 PM2.5 PM2.5 TSP TSP37-337A

Page 128 HICKORY RUN ENERGY STATION



## PROPOSED 944870 DEP Auth ID: SECTION G. Miscellaneous. a) The Capacity/Hour numbers listed on Page 5 and provided in Section D of this permit for individual sources are for informational purposes only and are not to be considered enforceable limits. Enforceable emission limits are listed in the Restriction section for each source. They are also summarized for informational purposes only in Section F. b) Source ID: Department assigned ID number for the source Source Name: Department assigned name for the source Capacity: The maximum capacity for the source (not a limit) Fuel/Material: The fuel/material assigned to SCC for the source Schematics: FML: Fuel material location Comb: Combustion source Proc: Process CD: Control device EP: Emission point Pollutant: Ammonia: Ammonia CO: Carbon Monoxide CO2: Carbon Dioxide HAP: Hazardous Air Pollutants NOx: Nitrogen Oxide PM10: PM < 10 microns PM2.5: PM < 2.5 microns SOx: Sulfur Oxide Sulfuric Acid: Sulfur Acid TSP: Total Suspended Particulate VOC: Volatile Organic Compound c) For the purpose of this plan approval, the combustion turbines incorporated into the Combined Cycle Units will be one of the four proposed make and models: 1. General Electric 7FA (2.7 mmscf/hr natural gas) 2. Siemens F (2.8 mmscf/hr natural gas) 3. Siemens H (3.4 mmscf/hr natural gas) 4. Mitsubishi G (3.4 mmscf/hr natural gas) d) For the purpose of this plan approval, Source 031 (Combined Cycle Unit) consists of the following: 1. A combustion turbine generator (CTG) and a heat recovery steam generator (HRSG) that will provide steam to drive a single steam turbine generator (STG). The combined cycle unit (CCU) is a CTG and a HRSG. Each HRSG will be equipped with a natural gas-fired duct burner (500 mmbtu/hr) which may be utilized at times of peak power demand to supplement power output by raising the heat content of the exhaust gas and thereby increasing the amount of steam generated. e) For the purpose of this plan approval, Source 032 (Combined Cycle Unit) consists of the following: 1. A combustion turbine generator (CTG) and a heat recovery steam generator (HRSG) that will provide steam to drive a single steam turbine generator (STG). The combined cycle unit (CCU) is a CTG and a HRSG. Each HRSG will be equipped with a natural gas-fired duct burner (500 mmbtu/hr) which may be utilized at times of peak power demand to supplement power output by raising the heat content of the exhaust gas and thereby increasing the amount of steam generated. f) For the purpose of this plan approval, Source 033 (Auxiliary Boiler) consists of the following: 1. Forty (40) mmbtu/hr natural gas fired boiler. Make and model will be determined at a later date. (expected operating hours = 4,600 hr/yr) g) For the purpose of this plan approval, Source 101 (Emergency Generator) consists of the following:37-337A

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## PROPOSED 944870 DEP Auth ID: SECTION G. Miscellaneous. 1. The generator is rated at 1,135 bhp (750 kW) and fired with ULSD. Make and model will be determined at a later date. (expected operating hours = 100 hr/yr) h) For the purpose of this plan approval, Source 102 (Emergency Firewater Pump) consists of the following: 1. The fire pump is rated at 450 bhp and fired with ULSD. Make and model will be determined at a later date. (expected operating hours = 100 hr/yr) i) For the purpose of this plan approval, Source 103 (Cooling Water Tower) consists of the following: 1. A multi-cell mechanical draft cooling tower with a water circulation rate of 175,000 gpm; with a TDS concentration of 5,000 ppmv; and with an associated drift of 0.0005%. j) For the purpose of this plan approval, Source 104 (Fuel Storage Tanks) consists of the following: 1. Two (2) AGST with capacities less than 20,000 gallons for the storage of ULSD.

## ****** End of Report ******ATTACHMENT Response to Comments from U.S. Enviro nmental Protection Agency Region III Air Quality Analysis for Prevention of Significant Deterioration DEP Intent to Issue Plan Approval 37-337A to Hickory Run Energy, LLC Proposed Hickory Run Energy Station, North Beaver Township, Lawrence County

