COMMONWEALTH OF PENNSYLVANIA

Department of Environmental Protection

April 15, 2013

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/Permit/37-337A

APS ID: 792406 Auth ID: 944870

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 Quality 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 demands 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, 2012, with the 

Completeness Letter being sent on October 17, 2012. Receipt of the application was published 

in the PA Bulletin on November 3, 2012. 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 November 13, 2012. 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

DRAFT
PA Review Memo 37-337A PSD 2 April 15, 2013

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 The GIF contains the name, mailing address, email address, 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 project 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 milestones 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 estimates 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 pollutant 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 air 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 Class 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 application 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 application 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 37-337A PSD 3 April 15, 2013

DRAFT

From the Permit Manual, in order to comply with the 40 CFR 52.21, a complete application 

subject to PSD regulations 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 review 

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, 2013, at North Beaver Township VFD in North Beaver 

Township (969 Mount Jackson Road, New Castle, PA). The hearing will run from 6:00 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 Protection Agency (EPA) received the Department’s draft plan 

approval on March 4, 2013, and was afforded the required 45 days for comment (until April 18, 

2013). EPA’s submitted comments on the proposed Plan Approval on April 5, 2013, and are 

addressed within 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 km 
PA Review Memo 37-337A PSD 4 April 15, 2013

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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 Brigantine 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. The USFS stated in an email dated January 3, 2013, that 

they are not requesting a Class I (AQRV) analysis for Otter Creek Wilderness, Dolly Sods 

Wilderness, and James River Face Wilderness.

BACKGROUND

Hickory Run Energy (HRE) project is a natural gas-fired combined-cycle (NGCC) electric 

generation facility located in North Beaver Township, Lawrence County. The project is designed 

to generate up to 900 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 cooling 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

CCUs (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 will 

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 superheater, 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 condensed and heat rejection accomplished via an 
PA Review Memo 37-337A PSD 5 April 15, 2013

DRAFT

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 providing 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 pollution 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 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.

CCUs Controls (C031A & C031B) & (C032A & C032B)

Each unit will 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. 

The 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 NOx and ammonia emissions and make adjustments to maintain NOx

emissions below 2 ppm. The anticipated removal efficiency is ~ 92% (NOx 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 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 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-temperature 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 boiler must be able to operate during periods when the CCU are not in steady-state operation. 

The boiler 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 (Source 101)
PA Review Memo 37-337A PSD 6 April 15, 2013

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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 and 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 Performance 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 fire. 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 requirements 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 will 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. Emissions are estimated to be 2.19 #/hr for PM, 0.66 #/hr for PM10, 

and 0.0039 #/hr for PM2.5.

Storage Tanks (Source 104)

ULSD fuel for the emergency generator and the firewater pump will be stored in separate aboveground tanks at the site. These tanks 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, 1984) 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 Units (CCU). 

Potential emissions, as proposed by the applicant, from both CCUs based on 8,760 hours of 

operation per year, are summarized below.

Uncontrolled Combined Cycle Units (each)

Combustion 

Unit Mode

NOx CO VOC SO2 H2SO4 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 20.05
PA Review Memo 37-337A PSD 7 April 15, 2013

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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 18.28 408.75 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 – 8,010 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 fuel consumption per unit – 27,331 mmscf/yr
PA Review Memo 37-337A PSD 8 April 15, 2013

DRAFT

Controlled Combined Cycle Units (each)

Combustion 

Unit Mode

NOx CO VOC SO2 H2SO4 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 14.4 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 148.03 246.81 101.86 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 45.0 141.82 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

Mitsubishi M501GAC (Mitsubishi G)

Normal Duct 

Off

25.45 51.03 15.5 31.07 6.66 13.35 6.17 12.38 0.93 1.86 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

172.25 401.88 101.86 28.26 4.26 66.91

Minimum 

Emissions

124.26 213.9 78.58 22.34 3.35 58.85
PA Review Memo 37-337A PSD 9 April 15, 2013

DRAFT

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 – 8,010 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 fuel consumption per unit – 27,331 mmscf/yr

 For all turbine types, NOx, 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 Off) 

