NR0-079-13 

Uodietas 

CC) A/. °NWT:ALP-1 

'T,7R0 

t< CAIN REGIONA1 

13901 Crcm n Court. Woodbridge. 

03) .:3800 Fax 

David K. Pavlor 

Director 

April 30, 2013 

Mr. John A. Andrews 

Green Energy Partners / Stonewall, LLC 

39100 East Colonial Highway 

Hamilton, Virginia 20158 

Location: Loudoun County 

Registration Number: 73826 

Dear Mr. Andrews: 

Attached is a permit to construct and operate an electric power generation facility in 

accordance with the provisions of the Virginia State Air Pollution Control Board Regulations for 

the Control and Abatement of Air Pollution. 

In the course of evaluating the application and arriving at a final decision to approve the 

project, the Department of Environmental Quality (DEQ) deemed the application complete on 

February 26, 2013 and solicited written public comments by placing a newspaper advertisement 

in the Washington Post and The Loudoun Times Mirror on February 27, 2013. A public hearing 

was held on April 3, 2013. The required comment period, provided by 9 VAC 5-80-1775 F 

expired on April 19, 2013. 

This permit contains legally enforceable conditions. Failure to comply may result in a 

Notice of Violation and/or civil charges. Please read all permit conditions carefully. 

This permit approval to construct and operate shall not relieve Green Energy Partners / 

Stonewall, LLC of the responsibility to comply with all other local, state, and federal permit 

regulations. Please note that your proposed emergency generator (EG-1) and emergency fire 

water pump (EFP-1) may be affected facilities under 40 CFR 60, New Source Performance 

Standard (NSPS), Subpart 1111 and therefore subject to owner/operator requirements of the 

NSPS; and to 40 CFR 63, Maximum Achievable Control Technology, (MACT), Subpart ZZZZ, 

and therefore subject to owner/operator requirements of the MACT. In summary, the units 

could be required to comply with certain federal emission standards and operating limitations 

over their useful life. The DEQ advises you to review the appropriate NSPS and MACT to 

ensure compliance with applicable emission and operational limitations. As the owner/ operator 

you are also responsible for monitoring, notification, reporting and recordkeeping requirements 

of the NSPS and MACT. Notifications for these regulations and the results of performance tests 

required by 40 CFR 60, Subparts Dc, 1111, and KKKK shall to be sent to: 
Green Energy Partners I Stonewall, LLC 

Registration Number: 73826 

Page 2 

Associate Director 

Office of Air Enforcement (3AP20) 

U.S. Environmental Protection Agency 

Region III 

1650 Arch Street 

Philadelphia, PA 19103-2029 

The Board's Regulations as contained in Title 9 of the Virginia Administrative Code 5-

170-200 provide that you may request a formal hearing from this case decision by filing a 

petition with the Board within 30 days after this case decision notice was mailed or delivered to 

you. 9 VAC 5-170-200 provides that you may request direct consideration of the decision by the 

Board if the Director of the DEQ made the decision. Please consult the relevant regulations for 

additional requirements for such requests. 

As provided by Rule 2A:2 of the Supreme Court of Virginia, you have 30 days from the 

date you actually received this permit or the date on which it was mailed to you, whichever 

occurred first, within which to initiate an appeal of this decision by filing a Notice of Appeal with: 

David K. Paylor, Director 

Department of Environmental Quality 

P. O. Box 1105 

Richmond, VA 23218 

If this permit was delivered to you by mail, three days are added to the thirty-day period in which 

to file an appeal. Please refer to Part Two A of the Rules of the Supreme Court of Virginia for 

information on the required content of the Notice of Appeal and for additional requirements 

governing appeals from decisions of administrative agencies. 

If you have any questions concerning this permit, please contact the regional office at 

(703) 583-3800. 

Sincerely, 

Thomas A. Faha 

Regional Director 

TAF/JBL/TMV/73826PSD.docx 

Attachments: Permit 

Source Testing Report Format 

cc: Director, OAPP (electronic file submission) 

Manager, Data Analysis (electronic file submission) 

Chief, Office of Air Enforcement and Compliance Assistance, U.S. EPA, Region III 

(electronic file submission) 

Manager, Air Compliance 
NR0-079-13 

D;-.v ,.d i.. Pr.7,.,lor 

1-1- ). A. Faha 

Regional Director 

COMMON 

DEPARTAIE, 

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13901 Crown Court, 

(703)583-3800 Fax (. 

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583-3821 

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PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

NON-ATTAlls77,INT NEW SOURCE REVIEW PERMIT 

STATIONARY SOURCE PERMIT TO CONSTRUCT AND OPERATE 

This permit includes designated equipment subject to New Source Performance 

Standards (NSPS). 

In compliance with the Federal Clean Air Act and the Commonwealth of Virginia Regulations for 

the Control and Abatement of Air Pollution, 

Green Energy Partners / Stonewall, LLC 

P.O. Box 660 

Hamilton, Virginia 20158 

Registration Number: 73826 

Plant ID No. 51-107-01019 

is authorized to construct and operate: 

An electric power generation facility 

located at: 

20077 Gant Lane 

Leesburg, VA 20175 (Loudoun County) 

(approximately 4 miles south/south east of 

Leesburg & north of Dulles Toll Road (SR 267) 

39.058 N Latitude, 77.545' W Longitude 

in accordance with the conditions of this permit 

Approved on: April 30, 2013 

Thomas A. Faha 

Regional Director 

Permit consists of 37 pages 

Permit Conditions 1 to 83. 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 2 

INTRODUCTION 

This permit approval is based on the permit application dated July 19, 2012, with additional 

information submitted on August 16, 2012, and the modeling analysis and revised application 

which were both submitted on October 5, 2012, and November 15, 2012. Any changes in the 

permit application specifications, or any existing facilities which alter the impact of the facility on 

air quality, may require a permit. Failure to obtain such a permit prior to construction may result 

in enforcement action. In addition, this facility may be subject to additional applicable 

requirements not listed in this permit. 

Words or terms used in this permit shall have meanings as provided in 9 VAC 5-80-1110, 9 

VAC 5-80-2010, and 9 VAC 5-10-20 of the Commonwealth of Virginia State Air Pollution Control 

Board's (Board's) Regulations (Regulations) for the Control and Abatement of Air Pollution. The 

regulatory reference or authority for each condition is listed in parentheses () after each 

condition. 

Annual requirements to fulfill legal obligations to maintain current stationary source emissions 

data will necessitate a prompt response by the permittee to requests by the Department of 

Environmental Quality (DEQ) or the Board for information to include, as appropriate: process 

and production data; changes in control equipment; and operating schedules. Such requests 

for information from the DEQ will either be in writing or by personal contact. 

The availability of information submitted to the DEQ or the Board will be governed by applicable 

provisions of the Freedom of Information Act, §§ 2.2-3700 through 2.2-3714 of the Code of 

Virginia, § 10.1-1314 (addressing information provided to the Board) of the Code of Virginia, and 

9 VAC 5-170-60 of the Board's Regulations. Information provided to federal officials is subject 

to appropriate federal law and regulations governing confidentiality of such information. 

PROCESS REQUIREMENTS 

1. Equipment List 

Equipment to be constructed at this facility consists of: 

- Two (2) combined-cycle electric power generating units (Ref. No. CCT1 & CCT2) where 

each unit includes the following emission units: 

• One (1) General Electric natural gas-fired combustion turbine (CT) generator, Model 

GE 7FA.05, rated at 2,230 million Btu per hour heat input (Ref. No. CT1 & CT2) with 

inlet evaporative coolers (NSPS Subpart KKKK) and, 

• One (1) 650 million Btu per hour duct fired (Ref. No. DB1 & DB2) heat recovery 

steam generator (HRSG) that provides steam to a common steam turbine generator 

(NSPS Subpart KKKK). 

OR 

• One (1) Siemens natural gas-fired combustion turbine (CT) generator, Model SGT6-

5000F5, rated at 2,260 million Btu per hour heat input (Ref. No. CT1 & CT2) with 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 3 

inlet evaporative coolers (NSPS Subpart KKKK) and, 

• One (1) 450 million Btu per hour duct fired (Ref. No. DB1 & DB2) heat recovery 

steam generator (HRSG) that provides steam to a common steam turbine generator 

(NSPS Subpart KKKK). 

- One (1) natural gas-fired auxiliary boiler rated at 75 million Btu per hour heat input (Ref. 

No. AB1) (NSPS Subpart Dc). 

- One (1) natural gas-fired fuel gas heater, rated at 20 million Btu per hour heat input (Ref. 

No. FGH1) (NSPS Subpart Dc). 

- One (1) diesel-fired emergency generator, rated at 15.4 million Btu per hour heat input and 

1,500 kW electric power output (Ref. No. EG1) (NSPS Subpart 1111 and MACT Subpart 

ZZZZ). 

- One (1) diesel-fired emergency fire pump, rated at 2.54 million Btu per hour heat input and 

330 BHP mechanical power output (Ref. No. EFP1) (NSPS Subpart 1111 and MACT Subpart 

ZZZZ). 

- One (1) ten cell mechanical draft cooling tower rated at 187,400 gallons/minute of cooling 

water (Ref. No. MCT1- MCT10). 

- One (1) 12,000-gallon aqueous ammonia above ground storage tank (Ref. No. AST1). 

- One (1) 1,250-gallon diesel above ground storage tank for the emergency generator (Ref. 

No. AST2). 

- One (1) 400-gallon diesel above ground storage tank for the fire pump (Ref. No. AST3). 

- Circuit Breakers containing sulfur hexafluoride (SF6) (Ref. No. CB1) 

Specifications included in the permit under this condition are for informational purposes only 

and do not form enforceable terms or conditions of the permit. 

(9 VAC 5-80-1180 D 3, 9 VAC 5-80-2050, and 9 VAC 5-80-1605 A) 

2. Emission Controls: Combustion Turbines (Ref. No. CT1 & CT2) and Heat Recovery 

Steam Generators (HRSG) Duct Burners (DB1 & DB2) 

a. NOx 

Oxides of nitrogen (NOx) emissions from each combustion turbine (Ref. No. CT1 & 

CT2) and each heat recovery steam generator (HRSG) duct burner (Ref. No. DB1 & 

DB2) shall be controlled by dry low-NOxcombustion with selective catalytic reduction 

(SCR) control system with ammonia injection. The SCR system shall be provided 

with adequate access for inspection and shall be in operation when the combustion 

turbines and duct burners are operating, at all times except during start up and 

shutdown, as defined in Condition 15. 

b. CO and VOC 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 4 

Carbon monoxide (CO) and volatile organic compounds (VOC) emissions from each 

combustion turbine (Ref. No. CT1 & CT2) and each heat recovery steam generator 

(HRSG) duct burner (Ref. No. DB1 & DB2) shall be controlled by an oxidation 

catalyst and combustion practices as recommended by the equipment manufacturer. 

The oxidation catalyst shall be provided with adequate access for inspection and 

shall be in operation when the combustion turbines and duct burners are operating, 

at all times except during start up and shutdown, as defined in Condition 15. 

c. PM-10 and PM-2.5 

Particulate matter (PM-10 and PM-2.5) emissions from each combustion turbine 

(Ref. No. CT1 & CT2) and each heat recovery steam generator (HRSG) duct burner 

(Ref. No. DB1 & DB2) shall be controlled by combustion practices as recommended 

by the equipment manufacturer, and use of pipeline natural gas, as defined in 40 

CFR §72.2. 

d. Greenhouse Gases 

Greenhouse gas emissions (including carbon dioxide, methane, and nitrous oxide), 

as CO2e from the combined cycle gas turbine generators (CT1 & CT2) for both the 

GE 7FA.05 and Siemens SGT6-5000F5 and associated heat recovery steam 

generator (HRSG) duct burner (Ref. No. DB1 & DB2) shall be controlled by 

combustion practices as recommended by the equipment manufacturer, and use of 

pipeline natural gas, as defined in 40 CFR § 72.2. The combined cycle gas turbine 

generators and associated HRSG DBs shall operate at a Higher Heating Value 

(HHV) heat rate, at full load and corrected to ISO conditions, not to exceed 7,340 Btu 

HHV/kWh gross output without duct burning and 7,780 Btu HHV/kWh gross output 

with duct burning. Compliance with this limit shall be demonstrated as contained in 

Conditions 63 and 68. 

(9 VAC 5-80-1180, 9 VAC 5-50-260, 9 VAC 5-80-2050, and 9 VAC 5-80-1705 B) 

3. Emission Controls: Auxiliary Boiler ((Ref. No. AB1) and Fuel Gas Heater (Ref. o. 

FGH1) 

a. algA 

Oxides of nitrogen (NOx) emissions from the auxiliary boiler (Ref. No. AB1) and the fuel 

gas heater (Ref. No. FGH1) shall be controlled by ultra low-NOxburners with a NOx 

performance of 9 ppmvd at 3% 02for natural gas. The low NOx burners shall be 

installed and operated in accordance with manufacturer's specifications. 

b. CO and VOC 

Carbon monoxide (CO) and volatile organic compounds (VOC) emissions from the 

auxiliary boiler (Ref. No. AB1) and the fuel gas heater (Ref. No. FGH1) shall be 

controlled by good combustion practices, operator training, and proper emissions unit 

design, construction and maintenance to achieve a maximum CO emission rate of 50 

ppmvd at 3% 02. Boiler and heater operators shall be trained in the proper operation of 

all such equipment. (Refer to Condition 75 for training and record keeping 

requirements). 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 5 

c. Particulate Matter (PM-10 and PM-2.5) 

PM-10 and PM-2.5 emissions from the auxiliary boiler (AB1) and the fuel gas heater 

(FGH1) shall be controlled by good combustion practices and the use of pipeline-quality 

natural gas with a sulfur content of no greater than 0.1 grains per 100 standard cubic 

feet (scf), on a 12-month rolling average. 

d. Greenhouse Gases 

CO2e from the auxiliary boiler (AB1) and the fuel gas heater (FGH1) shall be controlled 

by the use of pipeline-quality natural gas and high efficiency design and operation. 

(9 VAC 5-80-1180, 9 VAC 5-50-260, 9 VAC 5-80-1705 B and 9 VAC 5-80-2050) 

4. Emission Controls: Emergency Generator (Ref. No. EG1) 

Oxides of nitrogen (N0x), carbon monoxide (CO), volatile organic compounds (VOC), and 

particulate matter (PM-10 and PM-2.5) emissions from the emergency generator (Ref. No. 

EG1) shall be controlled by combustion practices as recommended by the equipment 

manufacturer and the use of ultra low sulfur diesel fuel oil with a maximum sulfur content of 

15 ppm by weight. CO2e emissions shall be controlled by high efficiency design and 

operation. 

(9 VAC 5-80-1180, 9 VAC 5-80-1705 B and 9 VAC 5-50-260) 

5. Emission Controls: Emergency Fire Pump (Ref. No. EFP1) 

Oxides of nitrogen (N0x), carbon monoxide (CO), volatile organic compounds (VOC), and 

particulate matter (PM-10 and PM-2.5) emissions from the emergency fire pump (Ref. No. 

EFP1) shall be controlled by combustion practices as recommended by the equipment 

manufacturer and the use of ultra low sulfur diesel fuel oil with a maximum sulfur content of 

15 ppm by weight. CO2e emissions shall be controlled by high efficiency design and 

operation. 

(9 VAC 5-80-1180, 9 VAC 5-80-1705 B, 9 VAC 5-80-2050, and 9 VAC 5-50-260) 

6. Monitoring Devices: SCR — Each SCR system shall be equipped with devices to 

continuously measure and record ammonia feed rate and catalyst bed inlet gas 

temperature. Each monitoring device shall be installed, maintained, calibrated and operated 

in accordance with the device manufacturer's written requirements and recommendations. 

Each monitoring device shall be provided with adequate access for inspection, and shall be 

in operation when the SCR system is operating. 

(9 VAC 5-80-1180, 9 VAC 5-50-20 C, 9 VAC 5-50-260, 9 VAC 5-80-2050, and 9 VAC 5-80-

1705 B) 

7. Monitoring Devices: Oxidation Catalyst — Each oxidation catalyst shall be equipped with 

a device to continuously measure and record temperature at the catalyst bed inlet and 

outlet. Each monitoring device shall be installed, maintained, calibrated and operated in 

accordance with the device manufacturer's written requirements and recommendations. 

Each monitoring device shall be provided with adequate access for inspection and shall be 

in operation when the oxidation catalyst is operating. 

(9 VAC 5-80-1180, 9 VAC 5-50-20 C, 9 VAC 5-50-260, 9 VAC 5-80-2050, and 9 VAC 5-80-

1705 B) 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 6 

8. Monitoring Device Observation and Documentation: SCR — The devices used to 

continuously measure ammonia feed rate and SCR catalyst bed inlet gas temperature shall 

be observed by the permittee with a frequency sufficient to ensure good performance of the 

SCR system, but not less than once per day of operation. 

(9 VAC 5-50-50 H) 

9. Monitoring Device Observation and Documentation: Oxidation Catalyst - The devices 

used to continuously measure the catalyst bed inlet and outlet gas temperatures for each 

oxidation catalyst shall be observed by the permittee with a frequency sufficient to ensure 

good performance of the oxidation catalyst, but not less than once per day of operation. 

(9 VAC 5-50-50 H) 

10. Monitoring Device: Hour Meter - The emergency generator (Ref. No. EG1) and the 

emergency fire pump (Ref. No. EFP-1) shall be equipped with a non-resettable hour 

metering device to monitor the operating hours of each unit. Each monitoring device shall 

be observed by the permittee with a frequency of not less than once each day that the 

generator/fire pump is in operation. The permittee shall keep a log of these observations. 

Each monitoring device shall be installed, maintained, calibrated (as appropriate) and 

operated in accordance with approved procedures which shall include, as a minimum, the 

manufacturer's written requirements or recommendations. Each monitoring device shall be 

provided with adequate access for inspection and shall be in operation when the 

generator/fire pump is operating. 

(9 VAC 5-80-1180 D and 40 CFR 60.4209) 

OPERATIONAL LIMITATIONS 

11. Fuel: Natural Gas Fired Units — The approved fuel for each combustion turbine (Ref. No. 

CT1 & CT2), each heat recovery steam generator (HRSG) duct burner (Ref. No. DB1 & 

DB2), the auxiliary boiler (Ref. No. AB1), and the fuel gas heater (Ref. No. FGH1) is pipeline 

natural gas as defined in 40 CFR § 72.2, with a maximum sulfur content of 0.1 grains or less 

of total sulfur per 100 standard cubic feet. A standard cubic foot of gas is defined as a cubic 

foot of gas at standard conditions (68°F and 29.92 in Hg) as specified in 40 CFR § 72.2. No 

change in fuel type may occur without DEQ approval. A change in the fuel may require a 

permit to modify and operate. 

(9 VAC 5-50-410, 9 VAC 5-80-1705, 9 VAC 5-80-1715, 9 VAC 5-50-260, 9 VAC 5-80-2050, 

and 40 CFR 60.4330(a)(2)) 

12. Fuel Specification: Diesel Fired Units - The approved fuel for the emergency engine 

generator (Ref. No. EG1) and the emergency fire pump (Ref. No. EFP1) shall be diesel fuel 

that meets the specifications below: 

a. Does not exceed the American Society for Testing and Materials (ASTM) specifications, 

D975, for grade ultra low sulfur 2-D, or grade 2-D S14, or 

b. Has a maximum sulfur content not to exceed 0.0015% by weight (15 ppm), and either a 

minimum cetane number of forty or maximum aromatic content of thirty-five percent by 

volume. 

(9 VAC 5-80-1180, 9 VAC 5-80-2050, and 9 VAC 5-50-260) 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 7 

13. Fuel Certification - The permittee must use the sources listed in Condition 13.a to 

demonstrate compliance with Condition 11 and the sources of information in Condition 13.b 

to demonstrate compliance with Condition 12: 

a. The fuel characteristic in a current, valid purchase contract, tariff sheet or transportation 

contract for the natural gas, specifying that the maximum total sulfur content for the 

natural gas is 0.1 grains of sulfur or less per 100 standard cubic feet and / or 

representative fuel sampling data, which shows that the sulfur content of the fuels does 

not exceed 2.61 x 0-4lb S02/MMBtu heat input. 

If the permittee elects not to demonstrate the sulfur content using the above option, the 

permittee may: 

i. Determine and record the total sulfur content of the natural gas once per unit 

operating day; or, 

ii. Develop custom schedules for determination of the total sulfur content of the natural 

gas, based on the design and operation of the affected facility and the characteristics 

of the fuel supply. Except as provided in 40 CRF 60.4370(c)(1) and (c)(2), custom 

schedules shall be substantiated with data and shall receive prior EPA approval. 

b. The permittee shall obtain a fuel certification from the fuel supplier with each shipment of 

diesel fuel oil. Each fuel supplier certificate shall contain the following: 

i. The name of the fuel supplier, and 

ii. The date on which the diesel fuel oil was received, and 

iii. The quantity of diesel fuel oil delivered in the shipment, and 

iv. Either a statement that the diesel fuel oil conforms to the requirements of Condition 

12 — Fuel Specification, or 

v. Alternately, the permittee shall obtain approval from the Regional Air Compliance 

Manager of the DEQ's Northern Regional Office (NRO) at the address listed in 

Condition 57 if other documentation will be used to certify the diesel fuel oil type. 

Fuel sampling and analysis, independent of that used for certification, as may be periodically 

required or conducted by the DEQ, may be used to determine compliance with the fuel 

specifications stipulated in Condition 12. Exceedance of these specifications may be 

considered credible evidence of the exceedance of emission limits. 

(9 VAC 5-80-1180, 9 VAC 5-50-410, 9 VAC 5-80-2050, 9 VAC 170-160, 40 CFR 60.4365(a), 

40 CFR 60.4370(b), and 40 CFR 60.4370(c)) 

14. Fuel Throughput — The two GE 7FA.05 combustion turbines (Ref. No. CT1 & CT2) and two 

650 MMBtu/hr duct burners (Ref. No. DB1 & DB2) shall not consume more than 4.01 x 1010 

cubic feet of natural gas per year, calculated monthly as the sum of each consecutive 12-

month period. The two Siemens SGT6-5000F5 combustion turbines (Ref. No. CT1 & CT2) 

and two 450 MMBtu/hr duct burners (Ref. No. DB1 & DB2) shall not consume more than 

4.00 x 1010cubic feet of natural gas per year, calculated monthly as the sum of each 

consecutive 12-month period. Compliance for the consecutive 12-month period shall be 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 8 

demonstrated monthly by adding the total for the most recently completed calendar month to 

the individual monthly totals for the preceding 11 months. 

(9 VAC 5-80-1180 and 9 VAC 5-80-2050) 

15. Startup / Shutdown — The short-term emission limits contained in Condition 33 apply at all 

times except during periods of startup and shutdown. 

a. Startup and shutdown periods are defined as the average time per turbine for the two 

turbine plant to complete startup and shutdown as follows: 

i. Cold Startup — refers to restarts made 72 hours or more after shutdown. 

Exclusion from the short-term emission limits for cold startup periods shall not 

exceed 226 minutes per occurrence. 

ii. Warm Startup — refers to restarts made more than 4, but less than 72 hours after 

shutdown. Exclusion from the short-term emission limits for warm startup 

periods shall not exceed 128 minutes per occurrence. 

iii. Hot Startup — refers to restarts made 4 hours or less after shutdown. Exclusion 

from the short-term emissions limits for hot startup periods shall not exceed 38 

minutes per occurrence. 

iv. Shutdown — refers to the period between the time the turbine load drops below 

50 percent operating level and the fuel supply to the turbines is cut. Exclusion 

from the short-term emissions limits for shut down shall not exceed 14 minutes 

per occurrence. 

b. The permittee shall operate the Continuous Emission Monitoring Systems (CEMS) 

during the periods of startup and shutdown. 

c. The permittee shall record the date, time, and duration of each startup and shutdown 

period. The records must include calculations of NOx and CO emissions during each 

event based on the CEMS data. These records must be kept for five years following the 

date of such event. 

d. During startup, the combustion turbine SCR system, including ammonia injection, shall 

be operated in a manner to minimize emissions, as technologically feasible, and not later 

than when the load reaches 50% of unit output. 

(9 VAC 5-50-260, 9 VAC 5-80-1715, 9 VAC 5-80-1180, and Table 1 to NSPS KKKK of part 

60) 

16. Operational Limit — Duct Burners 

The duct burners (Ref. No. DB1 & DB2) shall not operate independently of each combustion 

turbine (Ref. No. CT1 & CT2). 

(9 VAC 5-80-1180, 9 VAC 5-80-2050, 9 VAC 5-40-410, and 40 CFR 60.4320) 

17. Operational Limit — Duct Burners 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 9 

Each heat recovery steam generator (HRSG) duct burner (Ref. No. DB1 & DB2) shall not 

operate more than 1,400 hours per year, calculated monthly as the sum of each consecutive 

twelve month period. 

(9 VAC 5-50-260, 9 VAC 5-80-1180, and 9 VAC 5-80-2050) 

18. Requirements by Reference — Except where this permit is more restrictive than the 

applicable requirement, the combustion turbines (Ref. No. CT1 & CT2) and the heat 

recovery steam generator (HRSG) shall be operated in compliance with the requirements of 

40 CFR 60, Subpart KKKK. 

(9 VAC 5-50-400, 9 VAC 5-50-410, 9 VAC 5-80-1180, 9 VAC 5-80-2050, and 40 CFR 60, 

Subpart KKKK) 

19. CAIR (Clean Air Interstate Rule) NOxAnnual Trading Requirements —The combinedcycle power generating units (Ref. No. CCT1 & CCT2) listed in Condition 1 meet the 

definition of a CAIR NOxUnit and are subject to the CAIR NOxemission limits under 9 VAC 

5-140-1040 or for opt in sources under 9 VAC 5-140-1800. As required by 9 VAC 5-140-

1200 A, for each CAIR NOxsource required to have a federally enforceable permit, such 

permit will include the CAIR permit to be administered by the permitting authority. The 

following requirements pertain to the CAIR NOxAnnual Trading program: 

a. Prior to commencement of operation, the permittee shall obtain a CAIR permit, as 

required by 9 VAC 5-140-1200 A, to be administered by the Virginia Department of 

Environmental Quality (DEQ) under the authority of 9 VAC 5-80-360 et seq., and 9 VAC 

5-140-1010 et seq. 

b. As commencement of operation of the permitted facility (the first day a combustion 

turbine burns fuel), the permittee shall comply with the requirements of the CAIR NOx 

emission limitations under 9 VAC 5-140-1040. 

c. Each combined-cycle power generating unit (combustion turbine and heat recovery 

steam generator) in Condition 1 meets the applicability requirements as provided in 9 

VAC 5-140-1040 A.1 and A.2. The permittee shall meet the monitoring, emission 

calculation, recordkeeping, reporting, and testing requirements as applicable under 9 

VAC 5 Chapter 140, Part II, Article 8. 

(9 VAC 5-80-1180, 9 VAC 5-80-2050, and 9 VAC 5 Chapter 140, Part II, Article 8) 

20. Fuel Throughput — Auxiliary Boiler (AB1) 

The auxiliary boiler (Ref. No. AB1) shall not consume more than 6.44 x 108cubic feet of 

natural gas per year, calculated monthly as the sum of each consecutive 12-month period. 

Compliance for the consecutive 12-month period shall be demonstrated monthly by adding 

the total for the most recently completed calendar month to the individual monthly totals for 

the preceding 11 months. 

(9 VAC 5-80-1180 and 9 VAC 5-80-2050) 

21. Fuel Throughput — Fuel Gas Heater (Ref. No. FGH1) 

The fuel gas heater (Ref. No. FGH1) shall not consume more than 1.72 x 108cubic feet of 

natural gas per year, calculated monthly as the sum of each consecutive 12-month period. 

Compliance for the consecutive 12-month period shall be demonstrated monthly by adding 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 10 

the total for the most recently completed calendar month to the individual monthly totals for 

the preceding 11 months. 

(9 VAC 5-80-1180 and 9 VAC 5-80-2050) 

22. Requirements by Reference — Except where this permit is more restrictive than the 

applicable requirement, the auxiliary boiler (Ref. No. AB1) and the fuel gas heater (Ref. No. 

FGH1) shall be operated in compliance with the requirements of 40 CFR 60, Subpart Dc. 

(9 VAC 5-50-400, 9 VAC 5-50-410, 9 VAC 5-80-1180, 9 VAC 5-80-2050, and 40 CFR 60, 

Subpart Dc) 

23. Emergency Generator and Emergency Fire Pump Operation — The operation of the 

emergency generator (Ref. No. EG1) and the emergency fire pump (Ref. No. EFP1) are 

limited to emergency situations. Emergency situations include emergency generator use 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 and emergency engine use to pump water 

in case of fire or flood, etc. The emergency generator (Ref. No. EG1) and the emergency 

fire pump (Ref. No. EFP1) may be operated for the purpose of maintenance checks and 

readiness testing, provided that the tests are recommended by the 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 for each unit. 

(9 VAC 5-80-1180, 40 CFR 60.4211(e), and 40 CFR 60.4219) 

24. Operating Hours: Emergency Generator — The emergency generator (Ref. No. EG1) shall 

not operate more than 500 hours per year, calculated monthly as the sum of each 

consecutive 12-month period. Compliance for the consecutive 12-month period shall be 

demonstrated monthly by adding the total for the most recently completed calendar month to 

the individual monthly totals for the preceding 11 months. 

(9 VAC 5-80-1180 and 9 VAC 5-80-2050) 

25. Operating Hours: Emergency Fire Pump — The emergency fire pump (Ref. No. EFP1) 

shall not operate more than 500 hours per year, calculated monthly as the sum of each 

consecutive 12-month period. Compliance for the consecutive 12-month period shall be 

demonstrated monthly by adding the total for the most recently completed calendar month to 

the individual monthly totals for the preceding 11 months. 

(9 VAC 5-80-1180) 

26. Maintenance and Operation — The permittee must maintain and operate the emergency 

generator (Ref. No. EG1) and the emergency fire pump (Ref. No. EFP1) in accordance with 

the manufacturer's written requirements. In addition, the permittee may only change those 

settings that are allowed by the equipment manufacturer's written requirements. 

(9 VAC 5-80-1180, 9 VAC 5-50-260, 40 CFR 60.4206, and 40 CFR 60.4211) 

27. Emission Controls: Cooling Tower — Particulate matter emissions from the ten cell 

mechanical draft cooling tower (Ref. No. MCT1 — MCT10) shall be controlled to a drift rate of 

0.0005 percent of the circulating water flow and a total dissolved solids content of the 

cooling water of no more than 5,000 ppm total dissolved solids. 