April 19, 2013 Page 1 of 5 EPA Comment 1: Please ensure that the 1-hr background concentration correctly reflects New Castle's current (cer tified) design value in ppb. (Table 2-3: 1-hr SO 2 Background) DEP Response 1: The 1-hour SO 2 background for New Castle was calculated utilizing air monitoring data for the 2009-11 pe riod. The DEP certified the mo st recent year’s (2011) air monitoring data by the EPA im posed deadline of May 1, 2012. EPA Comment 2: BEE-line output provided to EPA Region 3 by PA DEP indicates an earlier version of AERMOD (12060) was used in the mo deling analysis. Should the most recent version of AERMOD (12345) have been used in the modeling anal ysis? The modeling analysis also used versions of AERMET, AE RMINUTE and AERSURFACE that were no longer the current versions that are posted on EP A’s SCRAM website. (Section 3.1: Model Selection) DEP Response 2: The plan approval applicatio n (along with the air quality analysis) was submitted to the DEP on September 27, 2012. At the time of the original submittal, AERMOD 12060 was the most recent version of AERMOD. Subsequently, AERMET 11059 and AERSURFACE 08009 were the most recent vers ions of their respective models at the time of the plan approval application submi ttal. The change implemented in AERMINUTE 11325 (from AERMINUTE 11059) did not have an impact in the generation of the Youngstown surface data file (.SFC). Therefore, the DEP feels that the versions of AERMOD, AERMET, AERSURFACE and AERMINUTE utilized in the application were sufficient. EPA Comment 3: Given the high stack heights of the combustion turbines, were the model peak locations examined to determine if the peak model concentrations were being captured within the finest model receptor grid (50 m) sp acing? Inadequate model receptor spacing in the areas of where the model peaks are occurring could lead to an underestimation of the maximum model concentrations (see section 7. 2.2(a) of Appendix W). (Section 3.5: Receptor Grids) DEP Response 3: The DEP confirmed that mo st of the maximum modeled concentrations occurred within two kilometers (where the rece ptor spacing is 50 meters) of the center of the proposed Hickory Run Energy (HRE) facility. Given that the highest modeling concentration (from all pollutants) was only 80% of its respective significance impact level (SIL) and in accordance with Section 7.2.2(a) of Appendix W, the receptor grid that was used for the analysis provided an adequa te account of where the maximum modeled concentrations were occurring. The DEP feels that any slight rise in concentrations (by refining the receptor grid near the maximum co ncentration) should not be high enough to exceed the SIL for any pollutant. EPA Comment 4: The four (4) combustion tu rbine configurations modeled have stack heights that exceed GEP. HRE’s BPIP analys is shows that the physical height of the combustion turbine stacks exceeds the GEP heig ht; 87.m versus BPIP analysis of 74.6 m. Did HRE adequately justify its combustions tu rbine heights in accordance with GEP? (Section 3.7: GEP Stack Height Analysis) DEP Response 4: In Section 3.7 of the revi sed Air Quality Dispersion Modeling Report submitted in February 2013, the documentation st ates “[f]or the combustion turbine stacks, GEP was calculated by BPIP

‐ PRIME as 87.6 m (288 ft). HRE has proposed a stack height ofATTACHMENT Response to Comments from U.S. Enviro nmental Protection Agency Region III Air Quality Analysis for Prevention of Significant Deterioration DEP Intent to Issue Plan Approval 37-337A to Hickory Run Energy, LLC Proposed Hickory Run Energy Station, North Beaver Township, Lawrence County

April 19, 2013 Page 2 of 5 74.7 m (245 ft), which complies with the GEP fo rmula height modeling requirements.” The values in EPA’s Comment 4 were interchanged. These values were verified (by execution of Bpip) during the DEP’s review of the air quality analysis. EPA Comment 5: Final permitted emission rate s for HRE should reflec t the emission rates used in the modeling analysis. NOx controls necessary for ozone compliance should be operated year round to ensure compliance with the NO2 NAAQS. (Section 3.8.3: Source Parameters and Emission Rates) DEP Response 5: After consultation with the DEP Northwest Regional Office staff, the DEP was able to confirm that the emission rates that were utilized in the modeling analysis were the final permitted emission ra tes for the HRE project. Section D, Condition #037 of the final plan approval outlines the n eed to operate controls year round. EPA Comment 6: Only three operating modes were included in the modeling analysis. Did HRE adequately account for all of the possible operating modes that co uld have contributed to the maximum modeled concentrations in acco rdance with section 8.1.2(a) of Appendix W. (Section 3.8.3: Source Pa rameters and Emission Rates) DEP Response 6: The methodology for choosing the operating scenarios that were modeled is consistent with Section 8.1.2(a) of the EPA’s “Guideline on Air Quality Models,” codified in 40 CFR Part 51, Appendix W. HRE provided supporting documentation on their load analysis. Those details are provided below: Section 8.1.2(a) of 40 CFR Part 51 Appendix W requires the following regarding adequately accounting for operating modes: “...As a minimum, the source should be mode led using the design capacity (100 percent load). If a source operates at greater than design capacity for periods that could result in violations of the standards or PSD increm ents, this load) should be modeled. Where the source operates at substantially less th an design capacity, and the changes in the stack parameters associated with the operatin g conditions could lead to higher ground level concentrations...should also be modeled. A range of operating conditions should be considered in screening analyses; the load caus ing the highest concentration, in addition to the design load, should be included in refined modeling...” The modeling analysis for the project reflects the range of expected operating loads for the generating equipment, from mi nimum to maximum, including pe riods of startup/shutdown. A total of four (4) operating modes were evalua ted in the dispersion modeling analysis. The four (4) modeled scenarios we re startup/shutdown, 50% load, 100% load, and 100% load with duct burners. As shown in Tables 4-1 through 4-12 of HRE’s modeling report, all maximum impacts for all pollutants and all averaging periods occurred as a result of the maximum emission rate modeling scenarios (i.e., 100% load with duct firing and/or st artup emissions). The lower stack parameter/emission rate scenarios (i.e., 50% load and 100% load with no duct firing) did not result in a maximum impact for any pollutant or averaging period. Introducing additional reduced emi ssion rate modeling scenarios (e.g., 75% load, 65% load, etc.) where stack parameters (flow rate and temperature) would not differ substant ially from baseloadATTACHMENT Response to Comments from U.S. Enviro nmental Protection Agency Region III Air Quality Analysis for Prevention of Significant Deterioration DEP Intent to Issue Plan Approval 37-337A to Hickory Run Energy, LLC Proposed Hickory Run Energy Station, North Beaver Township, Lawrence County