(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 87.5

Siemens F 19.06 45.37 22.72 45.44 90.8

Mitsubushi G 23.61 56.20 27.19 54.38 110.6

Siemens H 23.53 56.01 27.11 54.22 110.2

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

NOx 0.011 #/mmbtu A 0.44 1.01

SO2 S/7000*104*64/32 #/mmscf B 0.08 0.19

H2SO4 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-42 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 0.02
PA Review Memo 37-337A PSD 10 April 15, 2013

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NOx 0.013 #/kWh A 9.89 0.49

CO 0.0077 #/kWh A 5.79 0.29

VOC 0.09 #/mmbtu C 0.7 0.03

SO2 0.00809S #/bhp-hr D 0.01 0.00069

H2SO4 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-42 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

NOx 0.0041 A 1.86 0.09

CO 0.0057 A 2.58 0.13

VOC 0.00247 C 1.11 0.06

SO2 0.00809S C 0.0055 0.00027

H2SO4 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 Specific 

gal/min #/hr Gravity

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 37-337A PSD 11 April 15, 2013

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Greenhouse Gas Emissions

Emission Unit Pollutant Emission 

Factor 

(kg/mmbtu)

GHG 

Emissions 

(tpy)

Global 

Warming 

Potential

Equivalent Emissions 

(tons CO2(e)/yr)

GE7FA (each) (2,276 

mmbtu/hr) (21,937,760 

mmbtu/yr)

CO2 53.02 1,446,505 1 1,446,505

CH4 0.001 27.3 21 573

N2O 0.0001 2.8 310 846

Total 1,447,924

Emission Unit Pollutant Emission 

Factor 

(kg/mmbtu)

GHG 

Emissions 

(tpy)

Global 

Warming 

Potential

Equivalent Emissions 

(tons CO2(e)/yr)

Siemens F (each)

(2,352 mmbtu/hr)

(22,603,520 mmbtu/yr)

CO2 53.02 1,490,403 1 1,490,403

CH4 0.001 28.2 21 591

N2O 0.0001 2.9 310 872

Total 1,491,866

Emission Unit Pollutant Emission 

Factor 

(kg/mmbtu)

GHG 

Emissions 

(tpy)

Global 

Warming 

Potential

Equivalent Emissions 

(tons CO2(e)/yr)

Mitsubishi G (each)

(2,954 mmbtu/hr)

(27,877,040 mmbtu/yr)

CO2 53.02 1,838,121 1 1,838,121

CH4 0.001 34.7 21 729

N2O 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 CO2(e)/yr)

Siemens H (each)

(2,942 mmbtu/hr)

(27,771,920 mmbtu/yr)

CO2 53.02 1,831,190 1 1,831,190

CH4 0.001 34.6 21 726

N2O 0.0001 3.5 310 1,071

Total 1,832,987

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 CO2(e)/yr)

Auxiliary Boiler CO2 53.02 12,130 1 12,130

CH4 0.001 0.23 21 4.8

N2O 0.0001 0.023 310 7.1

Total 13,696
PA Review Memo 37-337A PSD 12 April 15, 2013

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 CO2(e)/yr)

Emergency 

Generator

CO2 73.96 71.1 1 71.1

CH4 0.003 0.0029 21 0.061

N2O 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 

Emissions 

(tpy)

Global 

Warming 

Potential

Equivalent Emissions 

(tons CO2(e)/yr)

Firewater Pump CO2 73.96 29.9 1 29.9

CH4 0.003 0.0012 21 0.025

N2O 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 Global warming 

potentials based on Table A-1 of 40 CFR 98

Facility-wide Potential Emissions (based on worst case turbine selection scenario)

Pollutant 2 CCU (tpy) Auxiliary Boiler 

(tpy)

Emergency 

Generator (tpy)

Emergency Fire 

Pump (tpy)

Cooling 

Tower (tpy)

Total Facility 

PTE (tpy)

CO 803.8 3.31 0.29 0.13 807.53

GHG (CO2(e)) 3,679,850 13,696 80.5 33.8 3,693,660.3

H2SO4 8.52 0.04 0.0001 0.0001 8.57

Lead 0.001 4.5E-05 0.001

NO2 344.5 1.01 0.49 0.09 346.09

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

SO2 56.5 0.19 0.001 56.70

VOC 203.72 0.14 0.03 0.06 203.95

Ammonia 221.2 221.2

HAPs 15.0 0.17 6.6E-04 6.4E-04 15.3

Note: Formaldehyde is the largest HAP PTE of 6.88 tpy
PA Review Memo 37-337A PSD 13 April 15, 2013