(9 VAC 5-80-1705 B, 9 VAC 5-50-280 and 9 VAC 5 -80-2050) 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 11 

28. Sampling & Monitoring — Ten Cell Mechanical Draft Cooling Tower (Ref. No. MCT1-

MCT10) 

The facility shall sample the water used by the ten cell mechanical draft cooling tower (Ref. 

No. MCT1 — MCT10) for total dissolved solids (TDS) at a frequency of not less than once 

per month to ensure compliance with the TDS in Condition 27. If the TDS sampling 

demonstrates compliance for three years of cooling tower operation, then the permittee can 

request a reduction in the sampling frequency. Samples taken as required by this permit 

shall be analyzed in accordance with 1 VAC 30-45, Certification for Noncommercial 

Laboratories, or 1 VAC 30-46, Accreditation for Commercial Environmental Laboratories. 

(9 VAC 5-50-260, 9 VAC 5-170-160, 9 VAC 5-80- 2050, and 9 VAC 5-80-2080) 

29. Emission Controls: Electrical Breakers — Greenhouse gas emissions (including SF6) 

from the electrical circuit breakers (Ref No. CB1) shall be controlled by an enclosed circuit 

breaker, with a maximum annual leakage rate of 1.0 percent, and a low pressure detection 

system (with alarm). The low pressure detection system shall be in operation when the 

circuit breakers are in use. Emissions shall be monitored in accordance with the 

requirements of the Mandatory Greenhouse Gas Reporting Rule for Electrical Transmission 

and Distribution Equipment Use (40 CFR Part 98, Subpart DD). 

(9 VAC 5-80-1705 B, 9 VAC 5-50-280) 

30. Re-tuning — Excess emissions resulting from the retuning of the combustion turbines (Ref. 

No. CT1 & CT2) shall be permitted provided that: 

a. Best operational practices are adhered to and the duration of excess emissions shall be 

minimized but in no case exceed twelve hours per combustion turbine (Ref. No. CT1 & 

CT2) re-tuning event in any 24 hour period. The operator may request additional hours 

from the DEQ as long as the notification is done as soon as the source is aware that the 

re-tuning event will exceed twelve hours. 

b. During each combustion turbine (Ref. No. CT1 & CT2) retuning event, NOxemission 

concentrations, based on an hourly average, shall not exceed the NOxstandards of the 

New Source Performance Standards (NSPS) 40 CFR 60 Subpart KKKK — Standards of 

Performance for Stationary Combustion Turbines (60.4300 et seq.). 

c. The permittee shall notify the Regional Air Compliance Manager of the DEQ's NRO at 

the address listed in Condition 57 no less than 24 hours prior to each turbine's retuning 

event. The notification shall include, but is not limited to: 

i. Identification of the specific turbine to be retuned. 

ii. Reason for the retuning event. 

iii. Measures to be taken to minimize the length of the retuning event. 

d. The permittee shall furnish a written report to the Regional Air Compliance Manager of 

the DEQ's NRO of all the pertinent facts concerning the retuning event, as soon as 

practicable, but not later than 14 business days after the retuning event. The notification 

shall include, but is not limited to: 

Identification of the turbine that was retuned. 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 12 

The magnitude of excess emissions per turbine, any conversion factors used in 

the calculation of excess emissions, and the date and time of commencement 

and completion of each period of excess emissions. 

e. NOxemissions during each turbine's retuning shall be recorded and included in the 

associated quarterly reports and the total annual emissions as required by this permit. 

f. The retuning event for each turbine shall be identified on the Data Acquisition Report. 

(9 VAC 5-20-180, 9 VAC 5-50-50, and 9 VAC 5-50-410) 

31. Pollution Prevention: Ammonia — Compliance with the ammonia emission limit in 

Condition 33 shall be determined based on a one-hour block average. At least three 

months prior to startup, the permittee shall submit a plan for approval for monitoring the 

ammonia emissions and demonstrating compliance with the ammonia emission limit from 

each SCR system to the Regional Air Compliance Manager of the DEQ's NRO at the 

address listed in Condition 57. Implementation of the plan shall commence upon startup of 

the facility. The permittee shall demonstrate compliance with the ammonia emission limit at 

least 95 percent of the time that the SCR is operating. Compliance with the 95 percent time 

percentage requirement shall be calculated daily and based on a 30-day rolling period. 

Alternatively, if on a given day less than 100 hours of operation has occurred in the prior 

thirty days, compliance with the 95 percent limits may be based on the most recent 100 

hours of SCR operation. 

(9 VAC 5-80-1180, 9 VAC 170-160, and the Virginia Pollution Prevention Act Subsection 

10.1-1425.11) 

32. Pollution Prevention: SCR Replacement — At least two years prior to a planned 

replacement of the entire SCR system, the permittee shall conduct a study of technically 

and economically feasible and commercially available NOxcontrol devices. The study shall 

include the cost effectiveness for each control device evaluated, including SCR. The results 

of the evaluation shall be submitted to the Regional Air Permitting Manager of the DEQ's 

NRO at the address listed in Condition 57 prior to ordering the new system. In the event the 

permittee wants to replace the SCR with an alternative control device, such a replacement 

may not require a permit to modify and operate, providing the new system provides an equal 

or better level of control. 

(9 VAC 5-80-1180, 9 VAC 5-80-2050, 9 VAC 5-170-160, and the Virginia Pollution 

Prevention Act Subsection 10.1-1425.11) 

EMISSION LIMITS 

33. Emission Limits - Combined-Cycle Power Generation Units (Ref. No. CCT1 & CCT2) 

Short-Term Emission Limits - Emissions from the operation of each combined-cycle 

power generating unit (Ref. No. CCT1 & CCT2) shall not exceed the limits specified below: 

GE 7FA.05 

Air Pollutant Short-Term Emission Limits 

Oxides of Nitrogen (as ■ 2.0 ppmvd at 15% 02W & w/o DB firing 

NO2) ■ 21.0 lb/hr with HRSG duct burner firing 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

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■ 16.2 lb/hr without HRSG duct burner firing 

Carbon Monoxide 

(CO) 

■ 

■ 

■ 

2.0 ppmvd at 15% 02with & w/o duct burning. 

12.7 lb/hr with HRSG duct burner firing 

9.9 lb/hr without HRSG duct burner firing 

Volatile Organic 

Compounds (VOCs) 

(as methane) 

■ 

■ 

■ 

■ 

2.4 ppmwv at 15% 02with duct burner firing 

1.0 ppmwv at 15% 02without duct burner firing 

7.3 lb/hr with HRSG duct burner firing 

2.8 lb/hr without HRSG duct burner firing 

PM-10 (Includes 

filterable and 

condensibles) 

■ 

■ 

■ 

3.34 x 10-3lb/MMBtu at full load 

16.2 lb/hr with HRSG duct burner firing 

9.6 lb/hr without HRSG duct burner firing 

PM-2.5 (Includes 

filterable and 

condensibles) 

■ 

■ 

■ 

3.34 x 10-3lb/MMBtu at full load 

16.2 lb/hr with HRSG duct burner firing 

9.6 lb/hr without HRSG duct burner firing 

Sulfur Dioxide (SO2) ■ 

■ 

■ 

2.61 x 10-4lb/MMBtu 

0.75 lb/hr with HRSG duct burner firing 

0.58 lb/hr without HRSG duct burner firing 

Ammonia (NH3) ■ 5.0 ppmvd at 15% 02 

Siemens SGT6-5000F5 

Air Pollutant Short-Term Emission Limits 

Oxides of Nitrogen (as 

NO2) 

• 

■ 

■ 

2.0 ppmvd at 15% 02 

20.4 lb/hr with HRSG duct burner firing 

17.1 lb/hr without HRSG duct burner firing 

Carbon Monoxide ■ 2.0 ppmvd at 15% 02with & w/o duct burning. 

(CO) ■ 12.5 lb/hr with HRSG duct burner firing 

■ 10.4 lb/hr without HRSG duct burner firing 

Volatile Organic ■ 1.5 ppmwv at 15% 02with duct burner firing 

Compounds (VOCs) ■ 1.0 ppmwv at 15% 02without duct burner firing 

(as methane) ■ 5.7 lb/hr with HRSG duct burner firing 

■ 3.0 lb/hr without HRSG duct burner firing 

PM-10 (Includes ■ 3.74 x 10-3lb/MMBtu at full load 

filterable and ■ 14.5 lb/hr with HRSG duct burner firing 

condensables) ■ 10.1 lb/hr without HRSG duct burner firing 

PM-2.5 (Includes ■ 3.74 x 10-3lb/MMBtu at full load 

filterable and ■ 14.5 lb/hr with HRSG duct burner firing 

condensables) ■ 10.1 lb/hr without HRSG duct burner firing 

Sulfur Dioxide (SO2) ■ 2.61 x 10-4lb/MMBtu 

■ 0.70 lb/hr with HRSG duct burner firing 

■ 0.58 lb/hr without HRSG duct burner firing 

Ammonia (NH3) ■ 5.0 ppmvd at 15% 02 

Where: 

ppmvd = parts per million by volume on a dry gas basis, corrected to 15 percent 02. 

ppmwv = parts per million by volume on a wet gas basis, corrected to 15 percent 02. 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 14 

Short-term emission limits for VOC, PM-10 and PM-2.5 represent averages for a three-hour 

sampling period. Short-term emission limits for nitrogen oxides and carbon monoxide shall 

be calculated as one-hour averages. 

Unless otherwise specified, limits apply at all times except during startup, shutdown, and 

malfunction. Periods considered startup and shutdown are defined in Condition 15 of this 

permit. 

Compliance with the SO2limit may be determined as stated in Condition 11. 

This permit may be changed in accordance with 9 VAC 5-80-1925 and 9 VAC 5-80-2000, to 

reduce the emission limits based on results from stack testing as required in Conditions 56, 

58 and 59 of this permit. 

(9 VAC 5-80-1180, 9 VAC 5-50-260, 9 VAC 5-50-410, 9 VAC 5-80-2050, 9 VAC 5-80-1705, 

40 CFR 60.4320, 40 CFR 60.4330 and the Virginia Pollution Prevention Act Subsection 

10.1-1425.11) 

34. Emission Limits: Combined-Cycle Power Generating Units (Ref. No. CCT1 & CCT2) - 

CO2e emissions from the combined cycle gas turbine generators and associated HRSGs 

shall not exceed 903 lb/MWh (gross) calculated monthly on a 12-operating month annual 

average basis. Compliance shall be determined each month by summing the CO2e 

emissions for all hours in which power is being generated to the grid during the previous 12 

months and dividing that value by the sum of the gross electrical energy output over that 

same period. 

(9 VAC 5-50-280, 9 VAC 5-80-1705, and 9 VAC 5-80-1715) 

35. Annual Process Emission Limits — Total emissions from the combined operation of the 

two combined-cycle power generating units (Ref. No. CCT1 & CCT2), including duct 

burners, shall not exceed the limits specified below: 

GE 7FA.05 

Pollutant Annual Emissions 

(tons per year) 

Oxides of Nitrogen (as NO2) 148.6 

Carbon Monoxide (CO) 188.8 

Volatile Organic Compounds 

(VOC) 31.0 

PM-10 (Includes filterable and 

condensables) 93.7 

PM-2.5 (Includes filterable and 

condensables) 93.7 

Sulfur Dioxide (SO2) 5.3 

Greenhouse Gases (GHG) 

Carbon Dioxide Equivalent 

(CO2e) 

2,418,273 

Or: 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 15 

Siemens SGT6-5000F5 

Air Pollutant Annual Emissions 

(tons per year) 

Oxides of Nitrogen (as NO2) 154.45 

Carbon Monoxide (CO) 124.8 

Volatile Organic Compounds 

(VOC) 45.26 

PM-10 (Includes filterable and 

condensables) 94.68 

PM-2.5 (Includes filterable and 

condensables) 94.68 

Sulfur Dioxide (SO2) 5.26 

Greenhouse Gases (GHG) 

Carbon Dioxide Equivalent 

(CO2e) 

2,414,296 

Annual emission limits are derived from the estimated overall emission contribution from 

operating limits, including periods of startup and shutdown. Exceedance of the operating 

limits may be considered credible evidence of the exceedance of emission limits. 

Compliance with these limits may be determined as stated in Conditions 11, 14, 17, 47, and 

70. Annual emissions shall be calculated as the sum of each consecutive 12-month period. 

This permit may be changed in accordance with 9 VAC 5-80-1925, to reduce the emission 

limit based on results from stack testing as required in Conditions 56, 58 and 59 of this 

permit. 

(9 VAC 5-80-1180, 9 VAC 5-50-260, 9 VAC 5-50-410, 9 VAC 5-80-2050, 9 VAC 5-80-1705, 

and 9 VAC 5-80-1715) 

36. Visible Emission Limit — Visible emissions from each combined-cycle power generating 

unit (Ref. No. CCT1 & CCT2) stack shall not exceed 10 percent opacity, except during one 

six-minute period in any one hour in which visible emissions shall not exceed 20 percent 

opacity as determined by EPA Method 9 (Reference 40 CFR 60, Appendix A). This 

condition applies at all times except during start up, shutdown (as defined in Condition 15), 

and malfunction. 

(9 VAC 5-50-20, 9 VAC 5-50-260, and 9 VAC 5-80-1705) 

37. Process Emission Limits — Auxiliary Boiler (Ref. No. AB1) 

Emissions from the auxiliary boiler (Ref. No. AB1) shall not exceed the limits specified 

below: 

Pollutant lb/hr tons/year 

Oxides of Nitrogen (as NO2) 0.83 3.61 

Carbon Monoxide (CO) 2.78 12.15 

Volatile Organic Compounds 

(VOC) 0.15 0.66 

PM-10 (Includes filterable and 

condensibles) 0.15 0.66 
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Registration Number: 73826 

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PM-2.5 (Includes filterable and 

condensibles) 0.15 0.66 

Greenhouse Gases (GHG) 

Carbon Dioxide Equivalent (CO2e) 8873 38,856 

These emissions are derived from the estimated overall emission contribution from 

operating limits. Exceedance of the operating limits shall be considered credible evidence 

of the exceedance of emission limits. 

(9 VAC 5-50-260 and 9 VAC 5-80-1180) 

38. Process Emission Limits — Fuel Gas Heater (Ref. No. FGH1) 

Emissions from the fuel gas heater (Ref. No. FGH1) shall not exceed the limits specified 

below: 

Pollutant lb/hr tons/year 

Oxides of Nitrogen (as NO2) 0.22 0.96 

Carbon Monoxide (CO) 0.74 3.24 

Greenhouse Gases (GHG) 

Carbon Dioxide Equivalent (CO2e) 2,365 10,362 

These emissions are derived from the estimated overall emission contribution from the 

operating limits. Exceedance of the operating limits shall be considered credible evidence 

of the exceedance of emission limits. 

(9 VAC 5-50-260 and 9 VAC 5-80-1180) 

39. Visible Emission Limit — Visible emissions from both the auxiliary boiler (Ref. No. AB1) 

and the fuel gas heater (Ref. No. FGH1) stacks shall not exceed 10 percent opacity as 

determined by EPA Method 9 (Reference 40 CFR 60, Appendix A). 

(9 VAC 5-80-1180) 

40. Process Emission Limits — Emergency Generator (Ref. No. EG1) 

Emissions from the emergency generator (Ref. No. EG1) shall not exceed the limits 

specified below: 

Pollutant lb/hr tons/year 

Oxides of Nitrogen (as NO2) 21.16 5.29 

Carbon Monoxide (CO) 11.57 2.89 

Volatile Organic Compounds 

(VOC) 21.16 5.29 

Greenhouse Gases (GHG) 

Carbon Dioxide Equivalent (CO2e) 2,534 634 

These emissions are derived from the estimated overall emission contribution from 

operating limits. Exceedance of the operating limits shall be considered credible evidence 

of the exceedance of emission limits. Compliance with the annual emission limits may be 

determined as stated in Condition 24. 

(9 VAC 5-50-260, 9 VAC 5-80-1180, 9 VAC 5-80- 1785 and 9 VAC 5-80-2050) 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 17 

41. Process Emission Limits — Emergency Fire Pump (Ref. No. EFP1) 

Emissions from the emergency fire pump (Ref. No. EFP1) shall not exceed the limits 

specified below: 

Pollutant lb/hr tons/year 

Oxides of Nitrogen (as NO2) 2.17 0.54 

Carbon Monoxide (CO) 1.90 0.47 

Volatile Organic Compounds 

(VOC) 2.17 0.54 

Greenhouse Gases (GHG) 

Carbon Dioxide Equivalent (CO2e) 416 104 

These emissions are derived from the estimated overall emission contribution from 

operating limits. Exceedance of the operating limits shall be considered credible evidence 

of the exceedance of emission limits. Compliance with the annual emission limits may be 

determined as stated in Condition 25. 

(9 VAC 5-50-260, 9 VAC 5-80-1773 and 9 VAC 5-80-2050) 

42. Process Emission Limits — Ten Cell Mechanical Draft Cooling Tower (Ref. No. MCT1 -

MCT1©) 

Emissions from the ten cell mechanical draft cooling tower (Ref. No. MCT1 — MCT10) shall 

not exceed the limits specified below: 

Pollutant I b/hr tons/year 

PM-10 (Includes filterable and 

condensibles) 2.35 10.27 

PM-2.5 (includes filterable and 

condensibles) 0.73 3.19 

These emissions are derived from the estimated overall emission contribution from 

operating limits. Exceedance of the operating limits shall be considered credible evidence 

of the exceedance of emission limits. Compliance with these emission limits may be 

determined as stated in Conditions 27 and 28. 

(9 VAC 5-50-260, 9 VAC 5-80-1180, and 9 VAC 5-80-2050) 

43. Process Emission Limits — Total Annual Facility-Wide Emission Limits 

Emissions from the facility shall not exceed the limits specified below: 

Pollutant GE 7FA.05 

tons/year 

Siemens 

SGT6-5000F5 

tons/year 

Oxides of Nitrogen (as NO2) 159.0 164.9 

Carbon Monoxide (CO) 205.6 143.6 

Volatile Organic Compounds 

(VOC) 37.6 51.9 

PM-10 (includes filterable and 

condensibles) 105.2 106.1 

PM-2.5 (includes filterable and 98.1 99.1 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

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condensibles 

Sulfur Dioxide (SO2) 5.44 5.37 

Greenhouse Gases (GHG) 

Carbon Dioxide Equivalent 

(CO2e) 

2,468,468 2,464,490 

These emissions are derived from the estimated overall emission contribution from 

operating limits. Exceedance of the operating limits may be considered credible evidence of 

the exceedance of emission limits. 

(9 VAC 5-50-260, 9 VAC 5-80-1180, 9 VAC 5-80-1785 and 9 VAC 5-80-2050) 

EMISSION OFFSETS 

44. NOx(and VOC) Offsets — The permittee shall secure NOxemission offsets if the GE 

7FA.05 combustion turbines are installed, and NOxand VOC emission offsets if the 

Siemens SGT6-5000F5 combustion turbines are installed in accordance with 9 VAC 5-80-

2120 and 40 CFR Part 51, Appendix S. The emission offsets are based on total annual 

facility-wide emissions limits in Condition 43. The offsets shall, at a minimum, meet the 

following conditions: 

a. The permittee shall secure NOxemission offsets of no less than 159 tons x 1.15 = 

182.85 tons for the GE 7FA.05 combustion turbines, and 164.9 tons x 1.15 = 189.64 

tons for the Siemens SGT6-5000F5 combustion turbines. The permittee shall secure 

VOC emission offsets of no less than 51.9 tons x 1.15 = 59.69 tons for the Siemens 

SGT6-5000F5 combustion turbines. 

b. The emission reduction credits shall be creditable, surplus, quantifiable, permanent and 

state and federally enforceable. The baseline for calculating the offsets shall be 

determined pursuant to the method set forth in 40 CFR Part 51, App S, Subsection IV.C. 

c. The offsets shall be obtained within the Northern Virginia ozone nonattainment area or 

from another ozone nonattainment area. If the offsets are obtained from another ozone 

nonattainment area, the following requirements apply: 

i. The ozone nonattainment area must have an equal or higher nonattainment 

classification than the area in which the source is to be located. 

ii. For any offsets secured from outside of the Commonwealth of Virginia, the emission 

reductions must be certified to be surplus, quantifiable, permanent and state and 

federally enforceable by the state or locality where the emission reductions occurred. 

Documentation of the certification must be provided to and approved by the DEQ 

Northern Regional Office prior to the beginning of operation of the facility. 

d. Prior to beginning operation, the offsets shall be secured, in effect, and state and 

federally enforceable. 

(9 VAC 5-80-2120 and 40 CFR Part 51, Appendix S) 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 19 

45. Offset Timing — Initial startup and operation of the permitted equipment shall not be 

initiated until the permittee has provided the DEQ-NRO with an official document from the 

DEQ and / or the State Agency of the state the offsets were obtained indicating that it 

recognizes the reduction as creditable and permanent. At a minimum, the document shall 

state that the emission reduction has not been and will not be credited toward another 

reduction requirement and that the emissions cannot be resurrected from the same facility 

without the owner first obtaining a permit under a federally-enforceable new source review 

program. The document must also provide evidence that the U.S. EPA accepts that the 

emission reductions are creditable for offset purposes. 

(9 VAC 5-80-2120 and 9 VAC 5-80-2050 A.3.a) 

46. Offset Recordkeeping - The permittee shall maintain at the permitted facility a copy of the 

following: 

i. Identification of each source from which the offsets were obtained. Identification 

shall include the name, address, and Universal Transverse Mercator (UTM) 

coordinates of the facility and any identification number assigned to the facility by the 

air pollution control facility that regulates it. 

ii. Certification Document from each air pollution control agency required by Condition 

44.c and any supporting documentation. 

(9 VAC 5-80-2050 and 9 VAC 5-80-2120) 

CONTINOUS EMISSION MONITORING SYSTEMS (CEMS) 

47. CEMS — Continuous Emission Monitoring Systems (CEMS) shall be installed on CCT1 and 

CCT2 to measure and record the emissions of NOx(measured as NO2) and carbon 

monoxide (CO), in parts per million by volume (ppmvd) corrected to 15 percent 02, from 

each combined-cycle power generating unit (Ref. No. CCT1 & CCT2). CEMS shall also be 

installed to measure and record the emissions of carbon dioxide (CO2). The NOx CEMS 

shall be installed, evaluated, and operated, and meet the design specifications of 40 CFR 75 

whereas CEMS for CO shall be installed, evaluated, and operated according to the 

"Monitoring Requirements" in 40 CFR 60.13. The CEMS shall also be installed on CCT1 

and CCT2 to measure and record the oxygen content of the flue gas at each location where 

NOxand CO emissions are monitored. Heat input and power output for CCT1 and CCT2 

shall also be measured and recorded. A CEMS or alternative method as allowed by 40 CFR 

75 shall be used to measure sulfur dioxide emissions to comply with the requirements of 40 

CFR 75 (acid rain program monitoring). For compliance with the emission limits contained 

in Condition 33, NOxdata and CO data shall each be reduced to one-hour rolling blocks. 

The relative accuracy test audit (RATA) of the NOx/02CEMS shall be performed on a 

lb/MMBtu basis. 

(9 VAC 5-50-40, 9 VAC 5-80-410, 9 VAC 5-50-420, 40 CFR 75, 40 CFR 60.13, and 40 CFR 

60.4340 (b)) 

48. CEMS Performance Evaluations (NOxCEMS)— Performance evaluations of the NOxand, 

if applicable, SO2CEMS shall be conducted in accordance with 40 CFR 75, Appendix B , 

and shall take place during the performance tests under 9 VAC 5-50-30 or within 30 days 

thereafter. One copy of the performance evaluation report shall be submitted to the DEQ, 

within 45 days of the evaluation. The continuous monitoring systems shall be installed and 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 20 

operational prior to conducting the initial performance tests. Verification of operational 

status shall, at a minimum, include completion of the manufacturer's written requirements or 

recommendations for demonstration of the continuous monitoring system's performance, 

and subsequent notifications shall be submitted to the DEQ. 

(9 VAC 5-50-40, 40 CFR 75, and 40 CFR 60.4345(a)) 

49. CEMS Performance Evaluations (CO CEMS) — Performance evaluations of the CO CEMS 

shall be conducted in accordance with 40 CFR 60, Appendix B, and shall take place during 

the performance tests under 9 VAC 5-50-30 or within 30 days thereafter. One copy of the 

performance evaluation report shall be submitted to the DEQ, within 45 days of the 

evaluation. The continuous monitoring systems shall be installed and operational prior to 

conducting the initial performance tests. Verification of operational status shall, at a 

minimum, include completion of the manufacturer's written requirements or 

recommendations for demonstration of the continuous monitoring system's performance, 

and subsequent notifications shall be submitted to the DEQ. 

(9 VAC 5-50-40, 40 CFR 60, and 40 CFR 60.4345(a)) 

50. CEMS Quality Control Program — For the NOxand diluent CEMS, the quality control 

requirements of 40 CFR Part 75 shall be met. The Quality Assurance Accuracy 

Specifications for the CO CEMS shall be 40 CFR 60 Appendix F, Procedure 1. A linearity 

test for NOxand diluent, and a Cylinder Gas Audit (CGA) for CO shall be performed once 

per QA operating quarter 168 hours operation) not to exceed four calendar quarters. A 

RATA test for each installed CEMS shall be conducted once every four Quality Assurance 

(QA) operating quarters 168 hours operation each), not to exceed eight calendar 

quarters. The provisions for a grace period to complete testing shall apply (40 CFR 75, 

Appendix B 2.2.4 & 2.3.3). Data validation shall be as defined in 40 CFR Part 75, Appendix 

B, 2.3.2 with the exception that missing data for CO, resulting from continuous monitor 

system breakdown, repair, calibration checks, and zero and span adjustments, shall be 

reported as monitor downtime and not substituted. No bias factor shall be applied to the CO 

monitored value as per 40 CFR Part 60. 

(9 VAC 5-50-40, 40 CFR 60.13, 40 CFR 60.4543(e), and 40 CFR 60) 

51. Excess Emissions and Monitor Downtime for NOxContinuous Monitoring Systems —

For the purpose of this permit, periods of excess emissions and monitor downtime that must 

be reported under Condition 53 are defined as follows: 

a. An excess emission is any unit operating period in which the one-hour average NOx 

emission rate exceeds the applicable emission limit in Condition 33, and 

b. 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, 02concentration, 

fuel flow rate, steam flow rate, steam temperature, steam pressure, or megawatts. The 

steam flow rate, steam temperature, and steam pressure are only required if the 

permittee uses this information for compliance purposes. 

(9 VAC 5-50-50, 9 VAC 5-50-410, 40 CFR 60.7(c), and 40 CFR 60.4380) 

52. Excess Emissions and Monitor Downtime for SO2Monitoring Systems: 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 21 

For the purpose of this permit, periods of excess emissions and monitor downtime that must 

be reported under Condition 53 are defined as follows: 

a. An excess emission occurs each unit operating hour included in the hour 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; and 

b. 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. 

(9 VAC 5-50-50, 9 VAC 5-50-410, 40 CFR 60.7(c), and 40 CFR 60.4385) 

53. Reports for Continuous Monitoring Systems — The permittee shall furnish written reports 

to the Regional Air Compliance Manager of the DEQ's NRO at the address listed in 

Condition 57 from any process monitored by a CEMS, on a quarterly basis, postmarked no 

later than the 30th day following the end of the calendar quarter. These reports shall 

include, but are not limited to the following information: 

a. The magnitude of excess emissions, any conversion factors used in the calculation of 

excess emissions, and the date and time of commencement and completion of each 

period of excess emissions. For each month in the quarter, report each hour in which a 

NOxpermit limit is exceeded. The report shall include for each excess emission of NOx: 

start time, duration, equipment involved, actual NOxemissions in ppmvd @ 15% 02, fuel 

consumption rate, actual weather conditions (temperature and barometric pressure) and 

turbine load. 

b. Specific identification of each period of excess emissions that occur during startups, 

shutdowns or malfunctions of the process, and the nature and cause of the malfunction 

the corrective action taken, and preventative measures adopted; 

c. The date and time identifying each time period during which the continuous monitoring 

system was inoperative except for zero and span checks, and the nature of the system 

repairs or adjustments; 

d. If during the calendar quarter no excess emissions have occurred or the continuous 

monitoring systems have not been inoperative, repaired or adjusted, such information 

shall be stated in the report. 

e. Excess emission reports for sulfur dioxide and nitrogen dioxide as required in 40 CFR 

60.4395. 

Copies of the written reports referenced in items a through d above are to be sent to: 

Associate Director 

Office of Air Enforcement (3 AP 10) 

U.S. Environmental Protection Agency 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 22 

Region III 

1650 Arch Street 

Philadelphia, PA19103 — 2029 

(9 VAC 5-50-50, 9 VAC 5-50-410, 40 CFR 60.7(c), 40 CFR 60.4375(a), and 40 CFR 

60.4395) 

54. Excess Emissions for Continuous Monitoring Systems — For purposes of identifying 

excess emissions: 

a. All CEMS data must be reduced to hourly averages as specified in 40 CFR 60.13(h). 

b. For each operating hour in which a valid hourly average, as described in 40 CFR 

60.4345(b), is obtained for both NOxand diluent monitors, the data acquisition and 

handling system must calculate and record the hourly NOxemission rate in units of ppm, 

using the appropriate equation in 40 CFR 60, Appendix A Method 19. For any hour in 

which the hourly average of 02concentration exceeds 19.0 percent 02, a diluent cap 

value of 19.0 percent 02may be used in the emission calculations. 

c. Only quality assured data from the CEMS shall be used to identify excess emissions. 

Periods where the missing data substitution procedures in 40 CFR 75, Subpart D are 

applied are to be reported as monitor downtime in the excess emissions and monitoring 

performance report required under 40 CFR 60.7(c). 

(9 VAC 5-50-50, 9 VAC 5-50-410, 40 CFR 60.7(c), and 40 CFR 60.4350) 

TESTING 

55. Testing/ Monitoring Ports — The permitted facility shall be constructed so as to allow for 

emissions testing upon reasonable notice at any time, using appropriate methods. This 

includes constructing the facility such that volumetric flow rates and pollutant emission rates 

can be accurately determined by applicable test methods and providing stacks and ducts 

that are free from cyclonic flow. Test ports shall be provided in accordance with the 

applicable performance specification (reference 40 CFR Part 60, Appendices A & B). 