April 19, 2013 Page 3 of 5 but emissions would be at leas t 25% lower would not be expect ed to add useful information to the analysis. This conclusion is reinforced by a review of the detailed results contained in Appendix E of HRE’s modeling report. For annual average NO 2 , SO 2 , PM-2.5 and PM-10, as well as 1-hour and 8-hour average CO, there is no variatio n between the 50% and 100% load results. This is due to ancillary equipment driving the maximum impacts. Therefore, modeling another load for the turbines for these pollutants and averag ing period would not change the maximum concentrations already reported. This is also true for 24-hour average PM-10 and 24-hour SO 2 where differences in the maximum modeled concentrations between the 100% and 50% loads were 0.02 micr ograms per cubic meter (mg/m 3 ) or less. For the remaining pollutants an d averaging periods, the maxi mum modeled concentrations are only a fraction of the SIL (e.g., 20% of the 1-hour SO 2 SIL, 50% of the 24-hour PM-2.5 SIL (a discussion of the recent court decision regarding the PM-2.5 SIL is outlined in HRE’s February 19, 2013 document), and 4% of the 3-hour SO 2 SIL, 80% of the 1-hour NO 2 SIL [unaveraged, and without applyi ng the Ambient Ratio Method]) and, in the case of 1-hour NO 2 , the 100% and 50% load result s are between 0.5 to 1 mg/m 3 less than the 100% load with duct firing. Based on the above, even co nsidering 75% load or other intermediate load points, the maximum impacts would still be well below the SILs, and therefore the conclusions of the analysis woul d not be affected under any additional scenarios that might be representative of source operation. EPA Comment 7: The modeling analysis presented by HRE is somewhat limited (only 9 model receptors). Model receptors appear to ha ve been chosen at re gular intervals in the direction of the nearest Class I areas. Does PA DEP and HRE believe the number of model receptors is sufficient enough to ensure that model concentrations are below the Class I increments (beyond 50 km)? (Section 6: Class I Area Significance Analysis) EPA Comment 8: The modeling files reviewed by EPA Region 3 did not include modeling results of the 3-hr and annual SO 2 Class I increments. Did HRE perform a modeling analysis for the 3hr and annual Class I SO 2 increments? (Section 6: Class I Area Significance Analysis) DEP Response 7 and DEP Response 8: Otter Creek in West Virginia is the closest Class I area (at approximately 225 kilometers) to HR E, lying to the south, southeast of the proposed HRE facility. HRE’s modeling analysis demonstrated that the closer the plume (in the model) traveled to 50 kilometers, the lesse r the impact. Any impact that would extend beyond 50 kilometers (for example, at the O tter Creek Class I area) would be expected to have an even lesser impact th an the results at 50 kilometers . These results were also supported in the Class II analysis for each pollu tant and each averaging time with respect to the appropriate Class I significance impact level (for 1-hour, 3-ho ur, 24-hour, and annual SO 2 , annual NO 2 , and 24-hour and annual PM-2.5). EPA Comment 9: Model receptor heights are probably much lower than the elevations within the nearest Class I Area (Otter Creek). How will the discrepancy in the model receptor elevations and Class I Area elevations affect th e final model concentrations and conclusions? (Section 6: Class I Area Significance Analysis)ATTACHMENT Response to Comments from U.S. Enviro nmental Protection Agency Region III Air Quality Analysis for Prevention of Significant Deterioration DEP Intent to Issue Plan Approval 37-337A to Hickory Run Energy, LLC Proposed Hickory Run Energy Station, North Beaver Township, Lawrence County