DRAFT

REGULATORY ANALYSIS

The proposed facility is subject to New Source Review which includes Prevention of Significant 

Deterioration (PSD) regulations including a demonstration of compliance with the National 

Ambient Air Quality Standards (NAAQS) and the non-attainment 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 facility 

will be a major source (CO, NOx, PM, PM10, PM2.5, VOC, and GHG) and will emit significant 

amounts, as defined in 40 CFR Part 52.21, for the following pollutants: CO, NO2, VOC, SO2, 

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, the Greenhouse Gas 

(GHG) Tailoring Rule requires a BACT analysis to be performed for CO2(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 the 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 SO2.

 Lawrence County 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 designated as cannot be classified or better than national standards for NO2

(1971 annual standard).

 Lawrence County is designated as Unclassifiable/Attainment for NO2 (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/Attainment for PM2.5 (24-hr NAAQS for both 

1997 & 2006).

 Lawrence County is designated as Unclassifiable/Attainment for Lead (2008 NAAQS).

PSD Increment Consumption
PA Review Memo 37-337A PSD 14 April 15, 2013

DRAFT

An ambient air quality analysis must be conducted to demonstrate that the PSD ambient air 

quality increments are not exceeded. This facility will be located in a Class II area, increments 

for CO, PM-10, PM-2.5, NO2, and SO2 apply. There are three Class I areas between 235 and 300 

km from the facility. The facility has informed the applicable Federal 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 impacts from the proposed facility. Since 

the modeling indicates that the Significant Impact Levels (SILs) were not exceeded for any 

pollutants, other increment consuming sources need not be evaluated. Dispersion modeling was 

conducted for the proposed facility with representative emission source data, terrain data, and 

meteorological 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 the 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 Standards 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):

 NO2/NOx (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

 SO2 (3-hour average): 0.91 vs. standard of 512

 SO2 (24-hour average): 0.26 vs. standard of 91

 SO2 (annual average): 0.018 vs. standard of 20

Additional Impact Analysis

The owner or operator shall provide an analysis of the impairment to visibility, soils 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 vegetation 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) of 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 Section of the memo.
PA Review Memo 37-337A PSD 15 April 15, 2013

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)

Significant 

Emission 

Threshold (tpy)

Applicable 

New 

Source 

Program

NOx 346.09 346.09 346.09 40 PSD/NSR

CO 807.53 807.53 807.53 100 PSD

VOC 203.95 203.95 203.95 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

SO2 56.7 56.7 56.7 40 PSD

H2SO4 8.57 8.57 8.57 7 PSD

CO2(e) 3,693,661 3,693,661 3,693,661 100,000 new

75,000 existing

PSD

Pb 0.001 0.001 0.001 0.6 PSD

Fluorides 3 PSD

TRS 

Compounds

including H2S

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.

PSD Applicability Determination Step 2: Contemporaneous Emissions

Because Step 1 Emission Increase is greater than the significant threshold, an increase or 

decrease is contemporaneous 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 contemporaneous emissions.

NSR Pollutant Step 1 Project 

Emissions 

Increase (tpy)

Contemporaneous 

Emission 

Increases (tpy)

Net Emission 

Increase or 

Decrease (tpy)

Significant 

Emissions 

Threshold (tpy)

NOx 346.09 346.09 40

CO 807.53 807.53 100

VOC 203.95 203.95 40

PM 143.98 143.98 25

PM10 137.26 137.26 15
PA Review Memo 37-337A PSD 16 April 15, 2013

DRAFT

PM2.5 134.41 134.41 10

SO2 56.7 56.7 40

H2SO4 8.57 8.57 7

CO2(e) 3,693,661 3,693,661 100,000 new

75,000 existing

Pb 0.001 0.001 0.6

Fluorides 3

TRS Compounds 

including H2S

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 attainment (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 site

has potential emissions equal to or greater than 100 tpy for NOx 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 facility must demonstrate the NOx 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 127.210. Section 127.210 specifies that NOx emission offsets 

for the Transport Area shall be at a ratio of 1.15:1 for flue emissions and 1.15:1 for NOx fugitive 

emissions. Section 127.205 also requires the facility to perform an alternative site analysis which 