(9 VAC 5-50-30 F) 

56. Initial Performance Test (CO, VOCs, PM-10 & PM-2.5) — Combustion Turbines - Initial 

performance tests shall be conducted on each combined-cycle power generation unit (Ref. 

No. CCT1 & CCT2) for the following pollutants using the specified methods, as appropriate: 

Pollutant Test Method 

Carbon Monoxide (CO) 40 CFR 60, Appendix A, Method 10 

Volatile Organic Compounds (VOC) 40 CFR 60, Appendix A, Method 25A 

PM-10 & PM-2.5 (includes condensables) 

40 CFR 60, Appendix A, Methods 5 or 17 

and 19 and 40 CFR 51, Appendix M, Method 

201A and 202 

Tests shall be conducted to determine compliance with the emission limits contained in 

Condition 33. The tests shall be performed, reported and demonstrate compliance within 60 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 23 

days after achieving the maximum production rate at which the unit will be operated, but in 

no event later than 180 days after startup of the permitted unit. The tests shall be 

conducted on each combined-cycle power generation unit for two different operating 

scenarios: natural gas firing with the duct burners off; and natural gas firing with the duct 

burners on. The tests shall be conducted and reported and data reduced as set forth in 9 

VAC 5-50-30, and the test methods and procedures contained in each applicable section or 

subpart listed in 9 VAC 5-50-410. The details of the tests are to be arranged with the 

Regional Air Compliance Manager of the DEQ's NRO at the address listed in Condition 57. 

The permittee shall submit a test protocol at least 30 days prior to testing. Two copies, one 

hard copy, and one electronic copy on removable electronic media, of the test results shall 

be submitted to the Regional Air Compliance Manager of the DEQ's NRO within 60 days 

after test completion, but no later than 180 days after startup of the permitted unit and shall 

conform to the test report format enclosed with this permit. 

(9 VAC 5-50-30, 9 VAC 5-50-410 and 9 VAC 5-80-2080) 

57. Correspondence - All correspondence to DEQ concerning compliance with this permit shall 

be submitted to the following address: 

Regional Air Compliance Manager 

Department of Environmental Quality 

Northern Regional Office 

13901 Crown Court 

Woodbridge, VA 22193 

(9 VAC 5-50-30, 9 VAC 5-50-410 and 9 VAC 5-80-2050) 

58. Initial Performance Test (NOx) — Combustion Turbines - Initial performance tests shall 

be conducted on each combined-cycle power generating unit (Ref. No. CCT1 & CCT2) for 

oxides of nitrogen (as NO2) to determine compliance with the limits in Condition 33 as 

follows: 

a. 40 CFR 60, Appendix A, Methods 7E or 20 shall be used to measure the NOx 

concentration (in ppm). Sampling traverse points for NOxand (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 transversing single hole probe, or, if feasible, with a stationary multi probe hole 

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. 

b. Notwithstanding Condition 58a above, the permittee may test at fewer points than are 

specified in Method 1 or Method 20 if the following conditions are met: 

The permittee may perform stratification tests for. NOxand dilutant pursuant to the 

procedures specified in 40 CFR 75, Appendix A, Section 6.5.6.1(a) through (e). Once 

the stratification sampling is completed, the permittee may use following alternate 

sample point section criteria for the performance test: 
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Registration Number: 73826 

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i. If each of the individual transverse point NOxconcentrations is within +- 10 percent 

of the mean concentration for all traverse points, or the individual traverse point 

diluent concentrations differ by no more than +-5 ppm, or +- 5 percent 02from the 

mean for all traverse points, three points located either 16.7, 50.0, or 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 may be used. 

The three points must be located along the measurement line that exhibited the 

highest average NOxconcentration during the stratification test, or 

ii. The permittee may sample at a single point, located at least one meter from the 

stack wall or at the stack centroid if each of the individual transverse point NOx 

concentrations is within +- 2.5 percent of the mean concentration for all transverse 

points, or the individual transverse point diluent concentration differs by no more than 

+- 1 ppm or +- 0.15 percent 02from the mean for all traverse points. 

c. The performance test must be done at any load condition within +- 25 percent of 100 

percent peak load. Testing may be performed at the highest achievable load point, if at 

least 75 percent of peak load cannot be achieved in practice. Three separate test runs 

for each performance test must be conducted. The minimum time per run is 20 minutes. 

d. The permittee must measure the total NOxemissions after the duct burner rather than 

after the turbine. The duct burner must be in operation during the performance test. 

e. Compliance with the applicable emission limit in Condition 33 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 Condition 33. 

f. The performance evaluation of the CEMS may either be conducted separately or (as 

described in 40 CFR 60.4405) as part of the initial performance test of the affected unit. 

g. The ambient temperature must be greater than 0°F during the performance test. 

h. The permittee may use the following alternatives to the reference methods and 

procedures in this condition: 

i. Perform a minimum of nine RATA reference method runs, with a minimum time per 

run of 21 minutes, at a single load level, within ±25 percent of 100 percent of peak 

load. The ambient temperature must be greater than 0°F during the RATA runs. 

ii. Compliance with the applicable emission limits in Condition 33 is achieved if the 

arithmetic average of all the NOxemission rates for the RATA runs, expressed in 

ppm, does not exceed the emissions limit. 

The tests shall be performed, reported and demonstrate compliance within sixty days after 

achieving the maximum production rate at which the unit will be operated, but in no event 

later than 180 days after startup of the permitted unit. Tests shall be conducted and 

reported and the data reduced as set forth in 9 VAC 5-50-30 and the test methods and 

procedures contained in each applicable section of 9 VAC 5-50-410. The details of the tests 

are to be arranged with the Regional Air Compliance Manager of the DEQ's NRO at the 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 25 

address listed in Condition 57. The permittee shall submit a test protocol at least 30 days 

prior to testing. Two copies of the test results shall be submitted (one on paper, and one on 

removable electronic media) to the Regional Air Compliance Manager of the DEQ's NRO 

within 60 days after test completion, but no later than 180 days after startup of the permitted 

unit and shall conform to the test report format enclosed with this permit. 

(9 VAC 5-50-30, 9 VAC 5-80-1180, 9 VAC 5-80-2050, 9 VAC 5-80-2080, 9 VAC 5-50-410, 

40 CFR 60.8, 40 CFR 60.4405 and 40 CFR 60.4400) 

59. Initial Perfoi mance Test (SO2) — Combustion Turbines — Initial performance tests shall 

be conducted on each combined-cycle power generating unit (Ref. No. CCT1 & CCT2) for 

sulfur dioxide (SO2) to determine compliance with the limits in Condition 33. The permittee 

may use one of the following three (a, b, or c below) to conduct the performance test: 

a. If the permittee chooses 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 40 CFR 60.17) or by manually sampling 

using Gas Process Association Standard 2166 for natural gas. The fuel analyses may 

be performed either by the permittee, a service contractor retained by the permittee, the 

fuel vendor, or any other qualified agency. The samples for the total sulfur content of the 

fuel shall be analyzed using ASTM D1072, or alternately D3246, D4084, D4468, D4810, 

D6228, D6667, or Gas Processors Association Standard 2377 (all of which are 

incorporated by reference, see 40 CFR 60.17). 

b. 40 CFR 60, Appendix A, Methods 6, 6C, 8 or 20 shall be used to measure the SO2 

concentration (in ppm). In addition, the American Society of Mechanical Engineers 

(ASME) standard, ASME PTC 9-10-1981-Part 10 "Flue and Exhaust Gas Analysis", 

manual methods for sulfur dioxide (incorporated by reference, see 40 CFR 60.17) can 

be used instead of EPA Methods 6 or 20. 

c. 40 CFR 60, Appendix A, Methods 6, 6C, or 8 and 3A, or 20 shall be used to measure the 

SO2and diluent gas concentrations. In addition, the permittee may use manual methods 

for sulfur dioxide ASME PTC 9-10-1981-Part 10 (incorporated by reference, see 40 CFR 

60.17). 

The tests shall be performed, reported, and demonstrate compliance within 60 days after 

achieving the maximum production rate at which the unit will be operated, but in no event 

later than 180 days after startup of the permitted unit. Tests shall be conducted and reported 

and the data reduced as set forth in 9 VAC 5-50-30 and the test methods and procedures 

contained in each applicable section of 9 VAC 5-50-410. The details of the tests are to be 

arranged with the Regional Air Compliance Manager of the DEQ's NRO at the address 

listed in Condition 57. The permittee shall submit a test protocol at least 30 days prior to 

testing. Two copies of the test results (one on paper, and one copy electronically on 

removable electronic media) shall be submitted to the Regional Air Compliance Manager of 

the DEQ's NRO within 60 days after test completion, but no later than 180 days after startup 

of the permitted unit and shall conform to the test report format enclosed with this permit. 

(9 VAC 5-50-30, 9 VAC 5-80-1180, 9 VAC 5-80-2050, 9 VAC 5-80-2080, 9 VAC 5-50-410, 

40 CFR 60.8, 40 CFR 60.4405 and 40 CFR 60.4400) 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 26 

60. Initial Performance Test — Auxiliary Boiler and Fuel Gas Heater - Initial performance 

tests shall be conducted on the auxiliary boiler (Ref. No. AB1) and the fuel gas heater (Ref. 

No. FGH1) for NOxand CO to determine compliance with the emission limits in Conditions 

37 and 38. The tests shall be performed, reported, and demonstrate compliance within 60 

days after the boiler or fuel gas heater, as applicable, reach the maximum load level at 

which the unit will be operated but in no event later than 180 days after its initial startup. 

Tests shall be conducted and reported and data reduced as set forth in 9 VAC 5-50-30. The 

details of the tests are to be arranged with the Regional Air Compliance Manager of the 

DEQ's NRO at the address listed in Condition 57. The permittee shall submit a test protocol 

at least 30 days prior to testing. Two copies of the test results (one on paper, and one copy 

electronically on removable electronic media) shall be submitted to the Regional Air 

Compliance Manager of the DEQ's NRO within 60 days of the test completion but no later 

than 180 days from after startup of the permitted unit and shall conform to the test report 

format enclosed with this permit. 

(9 VAC 5-50-30, 9 VAC 5-80-1180, 9 VAC 5-80-2050, and 9 VAC 5-80-2080) 

61. Visible Emissions Evaluation — Combustion Turbines - Concurrently with the initial 

performance tests, Visible Emission Evaluations (VEE) in accordance with 40 CFR Part 60, 

Appendix A, Method 9, shall be conducted by the permittee on each combined-cycle power 

generating unit (Ref. No. CCT1 & CCT2) exhaust stack. Each test shall consist of 30 sets of 

24 consecutive observations (at 15 second intervals) to yield a six-minute average. The 

tests shall be conducted on each combined-cycle power generation unit for two different 

operating scenarios: natural gas firing with the duct burners off; and natural gas firing with 

the duct burners on. The details of the tests are to be arranged with the Regional Air 

Compliance Manager of the DEQ's NRO at the listed referenced in Condition 57. The 

permittee shall submit a test protocol at least 30 days prior to testing. The evaluation shall 

be performed within 60 days after achieving the maximum production rate at which the unit 

will be operated, but in no event later than 180 days after start-up of the permitted unit. 

Should conditions occur which require rescheduling the testing, the Regional Air 

Compliance Manager of the DEQ's NRO shall be notified in writing, within seven days, and 

visible emissions testing shall be rescheduled within 30 days. Rescheduled testing shall be 

conducted under the same conditions (as possible) as the initial performance tests. Two 

copies, one hard copy and one electronic copy on removable electronic media, of the test 

results shall be submitted to the Regional Air Compliance Manager of the DEQ's NRO within 

60 days after test completion but no later than 180 days after startup of the permitted facility 

and shall conform to the test report format enclosed with this permit. 

(9 VAC 5-50-30, 9 VAC 5-80-1180, 9 VAC 5-80-2050 and 9 VAC 5-80-2080) 

62. Visible Emissions Evaluation — Auxiliary Boiler and Fuel Gas Heater - Concurrently with 

the initial performance tests, Visible Emission Evaluations (VEE) in accordance with 40 CFR 

Part 60, Appendix A, Method 9, shall also be conducted on the auxiliary boiler (Ref. No. 

AB1) and the fuel gas heater (Ref. No. FGH1) exhaust stacks. Each test shall consist of 10 

sets of 24 consecutive observations (at 15 second intervals) to yield a six minute average. 

The details of the tests are to be arranged with the Regional Air Compliance Manager of the 

DEQ's NRO at the address listed in Condition 57. The permittee shall submit a test protocol 

at least 30 days prior to testing. The evaluation shall be performed within 60 days after 

achieving the maximum production rate at which the boiler or fuel gas heater, as applicable, 

will be operated, but in no event later than 180 days after start-up of the permitted unit. 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 27 

Should conditions occur which require rescheduling the testing, the Regional Air 

Compliance Manager of the DEQ's NRO shall be notified in writing, within seven days, and 

visible emissions testing shall be rescheduled within 30 days. Rescheduled testing shall be 

conducted under the same conditions (as possible) as the initial performance tests. Two 

copies, one hard copy, and one on removable electronic media of the test results shall be 

submitted to the Regional Air Compliance Manager of the DEQ's NRO within 60 days after 

test completion but no later than 180 days after startup of the permitted facility and shall 

conform to the test report format enclosed with this permit 

(9 VAC 5-50-30, 9 VAC 5-80-1180, 9 VAC 5-80-2050, and 9 VAC 5-80-2080) 

63. Testing: Heat Rate Limit — Initial compliance testing, using ASME Performance Test Code 

on Overall Plant Performance (ASME PTC 46-1996) or equivalent method approved by the 

DEQ's NRO, shall be conducted for the heat rate limit of the combined cycle power 

generating plant (i.e., a combination of the combustion turbines, HRSG DBs and the steam 

turbine generator) to show compliance with the heat rate limit contained in Condition 2.d. 

The testing shall be performed, reported and demonstrate compliance within 90 days after 

achieving the maximum production rate at which the facility will be operated but in no event 

later than 180 days after start-up of the permitted facility. The details of the tests are to be 

arranged with DEQ's NRO. The permittee shall submit a test protocol at least 30 days prior 

to testing. Two copies of the test results (one on paper, and one copy electronically on 

removable electronic media) shall be submitted to the Regional Air Compliance Manager of 

the DEQ's NRO within 60 days of the test completion but no later than 180 days from after 

startup of the permitted unit and shall conform to the test report format enclosed with this 

permit. An exceedance of the heat rate limit is not considered a violation of this permit, but 

triggers a requirement for the permittee to submit a maintenance plan to DEQ's NRO which 

specifies the actions the permittee plans to take in order to achieve the heat rate limit 

contained in Condition 2.d. The details of this plan are to be arranged with DEQ's NRO. 

(9 VAC 5-50-30 and 9 VAC 5-80-1675) 

64. Annual SO2Performance Test — Combustion Turbines — Annual performance tests shall 

be conducted on each combined-cycle combustion turbine (Ref. No. CCT1 & CCT2) for 

sulfur dioxide (SO2) to determine compliance with the limits contained in Condition 33. The 

permittee may use one of the following three methods (a, b, or c below) to conduct the 

performance test: 

a. If the permittee chooses 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 40 CFR 60.17) or by manually sampling 

using Gas Process Association Standard 2166 for natural gas. The fuel analysis may be 

performed either by the permittee, a service contractor retained by the permittee, the fuel 

vendor, or any other qualified agency. The samples for the total sulfur content of the fuel 

shall be analyzed using ASTM D1072, or alternately D3246, D4084, D4468, D4810, 

D6228, D6667, or Gas Processors Association Standard 2377 (all of which are 

incorporated by reference , see 40 CFR 60.17). 

b. 40 CFR 60, Appendix A, Methods 6, 6C, 8 or 20 shall be used to measure the SO2 

concentration (in ppm). In addition, the American Society of Mechanical Engineers 

(ASME) standard, ASME PTC 9-10-1981-Part 10 "Flue and Exhaust Gas Analysis", 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 28 

manual methods for sulfur dioxide (incorporated by reference, see 40 CFR 60.17) can 

be used instead of EPA Methods 6 or 20. 

c. 40 CFR 60, Appendix A, Methods 6, 6C, or 8 and 3A, or 20 shall be used to measure the 

SO2and diluent gas concentrations. In addition, the permittee may use manual methods 

for sulfur dioxide ASME PTC 9-10-1981-Part 10 (incorporated by reference, see 40 CFR 

60.17). 

The tests shall be conducted on an annual basis (no more than 14 calendar months 

following the previous performance test). Tests shall be conducted and reported and data 

reduced as set forth in 9 VAC 5-50-30 and the test methods and procedures contained in 

each applicable section or subpart listed in 9 VAC 5-50-410. The details of the tests are to 

be arranged with the Regional Air Compliance Manager of the DEQ's NRO at the address 

listed in Condition 57. The permittee shall submit a test protocol at least 30 days prior to 

testing. Two copies of the test results (one on paper, and one copy electronically on 

removable electronic media) shall be submitted to the Regional Air Compliance Manager of 

the DEQ's NRO within 60 days after test completion and shall conform to the test report 

format enclosed with this permit. 

(9 VAC 5-50-30, 9 VAC 5-80-1180, 9 VAC 5-80-2050, 9 VAC 5-80-2080, 9 VAC 5-50-410, 

and 40 CFR 60.4415(a)) 

65. Biennial VOC, PM-10 & PM-2.5 Performance Test — Combustion Turbines - Upon 

completion of the initial performance tests required by Condition 56, the permittee shall 

conduct biennial performance tests on each combined-cycle power generating unit (Ref. No. 

CCT1 & CCT2) at 24 month intervals for VOC, PM-10, and PM-2.5 emissions as prescribed 

in Condition 56. The first such biennial test event shall occur no later than 24 months 

following completion of the initial performance tests required by Condition 56. If during three 

consecutive test events, including the initial performance tests, neither unit has tests results 

that show emissions at greater than 80 percent of the emission limits in Condition 33, the 

testing interval for each turbine may be expanded up to 60 months upon approval from the 

Regional Air Compliance Manager of the DEQ's NRO. If any subsequent test results in 

emissions of greater than 80 percent, biennial testing at no more than 24 month intervals 

shall resume. The tests for each turbine may be staggered within the schedule above, so 

that they are not necessarily conducted for both units in the same calendar year. The tests 

need only be conducted at the maximum load in the normal operating range and the 

minimum load of the normal operating range, unless the minimum load is within ten percent 

of the maximum load, in which case testing is required at only the maximum load. The 

normal operating range shall be determined from records of actual operation. Upon request 

by the DEQ, the permittee shall conduct additional performance tests for each combinedcycle power generating unit (Ref. No. CCT1 & CCT2) to demonstrate compliance with the 

emission limits contained in this permit. The details of the tests shall be agreed upon with 

the Regional Air Compliance Manager of the DEQ's NRO. 

(9 VAC 5-50-30 G, 9 VAC 5-80-1180, 9 VAC 5-80-2050, 9 VAC 5-80-2080, and 9 VAC 5-50-

410) 

66. Visible Emissions Evaluation — Combustion Turbines — After the initial Visible Emissions 

Evaluation, the permittee shall conduct visible emission inspections on each combined-cycle 

power generating unit (Ref. No. CCT1 & CCT2) stack in accordance with the following 

procedures and frequencies: 
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Registration Number: 73826 

Page 29 

a. At a minimum of once per week, the permittee shall observe the exhaust stack of each 

combined-cycle power generating unit (Ref. No. CCT1 & CCT2) when in operation for 

the presence of visible emissions. If during the inspection, visible emissions are 

observed, a visible emissions evaluation (VEE) shall be conducted in accordance with 

40 CFR 60, Appendix A, EPA Method 9. The VEE shall be conducted for a minimum of 

six minutes. If any of the individual observations exceed the applicable standard, the 

VEE shall be continued for 60 minutes. 

b. If visible emissions inspections conducted during 12 consecutive weeks show no visible 

emissions for a particular unit stack, the permittee may reduce the monitoring frequency 

to once per month for that unit stack. Anytime the monthly visible emissions inspections 

show visible emissions, or when requested by the DEQ, the monitoring frequency shall 

be increased to once per week for that stack. 

c. The details and results of all visible emission inspections and observations, and VEEs 

shall be recorded. The permittee shall maintain records of all such events. 

(9 VAC 5-50-20 and 9 VAC 5-80-2080) 

67. Visible Emissions Evaluation — Auxiliary Boiler and Fuel Gas Heater —The permittee 

shall conduct visible emission inspections on the auxiliary boiler (Ref. No. AB1) and fuel gas 

heater (Ref. No. FGH1) stacks in accordance with the following procedures and frequencies: 

a. At a minimum of once per month, the permittee shall observe the exhaust stack of the 

auxiliary boiler (Ref. No. AB1) and the fuel gas heater (Ref. No. FGH1) when in 

operation for the presence of visible emissions. If during the inspection, visible 

emissions are observed, a visible emissions evaluation (VEE) shall be conducted in 

accordance with 40 CFR 60, Appendix A, EPA Method 9. The VEE shall be conducted 

for a minimum of six minutes. If any of the observations exceed the applicable standard, 

the VEE shall be continued for 60 minutes. 

b. If visible emission inspections conducted during 12 consecutive months show no visible 

emissions, the permittee may reduce the monitoring frequency to once per quarter. 

Anytime the quarterly visible emissions inspections show visible emissions, or when 

requested by the DEQ, the monitoring frequency shall be increased to once per month. 

c. The details and results of all visible emission inspections and observations, and VEEs 

shall be recorded. The permittee shall maintain records of all such events. 

(9 VAC 5-50-20 and 9 VAC 5-80-2080) 

68. Periodic Testing: Heat Rate Limit — Every five years after initial evaluation of the heat rate 

limit of the power generation block, the permittee shall conduct a heat rate evaluation of the 

power generation block to show compliance with the heat rate limit contained in Condition 2 

d. The details of the evaluation are to be arranged with DEQ's NRO. 

(9 VAC 5-50-30 and 9 VAC 5-80-1675) 
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Registration Number: 73826 

Page 30 

69. Stack Tests — Upon request by the DEQ, the permittee shall conduct additional 

performance tests to demonstrate compliance with the emission limits contained in this 

permit. The details of the stack tests shall be arranged with the Regional Air Compliance 

Manager of the DEQ's NRO. 

(9 VAC 5-50-30 G) 

RECORDKEEPING 

70. On Site Records — The permittee shall maintain records of emission data and operating 

parameters as necessary to demonstrate compliance with this permit. The content and 

format of such records shall be arranged with the Regional Air Compliance Manager of the 

DEQ's NRO. These records shall include, but are not limited to: 

a. Fuel records to demonstrate compliance with Conditions 11, 12 and 13. 

b. Fuel monitoring device QA/QC for the CEMS per 40 CFR Part 75. 

c. Monthly and annual throughput of natural gas to each combustion turbine (Ref. No. CT1 

& CT2). calculated monthly as the sum of each consecutive 12 month period. 

d. Monthly and annual throughput of natural gas to each duct burner (Ref. No. DB1 & 

DB2), calculated monthly as the sum of each consecutive 12-month period. 

e. Time, date, and duration of each startup, shutdown, malfunction and turbine retuning 

period for each combined-cycle power generating unit (Ref. No. CCT1 & CCT2). 

f. Annual number of startup and shutdown occurrences for each combined-cycle power 

generating unit (Ref. No. CCT1 & CCT2), calculated monthly as the sum of each 

consecutive 12-month period. 

g. Emissions calculations sufficient to verify compliance with the annual emission limits in 

Condition 35 (Ref. No. CCT1 & CCT2), Condition 37 (Ref. No. AB1), Condition 38 (Ref. 

No. FGH1), Condition 40 (Ref. No. EG1), Condition 41 (Ref. No. EFP1), Condition 42 

(Ref. No. MCT1 — MCT10), and facility-wide emission limits in Condition 43, calculated 

monthly as the sum of each consecutive 12-month period. Calculation methods shall 

be approved by the Regional Air Compliance Manager of the DEQ's NRO 

h. Monthly total dissolved solids sampling results from the water used by the ten cell 

mechanical draft cooling tower. 

i. Continuous records of heat input for each combined-cycle power generating unit (Ref. 

No. CCT1 & CCT2). 

j. Continuous records of power output for each combined-cycle power generating unit 

(Ref. No. CCT1 & CCT2) and the steam turbine generator. 

k. Continuous monitoring systems emissions data, calibrations and calibration checks, 

percent operating time, and excess emissions. 
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Registration Number: 73826 

Page 31 

I. Annual hours of operation for the emergency generator (Ref. No. EG1) and the 

emergency fire pump (Ref. No. EFP1) for emergency purposes, calculated monthly as 

the sum of each consecutive 12-month period. 

m. Records of time, date and duration of operation for the emergency fire water pump (Ref. 

No. EFP1) and the emergency generator (Ref. No. EG1) for maintenance checks and 

readiness testing and the operational status of each combined-cycle power generating 

unit (Ref. No. CCT1 & CCT2) during those maintenance checks and readiness testing. 

n. Annual hours of operation for the emergency generator (Ref. No. EG1) and the 

emergency fire pump (Ref. No. EFP1) for maintenance checks and readiness testing, 

calculated monthly as the sum of each consecutive 12-month period. 

o. All fuel supplier certifications for the emergency generator (Ref. No. EG1) and the 

emergency fire pump (Ref. No. EFP1) to demonstrate compliance with Condition 13. 

p. Operation and control device monitoring records for each SCR system and each 

oxidation catalyst. 

Logs of dissolved solids content of cooling water to the ten cell mechanical draft cooling 

tower (Ref. No. MCT1- MCT10) 

r. Records for each combined-cycle power generating unit (Ref. No. CCT1 & CCT2) 

showing steady state vs. non steady state operation during a given hour, the ammonia 

emissions monitoring plan, and the ammonia emission monitoring results as required by 

Condition 31. 

s. Scheduled and unscheduled maintenance and operator training. 

t. Results of all stack tests, visible emissions evaluations, visible emission inspection 

results, and performance evaluations. 

u. Monthly and annual throughput of natural gas and hours of operation for the auxiliary 

boiler (Ref. No. AB1) and the fuel gas heater (Ref. No. FGH1), calculated monthly as 

the sum of each consecutive 12-month period. 

v. Records of manufacturer's instructions for proper operation of equipment for the 

auxiliary boiler (Ref. No. AB1) and the fuel gas heater (Ref. No. FGH1) as required by 

Condition 3. 

w. Records related to NOxoffsets as required by Conditions 44, 45 and 46. 

x. Records related to the CEMS quality control program as required in Condition 50. 

y. Records to verify compliance with the short term emission factors for GHG in 

Conditions 33 and 34. 

These records shall be available for inspection by the DEQ and shall be current for the most 

recent five years. 

(9 VAC 5-80-1180, 9 VAC 5-80-2050, and 9 VAC 5-50-50) 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 32 

NOTIFICATIONS 

71. Initial Notifications — The permittee shall furnish written notification to the Regional Air 

Compliance Manager of the DEQ's NRO of: 

a. The actual date on which the construction of the electric power generation facility 

begins within 30 days after such date. 

b. The actual date of the selection of the turbine and HRSG manufacturer has been 

selected including model number, and heat input rating within 30 days after such date. 

c. Date that emission offsets are identified, and the nature of the offsets within 30 days 

after such date. 

d. The anticipated start-up date of the electric power generation facility, postmarked not 

more than 60 days nor less than 30 days prior to such date. 

e. The actual start-up date of the electric power generation facility within 15 days after 

such date. 

f. The anticipated date of continuous monitoring system (CEMS) performance evaluations 

postmarked not less than 30 days prior to such date. 

g. The anticipated date of performance tests of each combined-cycle power generating 

unit (Ref. No. CCT1 & CCT2) postmarked at least 30 days prior to such date. 

h. The actual date on which construction of the auxiliary boiler (Ref. No. AB1) commenced 

within 30 days after such date. 

i. The anticipated start-up date of the auxiliary boiler (Ref. No. AB1) postmarked not more 

than 60 days nor less than 30 days prior to such date. 

j. The actual start-up date of the auxiliary boiler (Ref. No. AB1) within 15 days after such 

date. 

k. The actual date on which construction of the emergency generator (Ref. No. EG1) and 

emergency fire water pump (Ref. No. EFP1) commenced within 30 days after such 

date. The notification must contain the following: 

i. Name and address of the permittee, 

ii. The address of the affected source, 

iii. Engine information including make, model, engine family, serial number, model year, 

maximum engine power and engine displacement. 

iv. Fuel used 

I. The anticipated start-up date of the emergency generator (Ref. No. EG1) and 

emergency fire water pump (Ref. No. EFP1) postmarked not more than 60 days nor 

less than 30 days prior to such date. 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 33 

m. The actual start-up date of the emergency generator (Ref. No. EG1) and the emergency 

fire water pump (Ref. No. EFP1) within 15 days after such date. 

Copies of the written notification referenced in items a through d and f through h above are 

to be sent to the Associate Director of the U.S. EPA at the address in Condition 53. 

(9 VAC 5-50-50 and 9 VAC 5-80-1180) 

GENERAL CONDITIONS 

72. Permit Invalidation - This permit to construct and operate an electric power generation 

facility shall become invalid, unless an extension is granted by the DEQ, if: 

a. A program of continuous construction is not commenced within 18 months from the date 

of this permit: 

b. A program of construction is discontinued for a period of 18 months or more, or is not 

completed within a reasonable time. This provision does not apply to the period 

between construction of the approved phases of a phased construction project; each 

phase must commence construction within 18 months of the projected and approved 

commencement date. 

DEQ may extend the 18-month period upon a satisfactory showing that an extension is 

justified 

(9 VAC 5-80-1210, 9 VAC 5-80-1985 and 9-VAC 5-80-2180) 

73. Permit Suspension/Revocation - The Board may suspend or revoke any permit if the 

permittee: 

a. Knowingly makes material misstatements in the permit application or any amendments 

to it; 

b. Fails to comply with the terms or conditions of this permit; 

c. Fails to comply with any emission standards applicable to an emissions unit included in 

this permit; 

d. Causes emissions from the facility which result in violations of, or interfere with the 

attainment and maintenance of, any ambient air quality standard; 

e. Fails to operate this facility in conformance with any applicable control strategy, including 

any emission standards or emission limitations, in the State Implementation Plan if effect 

at the time an application for this permit is submitted 

(9 VAC 5-80-1210 F, 9 VAC 5-80-1985 F and 9 VAC 5-80-1210 G) 

74. Right of Entry - The permittee shall allow authorized local, state, and federal 

representatives, upon the presentation of credentials: 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 34 

a. To enter upon the permittee's premises on which the facility is located or in which any 

records are required to be kept under the terms and conditions of this permit; 

b. To have access to and copy at reasonable times any records required to be kept under 

the terms and conditions of this permit or the State Air Pollution Control Board 

Regulations; 

c. To inspect at reasonable times any facility, equipment, or process subject to the terms 

and conditions of this permit or the State Air Pollution Control Board Regulations; and 

d. To sample or test at reasonable times. 