April 19, 2013 Page 4 of 5 DEP Response 9: Within the Class II modeling an alysis, receptor elevations were calculated using AERMAP out to a radius of 50 kilometers from the HRE facility. As listed in the receptor file on the National Park Service website ( http://www.nature.nps.go v/air/maps/receptors/ ), the base elevations of Otter Creek range from 251 meters to 350 meters. Of the 35, 801 receptors that were modeled utilizing AERMOD, at least 38 receptors were modeled in the 50 kilometer domain that were less than the lowest elevation within the Otter Creek Class I area. As stated in DEP Response 3 above, the maximum modeled concentration (of all pollutants) was only 80% of its respective SIL. Therefore, the 38 receptors reference above within the 50 kilometer domain had modeled concentrations less than the SIL. This fact coupled with the 225 kilometer distance from HRE to Otter Creek would indicate that the results at the Class I area would be less than the modeled concentration at 50 kilometers, regardless of the difference in height elevation. EPA Comment 10: Precursor emi ssion contributions to secondary PM-2.5 formation were addressed in a response to comments docume nt provided by PA DEP (February 19, 2013 response from David Wilson). EPA issued dr aft guidance on how to address secondary PM2.5 formation on March 4, 2013. It would be us eful if HRE would revi ew this document and provide an expanded analysis for the proposed facility. (Secondary PM-2.5 Formation Analysis) DEP Response 10: The DEP has reviewed EPA’ s March 4, 2013 guidance document entitled Draft Guidance for PM2.5 Permit Modeling, a portion of which addresses secondary PM2.5 formation. In a response to a comment by the DEP on February 19, 2013, HRE outlined an approach for evaluating secondary PM-2.5 fo rmation consisting of a quantitative and qualitative analysis using existing data. To the maximum extent practicable, HRE demonstrated that primary and secondary PM-2 .5 emissions combined from the project, while considering existing current ambient ba ckground concentrations, would not cause or contribute to an exceedance of the PM-2.5 NAAQS. In Section III.2.2 of the March 4, 2013 guidance document, EPA outlined a similar a pproach, labeling “a hybr id quantitative and qualitative assessment” as one acceptable method of evalua ting secondary formation. HRE’s analysis was conservative in nature since it assumed that maximum concentrations resulting from the project’s primary and seco ndary PM-2.5 emissions would be paired in time and space. Since HRE’s PM-2.5 evaluati on was consistent with EPA’s guidance and used a conservative methodology for stacking primary and secondary impacts, the DEP feels that this approach satisfies the requirement of evaluating secondary formation of PM-2.5. EPA Comment 11: Please note th at EPA recently tightened the PM-2.5 NAAQS. An analysis could be expanded to include all monitors and any designated nona ttainment areas with 50+ km of the plant. It might also be impo rtant to examine any nonattainment areas that have clean-data determination to ensure continued compliance with the PM-2.5 NAAQS. (Secondary PM-2.5 Formation Analysis) DEP Response 11: HRE’s modeling analysis covered an examination of a PM-2.5 nonattainment area. Section 4.3 of the modeling analysis includes an evaluation for Taylor Township (which is a part of the Pittsburgh-Beaver Valley nonattainment area and only 5.6 kilometers to the southeast of HRE) in Lawr ence County, demonstrating that the project would not contribute to any a ttainment demonstration issues for this nonattainment area. Even adding secondary form ation rates from HRE’s February 19, 2013 analysis, theATTACHMENT Response to Comments from U.S. Enviro nmental Protection Agency Region III Air Quality Analysis for Prevention of Significant Deterioration DEP Intent to Issue Plan Approval 37-337A to Hickory Run Energy, LLC Proposed Hickory Run Energy Station, North Beaver Township, Lawrence County

April 19, 2013 Page 5 of 5 maximum PM2.5 impacts from the project are less than the levels specified in 40 CFR §51.165(b)(2) (which were preserved in the rece nt United States Court of Appeals for the D.C. Circuit decisi on in Sierra Club v. EPA, No. 10- 1413 (January 22, 2013)). Therefore, the project would not be deemed to cause or co ntribute to a violatio n of the NAAQS at any nonattainment area. In addition, the DEP is not aware of any PM-2.5 nonattainment area that has a clean data determination by EPA.