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 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 
PA Review Memo 37-337A PSD 17 April 15, 2013

DRAFT

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:

 GE 7FA: NOx - 342.3 tons and VOC - 234.6 tons

 Siemens F: NOx - 344.6 tons and VOC 181.0 tons

 Mitsubishi G: NOx - 287.7 tons and VOC 216.1 tons

 Siemens H: NOx - 398.1 tons and VOC 215.2 tons

NNSR Applicability Determination Step 1: Projected Emission Increases

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

NOx 346.09 346.09 40 NSR

VOC 203.95 203.95 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: Contemporaneous Emissions

Because Step 1 Emission Increase is greater than the significant threshold, an increase or 

decrease is contemporaneous 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 contemporaneous emissions.

NSR Pollutant Step 1 Project 

Emissions 

Increase (tpy)

Contemporaneous 

Emission 

Increases (tpy)

Net Emission 

Increase or 

Decrease (tpy)

Significant 

Emissions 

Threshold (tpy)

NOx 346.09 346.09 40

VOC 203.95 203.95 40

NNSR Applicability Summary

Based on the projected emission increase for NOx and VOC being greater than the significant 

emission threshold, NSR is triggered requiring a LAER analysis for each pollutant.

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 (NOx and VOC). BACT is 
PA Review Memo 37-337A PSD 18 April 15, 2013

DRAFT

defined in 25 PA Code 121 as an emissions limitation (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 determines 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 combination 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 operation, 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 considerations, 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 control 

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 reviewed 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 their complete analysis including the various control 

technologies for each pollutant analyzed, justifications as to what is technically feasible and what 

is technically 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 Control
PA Review Memo 37-337A PSD 19 April 15, 2013

DRAFT

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 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% O2 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 

shutdown 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 facility 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% O2. 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 shutdown periods.

CCU BACT and LAER for NOx:

The following table includes a list of potential control technologies.

Control Technology Combustion or Post Control

Wet Injection Combustion

DLN Combustor (dry low NOx) Combustion

Selective Catalytic Reduction (SCR) Post Control

SCONOX Post Control

Selective Non-Catalyst Reduction (SNCR) Post Control
PA Review Memo 37-337A PSD 20 April 15, 2013

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% O2 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 shutdown 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 (baghouse) 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 technically 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 Operation – Duct Burners off

 GE 7FA: 10.0 #/hr

 Siemens F: 10.0 #/hr

 Mitsubishi G: 12.0 #/hr
PA Review Memo 37-337A PSD 21 April 15, 2013

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.

CCU BACT for SOx 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) Post Control

 Wet Scrubber Post Control

 Spray Dryer Absorber (Dry 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 been determined to be technically infeasible 

because its efficiency decreases with lower inlet SOx 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 SOx and H2SO4 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 Technology

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 (significantly 

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 37-337A PSD 22 April 15, 2013

DRAFT

 GE 7FA: net plant heat rate of 6,700 btu/kWh, HHV @ ISO conditions at 59F ambient 

temperature with 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 # 

CO2/MW-hr (gross) on a 365-day rolling average which 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 0.036 

#/mmbtu.

Auxiliary Boiler BACT 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 NOx:

Based on the very low emissions, Ultra-low NOx 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 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 0.005 #/mmbtu.

Auxiliary Boiler BACT for SOx 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 SOx and 0.00048 #/mmbtu for H2SO4.

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 limitation of 3.5

g/kW-hr (0.0057 #/bhp-hr).
PA Review Memo 37-337A PSD 23 April 15, 2013

DRAFT

Emergency Engines (Generator and Fire Water Pump) BACT 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 0.09 #/mmbtu for emergency generator and 0.00247 #/bhp-hr for fire water pump.

Emergency Engines (Generator and Fire Water Pump) BACT and LAER for NOx:

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 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 SOx 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 emission limitation of 0.0018 #/mmbtu 

(0.0055 g/bhp-hr) for SOx for both the emergency generator and fire water pump and 0.00036 

#/mmbtu (0.0012 g/bhp-hr) for H2SO4 for both the emergency generator and fire water pump.

Cooling Tower BACT for PM/PM10/PM2.5:

The 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 BACT determination is drift 

rate of 0.0005%.