For purposes of this condition, the time for inspection shall be deemed reasonable during 

regular business hours or whenever the facility is in operation. Nothing contained herein 

shall make an inspection time unreasonable during an emergency. 

(9 VAC 5-170-130, 9 VAC 5-80-1180, and 9 VAC 5-80-2050) 

75. Maintenance/Operating Procedures - At all times, including periods of start-up, shutdown, 

and malfunction, the permittee shall, to the extent practicable, maintain and operate any 

affected facility, including associated air pollution control equipment, in a manner consistent 

with air pollution control practices for minimizing emissions. Determination of whether 

acceptable operating and maintenance procedures are being used will be based on 

information available to the Regional Air Compliance Manager of the DEQ's NRO, which 

may include, but is not limited to, monitoring results, opacity observations, review of 

operating and maintenance procedures, and inspection of the source. 

The permittee shall take the following measures in order to minimize the duration and 

frequency of excess emissions, with respect to air pollution control equipment, monitoring 

devices, and process equipment which affect such emissions: 

a. Develop a maintenance schedule and maintain records of all scheduled and nonscheduled maintenance. 

b. Maintain an inventory of spare parts. 

c. Have available written operating procedures for equipment. These procedures shall be 

based on the manufacturer's recommendations, at a minimum. 

d. Train operators in the proper operation of all such equipment and familiarize the 

operators with the written operating procedures, prior to their first operation of such 

equipment. The permittee shall maintain records of the training provided including the 

names of trainees, the date of training and the nature of the training. 

Records of maintenance and training shall be maintained on site for a period of five years 

and shall be made available to DEQ personnel upon request. 

(9 VAC 5-50-20 E, 9 VAC 5-80-1180 D, and 9 VAC 5-80-2050) 

76. Record of Malfunctions — The permittee shall maintain records of the occurrence and 

duration of any bypass, malfunction, shut-down or failure of the facility or its associated air 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 35 

pollution control equipment that results in excess emissions for more than one hour. The 

records shall be maintained in a form suitable for inspection and maintained for at least two 

years (unless a longer period is specified in the applicable emission standard) following the 

date of occurrence. Records shall include the date, time, duration, description (emission 

unit, pollutant affected, cause of malfunction), corrective action, preventive measures taken 

and name of person generating the record. 

(9 VAC 5-20-180 J, 9 VAC 5-80-1180 D, and 9 VAC 5-80-2050) 

77. Notification for Facility or Control Equipment Malfunction - The permittee shall furnish 

notification to the DEQ, of malfunctions of the affected facility or related air pollution control 

equipment that may cause excess emissions for more than one hour, by facsimile 

transmission, telephone or telegraph. Such notification shall be made as soon as 

practicable, but not later than four daytime business hours after the malfunction is 

discovered. The permittee shall provide a written statement giving all pertinent facts, 

including the estimated duration of the breakdown, within 14 days of the discovery. Owners 

subject to the requirements of 9 VAC 5-40-50 C and 9 VAC 5-50-50 C are not required to 

provide the written statement prescribed in this paragraph for facilities subject to the 

monitoring requirements of 9 VAC 5-40-40 and 9 VAC 5-50-40. When the condition causing 

the failure or malfunction has been corrected and the equipment is again operating the 

permittee shall notify the DEQ, in writing. 

(9 VAC 5-20-180 C, 9 VAC 5-80-1180, and 9 VAC 5-80-2050) 

78. Notification for Control Equipment Maintenance - The permittee shall furnish notification 

to the Regional Air Compliance Manager of the DEQ's NRO in case of shutdown or 

bypassing, or both, of air pollution control equipment for necessary scheduled maintenance, 

which results in excess emissions for more than one hour. The intent to shut down or 

bypass such equipment shall be reported to the Regional Air Compliance Manager of the 

DEQ's NRO and local air pollution control agency, if any, at least 24 hours prior to the 

planned shutdown. Such prior notice shall include, but is not limited to the following 

information: 

a. Identification of air pollution control equipment to be taken out of service, as well as its 

location and registration number; 

b. The expected length of time that the air pollution control equipment will be out of service; 

c. The nature and quantity of emissions of air pollution likely to occur during the shutdown 

period; and 

d. Measures that will be taken to minimize the length of the shutdown or to negate the 

effect of the outage. 

(9 VAC 5-20-180 B) 

79. Violation of Ambient Air Quality Standard - Regardless of any other provision of this 

permit, the permittee shall, upon request of the DEQ, reduce the level of operation of the 

facility if the DEQ determines that is necessary to prevent a violation of any primary ambient 

air quality standard. Under worst-case conditions, the DEQ may order that the permittee 

shut down the facility if there is no other method of operation to avoid a violation of the 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 36 

primary ambient air quality standard. The DEQ reserves the right to prescribe the method of 

determining if a facility will cause such a violation. In such cases, the facility shall not be 

returned to operation until it and the associated air pollution control equipment are able to 

operate without violation of any primary ambient air quality standard. 

(9 VAC 5-20-180 I) 

80. Change of Ownership - In the case of a transfer of ownership of a stationary source, the 

new owner shall abide by any current permit issued to the previous owner. The new owner 

shall notify the DEQ of the change of ownership within 30 days of the transfer. 

(9 VAC 5-80-1985 E and 9 VAC 5-80-1240 B) 

81. Permit Copy - The permittee shall keep a copy of this permit on the premises of the facility 

to which it applies. 

(9 VAC 5-80-1180, 9 VAC 5-80-1985 E and 9 VAC 5-80-2050) 

STATE ONLY ENFORCEABLE REQUIREMENTS 

The following terms and conditions are included to implement the requirements of 9 VAC 5-60-

300 et seq. and are enforceable only by the Virginia Air Pollution Control Board. Neither their 

inclusion in this permit nor any resulting public comment period make these terms federally 

enforceable. 

82. Emission Limits — Emissions from the electric power generation facility shall not exceed 

the limits specified below: 

Pollutant CAS# lb/hr Tons/yr 

Acrolyn 107-02-8 2.03E-02a/2.06 E-02b 8.76E-02a/ 8.88E-02b 

Formaldehyde 50-00-0 7.65E-01a/7.54E-01 b 3.09E-00a/ 3.11E-00b 

Cadimum 7440-43-9 6.31E-03a/5.95E-03b 2.25E-02a/2.25E-02b 

Chromium 7440-47-3 8.04E-03a/7.57E-03b 2.86E-02a12.86E-02b 

Nickel 7440-02-0 1.21E-02a/1.14E-02b 4.29E-02a/4.29E-02b 

aEmissions based on GE 7FA.05 

bEmissions based on Siemens SGT6-5000F5 

Annual emissions shall be calculated monthly as the sum of each consecutive 12-month 

period. 

(9 VAC 5-60-320 and 9 VAC 5-80-1625G) 

83. Onsite Records - The permittee shall maintain records of emission data and operating 

parameters as necessary to demonstrate compliance with this permit. The content and 

format of such records shall be arranged with the Northern Regional Office. These records 

shall include, but are not limited to the average hourly, monthly, and annual emissions (in 

pounds and tons) listed in Condition 82 for each toxic compound using the appropriate 

emission factor from AP-42, (Section 3-1 dated 4/2000 for stationary gas turbines), (Section 

1.4 dated 7/1998 for natural gas combustion), (Section 3.3 dated 4/2000 for gasoline and 

diesel industrial engines) and (Section 3.4 dated 4/2000 for large stationary dual fuel 

engines) times the appropriate fuel usage for the period.. Hourly emissions shall be 

calculated monthly. Annual emissions shall be calculated monthly as the sum of each 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 37 

consecutive 12-month period. These records shall be available for inspection by the DEQ 

and current for at least the most recent five years. 

(9 VAC 5-50-50 and 9 VAC 5-80-1625G) 
Green Energy Partners / Stonewall, LLC 

Registration Number: 73826 

Page 38 

SOURCE TESTING REPORT FORMAT 

Report Cover 

1. Plant name and location 

2. Units tested at source (indicate Ref. No. used by source in permit or registration) 

3. Test Dates. 

4. Tester; name, address and report date 

Certification 

1. Signed by team leader/certified observer (include certification date) 

2. Signed by responsible company official 

3. *Signed by reviewer 

Copy of approved test protocol 

Summary 

1. Reason for testing 

2. Test dates 

3. Identification of unit tested & the maximum rated capacity 

4. *For each emission unit, a table showing: 

a. Operating rate 

b. Test Methods 

c. Pollutants tested 

d. Test results for each run and the run average 

e. Pollutant standard or limit 

5. Summarized process and control equipment data for each run and the average, as required by the test 

protocol 

6. A statement that test was conducted in accordance with the test protocol or identification & discussion of 

deviations, including the likely impact on results 

7. Any other important information 

Source Operation 

1. Description of process and control devices 

2. Process and control equipment flow diagram 

3. Sampling port location and dimensioned cross section Attached protocol includes: sketch of stack (elevation 

view) showing sampling port locations, upstream and downstream flow disturbances and their distances 

from ports; and a sketch of stack (plan view) showing sampling ports, ducts entering the stack and stack 

diameter or dimensions 

Test Results 

1. Detailed test results for each run 

2. *Sample calculations 

3. *Description of collected samples, to include audits when applicable 

Appendix 

1. *Raw production data 

2. *Raw field data 

3. *Laboratory reports 

4. *Chain of custody records for lab samples 

5. *Calibration procedures and results 

6. Project participants and titles 

7. Observers' names (industry and agency) 

8. Related correspondence 

9. Standard procedures 

* Not applicable to visible emission evaluations 
AIR PERMIT MANAGER REVIEW: 

REGIONAL DIRECTOR REVIEW: 

COMMONWEALTH OF VIRGINIA 

Department of Environmental Quality 

Intra-Agency Memorandum 

DATE: April 30, 2013 

SUBJECT: Engineering Evaluation of a Nonattainment Area Major New Source 

Review (NAA-MNSR) and Prevention of Significant Deterioration (PSD) 

Permit Application Submitted by Green Energy Partners / Stonewall, LLC 

Registration No. 73826 

TO: Thomas A Faha, Director, Northern Regional Office 

FROM: Thomas Valentour, Environmental Specialist Senior, Northern Regional 

Office 

I. Executive Summary 

Green Energy Partners / Stonewall, LLC has proposed to construct and operate a 

combined-cycle electric power generating facility in Loudoun County with a 

nominal generating capacity of 750 megawatts (MW) at ISO (International 

Organization for Standardization) conditions. Both Major Nonattainment New 

Source Review (NAA-MNSR) permitting and Prevention of Significant 

Deterioration (PSD) permitting are applicable because, the facility is a fossil fuelfired steam electric plant of more than 250 million British thermal units (Btus) 

heat input capacity, and is locating in an ozone nonattainment area and a PM-2.5 

nonattainment area but an attainment area for the other criteria pollutants. The 

proposed facility has the potential to emit (PTE) more than 100 tons per year (tpy) 

of nitrogen oxides (NOx) and over 50 tpy of volatile organic compounds (VOC) 

which trigger the requirements of Major Nonattainment permitting under Article 9 

of 9 VAC 5 Chapter 80. The facility also has the PTE of more than 100 tpy of 

carbon monoxide (CO) triggering the PSD requirements under Article 8 of 9 VAC 

5 Chapter 80. Other pollutants for which the facility has the PTE in significant 

amounts include NOx, PM (TSP), PM-10, PM-2.5 and greenhouse gasses (CO2 e) 

all of which are also subject to PSD Review. The facility's PTE for all other 

regulated NSR pollutants is not significant for PSD purposes. 

Both the Nonattainment NSR and PSD regulations provide reviewing authority to 

Federal Land Managers (FLMs) of Class I areas that may be affected by 

emissions from the proposed facility. In accordance with Memoranda of 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 2 

Understanding (MOU) between the Virginia Department of Environmental 

Quality (DEQ) and the respective FLMs, both the National Park Service (NPS) 

and the National Forest Service (NFS) are given a 60-day review and comment 

period once provided notification that the application is considered complete. 

Within the first 30 days of the review period, the FLMs are asked whether or not 

they will provide a finding of an adverse impact on visibility and other applicable 

Air Quality Related Values (AQRVs) as a result of the proposed facility. FLMs 

may comment on any aspect of permit processing, but are specifically charged 

with protecting the AQRVs within the Class I areas. 

The following table shows the distances between the proposed plant site and the 

closest Class I areas: 

Table I. Distance of ro osed vlant from Class I areas 

Class t area Distance from proposed plant (km) 

Shenandoah National Park (SNP) 57 

Dolly Sods Wilderness Area (West Virginia) 152 

Otter Creek Wilderness Area (West Virginia) 175 

James River Face Wilderness Area 227 

Brigantine National Wildlife Refuge 271 

Sources located in nonattainment areas must apply the Lowest Achievable 

Emission Rates (LAER) to pollutants for which the area is in nonattainment. For 

this permit action, LAER was evaluated for both NO„ and VOCs. Also, as a 

requirement of MNSR, the source must obtain offsets of nonattainment pollutants. 

Pollutants for which the area is in attainment are subject to a Best Available 

Control Technology (BACT) analysis. This involves a "top down" analysis of all 

technically feasible control technologies and the utilization of the most stringent 

level of control that can be demonstrated to be either technically or economically 

feasible. Economic feasibility takes into consideration the cost of controls 

required at similar recently permitted facilities. Pollutants for which the facility's 

PTE is not significant may undergo a state BACT determination. 

Green Energy Partners / Stonewall, LLC originally submitted an application in 

May 2010, but did not complete the application process. In July 2012 they 

resubmitted the application that revised the plan to eliminate the two simple cycle 

combustion turbines. The application was treated as an amended application. 

II. Introduction and Background 

On July 24, 2012, the Northern Regional Office of the Department of 

Environmental Quality (NRO-DEQ) received an application dated July 19, 2012, 

from Green Energy Partners / Stonewall, LLC (GEP/S) for a NAAMNSR/PSD/Minor NSR permit to construct and operate a combined-cycle 

electric generating facility in Loudoun County. GEP/S has requested that the 

proposed permit allow two optional plant configurations, each having a different 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 3 

combustion turbine manufacturer. The two combustion turbine configuration 

options currently being considered are the General Electric GE7FA.05 and 

Siemens SGT6-5000F5 units. GEP/S will submit a letter requesting the 

withdrawal of one of the two options at the time when their final decision is made. 

A. Site Information 

The proposed site for Green Energy Partners / Stonewall, LLC (GEP/S) is 

a 101-acre parcel, approximately south-southeast of the Town of Leesburg 

airport and north of the Dulles Toll Road, and adjacent Gant Lane and 

Cochran. Mill Road. 

The address for the facility is 20077 Gant Lane, Leesburg, Virginia 20175. 

The UTM coordinates of the proposed site are 279.7435 kilometers (km) 

Easting and 4326.0578 km Northing. The project will be located at a base 

elevation of 320 feet above mean sea level. 

There is gently rolling terrain with wetlands, forest and undeveloped land 

around the proposed site. 

B. Site Suitability 

In accordance with Section 10.1-1307 E of the Air Pollution Control Law 

of Virginia, consideration has been given to the following facts and 

circumstances relevant to the reasonableness of the activity involved: 

1. The character and degree of injury to, or interference with safety, 

health, or the reasonable use of property which is caused or 

threatened to be caused: 

The activities regulated in this permit have been evaluated consistent 

with 9 VAC5-80-1750 (PSD BACT), 9VAC5-80-2050 (LAER), 9 

VAC 5-50-260 (State BACT) and 9 VAC 5-60-320 (Toxics Rule) and 

have been determined to meet these standards where applicable. 

Please see Section IV.D.2 for a description of the Lowest Achievable 

Emission Rate, and see Section IV.D.3 for Best Available Control 

Technology standards included in the permit. Please refer to Section 

IV.B for more information on the applicability of the Toxics Rule to 

the proposed facility. 

As a fossil fuel-fired steam electric generating plant having heat input 

greater than 250 million British thermal units per hour, the proposed 

facility is a major stationary source according to Article 8, 9 VAC 5-

80-1615 C for carbon monoxide (CO), nitrogen oxides (NOx), PM-10, 

and greenhouse gasses, and a major stationary source according to 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 4 

Article 9, 9 VAC 5-80-2000 for oxides of nitrogen (NO,). If the 

facility chooses the Siemens model combustion turbines, it will also be 

subject to 9 VAC 5-80-2000, et seq. for volatile organic compounds 

(VOC) air pollutant emissions. In accordance with Article 8 and 9, 

Permits for Major Stationary Sources and Major Modifications 

Locating in a Prevention of Significant Deterioration Areas and Major 

Sources Locating in Nonattainment Areas or the Ozone Transport 

Region, air quality modeling was conducted to predict the maximum 

ambient impacts of criteria pollutants emitted by the proposed source. 

The modeling results for NO2 (annual averaging period), PM-2.5 and 

CO (8-hour averaging period) were less than the applicable Significant 

Impact Levels (SILs) for both turbine options. Also, the modeling 

results for CO (1-hour averaging period) for the Siemens turbine 

option only were less than the applicable SIL. Therefore, a full impact 

analysis for these pollutants and averaging periods was not required. 

Furthermore, the additional pollution from this facility would not 

cause or contribute to a violation of any applicable National Ambient 

Air Quality Standard (NAAQS) or PSD increment for all pollutants 

and averaging periods with impacts below the applicable SILs. 

A full impact analysis for CO (1-hour averaging period, General 

Electric turbine option only), NO2(1-hour averaging period), and PM2.5 (24-hour averaging period) was conducted because the preliminary 

modeling analysis results exceeded the applicable SILs. Additionally, 

a full impact analysis was conducted for PM-2.5 (annual averaging 

period) at the request of DEQ even though the facility's predicted 

impact was below the SIL. This was done to provide additional 

assurance of NAAQS compliance in the Washington, D.C. 

Metropolitan Statistical Area (MSA). The results of the full impact 

analysis demonstrated compliance with the applicable NAAQS. 

GEP/S's project is proposed to be sited at a distance of 57 kilometers 

from SNP, a protected Class I area. Based on the level of emissions 

from the proposed facility, the FLMs determined an AQRV analysis is 

not required because the project is not expected to show any 

significant additional impacts to AQRVs. Therefore, only a Class I 

area analysis to assess compliance with the Class I PSD increments 

was required. The analysis demonstrated that the proposed facility 

does not cause or significantly contribute to a predicted violation of 

any applicable Class I area PSD increment. The modeling results are 

discussed in Attachment C. 

The emissions of toxic pollutants from electric generating units such as 

those proposed by GEP/S are subject to the standards in 9 VAC 5-60-

300 et seq. GEP/S calculated the emissions of toxic pollutants from all 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 5 

of the emission units proposed for the site. An analysis was conducted 

in accordance with the regulations for permitting applicability and the 

predicted concentrations for each toxic pollutant were below their 

respective Significant Ambient Air Concentrations (SAACs). 

Modeling demonstrated that proposed emissions of acrolein, 

formaldehyde, cadmium, chromium, and nickel are well below (less 

than 1 %) the associated SAACs. 

Since Loudoun County is part of the Northern Virginia Ozone 

Nonattainment area and is part of the Ozone Transport Region, GEP/S 

is required to obtain NO, emissions offsets at a 1.15:1.00 ratio. If 

GEP/S chooses Siemens combustion turbines, a VOC emission offset 

in the ratio of 1.15:1.00 will also be required. GEP/S had not yet 

identified the source of the offsets but is required to make them 

federally enforceable and enforceable as a practicable matter prior to 

the initial start up of the combined cycle combustion turbines. 

Results of modeling conducted for emissions from the proposed 

facility show compliance with the health-based NAAQS for all 

applicable pollutants. Furthermore, single source and cumulative 

modeling analyses indicate that the proposed project will not result in 

a violation of any PSD increment. Accordingly, approval of the 

proposed permit is not expected to cause injury to or interference with 

safety, health, or reasonable use of property. 

2. The social and economic value of the activity involved: 

The social and economic value of the facility submitting the 

application has been evaluated relative to local zoning requirements. 

The local official has deemed this activity not inconsistent with local 

ordinances. The signed Local Government Form is included in 

Attachment E. 

The proposed GEP/S facility will generate electricity using natural gas. 

The availability of clean fuel electric generation facilities is necessary 

if operation of conventional coal-fired power plants is to be reduced or 

replaced. Although it is not guaranteed that regional coal-powered 

generation will be reduced if clean-burning plants such as the GEP/S 

project are built, if they are not built, it is certain that electricity 

demand will continue to be met through use of the older, dirtier 

facilities. Construction of clean-burning, efficient generation plants 

such as the proposed GEP/S facility creates the potential for regional 

SO2and NO„ reductions resulting from displacement of older, more 

polluting forms of electricity generation. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 6 

3. The suitability of the activity to the area in which it is located: 

The activities regulated in this permit are deemed suitable as follows: 

(i) Air Quality characteristics and performance requirements 

defined by SAPCB regulations: 

This permit is written consistent with existing applicable 

regulations. The proposed facility will emit toxics and the 

modeling shows compliance with the applicable SAACs. The 

emissions for criteria pollutants associated with this permit 

have likewise been modeled and have been shown to not cause 

or contribute to a violation of the ambient air quality standards 

or allowable increments within any Class I or Class II areas. 

The PSD Regulations require that GEP/S conduct modeling 

analyses to determine potential impacts of the proposed facility 

on visibility and other applicable AQRVs in Class I areas. 

However, based on the level of emissions from the proposed 

facility, the FLMs deteimined an AQRV analysis is not 

required because the project is not expected to show any 

significant additional impacts to AQRVs. The Class I and 

Class II area modeling results are discussed in Attachment C. 

(ii) The health impact of air quality deterioration which might 

reasonably be expected to occur during the grace period 

allowed by the Regulations or the permit conditions to fix 

malfunctioning air pollution control equipment: 

The permit requires the facility to notify the Regional Office 

within four business hours of discovery of any malfunction of 

pollution control equipment. 

(iii) Anticipated impact of odor on surrounding communities or 

violation of the SAPCB Odor Rule: 

No violation of Odor requirements is anticipated as a result of 

the proposed project. 

4. The scientific and economic practicality of reducing or eliminating 

the discharge resulting from the activity: 

The state NSR program as well as the PSD and nonattainment 

programs require consideration of levels of control technology that 

are written into regulation to define the level of scientific and 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 7 

economic practicality for reducing or eliminating emissions. By 

properly implementing the Regulations through the issuance of the 

proposed permit, the staff has addressed the scientific and 

economic practicality of reducing or eliminating emissions 

associated with this project. 

The permit requires numerous pollution control strategies (e.g., 

BACT, LAER, etc.) that will result in reduction of emissions. 

LAER is the most stringent emissions limitation which is achieved 

in practice by such class or category of stationary sources. These 

include pollution prevention techniques such as use of clean fuels, 

good combustion practices, and clean burning "low-NO," lean 

premix burners as well as post-combustion controls (SCR for NO, 

removal and an Oxidation Catalyst for CO, VOC, and VOC toxic 

pollutant control). Pollution prevention measures have been 

included in the draft permit, such as a requirement to use ultra-low 

sulfur (no more than 0.0015 % by weight) oil in emergency 

equipment, and a limit on ammonia emissions (not currently a 

regulated pollutant) 

C. Project Summary 

Green Energy Partners / Stonewall, LLC applied for a permit to construct 

and operate a combined-cycle electric power generating facility with a 

nominal generating capacity of 750 megawatts (MW). The proposed 

facility is comprised of two combustion turbine (CT) generators, each 

having a heat recovery steam generator (HRSG) driving a common steam 

turbine (ST) for additional electricity generation. Each HRSG has a duct 

burner (DB) for supplemental firing. The CT-HRSG arrangement is 

commonly called combined cycle. The proposed facility also includes an 

auxiliary boiler, an emergency firewater pump, an emergency generator, a 

fuel gas heater, and two turbine air inlet conditioners. 

The CTs, HRSG DBs, the auxiliary boiler and fuel gas heater will only 

combust pipeline quality natural gas. The emergency firewater pump and 

emergency generator will utilize ultra low sulfur diesel fuel oil. 

GEP/S has requested that the proposed permit allow two optional plant 

configurations, each having a different combustion turbine manufacturer. 

The two combustion turbine configuration options currently being 

considered are the General Electric GE7FA.05 and Siemens SGT6-

5000F5 units. GEP/S will submit a letter requesting the withdrawal of one 

of the two options at the time when their final decision is made. 

Therefore, the proposed CT generators will either be General Electric 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 8 

GE7FA.05 or Siemens SGT6-5000F5 units. Both scenarios were 

evaluated. 

The proposed facility is capable of operating in either a gas (simple cycle) 

or steam cycle (combined cycle). In the simple cycle only the electric 

generators connected to the combustion turbine are used to produce 

electricity. The steam cycle provides increased efficiency by employing 

the HRSGs to recover otherwise lost heat from the CT exhaust and using it 

to create steam and drive the ST generator to produce additional 

electricity. The steam that exhausts the ST generator is cooled and 

condensed via the ten cell mechanical draft cooling tower for reuse in the 

steam cycle. The combined cycle system will provide approximately 750 

MW of nominal power output. 

Proposed annual mass emission rates from the GEP/S project are 

presented in Table 2. 

Table 2. Proposed Maximum Mass Emission rates (tons/yr) from the Green 

Energy Partners / Stonewall project. 

Pollutant 

NOx 

Emissions (tons/yr) 

GE F7FA.05 

Combustion 

Turbines & 

Siemens SGT6- 

5000E5 

Combustion 

Tnrhines & 

HRSGs with DBs HRSGs with DBs 

On 

159.0 

On 

164.9 

CO 205.6 143.6 

SO2 5.44 5.37 

VOC 37.6 51.9 

PM-10 105.2 106.2 

PM-2.5 98.1 99.1 

Greenhouse Gases (GHG) 

Carbon Dioxide Equivalent 

(CO2e) 

2,468,467 2,464,490 

Sulfuric acid mist 2.87 2.81 

Acrolein 8.76E-01 8.88E-02 

Cadmium 2.25E-02 2.25E-02 

Chromium 2.86E-02 2.86E-02 

Formaldehyde 3.09 3.11 

Nickel 4.29E-02 4.29E-02 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 9 

Note: Emissions of regulated toxic pollutants other than formaldehyde, acrolein, cadmium, chromium, and 

nickel are below permitting annual exemption thresholds and were therefore not included in Table 2. Tables 8 

and 9 below have all HAPS listed. 

The following permitting regulations apply to the proposed facility: 

• 9 VAC 5 Chapter 80 Article 9 Permits for Major Stationary 

Sources and Major Modifications Locating in Nonattainment 

Areas or the Ozone Transport Region NAA-NSR for either NON, 

or NO, and VOC depending on the combustion turbine model 

chosen. 

• 9 VAC 5 Chapter 80 Article 8 Permits for Major Stationary 

Sources and Major Modifications Locating in Prevention of 

Significant Deterioration Areas PSD permitting regulations for 

emissions of CO, NON, PM, PM10, and GHG. 

• 9 VAC 5 Chapter80 Article 6 Permits for New and Modified 

Stationary Sources - Minor NSR for PM-2.5, PM-10, CO, NOx 

and VOC 

• 9 VAC Chapter 80 Article 1 Federal (Title V) Operating Permits 

for Stationary Sources (application must be submitted within one 

year of commencing operation) 

The following regulations also apply to the proposed facility: 

• New Source Performance Standard (NSPS), 40 CFR 60, Subpart 

KKKK applies to the combustion turbines. 

• New Source Performance Standard (NSPS), 40 CFR 60, Subpart 

Dc applies to the auxiliary boiler and the fuel gas heater. 

• New Source Performance Standard (NSPS), 40 CFR 60, Subpart 

IIII applies to the emergency generator and fire water pump. 

• Maximum Achievable Control Technology (MACT), 40 CFR 63, 

Subpart ZZZZ applies to the emergency generator and fire water 

pump. 

Title IV Acid Rain Program. 

• 9 VAC 5 Chapter 140, NO, Budget Trading Program, Clean Air 

Interstate Rule (CAIR) NO, Annual Trading Program, CAIR NOx 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 10 

Ozone Season Trading Program, and CAIR SO2Annual Trading 

Program. 

Rules that don't apply: 

• The Combustion Turbine MACT, 40 CFR 63, Subpart YYYY, 

applies to combustion sources located at major sources of HAP. 

GEP/S is an area source of HAPs and therefore is not an affected 

source under the Combustion Turbine MACT. 

• The MACT for cooling towers, 40 CFR 63, Subpart Q, prohibits 

the use of chromium based water treatment chemicals in an 

industrial process using a cooling tower. This standard does not 

apply because the facility is not a major source of HAPs, and 

chromium-based cooling tower water treatment chemicals will not 

be used. 

D. Process/Equipment Description 

Green Energy Partners / Stonewall, LLC has proposed installation of the 

following combustion turbines and heat recovery steam generators: 

• Two GE (Model GE.7FA) or two Siemens (SGT6-5000F5) natural 

gas-fired combustion turbine generators with inlet evaporative coolers 

(CCT1 and CCT2); each GE combustion turbine will produce 204.6 

MW with the inlet evaporative coolers on and 193.3 MW with them 

off (at 92 °F). The maximum total gross power output is expected to 

be 230.9 MW at 18° F. For the Siemens option, each CT will produce 

217.3 MW with the evaporative coolers on and 207.4 MW with them 

off (at 92 °F). The maximum total gross power output is expected to 

be 230.9 MW at 18° F. 

• Two heat recovery steam generators (HRSG) with supplementary 

natural gas-fired duct burners (DB1, DB2), each rated at 650 

MMBtudir heat input for the GE7FA.05 or 450 MMBtuihr heat input 

for the SGT6-5000F5. 