Fuel Storage Tanks BACT 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 source. The conservation 

vent valves include both pressure-relief valves (to keep vapors at a safe pressure) and vacuumrelief valves (to allow outside air to enter to avoid a significant vacuum). The LAER and BACT 

determination is use of conservation vent valves.

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. These sources meet the definition of a new source as defined by 

Title 25 PA Code Section 121.1. BAT is defined in 25 PA Code 121 as equipment, 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 37-337A PSD 24 April 15, 2013

DRAFT

CCU BAT for Ammonia:

Ammonia is used as a reagent in the SCR for NOx control. Ammonia slip is the ammonia that 

doesn’t react in the SCR and exhausts into the atmosphere. The higher the NOx control 

efficiency usually requires greater amounts of ammonia which results in higher levels of 

ammonia slip. For optimum SCR efficiency, NOx and ammonia slip concentrations are measured

continuously and adjusted by automated control systems. The BAT emission limit for ammonia 

slip is 5.0 ppmvd at 15% O2 on a rolling 3-hour average period. This limit includes all periods of 

operations.

CCU BAT for HAPs:

Formaldehyde is the largest HAP emission and will be used as a surrogate for all organic 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 Determinations

Pollutant Source Criteria Control Device selected Emission limit

CO CCU BACT GCP and oxidation 

catalyst

2.0 ppmvd corrected to 15% O2

based on a 3-hour averaging period

VOC CCU LAER GCP and oxidation 

catalyst

1.5 ppmvd corrected to 15% O2

NOx CCU LAER DLN Combustors and 

SCR

2.0 ppmvd corrected to 15% O2

based on a 3-hour averaging period

PM/PM10/PM2.5 CCU 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: 19.5 
PA Review Memo 37-337A PSD 25 April 15, 2013

DRAFT

#/hr

 Siemens H: 18.5 #/hr

SO2 CCU BACT pipeline quality natural 

gas

0.75 grains sulfur per 100 scf natural 

gas based on fuel monitoring

H2SO4 Mist CCU 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 # CO2/MWhr (gross) on a 

365-day rolling average

Ammonia Slip CCU BAT optimum SCR efficiency 5.0 ppmvd at 15% O2 on a rolling 

12-month average basis

HAPs CCU 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 BACT GCP 0.036 #/mmbtu

VOC Aux Boiler LAER GCP 0.0015 #/mmbtu

NOx Aux Boiler LAER ULNB 0.011 #/mmbtu

PM/PM10/PM2.5 Aux Boiler BACT GCP and pipeline quality 

natural gas

0.005 #/mmbtu

SO2 Aux Boiler BACT pipeline quality natural 

gas

0.0021 #/mmbtu

H2SO4 Mist Aux Boiler BACT 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

NOx Emergency 

Engines

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

0.15 g/bhp-hr (0.23 g/KW-hr)

SO2 Emergency 

Engines

BACT ULSD 0.0018 #/mmbtu (0.0055 g/bhp-hr) 

for both the emergency generator 

and fire water pump

H2SO4 Mist Emergency BACT ULSD 0.00036 #/mmbtu (0.0012 g/bhp-hr) 
PA Review Memo 37-337A PSD 26 April 15, 2013

DRAFT

Engines for both the emergency generator 

and fire water pump

PM/PM10/PM2.5 Cooling 

Tower

BACT High efficiency drift 

eliminators

drift rate of 0.0005%

VOC Fuel 

Storage 

Tanks

LAER conservation vent valves

New Source Performance Standards:

 The CCUs are subject to the requirements of 40 CFR 60 Subpart KKKK (Standards of 

Performance for Stationary Combustion Turbines). The facility has proposed 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 comply 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-Commercial-Institutional Steam Generating Units).

 The emergency generator and the emergency fire water pump are subject to 40 CFR 60 

Subpart IIII (Standards of Performance for Stationary Compression Ignition Internal 

Combustion Engines). The facility has proposed 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 subject to 40 CFR 63 Subpart JJJJJJ (National Emission

Standards for Hazardous 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 Subpart DDDDD (National Emission 

Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional 

Boilers and Process Heaters) because the facility HAP emissions are not major.

Acid Rain Regulations (Title IV Program):

The purpose of the program is to reduce emissions of SO2 and NOx from electric utilities, thereby 

reducing the occurrence of acid rain. The program is being implemented in two phases for both 

SO2 and NOx. The acid rain regulations do apply to the proposed facility because the plant uses

fossil fuel.
PA Review Memo 37-337A PSD 27 April 15, 2013

DRAFT

Clean Air Interstate Rule (CAIR):

The facility is subject to 40 CFR 96 with regards to the CAIR rule. This rule had 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 rule 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 SO2 and NOx requirements 

continue to apply independently of the Transport Rule provisions. For the reasons explained

above, Title IV SO2 allowances are not allowed to be used in the Transport Rule trading 

programs. Similarly, Transport Rule SO2 allowances are not usable in the Acid Rain Program.

Compliance Assurance Monitoring 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 (NOx & CO) that would be major precontrol 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.

Alternative Sites 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 proposed 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 37-337A PSD 28 April 15, 2013

DRAFT

The company looked at a site in northern Ohio (outside the Commonwealth) and two sites in 

Lawrence County. The conclusion 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 Department concurs with this analysis. Below is a summary of the analysis.

Alternative Sites HRE evaluated alternative sites and chose to locate the Facility at the proposed 

location in North Beaver Township in Pennsylvania. HRE identified a need for reliable electrical 

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) and 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 the 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 electrical 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 interconnect 

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. Applying 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 wetland 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 transmission 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 the 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/discharge availability and 

minimizes off-site environmental and community impact.
PA Review Memo 37-337A PSD 29 April 15, 2013

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 region. 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 

mitigation.

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.

NOx 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, 2013.)

The Hickory Run proposal 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 Implementation 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 

(NO2), particulate matter less than 2.5 micrometers (PM2.5), particulate matter less than 10 

micrometers (PM10), and sulfur dioxide (SO2). 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 is 

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 addressed 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 air pollution in violation of the National 

Ambient Air Quality Standards (NAAQS) for CO, NO2, PM2.5, PM-10 and SO2, and the PSD 

increment standards for NO2, PM2.5, PM10, and SO2. In addition, the analysis adequately 
PA Review Memo 37-337A PSD 30 April 15, 2013

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 demonstrates 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 potential 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 construction.

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 Pennsylvania 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 Modeling Section (S. Nolan)

New Castle District Office – thru L. Vogel
37-337A

Page 1

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 PROGRAM
37-337A

Page 2

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

Page 4

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

SECTION A. Table of Contents

Section G. Miscellaneous
37-337A

Page 5

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 EMISSIONS
37-337A

Page 6

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

PERMIT MAPS

PROC

101

PROC

102

PROC

103

PROC

104

STAC

S101

STAC

S102

STAC

Z01

STAC

Z01

FML

FML02

FML

FML02
37-337A

Page 7

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 #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

DEP Auth ID: 944870 PROPOSED

 #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

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 #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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 #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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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

[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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 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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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

Source ID: 031 Source Name: 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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
37-337A

Page 19

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
37-337A

Page 20

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 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 Requirements
37-337A

Page 21

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 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 Requirements
37-337A

Page 22

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

Page 23

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 009 [25 Pa. Code §127.12b]

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 page 

of 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 Requirements
37-337A

Page 24

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
37-337A

Page 25

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 26

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
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 [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 Requirements
37-337A

Page 28

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
37-337A

Page 30

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
37-337A

Page 31

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 018 [25 Pa. Code §139.101]

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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
37-337A

Page 33

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 34

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 35

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 027 [25 Pa. Code §127.12b]

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 Requirements
37-337A

Page 37

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 38

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 39

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 40

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 038 [25 Pa. Code §127.12b]

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 Requirements
37-337A

Page 41

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 42

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 43

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 44

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 45

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
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 # 051 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4420]

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 Requirements
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 # 052 [40 CFR Part 72 Regulations on Permits §40 CFR 72.30]

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. Natural 

gas 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 Requirements
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 # 053 [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.106]

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 Requirements
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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 Requirements
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 # 054 [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.206]

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 Requirements
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(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 Requirements
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 # 055 [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.306]

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 Requirements
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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 Requirements
37-337A

Page 54

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

(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 Requirements
37-337A

Page 55

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

Source ID: 032 Source Name: 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 Requirements
37-337A

Page 56

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
37-337A

Page 57

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
37-337A

Page 58

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 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 Requirements
37-337A

Page 59

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 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 Requirements
37-337A

Page 60

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

Page 61

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 009 [25 Pa. Code §127.12b]