GEP/S has proposed the installation of the following ancillary equipment: 

• One reheat, condensing steam turbine driven electric generator 

designed for variable pressure operation and capable of producing 

approximately 350 MW of electrical power; 

• One natural gas-fired auxiliary boiler, rated at 75 MMBtu/hr heat input 

(AB1); 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 11 

• One natural gas-fired fuel gas heater, rated at 20.0 MMBtu/hr heat 

input (FGH1); 

• One diesel-fired Emergency Fire Water Pump, rated at 330 bhp (2.54 

MMBtu/hr heat input) (EFP1); 

• One diesel-fired Emergency Generator, rated at 2,088 bhp / 1,500 kW 

(15.04 MMBtu/hr heat input) (EG-1); and 

• One 1,250-gallon fuel oil storage tank (EGT). 

• One 400-gallon fuel oil storage tank (FWPT) 

• One 12,000 gallon aqueous ammonia storage tank 

• Ten cell mechanical draft cooling tower (MCT-1) 

Combustion Turbine Generators (CT) 

Each gas turbine power block will include an advanced firing temperature 

combustion turbine air compressor section, gas combustion system 

(utilizing dry, low-NO„ combustors), power turbine, and a generator. 

The gas turbine is the main component of a combined-cycle power system. 

First, air is filtered, cooled by the evaporative cooler during warm 

weather, and compressed in a multiple stage axial flow compressor. 

Compressed air and fuel are mixed and combusted in the turbine 

combustion chamber. Lean pre-mix dry low-NO, combustors minimize 

NO, formation during natural gas combustion. Hot exhaust gases from the 

combustion chamber are expanded through a multi-stage power turbine 

that results in energy to drive both the air compressor and electric power 

generator. 

In combined-cycle mode, the exhaust gas exiting the power turbine is 

ducted to a boiler commonly known as an HRSG where steam is produced 

to generate additional electricity in a steam turbine generator. Natural gasfired duct burners located within the HRSGs are used for supplementary 

firing to increase steam output. 

The combustion turbines are designed to operate in the dry low-NO, mode 

at loads from approximately 60 percent up to 100 percent rating and will 

normally be taken out of service for scheduled maintenance, or as dictated 

by economic or electrical demand conditions. 
Green Energy Partners I Stonewall, LLC 

April 30, 2013 

Page 12 

Turbine Inlet Evaporative Coolers 

Under certain meteorological conditions (e.g., hot, humid days), 

evaporative cooling will be used to cool the air entering the combustion 

turbine (CT) by evaporating water sprayed into the air intake, just behind 

the inlet filter. A mist eliminator will assure that no water droplets reach 

the turbine blades. The purpose of the cooling is to increase the density of 

the air entering the CT to increase its output capacity. The CT is a 

volumetric machine and thus produces more power with more pounds of 

air entering the machine. The evaporative cooler achieves this goal in the 

summer time by cooling the air when temperatures are high. 

Heat Recovery Steam Generators (HRSG) with Duct Burners (DB) 

The proposed facility will use two HRSGs, one for each CT, which will 

use waste heat to produce additional electricity. Each HRSG will act as a 

heat exchanger to derive heat energy from the CT exhaust gas to produce 

steam that will be used to drive a steam turbine generator (ST). The 

HRSGs system will extract heat from the exhaust of each gas turbine. 

Exhaust gas entering the HRSG at approximately 1,100 °F will be cooled 

to 165 °F to 200 °F by the time it leaves the HRSG exhaust stack. Steam 

production in the HRSGs may be augmented using duct burners (DBs) 

that will be fired by natural gas, and will be limited by a permit condition 

to operate 1,400 hours a year (each) on a rolling 12-month basis. The 

proposed DBs will have a firing rate of 650 MMBtu/hr each for the GE 

7FA.05 and 450 MMBtu/hr for the Siemens SGT6-5000F5. The heat 

recovered is used in the combined-cycle plant for additional steam 

generation and natural gas/feedwater heating. Each HRSG will include 

high-pressure superheaters, a high-pressure evaporator, high-pressure 

economizers, reheat sections (to reheat partially expanded steam), an 

intermediate-pressure superheater, an intermediate-pressure evaporator, an 

intermediate-pressure economizer, a low-pressure superheater, a lowpressure evaporator, and a low-pressure economizer. Control devices such 

as selective catalytic reduction (SCR) and oxidation catalysts will be 

installed to control NOxand CO, respectively. 

The stack will be equipped with a Continuous Emissions Monitoring 

System (CEMS) for monitoring emissions of NOx, CO and concentration 

of oxygen. 

Steam Turbine Generator (ST) 

The proposed project includes one reheat, condensing steam turbine 

designed for variable pressure operation. The high-pressure portion of the 

steam turbine receives high-pressure super-heated steam from the HRSGs, 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 13 

and exhausts to the reheat section of the HRSGs. The steam from the 

reheat section for the HRSGs is supplied to the inteimediate-pressure 

section of the turbine, which expands to the low-pressure section. The 

low-pressure turbine also receives excess low-pressure superheated steam 

from the HRSGs and exhausts to the condenser which is cooled with water 

from a cooling tower. The steam turbine set is designed to produce up to 

approximately 350 MW of electrical output at ISO conditions with duct 

firing. 

Ten Cell Mechanical Draft Cooling Tower (MCT1-MCT10) 

The proposed project will include a 10-cell, 187,400 gal/min mechanical 

draft cooling tower to service the condenser for the steam turbine. The 

tower will employ plume abatement to eliminate visible plumes except 

during extreme cold weather conditions. The cooling tower will also 

utilize highly efficient drift eliminators to reduce water losses during 

operation. The drift eliminators also serve the purpose of reducing 

particulate emissions from dissolved solids in the drift water. 

Auxiliary Boiler (AB1) 

The proposed facility will include an auxiliary boiler (AB I). The 

auxiliary boiler will provide sealing steam to the steam turbine generator 

at start-up and at cold starts to warm up the steam turbine generator rotor. 

The steam from the auxiliary boiler will not be used to augment the power 

generation of the CTGs or steam turbine. The proposed AB1 will be fired 

with natural gas, with a firing rate of 75 MMBtu/hr. GEP/S has requested 

the boiler to be permitted to operate without annual operating restrictions. 

Fuel Gas Heater (FGH1) 

The proposed facility will include a fuel gas heater (FGH1). The heater 

will be used to warm up the incoming natural gas fuel to prevent freezing 

of the gas regulating valves under certain gas system operating conditions. 

The proposed FGH1 will be fired with natural gas only and have a firing 

rate of 20 MMBtu/hr. 

Diesel-Fired Emergency Generator (EG1) 

The proposed facility will include a 2,088 bhp (15.04 MMBtu/hr and 

1,500 kW/hr) diesel-fired emergency generator that will be operated up to 

500 hours per year which includes the testing and maintenance hours. The 

emergency generator will provide power in emergency situations for 

turning gears, lube oil pumps, auxiliary cooling water pumps and water 

supply pumps. Testing and maintenance operation of the emergency 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 14 

generator will be limited to 100 hours per year. The emergency diesel 

generator is not intended to provide sufficient power for a black start, peak 

shaving or non emergency power. 

Diesel-Fired Emergency Fire Water Pump (EFP-1) 

The proposed project will include a 330 bhp (2.54 MMBtu/hr) diesel-fired 

fire water pump operated as a fire water pump driver. The unit will be 

limited to 500 hours per year, including monthly testing and maintenance. 

Fuel Oil Storage Tanks 

The proposed project will include a 1,250-gallon fuel oil storage tank to 

provide fuel for the emergency generator, and a 400-gallon fuel oil tank to 

provide fuel for the fire water pump. 

Aqueous Ammonia Storage Tank 

The proposed project will include a 12,000-gallon aqueous ammonia 

storage tank to provide ammonia for the Selective Catalytic Reaction 

systems on the combined cycle combustion turbines. 

Schedule of Project 

NRO received the modeling protocol for Green Energy Partners / 

Stonewall, LLC and Form 7 air permit application on July 24, 2012 (dated 

July 19, 2012). Application amendment information was submitted by 

GEP/S and received on August 16, 2012 and a revised application on 

October 4, 2012, and November 13, 2012. The proposed date for 

beginning actual construction is fall 2013. The target date for startup and 

electrical generation is 2014-2016. 

III. Emissions Calculations 

A. Criteria Pollutants 

Proposed emissions are primarily products of combustion from the 

combustion turbines and duct burners. There are also emissions from the 

cooling towers, auxiliary boiler, fuel gas heater, emergency generator, and 

the emergency firewater pump. 

Emissions from the combined-cycle units vary depending on ambient 

temperature, relative humidity, and percent of operating capacity ("load") 

of the unit. The CT manufacturer — GE or Siemens - provided criteria 

pollutant emissions for 6 operating scenarios (a.k.a. Operating Points) for 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 15 

the GE 7FA.05, and four operating scenarios for the Siemens SGT6-

5000F5 reflecting various temperature, humidity, and load conditions. 

Emissions for all operating loads (identified as Operating Point 1 through 

Operating Point 4, and one through 6) are shown in Table 5-2, and Table 

5-3 of the application. SO2emissions are based on use of natural gas 

having a sulfur content of 0.1 grains per 100 standard cubic feet of gas, the 

maximum sulfur content allowed by the proposed permit. 

Short-term emissions for the CTs and DBs have been based on the 

maximum hourly emission rates ("worst-case" from all operating 

scenarios) for each pollutant, as shown in Table 3a and Table 3b below. 

Table 3a. GE 7FA. 05 operating scenarios having highest short-term emissions (each C 

Pollutant Operating 

Point 

% 

Load 

Ambient 

Temp. 

(°F) 

Relative 

Humidity 

(%) 

r 

Inlet 

Ev a porative 

Coolers 

(On/Off) 

Emissions 

(1hs/hr) 

NOx 4 100 18 60 Off 21.00 

CO 4 100 18 60 Off 12.70 

SO2 4 100 18 60 Off 0.75 

VOC 4 100 18 60 Off 7.29 

PM-10 4 100 18 60 Off 16.2 

PM-2.5 4 100 18 60 Off 16.2 

Note: Operating point 4 shown above is with Duct Burner operation. 

Table 3b. Siemens SGT6-5000F5 operating scenarios having highest short-term 

emissions (each CT) 

Pollutant Operating 

Point Load 

Ambient 

Temp. 

Relative 

Humidity 

-

(°F) 

Inlet 

Evaporative 

Coolers 

Emissions 

(lbs/hr) ('Y0) (On/Off) 

NOx 6 100 59 60 On 20.40 

CO 6 100 59 60 On 12.50 

SO2 6 100 59 60 On 0.696 

VOC 6 100 59 60 On 5.68 

PM-10 6 100 59 60 On 14.5 

PM-2.5 6 100 59 60 On 14.5 

Note: Operating point 6 shown above is with Duct Burner operation. 

Annual emissions for the CTs were calculated based on the combinations 

of operating scenarios shown in Table 4a and Table 4b below. The 

combination, proposed by GEP/S in its application, yields a more realistic 

"worst-case" representation for annual emissions: it is assumed that the 

facility can operate 8,760 hours per year for each pollutant, but not at 

worst-case ambient conditions (such conditions would not occur for all 

8,760 hours). As listed in Table7 below, the worst case CT annual 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 16 

emissions for CO and VOC are based on annual emissions that include the 

startup and shutdown scenarios shown in Tables 4a and 4b. The worst 

case CT annual emissions for all other pollutants are based on the 

combination of CT with duct burner firing at 1,400 hours per year and the 

CT only at 7,360 hours per year. (Please note that the draft pennit 

requires GEP/S to include startup and shutdown emissions of all criteria 

pollutants in calculating emissions to show compliance with its annual 

emissions limits) The maximum annual turbine emissions were 

calculated in GEP/S's application and are included in Attachment A. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 17 

Table 4a. GE 7FA. 05 operating scenario structure used as basis for annual emissions (each CT) 

Hours Case 

0/0 

Load 

Inlet 

Chilling 

(0 n/Ofl) 

Ambient 

Temp. 

(° F) 

Relative 

Humidity 

(%) 

Emissions (lbs/hr) 

, CO VOA PM-I0 P 

2. f , 

S' O , 

- 

11'

> S0 

.1 100 Off 0 60 16.0 9.9 2.8 9.6 9.6 0.58 0.31 

1400 4 100 Off 18 60 21.00 12.7 7.29 16.2 16.2 0.75 0.40 

960 • NA NA NA NA NA 0 0 NA NA NA NA 

400 

W/ 

DB 

4 00 Off 0 60 21.00 12.7 7.29 16.2 16.2 0.75 NA 

4182 

O 

DB 

1 100 Off 0 60 16.0 9.9 2.8 9.6 9.6 0.58 0.31 

25.7 Hot 

Start NA NA NA NA 72.9 771.4 25.7 NA NA NA NA 

113.1 Warm 

Start NA NA NA NA 158.1 468.7 25.2 NA NA NA NA 

33.3 Cold. 

Start NANA NA NA 90.4 631.6 89.8 NA NA NA NA 

45.5 ShutNA 

down NA NA NA 72.9 745.7 38.6 NA NA NA NA 

Operating 

Mode 

W/O Duct 

Burner 

W/Duct 

Burner 

Start Up / 

Shut Down 

SO2emissions are based on conversion of all sulfur in fuel to SO2, so startup and shutdown do not affect SO2emissions appreciably. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 18 

Table 4b. Siemens SGT6-5000F5 operating scenario structure used as basis for annual emissions (each CT) 

Operating 

Mode Hours Case 0/° Load 

Inlet 

Chilling 

(On/Off) 

Ambient 

Temp. 

(° F) 

Relative 

Humidity 

(%) NOx CO 

Emissions 

VOC 

(lbs/hr) 

PM-10/ 

PM-2.5 SO2il 2 SO 4 

W/O Duct 

Burner 7360 1 100 Off 0 60 17.1 10.4 3.0 14.5 0.696 0.31 

W/Duct 

Burner 1400 4 100 Off 18 60 20.4 12.5 5.7 14.5 0.75 0.40 

Start Up / 

Shut Down 

2960 Offline NA NA NA NA NA 0 0 NA NA NA 

1400 

W/ 

DB 

4 100 Off 0 60 20.4 12.5 5.7 14.5 0.75 0.40 

4244 

W/O 

DB 

1 100 Off 0 60 17.1 10.4 3.0 14.5 0.696 0.31 

58.7 Hot 

Start NA NA NA NA 106.9 405.0 161.3 NA NA NA 

47.5 WarmNA 

Start NA NA NA 112.1 413.7 165.8 NA NA NA 

10.7 Cold 

Start NA NA NA NA 106.9 444.4 130.3 NA NA NA 

39.0 ShutNA 

down NA NA NA 125.0 385.0 150.0 NA NA NA 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 19 

NOR, CO, and SO2emissions from the auxiliary boiler and fuel gas heater 

were calculated based on the proposed BACT emission rates for natural 

gas-fired boilers and heaters provided in GEP/S's application. PM 10 and 

PM-2.5 emissions for the auxiliary boiler were calculated based on vendor 

data. The auxiliary boiler has a capacity of 75 MMBtu/hr and the fuel gas 

heater has a capacity of 20.0 MMBtu/hr and both will burn natural gas. 

Annual emissions for the boiler and heater are based on 8760 hours of 

operation per year. Hourly and annual emissions are shown in Table 5. 

Table 5. Emissions from auxiliary boiler (AB1) and fuel gas heater FGHI 

Pollumilt 

Auxiliary Boiler 

lbs/hr 

(A BI ) 

tons') iFuel Gas Heater (FGH1) 

lbs/hr tons/yr 

NO,' 0.83 3.61 0.22 0.96 

CO' 2.78 12.15 0.74 3.24 

VOCb 0.15 0.66 0.04 0.18 

PM-10 (Filterable 

and Condensable) 0.15 0.66 0.04 0.18 

PM-2.5 

(Filterable and 

Condensable) 

0.15 0.66 0.04 0.18 

SO2 0.02 0.087 0.005 0.002 

GHG and CO2e 8,873 38,856 2,365 10,362 

aBased on emission factors from the proposed BACT emission rates for natural gas-fired boilers and 

heaters. 

bBased on emission factor from AP-42, Table 1.4-2 (Natural Gas Combustion). 

Based on vendor data (auxiliary boiler only). 

Emissions from the emergency generator and the emergency fire water 

pump (EG1 and EFP1) were based on the NSPS Subpart MI limits for 

Stationary Compression Ignition Internal Combustion Engines. The 

emergency units will use ultra-low sulfur distillate oil having a maximum 

sulfur content of 0.0015% by weight consistent with NSPS Subpart IIII 

requirements . Annual emissions from EG1 and EFP1 are based on 500 

hours of operation each. Short-term and annual emissions are shown in 

Table 6. 

Table 6. Emissions from emer encv eauivment EG1 and EFP1 

Pollutant 

Emergency Generator (EG1) 

tons/yr 

Fire Water Pump 

lbs/hr 

(EFP1) 

lbs/hr tons/yr 

NO,,a 21.98 5.49 2.17 0.54 

COa 12.02 3.0 1.72 0.47 

VOCa' e 21.98 5.49 2.17 0.54 

PM-10d 1.37 0.34 0.22 0.0.00543 

PM-2.5 1.37 0.34 0.22 0.0.00543 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 20 

SO2b 0.025 0.0006 0.00039 0.000097 

GHG and 

CO2e 2,630 658 415 104 

aBased on emission factors from NSPS Subpart IIII limits for Stationary Compression Ignition Internal 

Combustion Engines (reference 40CFR 89.112 Table 1). NO„ emissions are assumed to be worst case as 

entire NMHC + NO, emission standard is used for NO, emission factor. 

blb/hr based on fuel sulfur. 

VOC = TOC. 

dSince AP-42 does not provide an emission factor for PM-10, the PM emission rate was multiplied by a 

factor of 2 to conservatively estimate the contribution of condensable particulate matter (CPM). 

A summary of estimated annual emissions from the proposed facility, 

showing the contribution from each emission unit type, is shown in Table 

7. 

Table 7. - Annual emissions of criteria nollutan 0 ro osed facility (tons/vr 

Pollutant 

Combined 

cycle units 

(CT-1+DB1, 

CT-2+DB2) 

Auxiliary 

Boiler 

(AB1) 

Fuel Gas 

Heater 

(FGH1) 

Emergency Emergency 

Firewater 

Pump 

(EFP1) 

Median 

ical 

Draft 

Cooling 

Tower 

(MCT1) 

Generator Total 

(EG1) 

NOx 

148.2" / 

154.48b 

3.61 0.96 5.49 0.54 159a/ 

164.9b 

CO 188.6a/124.8b 12.15 3.24 3.0 0.47 205.6a / 

143.6" 

VOC 30.96a / 

45.26" 

0.66 0.18 5.49 0.54 37.6a/ 

51.9b 

PM-10 

(Condensa 

ble and 

filterable) 

93.66a/ 

94.68b 

0.66 0.18 

0.34 0.00543 10.27 105.2a/ 

106.1b 

PM-2.5 

(Condensa 

ble and 

filterable) 

93.66a/ 

94.68 

0.66 0.18 

0.34 0.00543 3.19 98.1a / 

99.1b 

SO2 5.2a / 5.266 0.0857 0.02 0.0006 0.000097 5.44a/ 

5.37b 

GHG / 

CO2e 

2,418,272a/ 

2,414,2966 

38,856 10,362 

658 104 

2,468,468a 

/ 

2,464,490" 

a - Based on the GE F7A.05 emissions (includes both w/o duct burner and/ with duct burner 

operations) 

b - Based on the Siemens SGT6-5000F5 emissions (includes both w/o duct burner and with 

duct burner operations) 

Emission calculations and supporting documentation for criteria pollutants 

can be found in Appendix B of GEP/S's revised applications dated 

November 13, 2012. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 21 

HAPs/Toxic Pollutants 

Hazardous air pollutant (HAP) emissions were calculated to determine 

whether the proposed facility has the potential to be a major source of 

HAPs under Title III of the Clean Air Act Amendments of 1990. Based 

on worst case emission factors, HAP emissions are summarized in Tables 

8 and 9 below for the GE and Siemens turbines, respectively; detailed 

emission calculations are provided in Table B-5 of Appendix B of 

GEP/S's revised permit applications dated October 4, 2012 and November 

13, 2012. 

Table 8. GE 7FA.05 - Potential HAP emissions 

Pollutant Potential emissions 

lbs/hr TPY 

1,3 Butadiene 1.44E-03 5.90E-03 

2-Methylnaphthalene 2.36E-05 2.48E-05 

3-Methylchloranthrene 1.77E-06 1.86E-06 

7,12-Dimethylbenz(a)anthracene 1.58E-05 1.65E-05 

Acenaphthene 8.06E-05 2.16E-05 

Acenaphthylene 1.63E-04 4.22E-05 

Acetaldehyde 1.27E-01 5.48E-01 

Acrolein 2.03E-02 8.76E-01 

Anthracene 2.69E-05 8.61E-06 

Arsenic 1.15E-03 2.60E-04 

Benz(a)anthracene 1.60E-05 5.43E-06 

Benzene 5.44E-02 1..70E-01 

Benzo(a)pyrene 5.79E-06 2.39E-06 

Benzo(b)flouoranthene 1.99E-05 6.38E-06 

Benzo(g,h,l)perylene 1.01E-05 3.47E-06 

Benzo(k)fluoranthene 5.67E-06 2.83E-06 

Beryllium 6.89E-05 1.56E-05 

Cadmium 6.31E-03 1.43E-03 

Chromium 8.04E-03 1.82E-03 

Chrysene 2.73E-05 8.23E-06 

Cobalt 4.82E-04 1.09E-04 

Dibenzo(a,h)anthracene 8.23E-06 3.00E-06 

Dichlorobenzene 1.18E-03 1.24E-03 

Ethylbenzene 9.99E-02 4.38E-01 

Fluoranthene 8.71E-05 2.41E-05 

Fluorene 2.83E-04 7.29E-05 

Formaldehyde 7.65E-01 3.09E+00 

Hexane 1.77E+00 1.86E+00 

Indeno(1,2,3-cd)pyrene 9.38E-06 3.76E-06 
Green Energy Partners / Stonewall, LLC 

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Napthalene 6.97E-03 1.90E-02 

PAHs 6.87E-03 3.01E-02 

Phenanathrene 7.47E-04 2.00E-04 

Propylene Oxide 9.05E-02 3.97E-01 

Pyrene 7.67E-05 2.31E-05 

Toluene 4.15E-01 1.78E+00 

Xylene 2.04E-01 8.76E-01 

Lead compounds 2.87E-03 6.50E-04 

Manganese 2.18E-03 4.94E-04 

Mercury 1.49E-03 3.38E-04 

Nickel 1.21E-02 2.73E-03 

Selenium 1.38E-04 3.12E-05 

Total HAPs 3.60* 10.10 

Max Single HAP - 3.09 

* Federal major Hazardous Air Pollutant (HAP) source thresholds are annual 

(tons/yr); there are no short-term total HAP thresholds established. 

Table 9. Siemens SGT6-5000F5- Potential HAP emissions 

Pollutant Potential emissions 

lbs/hr TPY 

1,3 Butadiene 1.46E-03 5.98E-03 

2-Methylnaphthalene 1.71E-05 2.02E-05 

3-Methylchloranthrene 1.28E-06 1.51E-06 

7,12-Dimethylbenz(a)anthracene 1.14E-05 1.34E-05 

Acenaphthene 8.01E-05 2.12E-05 

Acenaphthylene 1.63E-04 4.18E-05 

Acetaldehyde 1.29E-01 5.55E-01 

Acrolein 2.06E-02 8.88E-02 

Anthracene 2.62E-05 8.15E-06 

Arsenic 1.08E-03 2.05E-04 

Benz(a)anthracene 1.55E-05 5.08E-06 

Benzene 5.43E-02 1.72E-01 

Benzo(a)pyrene 5.46E-06 2.16E-06 

Benzo(b)flouoranthene 1.94E-05 6.04E-06 

Benzo(g,h,l)perylene 9.79E-06 3.24E-06 

Benzo(k)fluoranthene 5.18E-06 2.49E-06 

Beryllium 6.49E-05 1.23E-05 

Cadmium 5.95E-03 1.13E-03 

Chromium 7.57E-03 1.44E-03 

Chrysene 2.68E-05 7.89E-06 

Cobalt 4.54E-04 8.61E-05 

Dibenzo(a,h)anthracene 7.90E-06 2.77E-06 

Dichlorobenzene 8.53E-04 1.01E-03 

Ethylbenzene 1.01E-01 4.43E-01 

Fluoranthene 8.63E-05 2.36E-05 

Fluorene 2.82E-04 7.24E-05 
Green Energy Partners / Stonewall, LLC 

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Page 23 

Formaldehyde 7.54E-01 3.11E+00 

Hexane 1.28E+00 1.51E+00 

Indeno(1,2,3-cd)pyrene 8.89E-06 3.41E-06 

Napthalene 6.85E-03 1.91E-02 

PAHs 6.96E-03 3.05E-02 

Phenanathrene 7.43E-04 1.97E-04 

Propylene Oxide 9.18E-02 4.02E-01 

Pyrene 7.53E-05 2.21E-05 

Toluene 4.19E-01 1.81E+00 

Xylene 2.06E-01 8.88E-01 

Lead Compounds 2.70E-03 5.13E-04 

Manganese 2.05E-03 3.90E-04 

Mercury 1.41E-03 2.67E-04 

Nickel 1.14E-02 2.15E-03 

Selenium 1.30E-04 2.46E-05 

Total HAPs 3.11* 9.041 

Max Single HAP 3.11 

Based on Tables 8 and 9, the maximum total HAPs from the proposed 

facility would be 10.10 tons per year; the single HAP emitted at the 

highest rate is formaldehyde at 3.11 tons per year. Major source 

thresholds for HAPs are 10 tons per year for an individual HAP or 25 tons 

per year total HAPs. Accordingly, GEP/S is not a major source of HAP 

and is not subject to requirements under 40 CFR Part 63 Subpart YYYY, 

the Combustion Turbine Maximum Achievable Control Technology 

(MACT) standard. 

Since the combustion turbines are not subject to the Combustion Turbine 

MACT, the units are exempt to the state toxics standards in 9 VAC 5-60-

300 et seq. Please see Section IV.B for further discussion of toxics 

emissions from the proposed facility. 

IV. Regulatory Review and Considerations 

A. Criteria Pollutants 

The proposed facility meets the definition of major source under 9 VAC 5 

Chapter 80 Article 8 (Prevention of Significant Deterioration (PSD) 

because it is a fossil-fuel-fired steam electric plant of more than 250 

MMBtu/hr heat input capacity and has the potential to emit (PTE) more 

than 100 tons per year of a regulated pollutant. When a new facility is 

subject to PSD, any regulated pollutant for which the area is in attainment 

having a PTE above the significance level is also subject to PSD. 

Additionally, based on 9VAC5 Chapter 85, GHGs from the proposed 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 24 

project are subject to regulation based on PTE. The pollutants subject to 

PSD for the proposed project are CO, NO,, PM, PM10, and GHG. 

The proposed facility will be locating in an area classified as an ozone and 

PM-2.5 nonattainment area as well as being part of the Ozone Transport 

Region (OTR) and meets the definition of a major source under 9 VAC 5 

Chapter 80 (Permits for Major Stationary Sources and Modifications — 

Nonattainment Areas or Ozone Transport Region). Accordingly, the 

proposed facility is subject to major nonattainment NSR permitting for 

NO, emissions from the GE 7FA.05 CT and NO, and VOC emissions 

from the Siemens SGT6-5000F5-CT. Although the area is also 

nonattainment for PM-2.5, the proposed PM-2.5 emissions do not exceed 

the major source threshold and therefore Article 9 is not applicable. 

Table 10 below compares the maximum proposed net emissions increases 

from GEP/S with PSD and NAA-MNSR significant increase levels. 

Table 10. Proposed emissions levels 

Pollutant 

Maximum 

Emissions 

(tPY) 

Allowable or 

PSD Significant PSD 

Threshold 

Levels (tpy) 

Subject to 

(Article 8) 

Non 

Attainment 

MNSR (Article 

9)e 

NO„ 159a/ 164b 40 Article 8 &Article 

9 

CO 207a/ 143b 100 Article 8 

VOC 38a 152b NA" Article 9e 

PM 105a / 106b 25 Article 8 

PM-10 105a/ 106b 15 Article 8 

PM-2.5 98a199b NAd Article 9 

SO2 5.44a/ 5.37b 10 No 

GHG (CO2e) 2,468,228a/ 

2,464,25b 100,000 Article 8 

Sulfuric acid 

mist (H2SO4) 2.87a/ 2.81b 7 No 

Lead (Pb)1 0.02 0.6 No 

a— Based on the GE F7A.05 emissions 

b — Based on the Siemens SGT6-5000F5 emissions 

c — Article 9 for the Siemens CT option only 

d — Although there are PSD significance levels for VOC and PM-2.5, Loudoun County is nonattainment for ozone (VOC) and PM-2.5; Non Attainment MNSR requirements apply if VOC 

emissions are > 50 tpy and also if PM-2.5 emissions are > 100 tpy. 

e — All pollutants were also reviewed for permitting applicability under Article 6 (mNSR). 

The pollutants subject to nonattainment NSR are NON, VOC (if using the 

Siemens model), and PM-2.5 and PSD review are NOx, PM, PM-10, and 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 25 

CO. PSD regulations require modeling analysis to demonstrate 

compliance with the NAAQS and PSD increments (NO„, PM-10, and 

CO). It should be noted that although there is a designated significance 

level for PM, and VOC, there are no modeling requirements for these 

pollutants. The details of the modeling analysis are provided in 

Attachment C. 

The facility is locating in a PM-2.5 nonattainment area but does not trigger 

MNSR. PM-2.5 was evaluated under Chapter 80, Article 6 and BACT 

was applied in accordance with 9VAC5-50-260. 

B. HAPs/Toxic Pollutants 

The electric generating units proposed by GEP/S are subject to the toxic 

pollutant standards in 9 VAC 5-60-300. As a result, GEP/S conducted an 

evaluation of toxic pollutants in comparison to the emission standards in 9 

VAC 5-60-300. This evaluation included a modeling analysis for five 

pollutants for which uncontrolled emissions were above the exemption 

levels in 9 VAC 5-60-300 (acrolein, formaldehyde, cadmium, chromium, 

and nickel). The modeling analysis indicates that the impacts of the five 

pollutants are well below their applicable Significant Ambient Air 

Concentrations (SAACs). Attachment B includes a table showing 

emissions of toxic pollutants from the proposed facility compared to the 

exemption thresholds. Attachment C contains the modeling results. 