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 page 

of 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 Requirements
37-337A

Page 62

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
37-337A

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 [25 Pa. Code §127.12b]

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 # 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 Requirements
37-337A

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DEP Auth ID: 944870 PROPOSED

 [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 Requirements
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 [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 Requirements
37-337A

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DEP Auth ID: 944870 PROPOSED

 [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 Requirements
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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 (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 Requirements
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HICKORY RUN ENERGY STATION

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 (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 Requirements
37-337A

Page 69

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 018 [25 Pa. Code §139.101]

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 Requirements
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 (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 Requirements
37-337A

Page 71

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 73

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 74

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 027 [25 Pa. Code §127.12b]

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 Requirements
37-337A

Page 75

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 76

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 77

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 78

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 038 [25 Pa. Code §127.12b]

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 Requirements
37-337A

Page 79

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 80

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 81

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

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 [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 Requirements
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 [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 Requirements
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 # 051 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4420]

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 Requirements
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 # 052 [40 CFR Part 72 Regulations on Permits §40 CFR 72.30]

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. Natural 

gas 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 Requirements
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 # 053 [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.106]

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 Requirements
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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 Requirements
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 # 054 [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.206]

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 Requirements
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(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 Requirements
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 # 055 [40 CFR Part 97 NOx Budget Trading Program and CAIR NOx and SO2 Trading Programs §40 CFR 97.306]

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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

(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 Requirements
37-337A

Page 93

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

Source ID: 033 Source Name: 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 Requirements
37-337A

Page 94

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 95

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

(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 Requirements
37-337A

Page 96

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 97

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 013 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.41c]

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 Requirements
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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
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HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

(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 Requirements
37-337A

Page 100

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

Page 101

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

Source ID: 101 Source Name: 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 Requirements
37-337A

Page 102

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 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 Requirements
37-337A

Page 103

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 009 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4212]

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 Requirements
37-337A

Page 104

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 105

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 106

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 in 

accordance 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 Requirements
37-337A

Page 107

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 108

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 109

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

Page 110

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

Page 111

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

Source ID: 102 Source Name: 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 Requirements
37-337A

Page 112

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

Page 113

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 114

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 115

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 116

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 117

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 118

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 # 020 [40 CFR Part 60 Standards of Performance for New Stationary Sources §40 CFR 60.4219]

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 Requirements
37-337A

Page 119

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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 Requirements
37-337A

Page 120

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

Source ID: 103 Source Name: 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 Requirements
37-337A

Page 121

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 122

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

Source ID: 104 Source Name: 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 Requirements
37-337A

Page 123

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

 [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 Requirements
37-337A

Page 124

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

SECTION E. Alternative Operation Requirements.

No Alternative Operations exist for this Plan Approval facility.
37-337A

Page 125

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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

TSP
37-337A

Page 126

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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

VOC
37-337A

Page 127

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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

TSP
37-337A

Page 128

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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

Page 129

HICKORY RUN ENERGY STATION

DEP Auth ID: 944870 PROPOSED

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. Environmental 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 (certified) design value in ppb. (Table 2-3: 1-hr SO2 Background) 

DEP Response 1: The 1-hour SO2 background for New Castle was calculated utilizing air 

monitoring data for the 2009-11 period. The DEP certified the most recent year’s (2011) air 

monitoring data by the EPA imposed 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 modeling analysis. Should the most recent 

version of AERMOD (12345) have been used in the modeling analysis? The modeling 

analysis also used versions of AERMET, AERMINUTE and AERSURFACE that were no longer 

the current versions that are posted on EPA’s SCRAM website. (Section 3.1: Model 

Selection) 

DEP Response 2: The plan approval application (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 versions of their respective models at the 

time of the plan approval application submittal. 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) spacing? 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 most of the maximum modeled concentrations 

occurred within two kilometers (where the receptor 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 adequate 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 concentration) should not be high enough to 

exceed the SIL for any pollutant. 

EPA Comment 4: The four (4) combustion turbine configurations modeled have stack 

heights that exceed GEP. HRE’s BPIP analysis shows that the physical height of the 

combustion turbine stacks exceeds the GEP height; 87.m versus BPIP analysis of 74.6 m. 

Did HRE adequately justify its combustions turbine heights in accordance with GEP? 