Table 11 

Pollutant tons/year a tons/year b 

Acrolein 8.76E-01 8.88E-02 

Cadmium 2.25E-02 2.25E-02 

Chromium 2.86E-02 2.86E-02 

Formaldehyde 3.09E+00 3.11E+00 

Nickel 4.29E-02 4.29E-02 

a — Based on the GE F7A.05 emissions 

b — Based on the Siemens SGT6-5000F5 

40 CFR 63 Subpart YYYY, National Emissions Standards for HAPs from 

Stationary Combustion Turbines, was promulgated March 5, 2004 and 

applies to CTs located at major HAP sources. According to GEP/S's 

application, the HAP emissions from the proposed GEP/S facility do not 

exceed major source thresholds for HAPs, i.e., 10 tons per year of a single 

HAP or 25 tons per year of all HAPs combined. Accordingly, the 

proposed facility is not subject to the MACT standard. It should be noted 

that the MACT stipulates oxidation catalyst as one way to comply with the 

MACT limits (oxidation catalysts not only reduce CO and VOC 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 26 

emissions, they also reduce volatile HAP emissions such as formaldehyde, 

toluene, acetaldehyde and benzene). GEP/S has proposed oxidation 

catalyst to control CO and VOC from its facility. 

C. Modeling Results 

The United States Forest Service (USFS), the United States Fish and 

Wildlife Service (FWS), and the National Park Service (NPS) each stated 

in an e-mail dated June 20, 2012, June 20, 2012, and July 3, 2012, 

respectively, that an AQRV analysis was not required since the project is 

not expected to show any significant additional impacts to AQRVs. 

Therefore, only a Class I area analysis to assess compliance with the Class 

I PSD increments was required. 

The Class I and Class II air quality modeling analyses conform to 40 CFR 

Part 51, Appendix W - Guideline on Air Quality Models and were 

performed in accordance with their respective approved modeling 

methodology that were included in a protocol that was submitted in 

advance by the proposed facility. 

The air quality modeling analyses results show compliance with all 

applicable NAAQS and PSD increments. The DEQ's air quality modeling 

analyses technical review memorandum is included as Attachment C. 

B. Control Technology Analysis 

1. BACT vs. LAER 

The permitting process involves two methods of control 

technology review: Best Available Control Technology (BACT) 

and Lowest Achievable Emission Rate (LAER). In geographic 

locations where ambient pollutant concentrations exceed the 

NAAQS, permit applicants are required to meet LAER. LAER is 

defined as the lowest emission rate achieved in practice on a 

similar design. Only technical and environmental factors are 

considered, without regard to cost. In areas where pollutant 

concentrations are within the NAAQS, the applicant must apply 

BACT. BACT represents the most stringent emission limit that is 

technically, environmentally, and economically feasible. EPA 

policy requires that LAER is the first consideration in the BACT 

analysis. Only when LAER is proven to be environmentally or 

economically infeasible may BACT be less stringent than LAER. 

However, in no case may BACT result in an emission rate less 

stringent than required by federal regulations such as NSPS or 

MACT requirements. Loudoun County is considered non 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 27 

attainment for ozone and PM-2.5, and is attainment for CO, NOx, 

S02, and PM-10. Therefore, a LAER analysis is required for 

emission controls for NO, and VOC, and BACT is considered for 

the remaining pollutants. 

2. LAER Requirements 

The proposed facility will be located in an ozone nonattainment 

area which is also part of the OTR. It will be major for NO, and 

VOC emissions for the Siemens CTGs configuration (and major 

for NO, for the GE CTGs configuration). Therefore, in accordance 

with 9VAC5-50-270, LAER must be applied for those pollutants. 

The NO, emissions are also subject to BACT as the region is 

attainment/unclassified for the NOx NAAQS. However because 

the region is nonattainment for the 1997 and 2008 8-hour ozone 

standards, LAER will be applied to the proposed CTGs for NOR. 

By applying LAER, which is the top level of control, the BACT 

requirement is presumed to be met. 

Emission units addressed in the LAER determination submitted by 

GEP/S include the combined-cycle units, the auxiliary boiler, the 

fuel gas heater, the emergency generator, and the emergency 

firewater pump. 

Combined-Cycle Combustion Turbine (CT) 

NGControl 

The combustion turbines and the HRSG duct burners are 

responsible for most of the emissions from the facility. The 

following control technologies were identified by GEP/S as 

applicable to NO, treatment for combined-cycle combustion 

turbines: 

• Selective Catalytic Reduction (SCR) 

• SCONOXTM 

• Selective Non-Catalytic Reduction (SNCR) and Non-Selective 

Catalytic Reduction (NSCR) 

• Dry Low-NO, (DLN) Combustors 

• Water or Steam Injection 

• XONONTM, LoTO,Tm, THERMALLONO,Tm, and PahlmannTM 

Of the NO, control technologies that were reviewed for the GEP/S 

facility, SCR and Dry Low-NO, (DLN) combustors were the two 

most stringent techniques that have been applied to a combined 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 28 

cycle turbine facility. A discussion of the control technologies is 

presented below. 

SCR is a process that involves post combustion removal of NO, 

from the flue gas with a catalytic reactor. In the SCR process, 

ammonia injected into the turbine exhaust gas reacts with nitrogen 

oxides and oxygen to form nitrogen and water. SCR converts 

nitrogen oxides to nitrogen and water through several possible 

reactions that take place on the surface of a catalyst. The function 

of the catalyst is to effectively lower the activation energy of the 

NO, decomposition reaction. Technical factors related to this 

technology include increased turbine backpressure, exhaust 

temperature materials limitations, theitual shock/stress during 

rapid starts, catalyst masking/blinding, reported catalyst failure due 

to "crumbling", design of the NH3injection system, and high NH3 

slip. SCR using ammonia as a reagent represents the state-of-theart for back end gas turbine NO, removal from base load, 

combined-cycle turbines. 

SCONOXTM is an emerging post-combustion technology that 

removes NO, from the exhaust gas stream after formation in the 

combustion turbine. SCONOXTM employs a potassium carbonate 

bed that adsorbs NO, where it reacts to form potassium nitrates. 

Periodically, a hydrogen gas stream is passed over the bed, 

resulting in the reaction of the potassium nitrates to re-form the 

potassium carbonate and the ejection of nitrogen gas and water. 

SCONOXTM is reportedly capable of achieving NO„ emission 

reductions of 90% or more for combustion turbine application, and 

it is currently operating on several small natural gas-fired turbines. 

The most notable advantage of SCONOXTM over SCR is that it 

reduces NO, without the use of ammonia. SCONOXTM thereby 

eliminates the possibility of "ammonia slip", or emissions of 

excess (unreacted) ammonia, that is present with use of SCR for 

NO, control. Similar to SCR, SCONOXTM only operates within a 

specific temperature range. 

GEP/S's application eliminated SCONOXTM as not technically 

feasible for application to this project since it is no longer being 

offered for large combustion turbines. SCONOXTM is considerably 

more complex than SCR, would consume significantly more water, 

and would require more frequent cleaning and other maintenance. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 29 

DEQ concurs with GEP/S's conclusion that at the present time, 

SCONOXTM cannot be considered a feasible control option for the 

proposed project. 

SNCR and NSCR - Two other back-end catalytic reduction 

technologies, SNCR and NSCR, have been used to control 

emissions from certain other combustion process applications. 

However, both of these technologies have limitations that make 

them inappropriate for application to combustion turbines. SNCR 

requires a flue gas exit temperature in the range of 1,300 to 2,100 

°F, with an optimum operating temperature zone between 1,600 

and 1,900 °F. Simple-cycle combustion turbines have exhaust 

temperatures of approximately 1,100 °F, and combined-cycle 

turbines have exhaust temperatures much lower than simple-cycle 

turbines. Therefore, additional fuel combustion or a similar energy 

supply would be needed to create exhaust temperatures compatible 

with SNCR operation. This temperature restriction and related 

economic considerations make SNCR infeasible and inappropriate 

for the proposed combustion turbines. NSCR is only effective in 

controlling fuel-rich reciprocating engine emissions and requires 

the combustion gas to be nearly depleted of oxygen (<4% by 

volume) to operate properly. Since combustion turbines operate 

with high levels of excess oxygen (typically 14 to 16% 02 in the 

exhaust), NSCR is infeasible and inappropriate for the proposed 

combustion turbines. 

Dry Low NO„ Combustors - Dry Low NO, (DLN) combustion 

control techniques reduce NO, emissions without injecting water 

or steam (hence "dry"). DLN combustors are designed to control 

peak combustion temperature, combustion zone residence time, 

and combustion zone free oxygen, thereby minimizing thermal 

NO, formation. This is accomplished by producing a lean, premixed flame that burns at a lower flame temperature and excess 

oxygen levels than conventional combustors. 

DLN combustors have been employed successfully for natural gasfired combustion turbines for more than fifteen years. 

XONONTM, LoTO„Tm, THERMALLONOXTM, and PahlmannTM A 

number of other combustion turbine NO, emissions control 

technologies for combustion turbines are being marketed including 

XONONTM, LoTO,Tm, THERMALLONOXTM, and PahlmannTM 

None of these technologies has reached the commercial 

development stage for large combustion turbines that will be fired 

with natural gas, and thus none are considered to be technically 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 30 

feasible for application to this project. DEQ concurs that these 

technologies are not yet commercially available technology 

suitable for controlling CTs of the size proposed at the GEP/S site. 

LAER Determination: 

GEP/S has proposed a combination of the remaining identified 

control options dry low-NO„ combustors and selective catalytic 

reduction (SCR) as LAER. The proposed GE 7FA and Siemens 

SGT6-5000F5 model turbines use a two-stage premixed 

combustion design resulting in uncontrolled NO, emissions of 15 

ppmvd at 15% 02 when firing natural gas, the fuel proposed for 

use by GEP/S. The draft permit proposes use of dry low-NO, 

combustors and SCR to control NO, emissions from the CTs to the 

following level (at 15% 02): 

2.0 ppmvd with and without the duct burner firing (16.0 lbs/hr for 

the GE 7FA and 17.1 lbs/hr for the Siemens SGT6-5000F5). 

Compliance with the limits is to be based on a one-hour block 

average. 

From 2007 to 20011, approximately fifteen projects were 

permitted at 2.0 ppmvd at 15% 02 including two LAER 

determinations. Recent PSD permits at 2 ppmvd at 15% 02 

include a September 1, 2011 issued permit for the Thomas C 

Ferguson Power Plant in Texas and a December 17, 2010 issued 

permit for the Warren County Power Station in Virginia. There is 

one project that was permitted at a NO, emission rate of 1.5 ppmvd 

at 15% 02 in the year 2000. However, this project has not been 

built and therefore, 1.5 ppmvd at 15% 02 has not been 

demonstrated as achievable in practice. With that one exception, 

the proposed limits are as stringent as any listed in EPA's 

RACT/BACT/LAER Clearinghouse (RBLC) for electric 

generating facilities. 

GEP/S's facility is expected to operate as a baseload plant, i.e., at 

close to 100% loading during most times. However, the proposed 

turbine units will serve the PJM electric grid capable of covering 

large swings in electric demand in short periods of time. As part of 

this process, the PJM system operator will take control of the units 

in order to meet the continuously changing demand. These load 

changes will necessitate ramping operation of the combustion 

turbines and, if necessary, the duct burners up and down to follow 

load demand. The permit does not restrict the facility from 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 31 

operating at lower loads and the 2.0 ppmvd limit applies to the 

operation of the turbines at all load levels except during periods of 

startup and shutdown. 

Auxiliary Boiler and Fuel Gas Heater 

GEP/S plans to install an auxiliary boiler and a fuel gas heater. 

Both units burn only pipeline quality natural gas and are relatively 

small emission sources when compared to the CTs. 

NO, control 

NO, emissions from the auxiliary boiler and fuel gas heater 

originate primarily as thermal NO,. The primary front-end 

combustion controls for boilers and heaters are low excess air, 

low-NO, burners, and ultra low-NO, burners. SCR can be used to 

remove NO, from the exhaust gas stream once NO, has been 

formed. 

Both ultra low-NO, burners and SCR are capable of limiting NO, 

emissions to approximately 0.011 lb/MMBtu or 9 ppmvd at 3% 02. 

Data from EPA's RBLC show that recently permitted emission 

rates for natural gas-fired boilers and fuel gas heaters less than 250 

MMBtu/hr are in the 0.035 lb/MMBtu to 0.060 lb/MMBtu range. 

However, several projects have been permitted in the 0.010 

lb/MMBtu to 0.012 lb/MMBtu range including one boiler 

permitted at 0.012 lb/MMBtu as LAER and one fuel gas heater 

permitted at 0.021 lb/MMBtu as LAER. 

The applicant proposes to burn only pipeline quality natural gas in 

the auxiliary boiler and fuel gas heater and to use ultra low-NO, 

burners to limit NO, emissions to 0.83 lb/hr, 0.011 lb/MMBtu 

(approximately 9 ppmvd at 3% 02). DEQ agrees that burning 

natural gas and using ultra low-NO, burners is LAER for NO, 

emissions from the auxiliary boiler and the fuel gas heater. 

Emergency Generator and Fire Water Pump 

The facility will have a 1.5 MW emergency generator and a 330 

bhp emergency firewater pump. Compliance with the New Source 

Performance Standard (40 CFR Part 60 Subpart IIII) is proposed as 

LAER for NO, and VOC. 

NGcontrol 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 32 

Because emergency engines must start quickly and change output 

rapidly to match fluctuating load demands, emergency units 

produce variations in exhaust temperature and flow rate as well as 

NO, concentration and are therefore not well-suited for a selective 

non-catalytic reduction (SNCR) or an SCR system. Additionally, 

because of the limited operating hours (a maximum of 500 per year 

as limited by the permit), control by SCR or SNCR would not be 

cost effective. 

At 500 hours of operation, the maximum annual NO, emissions for 

the emergency generator would be 5.8 tons per year and for the fire 

water pump would be about 0.5 tons per year. The emission 

factors for NO, used as the basis for the emergency generator and 

fire water pump emissions limits are based on the NSPS Subpart 

IIII limits for Stationary Compression Ignition Internal 

Combustion Engines (40 CFR 60 Subpart IIII), the current federal 

standard for stationary engines. 

Because of the low maximum emissions level at the limited 

allowed operating hours and the fact that the engines are required 

to meet the federal standards outlined in the NSPS, Subpart IIII, 

DEQ concurs that add-on control would not be appropriate for the 

emergency units and that the proposed emission levels meet 

LAER. 

As also required by the NSPS, Subpart IIII, the permit requires 

GEP/S to use ultra-low sulfur fuel oil in its emergency units. 

LAER VOC Control 

The proposed facility will be located in an area designated 

nonattainment for the 1997 and 2008 8-hour ozone NAAQS and 

OTR and will be required to apply LAER for Volatile Organic 

Compounds (VOC) if the facility-wide VOC emissions are 50 tpy 

or more. The Siemens SGT6-5000F5 option results in VOC 

emissions greater than 50 tons per year resulting in a need to apply 

LAER, whereas the GE CTG option results in VOC emissions less 

than 50 tpy resulting in a need to apply BACT (under Article 6). 

For VOCs, the Stonewall GE emissions are higher than Warren 

County. Although, there is no BACT or LAER requirement for 

VOC emissions for the Stonewall GE option, the VOC emission 

rates are consistent with LAER for the GE 7 FA combustion 

turbine. The available combustion turbine emission guarantees 

from GE are 1.4 ppmvd at 15% 02which is higher than the 1.0 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 33 

ppmvd at 15% 02guarantees for the Siemens and MHI combustion 

turbines. For Stonewall, the 2.4 ppmvd emission rate with duct 

burning is attributable to the duct burner operating at a reduced 

load of 10%. With the duct burner at full load, the emissions will 

be 2.0 ppmvd at 15% 02which is higher than the Siemens or 

Warren County emissions due the higher GE combustion turbine 

emissions. 

For VOCs, the Stonewall Siemens emissions are higher than 

Warren County without duct burning and slightly lower with duct 

burning. The available combustion turbine emission guarantees 

from Siemens and MHI are 1.0 ppmvd at 15% 02. The combustion 

turbine vendors indicate that they will not offer guarantees below 

1.0 ppmvd at 15% 02. For the Warren County project, Dominion 

may have chosen to go beyond 1.0 ppmvd at 15% 02 due the 

precedent send by older Warren County peiniits. Research into the 

Warren County project indicates that the original project was 

permitted and not built. The developer was expecting the oxidation 

catalysis to control excessive emissions; however, the project was 

never built to demonstrate the developer's claim. With duct 

burning the Stonewall Siemens emissions are slightly lower than 

the Warren County emissions. 

The use of good combustion control and an oxidation catalyst 

represent LAER for VOC control for the proposed CTGs. 

Emissions depend upon the performance of each CTG, the use of 

duct burning, and the performance of the oxidation catalyst. 

Available performance guarantees are limited by the low VOC 

concentrations before control and uncertainties regarding the 

compounds that are actually emitted. The following VOC emission 

rates, based on VOC control by an oxidation catalyst, are 

proposed as LAER for the SGT6-5000F CTGs: 

• 1.0 ppmvd @ 15% 02 (DBs Off); and 

• 1.5 ppmvd @ 15% 02 (DBs On). 

3. BACT Requirements 

The EPA guidance document New Source Review Workshop 

Manual: Prevention of Significant Deterioration and 

Nonattainment Area Permitting prescribes that for PSD 

permitting, the most stringent BACT review, otherwise known as 

"top-down" review, be conducted. The "top-down" method 

provides that all available control technologies be ranked in 

descending order of control effectiveness. The applicant first 

examines the most stringent or "top" alternative. The top 

alternative is established as BACT unless the applicant 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 34 

demonstrates that technical considerations or energy, 

environmental, or economic impacts justify that the most 

stringent technology is not feasible. If the most stringent is 

eliminated, the next most stringent is considered until BACT is 

established. 

All pollutants subject to PSD review are subject to a "top-down" 

BACT analysis, as BACT is established on a pollutant basis. For 

the proposed GEP/S facility, the pollutants include NOx, CO, 

PM, PM10, and greenhouse gases. Emission units addressed in 

the BACT determination submitted by GEP/S include the 

combined-cycle units, the auxiliary boiler, the fuel gas heater, the 

emergency generator, and the emergency firewater pump. 

A listing of BACT determinations included in the 

RACT/BACT/LAER Clearinghouse for similar facilities is 

included as Appendix C in GEP/S's application. 

Combined-Cycle Combustion Turbine (CT) 

CO BACT 

Carbon monoxide emissions are formed in the exhaust of a 

combustion turbine as a result of incomplete combustion of the 

fuel. Similar to the generation of NO, emissions, the primary 

factors influencing the generation of CO emissions are temperature 

and residence time within the combustion zone. Variations in fuel 

carbon content have relatively little effect on overall CO 

emissions. Generally the effect of the combustion zone 

temperature and residence time on CO emissions generation is the 

exact opposite of their effect on NOxemissions generation. Higher 

combustion zone temperatures and residence times lead to more 

complete combustion and lower CO emissions, but higher NOx 

emissions. The applicant proposed good combustion control and 

an oxidation catalyst to control CO emissions (based on 85% CO 

control) to the following levels, all corresponding to 15% 02as a 

1-hour rolling average: 

• 2.0 ppmvd with and without duct burner firing 

An oxidation catalyst is a post-combustion technology that 

removes CO from the exhaust gas stream after formation in the 

combustion turbine. In the presence of a catalyst, CO will react 

with oxygen present in the exhaust stream, converting it to carbon 

dioxide. No supplementary reactant is used in conjunction with an 

oxidation catalyst. The oxidation of CO to CO2 utilizes the excess 

air present in the turbine exhaust; and the activation energy 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 35 

required for the reaction to proceed is lowered in the presence of 

the catalyst. Technical factors relating to this technology include 

the catalyst reactor design, optimum operating temperature, back 

pressure loss to the system, catalyst life, and potential collateral 

increases in emissions of PM-10 and sulfuric acid mist emissions. 

CO catalytic oxidation reactors operate in a relatively narrow 

temperature range. Optimum operating temperatures for these 

systems generally fall into the range of 700 °F to 1,100 °F. At 

lower temperatures, CO conversion efficiency falls off rapidly. 

Above 1,200 °F, catalyst sintering may occur, thus causing 

permanent damage to the catalyst. For this reason, the CO catalyst 

is strategically placed within the proper turbine exhaust lateral 

distribution (it is important to evenly distribute gas flow across the 

catalyst) and proper operating temperature at base load design 

conditions. Operation at part load, or during startup/shutdown will 

result in less than optimum temperatures and reduced control 

efficiency. 

Typical pressure losses across an oxidation catalyst reactor 

(including pressure loss due to ammonium salt formation) are in 

the range of 0.7 to 1.0 inches of water. Pressure drops in this range 

correspond roughly to a 0.15 percent loss in power output and fuel 

efficiency or approximately 0.1 percent loss in power output for 

each 1.0 inch of water pressure loss. 

Catalyst systems are subject to loss of activity over time. Since the 

catalyst itself is the most costly part of the installation, the cost of 

catalyst replacement should be considered on an annualized basis. 

Catalyst life may vary from the manufacturer's typical 3-year 

guarantee to a 5- to 6-year predicted life. Periodic testing of 

catalyst material is necessary to predict annual catalyst life for a 

given installation. 

Oxidation catalysts have been employed successfully for two 

decades on natural gas combustion turbines. An oxidation catalyst 

is considered to be technically feasible for application to this 

project. 

Good combustion practices consisting primarily of controlled 

fuel/air mixing and adequate temperature and gas residence time 

are used to minimize the formation of CO. 

As shown in EPA's RBLC, only three projects have been 

permitted at CO emission rates below 2 ppmvd at 15% 02. For 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 36 

CO, the Stonewall emissions are higher than Warren County 

without duct burning but lower with duct burning. Most of the 

projects in EPA's RACT/BACT/LAER Clearinghouse that are 

below 2 ppmvd @15% 02 are various entries for Warren County 

from 2004 through 2010. Research into the Warren County project 

indicates that the original project was permitted and not built. The 

developer was expecting the oxidation catalysis to control 

excessive amounts of CO; however, the project was never built to 

demonstrate the developer's claim. The project was purchased by 

Dominion Energy and could not be built with the specified turbines 

listed in the permit because the turbines were no longer available. 

The current model offered had different emission characteristics, 

causing Dominion Energy to file for a new permit with a revised 

project configuration of 3 MHI turbines matched with one large 

steam turbine generator. 

The Stonewall emissions are based on emission data provided by 

GE and Siemens and are consistent with similar projects listed in 

EPA's RACT/BACT/LAER Clearinghouse. This is further 

demonstrated by the most recent entries into the 

RACT/BACT/LAER Clearinghouse that followed the Warren 

County permitting. 

The last 4 projects permitted in 2012 in Texas and Wyoming were 

permitted a 4.0 ppmvd CO at 15% 02. Two projects (Palmdale 

Hybrid Power Project (10/18/2011) and Avenal Energy Project 

(6/21/2011)), are listed at 1.5 ppmvd CO at 15% 02. The 1.5 

ppmvd emission rate is a conditional rate that must be achieved 

during a demonstration period after the first 3 years of operation or 

a special condition will allow the permit limit to be adjusted up to 

2.0 ppmvd CO at 15% O2for compliance. 

Typically, CO emission rates of 2 ppmvd at 15% 02 to 3.5 ppmvd 

at 15% 02are determined to be BACT and LAER. The higher CO 

emission rates generally account for the higher emissions 

associated with duct burning 

It should be noted that the lean pre-mix dry low-NO, combustion 

employed on the CTs also works to reduce CO emissions. DEQ 

concurs that the proposed oxidation catalyst control and good 

combustion practices constitute BACT for CO from the CTs. 

VOC BACT 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 37 

Only the GE CTG option is subject to PSD BACT for VOC 

emissions. Formation of VOC emissions in combustion turbines is 

attributable to the same factors as described for CO emissions 

above. VOC emissions are a result of incomplete combustion of 

carbonaceous fuels, and this is influenced primarily by the 

temperature and residence time within the combustion zone. 

An oxidation catalyst is a post-combustion technology that 

removes VOC from the exhaust gas stream after formation in the 

combustion turbine. In the presence of a catalyst, VOC will react 

with oxygen present in the exhaust stream, converting it to carbon 

dioxide and water vapor. The performance of an oxidation catalyst 

is affected by the VOCs that are actually emitted. No 

supplementary reactant is used in conjunction with an oxidation 

catalyst. An oxidation catalyst is considered to be technically 

feasible for application to this project. 

Good combustion practices consisting primarily of controlled 

fuel/air mixing and adequate temperature and gas residence time 

are used to minimize the formation of VOCs. 

The two most recent BACT decisions are the Warren County, 

Virginia project with BACT emissions limits set for MHI 501 

GAC CTGs at 1.5 ppmvd at 15% 02 without duct burning and 2.4 

ppmvd at 15% 02 with duct burning, and the Kleen Energy project 

at 4.0 ppmvd at 15% 02. The available combustion turbine 

emission guarantees from GE are 1.4 ppmvd at 15% 02 which is 

higher than the 1.0 ppmvd at 15% 02 guarantees for the Siemens 

and Warren County's MHI combustion turbines. For Stonewall, 

the 2.4 ppmvd emission rate with duct burning is attributable to the 

duct burner operating at a reduced load of 10%. With the duct 

burner at full load, the emissions will be 2.0 ppmvd at 15% 02 

which is higher than the Siemens or Warren County emissions due 

the higher GE combustion turbine emissions. 

The applicant has proposed to control VOC using good 

combustion practices in the CT and an oxidation catalyst. The 

oxidation catalyst is proposed for the dual purpose of controlling 

CO emissions and VOC emissions. The applicant proposed VOC 

limits, based on 30% control by an oxidation catalyst, as follows, 

all at 15% 02 and as CH4 (calculated as a three-hour average): 

• 1.0 ppmvd without duct burner firing 

• 1.5 ppmvd with duct burner firing 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 38 

The VOC emissions are subject to the design of the turbine 

manufacturers who are balancing emissions while trying to achieve 

higher efficiency. The turbines will react differently, producing 

different emissions at different load conditions and with or without 

duct burner operations. Discussions with manufacturers indicate 

that 1.0 ppmvd at 15% 02 for VOC is where they will guarantee 

their F class machines for this project. The Stonewall project has 

taken into account the various operating conditions that this project 

will face and has determined the BACT limit based on the worst 

case to set the not to exceed BACT limit for this project. 

The use of good combustion control and an oxidation catalyst 

represent BACT for VOC control for the proposed combustion 

turbines. 

PM/PM-1 0/PM-2. 5 BACT 

Particulate matter emissions from combustion turbines are a 

combination of filterable (front-half) and condensable (back-half) 

particulate. Filterable particulate matter is formed from impurities 

contained in the fuels and from incomplete combustion. 

Condensable particulate emissions, which contribute to PM-10 and 

PM-2.5, are attributable primarily to the formation of sulfates and 

possibly organic compounds. 

The most stringent particulate control method demonstrated for gas 

turbines is the use of low ash and low sulfur fuel. No add-on 

control technologies are listed in EPA's RBLC. Proper 

combustion control and the firing of fuels with negligible or zero 

ash content and a low sulfur content for the combustion turbines is 

the only control method listed. Add-on controls, such as 

electrostatic precipitators (ESPs) or baghouses, have never been 

applied to commercial gas turbines. The use of ESPs and 

baghouses are considered technically infeasible, and do not 

represent an available control technology. The maximum PM-10 

concentrations, including condensable PM-10, from combined 

cycle combustion units are approximately 0.002 gr/dscf which is 

lower than 0.01 gridscf, which is a typical baghouse performance 

specification. 

Proper combustion control and the firing of fuels with negligible or 

zero ash content and a low sulfur content for the combustion 

turbines is considered to be technically feasible for application to 

this project. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 39 

The applicant proposed the use of good combustion practices and 

pipeline quality natural gas as BACT for PM, PM-10, and PM-2.5 

control for the proposed combined-cycle turbines. The following 

PM/PM-10/PM-2.5 emission rates were proposed as BACT for the 

GE 7FA.05 and the Siemens SGT6-5000F5 combustion turbines in 

GEP/S's application: 

GE 7FA.05 

• 9.6 lb/hr without duct burner firing 

• 16.2 lb/hr with duct burner firing 

• 3.34 x 10-3lb/MMBtu at full load 

Siemens SGT6-5000F5 

• 10.1 lb/hr without duct burner firing 

• 14.5 lb/hr with duct burner firing 

• 3.74 x 10'3lb/MMBtu at full load 

Unlike NON, CO, or VOC, there are no demonstrated add-on 

technologies or design changes that are used for control of 

particulate matter. The specific combustion turbine models that 

GEP/S is considering for this project are more advanced than each 

manufacturer's comparable models currently in operation. The 

combustion turbine uses less fuel per kilowatt of power generated. 

The gain in generation efficiency allows the project to use 

comparatively less fuel to produce more power. While total fuel 

use will increase proportionately to the increased output capability 

of the new machines, the decrease in heat rate means that the gain 

in electric generation is a greater benefit. Fuel use is related to 

particulate matter generation because more fuel mass will equal 

more particulate mass out; however, use of the more efficient 

turbines will generate particulates at a lower rate (on an electrical 

output basis) than combustion turbines permitted ten years ago in 

California and other states. Combustion turbines (GE and Siemens 

turbine model versions) in California have been peiniitted at very 

low emission limits 

According to EPA's RBLC during the time period from 2005-

2009, the PM emission limits on a lb/MMBtu basis for combinedcycle power plants ranged from 0.0055 to 0.0210 lb/MMBtu. 

Therefore, on a lb/MMBtu basis, the proposed CTs are comparable 

to those at other combined-cycle power plants. DEQ agrees that 

these emission rates along with limiting the fuel fired in the CTs to 

pipeline-quality natural gas having a maximum sulfur content of 

0.0003 percent by weight (i.e., 0.1 grain or less of total sulfur per 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 40 

100 standard cubic feet) and good combustion practices meets 

BACT for particulate matter emissions. 

SO, and Sulfuric acid mist control 

SO2 and sulfuric acid mist emissions are not subject to PSD BACT 

or minor NSR review. Emissions of SO2 from combustion 

turbines are a result of oxidation of fuel sulfur. Sulfuric acid mist 

emissions (S03/H2SO4) result from oxidation of fuel sulfur as well 

as oxidation of SO2 by the duct burners and catalysts used for NON, 

CO, and VOC control. 

The only technically feasible method for SO2and sulfuric acid mist 

emission control is the use of low sulfur fuels. The use of flue gas 

desulfurization is not technically feasible because the SO2 

emissions from the proposed combustion turbines are two orders of 

magnitude lower than emission rates achievable using flue gas 

desulfurization. 

GEP/S proposed the following SO2and sulfuric acid mist emission 

rates based on a natural gas heating value of 1,020 Btu/scf for the 

GE 7FA.05 model and the Siemens CTG6-5000F5 model 

combustion turbines: 

SO, 

• 0.00026 lb/MMBtu with and without the duct burners firing 

Sulfuric Acid Mist 

• 0.00014 lb/MMBtu with and without the duct burner firing 

The amount of SO2 and sulfuric acid mist formation is directly 

proportional to the amount of sulfur present in the fuel. The 

applicant proposes to use only natural gas in the CTs to control 

SO2and sulfuric acid mist emissions. 

Ammonia (NH) control 

Since ammonia is not a regulated pollutant, it is not subject to PSD 

or minor NSR BACT. However, as a precursor to PM-2.5, it can 

affect visibility Ammonia emissions from combined-cycle gas 

turbine plants using SCR can be in the 5 to 10 ppmvd at 15% 02 

range. GEP/S proposed that ammonia emissions would be limited 

to 5 ppmvd at 15% 02. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 41 

CT & HRSG DB Greenhouse Gas (GHG) BACT 

As fossil fuel-fired combustion sources, the combustion turbine 

and HRSG duct burners will emit three greenhouse gases: 

methane, nitrous oxide and carbon dioxide. Methane is emitted 

from combustion devices as a result of incomplete combustion. 

Methane emissions can be reduced by operating the combustion 

turbine generators at higher flame temperatures, increased 

residence time and higher excess oxygen; however this has the 

effect of increasing emissions of NOx. Nitrous oxide will be 

emitted in trace quantities from the combustion turbine generators 

as a result of partial oxidation of nitrogen from the excess oxygen 

used in combustion. Methane and nitrous oxide account for only 

0.1% of all greenhouse gas emissions, with the remaining 99.9% of 

emissions being CO2. Carbon dioxide is a product of combustion 

of any carbon-containing fuel. 

GHG emission controls that are currently available or under 

development are: 1) carbon capture and sequestration (CCS), 2) 

use of low carbon fuels, and 3) energy efficiency. The CTs will be 

fired on natural gas, which is considered a low carbon fuel as 

compared to coal. 

Separating carbon dioxide from the gas streams of the combustion 

turbines was presented as challenging due to the dilute 

concentrations (3 to 4 volume percent for gas fired turbines), trace 

impurities in the flue gas can degrade sorbents and reduce the 

effectiveness of certain CO2 capture processes. In addition to low 

concentration and impurities, compressing the captured CO2 to 

pipeline pressure represented a large power consumption on the 

facility. 

The facility would also be required to store the captured CO, in a 

geologic formation, and transport the CO2 from the generation 

point to the storage location. The potential formations that could 

be used for storage are located in southwest Virginia. 

The US DOE has estimated that CCS applied to a natural gas 

combined cycle power plant would more than double the total 

plant cost and increase the cost of electricity by 45%. The net 

result would be cost effectiveness in excess of $100/ton of CO2 

controlled. In addition, CCS would consume 20% of the power 

plant energy output. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 42 

Based on the information presented, the DEQ agrees that carbon 

capture and sequestration is infeasible for this project. 

On a ton/MMBtu basis, GHG from coal combustion are 

substantially higher than natural gas, as shown in the table below 

which lists several common fuels and their associated CO2 

emission factors. The use of low carbon fuels is technically 

feasible, and the proposed project will burn natural gas. 

Table 12 CO2 Emission Factors 

Fuel kg CO2/MMBtu 

Bituminous Coal 93.40 

Distillate Fuel Oil No. 

2 73.96 

Residual Fuel Oil 75.10 

Coke 102.04 

Wood & Wood 

Residuals 93.80 

Natural Gas 53.02 

Emission factors are from 40 CFR 98, Table C-1 

Energy Efficiency: Since BACT is based on an emission limitation 

which reflects the maximum degree of reduction for a particular 

pollutant, then the best means of comparison is of emission limits 

rather than percent control efficiency. Since energy efficiency 

plays a role in emissions, one must compare efficiency limits based 

on output (Btu/kWh or lb/kWh) rather than mass limits based on 

heat input (lb/MMBtu). This is because, as a unit gets older and 

less efficient, it may still meet a lb/MMBtu limit while, at the same 

time, using more fuel to achieve its heat input need, therefore 

increasing emissions. 

Stonewall is proposing to verify performance initially within 180 

days of startup and once every Title V permit term (z5 years) 

based on American Society of Mechanical Engineers Performance 

Test Code on Overall Plant Performance, ASME PTC 46-1996 or 

other method approved by DEQ. In order to establish a permit 

limit for these performance tests it is necessary to include margins 

to account for long term equipment performance. 

To determine the heat rate limit for the permit, the following 

compliance margins were added to the base heat rate of 6,550 Btu 

(HHV)/gross kWh without duct burning and 6,940 MMBtulhr with 

duct burning; 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 43 

1. A 3.4% performance margin reflecting the efficiency losses due 

to permanent and recoverable combustion turbine degradation. 

2. A 1.2% degradation margin reflecting operational variation and 

auxiliary power degradation. The operational variation assumes 

differences in operating techniques including but not limited to 

CT operation, degradation in catalyst life, HRSG tube leaks, 

excessive wear on equipment and design issues causing 

temporary derates, etc. Auxiliary power degradation includes 

efficiency losses over time of auxiliary (balance of plant) 

equipment including but not limited to pumps, motors, fans, etc. 

3. A 7.1% degradation margin reflecting the efficiency losses over 

time of the steam turbine system including but not limited to CT 

gas performance (i.e., less mass flow), the HRSG, the cooling 

tower, etc. 

Based on the above margins, Stonewall is proposing a 7,340 Btu 

(HHV)/gross kWh heat rate limit at full load, without duct burning, 

and a 7,780 Btu (HHV)/gross kWh heat rate limit at full load, with 

duct burning, adjusted to ISO conditions, which will be 

demonstrated once per Title V peimit term. 

Stonewall proposes to continuously monitor CO2 emissions using 

40 CFR Part 75 procedures. Emissions of CH4 and N20 as CO2e 

will be based on emission factors and global warming potentials in 

EPA's Mandatory GHG reporting rule and fuel use. The resulting 

emission rate is 118.28 lb CO2e/MMBtu. The proposed GHG 

emission limit will be a IbCO2e/gross MWh limit as a 12-month 

rolling average, and will include startups, shutdowns, and low load 

operations. In order to establish a permit limit for continuous 

performance a 3% operational margin was added to the heat rate 

margins cited above. This operational margin accounts for 

dispatch variability and start-up and shut-down events. During 

startup and shutdown events, the combustion turbine power 

production efficiency is low and the steam turbine is not in 

operation until late in the event resulting in a much higher heat 

rate. The proposed annual average GHG emission rate is 903 lb 

CO2e/MWh (118.28 lb/MMBtu x 6,612 Btu/kWh x 1.034 x 1.012 

x 1.071 x 1.03 x 1,000 kWh/MW x 1 MMBtu/1,000,000 Btu). 

Only a handful of combined cycle combustion turbines have been 

permitted for GHG so a quick comparison can be made in the table 

below. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 44 

Table 13 Comparison of GHG BACT Determinations 

Facility Type GHG BACT Limits Basis 

Green Energy Partners / Stonewall, 

Leesburg, VA 750 MW NGCC 

7,340 Btu (HHV)/gross kWh w/o DB 

7,780 Btu (HHV)/gross kWh w/ DB 

903 lb/MWh Gross 

Thermal Efficiency 

Dominion VA — Brunswick, VA 1400 MW 

NGCC 7500 Btu/kWh (net HHV) and 920 lb/MWh Thermal Efficiency 

Cricket Valley Energy Ctr, NY 1 00 0 MW 

NGCC 7605 Btu/kWh (net HHV) and 950 lb/MWh Thermal Efficiency 

Hess Newark Energy Center, NJ 655 MW NGCC 7522 Btu/kWh (net 1-111V) w/o DB and 887 

lb/MWh (gross) ThermalEfficiency 

CPV Valley Energy, NY 630 MW NGCC 7605 Btu/kWh(LHV

/M

) w/o DB and 950 

lbWh Thermal Efficiency 

PacifiCorp Lake Side, UT 629 MW NGCC 6918 Btu/kW (HHV) and 950 lb/MWh Thermal Efficiency 

Russell City Energy Ctr, CA 600 MW NGCC 7730 Btu/lWh and 242 tons/hr Thermal Efficiency 

LCRA Furguson Replacement, TX 590 MW NGCC 7720 Btu/kWh (net H1-1V) and 918 lb/MWh Thermal Efficiency 

Sevier Power Company, UT 580 MW NGCC 7515 Btu/kWh and 1,958558 tons/yr Thermal Efficiency 

Palmdale Hybrid Power, CA 

570 MW NGCC 

and 50 MW solar 

collectors 

7319 Btu/kWh and 774 lb/MWh (source 

wide) Thermal Efficiency 

Pioneer Valley Energy, MA 431 MW CC (oil 

backup) 6840 Btu/kW and 895 lb/MWh Thermal Efficiency 

Deer Park (Calpine) Energy Ctr., TX 180 MW NGCC 7730 Btu/kWh (net) and 920 lb/MWh Thermal Efficiency 

Channel Energy Center, TX 180 MW NGCC 7730 Btu/kWh (net) and 920 lb/MWh Thermal Efficiency 

Kalama Energy Center, WA 346 MW NGCC 

(peaker) 858 lb/MWh Thermal Efficiency 

As can be seen in the table above, this project is similar in size and 

output to most of the other recently permitted or proposed NGCC 

projects. Keeping in mind that the thermal efficiency increases 

with larger turbines, and the net heat rate (Btu/kW) decreases, the 

BACT level proposed for the 750 MW Green Energy Partners / 

Stonewall Plant and the other permitted or proposed 180-1400 

MW plants are comparable. When comparing a heat rate limit, it is 

important to know whether it is based on a HHV or LHV and 

whether it is for a gross power output or net power output, and duct 

fired or not duct fired operation. This is not always evident when 

researching other facilities. Also, some GHG BACT proposals 

include a "degradation factor" which takes into consideration the 

heat rate of a unit as it gets older and less efficient. More recently 

permitted plants have considered degradation, while earlier 

permitted plants may not have. 

No information could be found on GHG BACT limits for a natural 

gas combined cycle power plant using CCS for comparison with a 

thermal efficiency approach, but estimates have shown it to be 

about 90 % effective in reducing GHG emissions. 

Of the technologies discussed above, carbon capture and 

sequestration, use of low carbon fuels, and energy efficiency, CCS 

would be cost prohibitive. The remaining technologies, namely 

efficient power generation and the use of low carbon fuels are 

proposed for this facility and are accepted as BACT. Due to some 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 45 

variability in size, manufacturer, configuration, cooling practice, 

elevation and the method used to determine the heat rate among 

the permitted plants, some variation in BACT determinations is 

expected, however, DEQ determined that the proposed emission 

level of CO2e and efficiency level are BACT for this facility. The 

plant will be required to operate at a higher heating value heat rate 

of no more than 7,780 Btu/kWh (gross) with duct burners on, and 

emit CO2e at an average annual rate not to exceed 903 lb 

CO2e/MWh (gross) (which reflects a 118.28 lb CO2e/MMBtu 

adjusted to account for emissions from start up and shut down and 

low load operation). This falls into the range of BACT for recently 

issued or drafted GHG PSD permits. 

Circuit Breakers GHG BACT 

The circuit breakers are electrical equipment insulated with sulfur 

hexafluoride (SF6), which is a greenhouse gas. SF6 is a dielectric 

gas used in high voltage applications because of its ease of use and 

excellent insulation and arc-interruption properties. 

The state of the art enclosed-pressure circuit breakers with leak 

detection equipment has been selected as BACT. The manufacturer 

guarantee is an annual leak rate of less than 1% for the proposed 

circuit breakers, and a low-pressure alarm will be installed to alert 

of fugitive leaks before a substantial quantity of SF6 is released. 

Emissions will be monitored in accordance with the requirements 

of the Mandatory Greenhouse Gas Reporting rule for Electrical 

Transmission and Distribution Equipment Use (40 CFR 98, 

Subpart DD). 

Auxiliary Boiler and Fuel Gas Heater 

GEP/S plans to install an auxiliary boiler and a fuel gas heater. 

Both units burn only pipeline quality natural gas and are relatively 

small emission sources when compared to the CTs. 

CO and VOC BACT 

Available emission control techniques for CO are good combustion 

practices and oxidation catalysts. These controls are capable of 

limiting CO emissions to 0.037 lb/MMBtu, which is equivalent to 

50 ppmvd at 3% 02. Data from EPA's RBLC show that recent 

emission rates for natural gas-fired boilers and fuel gas heaters less 

than 250 MMBtu/hr is in the range of 0.035 lb/MMBtu to 0.060 

lb/MMBtu. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 46 

Oxidation catalysts may be technically feasible to achieve lower 

CO emissions than using good combustion practices alone. 

However, due to low emission potential of 12.15 tpy of CO 

emissions, oxidation catalyst is expected to be not economically 

feasible. 

GEP/S proposes to implement good combustion practices as 

BACT in the auxiliary boiler and fuel gas heater to limit CO 

emissions to 0.037 lb/MMBtu. DEQ agrees that using good 

combustion practices is BACT for CO for the auxiliary boiler and 

the fuel gas heater. 

Available emission control techniques for VOC are good 

combustion practices and oxidation catalysts. GEP/S proposes to 

bum only pipeline quality natural gas in the auxiliary boiler and 

the fuel gas heater and to use good combustion practices as BACT 

to limit emissions to 0.002 lb/MMBtu. Annual VOC emissions 

from the auxiliary boiler will be limited to 0.66 tons/yr while 

emissions from the fuel gas heater will be limited to 0.18 tons/yr. 

At this low emission potential of VOC emissions, oxidation 

catalyst is expected to be not economically feasible. 

PM/PM-10/PM-2.5 BACT 

Particulate matter emissions from the boiler and fuel gas heater are 

a combination of filterable and condensable particulate. Good 

combustion practices and limiting fuel use to only pipeline quality 

natural gas are proposed by the applicant as BACT for PM/PM10/PM-2.5 emissions from the auxiliary boiler and fuel gas heater. 

DEQ agrees that this constitutes BACT for particulate emissions 

from the boiler and heater. Short-term PM-10/PM-2.5 emissions 

from the auxiliary boiler and the fuel gas heater will be limited to 

0.15 lbs/hr and 0.04 lbs/hr, respectively. Annual PM-10/PM-2.5 

emissions from the auxiliary boiler will be limited to 0.66 tons/yr 

while emissions from the fuel gas heater will be limited to 0.18 

tons/yr. 

SO2 and Sulfuric Acid Mist control 

SO2 and sulfuric acid mist emissions are not subject to PSD BACT 

or minor NSR review. Emissions of SO2from the auxiliary boiler 

and fuel gas heater are a result of oxidation of fuel sulfur. Sulfuric 

acid mist emissions (SO3/H2SO4) are based on a 5% conversion of 

SO2 to SO3by the boiler and heater. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 47 

The applicant has proposed the use of pipeline quality natural gas 

and good combustion practices to limit SO2 and sulfuric acid mist 

emissions. 

Greenhouse Gas (GHG) BACT 

The use of low carbon fuels, oxidation catalyst and designs for 

high fuel to electricity efficiency are all considered technically 

feasible control technologies and are already being proposed as 

part of the Project. There are no technically feasible technologies 

for further reducing greenhouse gas emissions from the 

combustion turbine generators. 

Emergency Diesel Generator and Diesel Fire Water Pump 

The emergency generator will be operated only during 

interruptions in normal electrical power supply to the facility or for 

maintenance, testing, and operator training. The emergency fire 

water pump will be operated only in the event of a plant fire, 

maintenance, testing, and operator training. Each unit is limited to 

500 hours of operation per year that includes 100 hours of 

operation per year for testing and maintenance. 

CO BACT 

Because of the limited hours of operation for the emergency units, 

resulting in low emissions, add-on controls for CO are not 

practical. The emission factors for CO used as the basis for the 

emergency generator and fire water pump emissions limits are 

based on the NSPS Subpart IIII limits for Stationary Compression 

Ignition Internal Combustion Engines, the current federal standard 

for stationary engines. 

DEQ considers the federal standard from EPA's Tier II non road 

and stationary emergency engines of 3.5 g/brake horse power (bhp) 

to be acceptable as BACT. At 500 hours of operation, the 

maximum annual CO emissions for the generator would be 2.89 

tons per year and for the firewater pump would be 0.47 tons per 

year. Given the limited allowable emissions, it is evident that addon controls would not be cost effective. 

PM/PM-10 /PM-2.5 BACT 

Particulate matter emissions from oil-fired internal combustion 

engines may result from trace metals present in the fuel, unburned 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 48 

carbon-containing materials and sulfate formation. The use of 

ultra-low sulfur fuel oil, good combustion practices, and a 

limitation on operating hours is considered BACT for PM/PM10/PM-2.5 from the emergency units. The proposed emission rate 

for PM, based on NSPS Subpart IIII, is 0.002 lb/MMBtu for both 

the generator and the fire water pump. Annual PM/PM-10/PM-2.5 

emissions from each unit are less than 0.5 ton per year, so DEQ 

finds the proposal acceptable as BACT for PM/PM-10/PM-2.5 

from the generator and fire water pump. 

It should be noted that the permit requirement to use ultra-low 

sulfur fuel per the federal motor vehicle diesel fuel standards (40 

CFR 80.500 and 80.520) is expected to result in reduced PM/PM10 emissions from the emergency equipment, as less sulfur will be 

available to form sulfates, a fine particulate. 

VOC BACT 

VOC emissions from internal combustion units are the result of 

incomplete combustion. Due to the limited operating hours for the 

emergency units, add-on controls, even if technically feasible, 

would not be economically feasible. The application proposes 

conservative VOC emission rates equal to the NSPS, Subpart IIII 

emission limits for non-methane hydrocarbons (NMHC) + NO, of 

6.4 g/kW-hr for the generator and 4.0 g/kW-hr for the fire water 

pump as BACT. NO„ and VOC are not segregated in the NSPS. 

At 500 hours of operation, the maximum annual VOC emissions 

for the generator would be 5.29 tons per year and for the fire water 

pump would be 0.54 tons per year. DEQ concurs with the 

proposed limits as BACT. 

SO, control 

SO2emissions are not subject to PSD BACT or minor NSR 

review. GEP/S has proposed to use ultra-low sulfur fuel in the 

generators (distillate oil having no more than 0.0015% sulfur by 

weight). 

Turbine Inlet Evaporative Coolers 

Evaporative coolers are located in the gas turbine inlet duct. Water 

is sprayed over a media to cool the incoming air. This process 

increases the amount of air mass flowing through the turbine, 

increasing the power generated and the turbine's efficiency. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 49 

Ten Cell Mechanical Draft Cooling Tower 

Green Energy Partners/Stonewall, LLC plans to install a 10-cell, 

187,400 gal/min mechanical draft cooling tower to service the 

condenser for the steam turbine. The tower will employ plume 

abatement to eliminate visible plumes except during extreme 

weather conditions. A plume abated tower is essentially a hybrid 

or wet/dry cooling tower design. The tower contains the wet 

evaporative section to cool the circulating water and the dry 

section to abate or reduce the visible plume. A plume is the result 

of the wet evaporative process that generates heated saturated air. 

When the saturated air exits the cooling tower and comes into 

contact with the cooler ambient air temperatures, condensation will 

occur, which creates a visible plume. In order to abate or reduce 

the plume of a cooling tower, the saturated air that is created by the 

wet evaporative process is dried out before exiting the tower. This 

is achieved by extending the plenum height of the tower and 

installing a dry heat transfer section into the side of the plenum, 

where dry air can be drawn through louvers, heated and then 

introduced into the plenum area. Once the warm dry air has 

entered the plenum area, it comes into contact with features 

installed to facilitate the mixing of the saturated air and the warm 

dry air. The effect of mixing these two air masses essentially dries 

out the saturated air, so that when it exits the tower and comes into 

contact with the cooler ambient air temperatures, the result is either 

a substantially reduced plume or no visible plume. The plume 

abatement system will generally be less effective during periods of 

high relative humidity and cold weather conditions. 

The cooling tower will also utilize highly efficient drift eliminators 

to reduce water losses during operation. The drift eliminators also 

serve the purpose of reducing particulate emissions from dissolved 

solids in the drift water. Table C-11 in Appendix C of the 

application summarizes the recent BACT determinations for 

cooling towers. All BACT determinations relate to controlling the 

drift from the cooling towers. As shown in Table C-11, the most 

stringent drift rate limit is 0.0005% of circulating water flow. 

Achieving a drift rate of 0.0005% is technically feasible. 

Consistent with recent BACT determinations, a drift rate of 

0.0005% is proposed as BACT for the cooling tower for the 

Project. The maximum annual emissions from the operation of the 

ten cell mechanical draft cooling tower is 10.27 tons per year of 

PM-10 and 3.19 tons per year of PM-2.5. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 50 

The method of calculating the emissions are as follows: 

Emission Rate (lb/hr) = Water Circulation Rate (gpm) x 60 min/hr 

x Drift (%) / 100 x 8.3453 (lb/gal) x TDS (ppmw, or lb 

PM/1,000,000 lb water) x Weight Percent of Particle Size (%) / 

100. 

For PM10, this would be Emission Rate for Total Cooling Tower 

(lb/hr) = 187400 (gpm) x 60 (min/hr) x 0.0005 (%) / 100 x 8.3453 

(lb/gal) x 5000 (lb PM/1,000,000 lb water) x 100 (%) / 100 = 2.35 

lb/hr. 

DEQ concurs with the proposed limits as BACT. 

4. NESHAP (40 CFR Part 61) 

National Emission Standards for Hazardous Air Pollutants 

(NESHAP), found at 40 CFR 61, regulate emissions of specific 

HAPs from a limited number of source categories. 40 CFR 61 

standards are incorporated by reference into Virginia Regulations 

at 9 VAC 5 Chapter 60, Part II, Article 1 (Rule 6-1). None of these 

Part 61 regulations apply to natural gas-fired stationary combustion 

turbines or the other emissions units proposed for the GEP/S 

Stonewall Energy Project. 

5. MACT (40 CFR Part 63) 

Maximum Achievable Control Technology (MACT) standards, 

found at 40 CFR 63, designate emission standards for HAPs from 

specific source categories. 40 CFR 63 standards are incorporated 

by reference into Virginia Regulations at 9 VAC 5 Chapter 60, Part 

II, Article 2 (Rule 6-2). 

40 CFR 63 Subpart YYYY, National Emissions Standards for 

HAPs from Stationary Combustion Turbines, was promulgated 

March 5, 2004 and applies to CTs located at major HAP sources. 

The potential HAP emissions from the proposed GEP/S facility do 

not exceed major source thresholds for HAPs, i.e., 10 tons per year 

of a single HAP or 25 tons per year of all HAPs combined. 

Accordingly, the proposed facility is not subject to the MACT 

standard. It should be noted that the MACT stipulates oxidation 

catalyst as one way to comply with the MACT limits (oxidation 

catalysts not only reduce CO and VOC emissions, they also reduce 

HAP emissions such as formaldehyde, toluene, acetaldehyde and 

benzene). GEP/S has proposed oxidation catalyst to control CO 

and VOC from its facility. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 51 

40 CFR 63 Subpart ZZZZ, National Emissions Standards for HAPs 

for Stationary Reciprocating Internal Combustion Engines, was 

promulgated June 15, 2004 and applies to stationary reciprocating 

internal combustion (IC) engines located at major and area sources 

of HAP emissions. Per 40 CFR 63.6590(c), stationary IC engines 

subject to Regulations under 40 CFR Part 60 can meet the 

requirements of Subpart ZZZZ by meeting the requirements of 40 

CFR 60 Subpart IIII for compression ignition engines. As 

mentioned below, 40 CFR 60 Subpart IIII applies to the proposed 

IC engines and the applicable requirements from Subpart IIII have 

been included in the permit. Therefore, no further requirements 

from Subpart ZZZZ apply to the engines. 

6. NSPS (40 CFR Part 60) 

New Source Performance Standards (NSPS), found at 40 CFR 60, 

designate emission standards for criteria pollutants (a few regulate 

HAPs as well) from new emissions units at specific source 

categories. 40 CFR 60 standards are incorporated into Virginia 

Regulations at 9 VAC 5 Chapter 50, Part II, Article 5 (Rule 5-5). 

There are NSPS that apply to the CTs, the DBs, the auxiliary 

boiler, the fuel gas heater, the emergency generator, and the fire 

water pump at the proposed facility, as detailed below: 

40 CFR 60 Subpart KKKK (Standards of Performance fo 

Stationary Combustion Turbines) 

Subpart KKKK applies to gas turbines having a heat input at 

peak load equal to or greater than 10 MMBtu/hr, based on the 

higher heating value of the fuel fired. The subpart also applies 

to emissions from the associated duct burners. The rule 

imposes limits on NO, and SO2emissions and monitoring and 

testing requirements. Using the most conservative 

assumptions, the NO, limit in Subpart KKKK is 15 ppm at 

15% 02 and the SO2limit must be 0.060 lb S02/MMBtu or 

lower. 

The LAER determination codified in the permit are more 

stringent than the NSPS requirements. For example, the NO, 

permit limit is 2.0 ppmvd, the fuel sulfur content is limited to 

0.0003 % by weight, and the SO2permit limit is 0.000261 

lb/MMBtu. Testing and monitoring requirements mirror or 

exceed those in Subpart KKKK. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 52 

• 40 CFR 60 Subpart Da (Standards of Performance for Electric 

Utility Steam Generating Units for Which Construction is 

Commenced After September 18, 1978) 

Subpart Da applies to electric utility steam generating units 

capable of combusting more than 250 MMBtu/hr heat input of 

fossil fuel for which construction began after September 18, 

1978. The DBs proposed by GEP/S meet the applicability 

criteria of the rule and are subject to its requirements. 

However, duct burners regulated under NSPS, Subpart KKKK 

are exempted from the requirements of NSPS, Subparts Da, 

Db, and Dc. 

• 40 CFR 60 Subpart Dc (Standards of Performance for Small 

Industrial-Commercial-Institutional Steam Generating Units) 

Subpart Dc applies to steam generating units with a maximum 

design heat input capacity in the range of 10 MMBtu/hr to 100 

MMBtu/hr for which construction began after June 9, 1989. 

The auxiliary boiler and the fuel gas heater meet the 

applicability criteria of the rule and are subject to its 

requirements. The applicable requirements for natural gas 

burning units have been incorporated into the peiiiiit. 

• 40 CFR 60 Subpart IIII (Standards of Performance for 

Stationary Compression Ignition Internal Combustion Engines) 

Subpart IIII applies to stationary internal combustion (IC) 

engines with a displacement of less than 30 liters per cylinder 

where the model year is 2007 or later, for engines that are not 

fire pump engines. For fire pump engines, Subpart IIII applies 

beginning with the model years listed in Table 3 of the subpart. 

The rule imposes emission standards on NOR, CO, and PM 

emissions based on the engine model year and engine use 

(emergency, fire pump, etc.). The subpart also requires engine 

owners and operators to use ultra-low sulfur fuel in the 

generators (distillate oil having no more than 0.0015% sulfur 

by weight). The applicable requirements for the generator and 

fire pump engines have been incorporated into the permit. 

Since the generator and fire pump engines will meet the 

requirements of Subpart IIII, the units do not have any further 

requirements under 40 CFR 63 Subpart ZZZZ (see above). 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 53 

• 40 CFR 60 Subpart Kb (Standards of Performance for Volatile 

Organic Liquid Storage Vessels) is not applicable to the 1,250 

and 400-gallon distillate oil storage tank proposed by the 

applicant. Subpart Kb applies only to storage vessels having a 

capacity of at least 10,566.88 gallons (40 m ). 

V. Offsets 

Green Energy Partners / Stonewall, LLC is required to secure NOxemissions 

offsets at a 1.00:1.15 ratio in accordance with 9VAC5-80-2120 and 40 CFR Part 

51, Appendix S. The permittee shall secure NOx emission offsets of no less than 

159 tons x 1.15 = 182.85 tons for the GE 7FA.05 combustion turbines, and 164.9 

tons x 1.15 = 189.64 tons for the Siemens SGT6-5000F5 combustion turbines. If 

GEP/S chooses the Siemens combustion turbines, a VOC emission offset in the 

ration of 1.15:1.00 will also be required. The permittee shall secure VOC 

emission offsets of no less than 51.9 tons x 1.15 = 59.69 tons for the Siemens 

SGT6-5000F5 combustion turbines GEP/S had not yet identified the source of the 

offsets but is required to assure they are state and federally enforceable prior to 

beginning operation. 

VI. Compliance Determination 

A. Stack testing requirements 

The permit requires initial compliance testing for NO,,, SO2, CO, PM-10, 

PM-2.5, and VOC from the combined-cycle units. The need for periodic 

perfollnance testing will be evaluated during processing of the Title V 

permit for the facility based on the results of the initial testing and 

operating data. A condition allowing DEQ to require additional testing 

has been included in the permit. 

B. Fuel testing requirements 

The permit allows the permittee to use the fuel quality characteristics in a 

current, valid purchase contract, tariff sheet or transportation contract for 

the fuel to verify that the sulfur content of the natural gas is 0.1 grain or 

less of total sulfur per 100 standard cubic feet. Alternatively, per 40 CFR 

60.4370, the permit allows GEP/S to determine the sulfur content of the 

natural gas by testing using two custom monitoring schedules or an EPAapproved schedule. The permit also requires the permittee to obtain fuel 

supplier certification for each shipment of distillate oil used in the 

emergency units. 

C. Visible emissions evaluations 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 54 

A visible emissions evaluation (VEE), concurrent with the initial CT stack 

test, is required by the permit. Periodic CT stack visible emission 

inspections, which trigger a VEE according to EPA Method 9 if visible 

emissions are observed, have been included in the permit. 