(Section 3.7: GEP Stack Height Analysis) 

DEP Response 4: In Section 3.7 of the revised Air Quality Dispersion Modeling Report 

submitted in February 2013, the documentation states “[f]or the combustion turbine stacks, 

GEP was calculated by BPIP‐PRIME as 87.6 m (288 ft). HRE has proposed a stack height of 
ATTACHMENT 

Response to Comments from U.S. Environmental 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 formula 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 rates for HRE should reflect 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 rates for the HRE project. Section D, Condition #037 of the 

final plan approval outlines the need 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 could have contributed 

to the maximum modeled concentrations in accordance with section 8.1.2(a) of Appendix 

W. (Section 3.8.3: Source Parameters 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 modeled 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 increments, this load) should be modeled. Where 

the source operates at substantially less than design capacity, and the changes in the 

stack parameters associated with the operating 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 causing 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 minimum to maximum, including periods of startup/shutdown. 

A total of four (4) operating modes were evaluated in the dispersion modeling analysis. The 

four (4) modeled scenarios were 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 startup 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 emission rate modeling scenarios (e.g., 75% load, 65% load, etc.) where 

stack parameters (flow rate and temperature) would not differ substantially from baseload 
ATTACHMENT 

Response to Comments from U.S. Environmental 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 least 25% lower would not be expected 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 NO2, SO2, PM-2.5 and PM-10, as well as 1-hour 

and 8-hour average CO, there is no variation 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 averaging period would not change 

the maximum concentrations already reported. This is also true for 24-hour average PM-10 

and 24-hour SO2 where differences in the maximum modeled concentrations between the 

100% and 50% loads were 0.02 micrograms per cubic meter (mg/m3

) or less. 

For the remaining pollutants and averaging periods, the maximum modeled concentrations 

are only a fraction of the SIL (e.g., 20% of the 1-hour SO2 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 SO2 SIL, 80% of the 1-hour NO2 SIL 

[unaveraged, and without applying the Ambient Ratio Method]) and, in the case of 1-hour 

NO2, the 100% and 50% load results are between 0.5 to 1 mg/m3

 less than the 100% load 

with duct firing. Based on the above, even considering 75% load or other intermediate load 

points, the maximum impacts would still be well below the SILs, and therefore the 

conclusions of the analysis would 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 have been chosen at regular 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 SO2 Class I increments. Did HRE perform a modeling 

analysis for the 3hr and annual Class I SO2 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 HRE, 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 lesser the impact. Any impact that would extend 

beyond 50 kilometers (for example, at the Otter Creek Class I area) would be expected to 

have an even lesser impact than the results at 50 kilometers. These results were also 

supported in the Class II analysis for each pollutant and each averaging time with respect to 

the appropriate Class I significance impact level (for 1-hour, 3-hour, 24-hour, and annual 

SO2, annual NO2, 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 the final model concentrations and conclusions? 

(Section 6: Class I Area Significance Analysis) 
ATTACHMENT 

Response to Comments from U.S. Environmental 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 analysis, 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.gov/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 emission contributions to secondary PM-2.5 formation were 

addressed in a response to comments document provided by PA DEP (February 19, 2013 

response from David Wilson). EPA issued draft guidance on how to address secondary PM2.5 formation on March 4, 2013. It would be useful if HRE would review 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 formation 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 background 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 approach, labeling “a hybrid quantitative and 

qualitative assessment” as one acceptable method of evaluating secondary formation. 

HRE’s analysis was conservative in nature since it assumed that maximum concentrations 

resulting from the project’s primary and secondary PM-2.5 emissions would be paired in 

time and space. Since HRE’s PM-2.5 evaluation 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 that EPA recently tightened the PM-2.5 NAAQS. An analysis 

could be expanded to include all monitors and any designated nonattainment areas with 

50+ km of the plant. It might also be important 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 Lawrence County, demonstrating that the project 

would not contribute to any attainment demonstration issues for this nonattainment area. 

Even adding secondary formation rates from HRE’s February 19, 2013 analysis, the 
ATTACHMENT 

Response to Comments from U.S. Environmental 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 recent United States Court of Appeals for the 

D.C. Circuit decision in Sierra Club v. EPA, No. 10-1413 (January 22, 2013)). Therefore, 

the project would not be deemed to cause or contribute to a violation 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.