D. Continuous emissions monitoring systems (CEMS) 

The peiiiiit requires that the CT stacks be equipped with CEMS meeting 

the requirements of 40 CFR Part 75 (Acid Rain program) for NO„ and SO2 

(unless an alternative method of determining SO2emissions has been 

approved for that purpose). In addition to providing a means to 

demonstrate compliance with the permit NO, limits, the CEMS will 

satisfy the NSPS Subpart KKKK requirement to monitor NO, emissions 

using a CEMS. The permit also requires that the CT stacks be equipped 

with CEMS meeting the monitoring requirements in 40 CFR 60.13 for 

CO. 

In addition to the CEMS, the draft permit requires GEP/S to conduct 

extensive, continuous monitoring of key operational parameters on the 

control devices to assure proper operation and performance (see 

Conditions 5 through 9). 

Compliance with NO, and CO emission limits for the CCCTs will be 

determined using Continuous Emission Monitoring Systems (CEMS). 

E. Recordkeeping requirements 

• Compliance with SO2emission limits will be determined through fuel 

sulfur monitoring and records of fuel usage. 

• VOC, CO, PM-10, and PM-2.5 emission factors (lb/MMbtu) will be 

verified during initial compliance testing. Since annual emission 

limits for these pollutants are based 8760 hours of operation with each 

unit operating at worst case conditions, compliance with annual 

emission limits can be demonstrated with fuel throughput records and 

operational limits. Accordingly, monthly record keeping of "rolling" 

12-month totals is required for natural gas throughput to each turbine 

and to each duct burner. 

Additionally, the permit requires that the following records be kept: 

• Time, date, and duration of each CT startup, shutdown, and 

malfunction period; 

• Annual number of startup and shutdown occurrences for each CT 

calculated monthly; 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 55 

• Continuous records of heat input and power output for each CT; 

• Emissions calculations sufficient to verify compliance with the annual 

emission limits in Conditions 35, 37, 38, 40, 41, 42, and 43 (calculated 

monthly as the sum of each consecutive 12-month period), and records 

sufficient to allow calculation of actual annual emissions from the 

remainder of the facility. Calculation methods are to be approved by 

the DEQ; 

• CEMS data, calibrations and calibration checks, percent operating 

time, and excess emissions; 

• Annual operating hours of the emergency generator and the fire water 

pump for emergency purposes and maintenance/testing, calculated 

monthly as the sum of each consecutive 12-month period; 

• Time, date, and duration of operation of emergency generator and fire 

water pump for maintenance and testing and the operational status of 

each CT during that time; 

• Fuel supplier certifications for distillate oil; 

• Records of engine manufacturer data; 

• Operation and monitoring records for each SCR system and each 

oxidation catalyst; 

• Records of steady-state vs. non-steady-state operation of each CT unit, 

the ammonia slip monitoring plan, and ammonia slip monitoring 

results; 

• Scheduled and unscheduled maintenance and operator training; 

• Results of all stack tests, VEEs, visible emissions inspections, and 

performance evaluations; 

• Monthly and annual fuel throughput to the auxiliary boiler and fuel gas 

heater; 

• Records of good combustion practices for the auxiliary boiler and fuel 

gas heater; 

• Records for emission offsets; and 

• Records of CEMS quality control program. 

The records must be available for DEQ inspection and maintained for five 

years. 

VII. Public Participation 

A. Applicant Informational Briefing 

In accordance with Section 9 VAC 5-80-1775 C of the Regulations, the 

applicant held an informational briefing at 6:30 p.m. on September 24, 

2012 at the Rust Library in Leesburg, Virginia. As required, the briefing 

was advertised in the Loudoun Times Mirror at least 30 days in advance 

(on August 24, 2012). 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 56 

B. Public Briefing 

9 VAC 5-80-1775 J specifies that a briefing be scheduled prior to the 

public comment period if appropriate. NRO has scheduled a public 

briefing at 6:00 p.m. to 7:00 p.m. on April 3, 2013 at Stone Bridge High 

School located at 43100 Hay Road in Ashburn, Virginia 20147. The 

briefing requires a 30-day (at minimum) notification period. A legal 

advertisement for the briefing was placed in the Washington Post and 

Loudoun Times Mirror on February 27, 2013. 

C. Public Hearing 

In accordance with 9 VAC 5-80-1775 E, NRO will hold a public hearing 

to accept comments on the air quality impact of the proposed source, 

alternatives to the source, the control technology required, and other 

appropriate considerations tentatively scheduled for April 3, 2013 at the 

Stone Bridge High School located at 43100 Hay Road in Ashburn, 

Virginia 20147 from 7:00 p.m. to 9:00 p.m. A legal advertisement for the 

hearing has been published in the Washington Post and Loudoun Times 

Mirror on February 27, 2013. 

D. Documents Concerning Public Comment Period 

Copies of the documents used in development of the draft permit were 

available for review at NRO. Additionally, a copy of Green Energy 

Partners / Stonewall, LLC permit application, modeling information and 

correspondence was placed online at the DEQ website. Upon completion 

of the application analysis and prior to the public briefing, the permit 

application, draft permit, and draft engineering analysis and all items 

contained in the attached Document List were accessible from DEQ's 

website at: 

http://www.deq.virginia.gov/Programs/Air/PermittingCompliance/Permitti 

ng/PowerPlants/GreenEnergyPartners.aspx. 

E. Public Comment 

The public comment period which runs for at least 45 days and includes 

15 days after the public hearing begins on February 28, 2013 and ends on 

April 19, 2013. All comments received will be recorded, reviewed and a 

Response to Comments document will be written. 

VIII. Notification of Other Government Agencies 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 57 

Local Zoning 

Because the proposed facility constitutes a new stationary source subject 

to air permitting regulations, a local governing body certification form is 

required in accordance with Department policy and § 10.1-1321.1 of the 

Code of Virginia. On May 13, 2010 Tim Hemstreet, the County 

Administrator for Loudoun County certified that the proposed facility is 

fully consistent with local ordinances. 

Environmental Protection Agency (EPA) 

In accordance with 9 VAC 5-80-2070, there are specific notification 

requirements to advise EPA of sources impacting nonattainment areas. 

Accordingly, a copy of the permit application, including supplemental 

addenda, and DEQ's initial letter of determination were provided to EPA 

Region III. EPA will be provided with a copy of the draft permit and will 

be notified of the public comment period and the final determination on 

permit issuance. 

C. Federal Land Managers 

Because of GEP's distance to SNP (see Table 1), DEQ has worked with 

the Federal Land Managers (FLMs) whose responsibility it is to oversee 

such areas. In accordance with the Memorandum of Understanding dated 

March 31, 1993, between DEQ and Shenandoah National Park (SNP) and 

the Jefferson National Forest, both the National Park Service (NPS) and 

U.S. Forest Service (USFS) were provided copies of GEP's permit 

application and supplemental addenda, most notably the Class I and Class 

II modeling analyses. 

Upon completion of DEQ's application analysis, DEQ provided the FLMs 

copies of correspondence generated in reaching its permit determination. 

On August 7, 2012, DEQ sent both NPS and USFS copies of the 

preliminary permit determination and provided notification that the 

application was considered complete and that the FLM 60-day review 

period had begun. Two updated applications were submitted to the DEQ, 

and on January 14, 2013 the FLM was notified. According to 9 VAC 5-

80-1765 B, that notification must be provided at least 60 days before the 

scheduled public hearing on the application. In emails dated June 20, 21, 

and July 3, 2012, the USFS, FWS, and NPS responded to the DEQ 

notification letter by stating that they did not plan to issue any finding of 

adverse impact on visibility and other applicable AQRVs as a result of 

emissions from the proposed GEP/S facility. Copies of the draft permit 

and engineering analysis were sent to the FLMs prior to the beginning of 

the public comment period. 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 58 

IX. Pollution Prevention 

The natural gas-fired combined-cycle turbine configuration may itself be 

considered a pollution prevention alternative in that it produces power much more 

cleanly (in pounds of pollutant emitted per kilowatt hour of power produced) than 

conventional coal or oil-fired power plants. The HRSGs are an important factor 

in clean power generation because they recover heat that would otherwise be lost 

to the atmosphere and use it to produce additional electrical power. 

Site-specific pollution prevention measures have been included as requirements in 

the permit, such as the following: 

• Use of clean fuels (natural gas containing no more than 0.0003 % sulfur by 

weight in the CTs, auxiliary boiler, and fuel gas heater; 

• Use of clean firing technology (lean premix low-NOxburners); 

• In the emergency generator and firewater pump, use of ultra low-sulfur (no 

more than 0.0015% sulfur by weight) distillate oil. Use of such fuels reduces 

emissions of not only sulfur dioxide and sulfuric acid mist but also of 

PM/PM-10/PM-2.5 (a component of which is sulfates) and is expected to 

reduce NOx emissions as well. 

The permit also includes requirements related to emissions of ammonia from the 

SCR. Ammonia is injected in the SCR system to induce the catalytic reduction of 

NOx, and, to ensure maximum conversion of NOR, ammonia in excess of its 

stoichiometric requirement (the minimum amount required to react with a given 

amount of NOR) is used. Any unreacted ammonia remaining is released to the 

atmosphere and is referred to as "ammonia slip". Although ammonia is not a 

regulated pollutant, ammonia emissions can nonetheless contribute to 

condensable particulate, regional haze, and nitrogen deposition. Furthermore, 

excessive ammonia emissions can indicate poor SCR system performance. 

Accordingly, the permit includes an ammonia emission limit of 5 ppmvd during 

operating conditions (as a one-hour average) for at least 95 % of the time that the 

SCR is operating and a requirement to submit a plan for monitoring ammonia slip. 

X. Title V Operating Permit (9 VAC 5 Chapter 80, Article 1) 

GEP/S is required by Virginia regulations to obtain a federal operating permit 

under Title V of the Clean Air Act. The Regulations require that GEP/S submit a 

Title V permit application no later than one year after startup of the facility. 

XI. Acid Rain Operating Permit (9 VAC 5 Chapter 80, 

Article 3) 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 59 

GEP/S is required by Virginia Regulations to obtain a permit under the federal 

Acid Rain program. Federal regulations require that a complete Acid Rain 

Program peiniit application be submitted at least 24 months prior to 

commencement of operation. 

XII. NO, and SO, Trading Programs (9 VAC 5 Chapter 14C) 

Virginia has established several emissions trading programs to meet the 

requirements of Section 110(a)(2)(D) of the Clean Air Act regarding transport of 

emissions from upwind states to downwind nonattainment areas. Electric 

generation units that have capacities above 25 MW and certain industrial boilers 

are generally subject to the restrictions of the trading programs, which EPA 

created to satisfy the mandates within Section 110(a)(2)(D) of the Clean Air Act 

to minimize impacts on downwind air quality. Accordingly, GEP/S will be 

required to comply with 9 VAC 5 Chapter 140 upon commencement of operation 

(first day any of the combustion turbines burn fuel). 

The emission trading programs rely on regional cap and trade mechanisms that 

provide an economic incentive to minimize emissions from applicable units. 

These programs include provisions for construction of new facilities by allowing 

new units to access limited amounts of pollution allocations, called new source set 

asides. New units also may purchase allocations on the cap and trade market to 

cover emissions. 

The NOxBudget Trading Program (9 VAC 5 Chapter 140 Part I "Regulations for 

Emissions Trading — NOxBudget Trading Program") became effective in 2002. 

This program required that applicable units participate in a regional NOxozone 

season cap and trade program. This regulation was later superseded by the more 

stringent Clean Air Interstate Rule (CAIR), which not only regulated NOx 

emissions during the ozone season but also regulated SO2 and NOx emissions on 

an annual basis. The CAIR rules, as adopted into Virginia's SIP, may be found at 

9 VAC 5 Chapter 140 Part II, "Regulation for Emissions Trading — NOxAnnual 

Trading Program"; Part III, "Regulations for Emissions Trading — NOxOzone 

Season Trading Program"; and Part IV, "Regulations for Emissions Trading —

SO2 Annual Trading Program." Similar to the NOx Budget Trading Program, the 

CAIR rules required that applicable units participate in regional NOxozone 

season and annual trading programs as well as a regional SO2 annual trading 

program. 

A December 2008 court decision remanded CAIR to EPA but kept the 

requirements of CAIR in place temporarily until a new rule could be issued. The 

new rule, called the Cross-State Air Pollution Rule (CSAPR) was finalized on 

July 6, 2011. CSAPR was subsequently remanded back to EPA due to an August 

21, 2012, ruling by the D. C. Circuit Court of Appeals. EPA has filed a petition 

seeking rehearing of this ruling. However, at this time, CAIR is in effect, and the 
Green Energy Partners / Stonewall, LLC 

April 30, 2013 

Page 60 

turbines and duct burners at GEP/S will be subject to the CAIR trading programs 

for annual and ozone season NOxemissions as well as for annual SO2 emissions. 

The fact that GEP/S is subject to CAIR will provide an incentive for the facility to 

minimize the number of times it starts up its CTs. During CT startup, NOx 

emissions from the unit are higher than they are during normal operation. If the 

facility has too many startups during a given period, it may exceed its NOx 

emission allotment. Such an exceedance in the trading program will cost the 

facility in that it may be required to purchase allowances to cover the additional 

emissions. 

XIII. Document List 

A list of documents used in preparing the application analysis is included as 

Attachment E. 

XIV. Recommendation 

Approval to proceed with public comment period is recommended. 

Attac:_ ents 

Attachment A: Maximum Annual Turbine Emissions with Startups and Shutdowns 

Attachment B: Public Hearing Notice 

Attachment C: DEQ Air Quality Modeling Analysis Memorandum 

Attachment D: Local Governing Body Form 
ATTACHMENT A: 

Maximum Annual Turbine Emissions 

with Startups and Shutdowns 
Table 3-4 GE 7FA,05 - Annual Emissions Including Start-up/Shutdown (Average Per CTG) 

Operating 

Mode 

hr/yr NO* CO VOC 

lb/hr(a) tpy ib/hr(a) tpy lb/hr(a) tpy 

Offline) 2,960 0 0 0 0 0 0 

Without duct 

burning 4,182.5 16.2 33.9 9.9 20.6 2.8 5.9 

With duct 

burning 1,400 21.0 14.7 12.7 8.9 7.3 5.1 

Hot start 25.7 72.9 0.9 771.4 9.9 25.7 0.3 

Warm start 113.1 158,1 8.9 468.7 26.5 25.2 1.4 

Cold start 33,3 90.4 1.5 631.6 10.5 89.8 1.5 

Shutdown 45.5 72.9 1.7 745.7 17.0 38.6 0.9 

TOTALS 8,760 61.6 93.4 15.1 

la) The lb/hr emissions represent the averaoe lb/hr for the duration of the event. not the 

maximum hourly emission rate during the event 

(b) The offline hours required to have 110 hot starts, 75 warm starts and 10 cold starts per 

year. 

Table 3-10 Siemens SGT6-5000F5 - Annual Emissions Including Start-up/Shutdown (Average 

Per CTG) 

Operating 

Mode 

hr/yr NOx CO VOC 

 lb/hr(a) tpy lb/hr(3) tpy lb/hr(a) tpy 

Offline) 2,960 0 0 0 0 0 0 

Without duct 

burning 4,244 17.1 36.3 10.4 22.1 3.0 6.4 

With duct 

burning 1,400 20.4 14.3 12.5 8.7 5.7 4.0 

Hot start 58.7 106.9 3.1 405.0 11.9 161.3 4.7 

Warm start 47.5 112.1 2.7 413.7 9.8 165.8 3.9 

Cold start 10.7 106.9 0.6 444.4 2.4 130.3 0.7 

Shutdown 39.0 125.0 2.4 385.0 7,5 150 2.9 

TOTALS 8,760 - 59.4 - 62.4 - 22.6 

fa) The lb/hr emissions represent the averaae lb/hr for the duration of the event. not the 

maximum hourly emission rate during the event. 

(b) The offline hours required to have 110 hot starts, 75 warm starts and 10 cold starts per 

year. 
ATTACHMENT B: 

Public Hearing Notice 
Public Notice — Environmental Permit 

PURPOSE OF NOTICE: To seek public comment and announce a public hearing and an information 

briefing on a draft permit from the Department of Environmental Quality to limit air pollution from a facility 

proposed to be located in Loudoun County, Virginia. 

PUBLIC COMMENT PERIOD: February 27, 2013 to April 19, 2013 

PUBLIC HEARING: Cafeteria, Stone Bridge High School, 43100 Hay Road, Ashburn, Virginia 20147 on 

April 3, 2013 from 7:00 p.m. to 9:00 p.m. 

INFORMATION BRIEFING: Same date and location as Public Hearing from 6:00 p.m. to 7:00 p.m. 

PERMIT NAME: Prevention of Significant Deterioration (PSD) & Non-Attainment New Source Review 

Permit issued by DEQ, under the authority of the Air Pollution Control Board 

APPLICANT NAME AND REGISTRATION NUMBER: Green Energy Partners / Stonewall, LLC; 73826 

FACILITY NAME AND PROPOSED LOCATION: Stonewall Combined Cycle Project; 20077 Gant Lane, 

Leesburg, Virginia 20175 (approximately 4 miles south/south east of Leesburg & north of Dulles Toll 

Road (SR267), 39.058° N Latitude, 77.545° W Longitude). 

PROJECT DESCRIPTION: Green Energy Partners / Stonewall, LLC has applied for a permit to construct 

and operate the Stonewall Combined-Cycle Project, a natural gas fired combined-cycle combustion 

turbine electric power generating facility having an electrical output capacity of approximately 750 MW. 

This area is in non-attainment for both the 1997 & 2008 8-hour ozone National Ambient Air Quality 

Standard (NAAQS) and the 1997 annual PM2.5 NAAQS. The area is in attainment for all other NAAQS. 

The maximum annual emissions of air pollutants from the facility are expected to be: 164.9 tons per year 

(tpy) of nitrogen oxides (as NO2), 205.6 tpy of carbon monoxide (CO), 51.9 tpy of volatile organic 

compounds (VOCs), 106.1 tpy of total filterable & condensable particulate matter (PM) with a diameter 

less than or equal to 10 microns (PMio), 99.1 tpy of PM2.5 (PM with a diameter less than or equal to 2.5 

microns), 5.44 tpy of sulfur dioxide (SO2), 2,468,468 tpy of green house gasses (carbon dioxide 

equivalent) and 10.1 tpy of total hazardous air pollutants. The applicant proposes to use 40.9 billion cubic 

feet per year of natural gas for fuel, and 9,370 gallons of diesel fuel per year. The proposed Stonewall 

Combined-Cycle Project does not cause or significantly contribute to a predicted violation of any 

applicable NAAQS or Class II area PSD increment. Emission offsets are required for nitrogen oxides and 

potentially for VOCs. 

HOW TO COMMENT AND/OR REQUEST BOARD CONSIDERATION: DEQ accepts comments and 

requests for Board consideration by hand-delivery, e-mail, fax or postal mail. All comments and requests 

must be in writing and be received by DEQ during the comment period. Submittals must include the 

names, mailing addresses and telephone numbers of the commenter/requester and of all persons 

represented by the commenter/requester. A request for Board consideration must also include: 1) The 

reason why Board consideration is requested. 2) A brief, informal statement regarding the nature and 

extent of the interest of the requester or of those represented by the requestor, including how and to what 

extent such interest would be directly and adversely affected by the permit. 3) Specific references, where 

possible, to terms and conditions of the permit with suggested revisions. Board consideration may be 

granted if public response is significant, based on individual requests for Board consideration, and there 

are substantial, disputed issues relevant to the permit. 

CONTACT FOR PUBLIC COMMENTS, DOCUMENT REQUESTS AND ADDITIONAL INFORMATION: 

Thomas Valentour; Northern Regional Office, 13901 Crown Court, Woodbridge, VA 22193; Phone: (703) 

583-3931; E-mail: Thomas.valentour@deq.virginia.gov;Fax: (703)583-3821. The public may review the 

draft permit and application at the DEQ office named above by appointment or may request copies of the 

documents from the contact person listed above. 
ATTACHMENT C: 

DEQ Air Quality Modeling Analysis Memorandum 
MEMORANDUM 

DEPARTMENT OF ENVIRONMENTAL QUALITY 

Office of Air Quality Assessments 

629 East Main Street, Richmond, VA 23219 

8thFloor 804/698-4000 

To: James LaFratta, Air Permit Manager (NRO) 

From: Mike Kiss, Director - Office of Air Quality Assessments (AQA) 

Date: December 14, 2012 

Subject: Virginia Department of Environmental Quality (DEQ) Technical Review of the Air Quality 

Analyses in Support of the Peitnit Application for the Proposed Green Energy 

Partners/Stonewall, LLC Natural Gas-Fired Electric Generating Facility in Loudoun 

County, Virginia (Stonewall Combined-Cycle Project) 

Copies: Bobby Lute 

I. Project Background 

Green Energy Partners/Stonewall, LLC has proposed to construct and operate a 750 megawatt 

(MW) natural gas-fired electric generating facility on an approximately 101-acre parcel 

located south-southeast of the Town of Leesburg Airport and north of the Dulles Greenway 

in Loudoun County, Virginia. The proposed new facility, called the Stonewall CombinedCycle Project, will consist of two identical natural gas-fired only combined-cycle turbines, each 

with its own duct-fired heat recovery steam generator (HRSG), one steam turbine 

generator, a 10-cell mechanical draft cooling tower, a natural gas-fired only auxiliary 

boiler, a natural gas-fired only fuel heater, a diesel-fired emergency generator and fire 

water pump, two distillate fuel oil storage tanks, and circuit breakers. Green Energy 

Partners/Stonewall, LLC has proposed the installation of either General Electric (7FA.05) or 

Siemens (SGT6-5000F5) turbines. 

The proposed facility meets the definition of major source under 9 VAC 5 Chapter 80, Article 8 

(Prevention of Significant Deterioration (PSD)) of the Commonwealth of Virginia Regulations 

for the Control and Abatement of Air Pollution because it is a fossil-fuel-fired steam electric 

plant of more than 250 MMBtu/hr heat input capacity and has the potential to emit 100 tons per 

year or more of a regulated pollutant. Also, the proposed facility has the potential to emit 
DEQ Air Quality Analyses Review 

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December 14, 2012 

Page 2 of 14 

greenhouse gas (GHG) emissions equal to or greater than 75,000 TPY carbon dioxide 

equivalent (CO2e). The pollutants subject to PSD review are nitrogen oxides (NOx), particulate 

matter having an aerodynamic diameter equal to or less than 10 microns (PM10), carbon 

monoxide (CO), and greenhouse gases (GHGs). As a result, PSD regulations require an air 

quality analysis be performed that demonstrates that the projected air emissions from the 

proposed facility will neither cause or significantly contribute to a violation of any applicable 

National Ambient Air Quality Standard (NAAQS) or PSD increment. In addition, PSD 

regulations require that an additional impact analysis consisting of a vegetation and soil analysis, 

a growth analysis, and a visibility impairment analysis be conducted. 

Loudoun County is included in the Washington, D.C. Metropolitan Statistical Area (MSA) 

which is currently designated as a "marginal" nonattainment area for the 2008 ozone NAAQS. 

NOxand volatile organic compound (VOC) emissions, precursors to ozone formation, are 

subject to the nonattainment permitting provisions. 

The Washington, D.C. MSA, including Loudoun County, is also currently designated as 

nonattainment for the 1997 annual particulate matter having an aerodynamic diameter of 2.5 

microns or less (PM25). However, the current air quality in the region is significantly below the 

1997 annual PM25NAAQS. Virginia intends to formally submit a request to EPA in 2013 to 

redesignate the area to attainment. 

The proposed facility's permit application addressed the following two possible PM2 5 scenarios 

because the area will not be folinally reclassified during the review of the permit application: 

• The area is nonattainment for PM25. 

• The area is eventually redesignated as attainment for PM25. 

As a result, an air quality analysis was also performed for PM25 to demonstrate that the 

projected PM2 5 emissions from the proposed facility will not cause or significantly contribute to 

a violation of any applicable PM25 NAAQS or PSD increment. 

An analysis of the project's impact on air quality and air quality related values (AQRVs) in any 

affected Class I area may also be required, contingent upon input from the Federal Land 

Managers (FLMs). The United States Forest Service (USFS), the United States Fish and 

Wildlife Service (FWS), and the National Park Service (NPS) each stated in an e-mail dated 

June 20, 2012, June 20, 2012, and July 3, 2012, respectively, that an AQRV analysis was not 

required since the project is not expected to show any significant additional impacts to AQRVs. 

Therefore, only a Class I area analysis to assess compliance with the Class I PSD increments 

was required. 

The following is a summary of the AQA's review of the required air quality analyses for the 

Stonewall Combined-Cycle Project for both Class I and Class 11 PSD areas. The worst-case 

impacts from all operating loads, including startup and shutdown operations, are presented in 

this memorandum. 
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December 14, 2012 

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IL Modeling Methodology 

The Class I and Class II air quality modeling analyses conform to 40 CFR Part 51, Appendix W 

- Guideline on Air Quality Models and were perfoinied in accordance with their respective 

approved modeling methodology. The air quality model used for the Class I area analysis was 

the EPA-approved regulatory version of the CALPUFF modeling system (Version 5.8, Level 

070623). The CALPUFF modeling system is the preferred model for long-range transport 

applications and is contained in Appendix W of 40 CFR Part 51. The air quality model used for 

the Class II area analysis was the most recent version of the AERMOD modeling system 

(Version 12060). The AERMOD modeling system is the preferred EPA-approved regulatory 

model for near-field applications and is also contained in Appendix W of 40 CFR Part 51. 

Additional details on the modeling methodology can be found in the applicable sections of 

Green Energy Partners/Stonewall, LLC's revised air permit application submittal dated 

November 2012. 

In. Modeling Results 

A. Class II Area - Preliminary Modeling Analysis 

A preliminary modeling analysis for criteria pollutants was conducted in accordance with 

PSD regulations to predict the maximum ambient air impacts. The preliminary analysis 

modeled emissions from the proposed facility only to determine whether or not the impacts 

were above the applicable significant impact levels (SIT s). For those pollutants for which 

maximum predicted impacts were less than the S1L, no further analyses was required (i.e., 

predicted maximum impacts less than Sits are considered insignificant and of no further 

concern). For impacts predicted to be equal to or greater than the SIL, a more refined air 

quality modeling analysis (i.e., full impact or cumulative impact analysis) is required to 

assess compliance with the NAAQS and PSD increment. 

The emissions associated with six (6) representative operating loads for the General Electric 

turbine option and four (4) representative operating loads for the Siemens turbine option 

were modeled, as well as their startup/shutdown emissions. Tables land 2 below show the 

maximum predicted ambient air concentrations for the General Electric and Siemens turbine 

options, respectively. 
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Table 1 

Class H Preliminary Modeling Analysis Results vs. Significant Impact Levels 

General Electric Turbines 

Pollutant Averaging 

Period 

Maximum Predicted 

Concentration From 

Proposed Facility 

(11011) 

Class II 

Significant 

Impact Level 

(1 tg/m3) 

NO2 1-hour 75.43 7.5 

Annual 0.97 

PMIo 

24-hour 2.89 5 

Annual 0.37 

PM25 

24-hour 1.70 1.2 

Annual 0.20 0.3 

CO 1-hour 2,381.37 2,000 

8-hour 113.58 500 

Table 2 

Class II Preliminary Modeling Analysis Results vs. Significant Impact Levels 

Siemens Turbines 

Pollutant Averaging 

Period 

Maximum Predicted 

Concentration From 

Proposed Facility 

(n/m3) 

Class II 

Significant 

Impact Level 

(14m3) 

NO2 1-hour 70.69 7.5 

Annual 0.96 1 

PM10 24-hour 2.72 5 

Annual 0.37 

PM2 5 

24-hour 1.35 1.2 

Annual 0.19 0.3 

CO 1-hour 633.91 2,000 

8-hour 48.21 500 

The modeling results for NO2 (annual averaging period), PK() (24-hour and annual 

averaging periods), PM25 (annual averaging period), and CO (8-hour averaging period) 

were less than the applicable SILs for both turbine options. Also, the modeling results for 

CO (1-hour averaging period) for the Siemens turbine option only were less than the 

applicable SIL. Therefore, a full impact analysis for these pollutants and averaging periods 

was not required. Furthermore, the additional pollution from this facility would not cause or 
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contribute to a violation of any applicable NAAQS or PSD increment for all pollutants and 

averaging periods with impacts below the applicable SILs. 

A full impact analysis for CO (1-hour averaging period, General Electric turbine option 

only), NO2 (1-hour averaging period), and PM2.5 (24-hour averaging period) was conducted 

because the preliminary modeling analysis results exceeded the applicable SILs. 

Additionally, a full impact analysis was conducted for PM2.5 (annual averaging period) at 

the request of DEQ even though the facility's predicted impact was below the SIL. This 

was done to provide additional assurance of NAAQS compliance in the Washington, D.C. 

MSA. 

The AQA has adopted the NO2 (1-hour) SIL in Table sl and 2 based on a review of the 

following documentation: 

Guidance Concerning the Implementation of the 1-hour NO2 NAAQS for the Prevention 

of Significant Deterioration Program, Stephen D. Page, EPA, June 29, 2010, 

The staff concurs with the EPA recommendations in this memorandum that it is appropriate 

to derive an interim 1-hour NO2SIL by using an impact equal to 4% of the 1-hour NO2 

NAAQS (4 ppb is equivalent to 7.5 μg/m3). The AQA believes that it is reasonable to adopt 

this value based on consideration of the impact level relative to the NAAQS and past EPA 

rationale for existing short-term averaging period SILs. The use of 4% of the NAAQS as a 

threshold is also consistent with previous EPA rulemaking and supporting documentation as 

described in the June 29, 2010 EPA memorandum. 

B. Class II Area — Cumulative Impact Modeling Analysis 

The cumulative impact analysis described below consisted of separate analyses to assess 

compliance with the NAAQS for CO (General Electric turbine option only), NO2, and PM2.5 

and the PSD increment for PM2.5 for the indicated averaging periods. It is important to note 

that the cumulative impact modeling results (both NAAQS and PSD increment) can 

sometimes be less than the "source only" modeling results in Tables land 2 of this 

memorandum. This is due to the fact that source only modeling uses the maximum 

concentration to determine significance, whereas the cumulative modeling results reflect the 

form of the air quality standard. For example, the following criteria must be met to attain 

the NAAQS: 

® CO (1-hour) - Not to be exceeded more than once per year. 

• NO2(1-hour) - To attain this standard, the 3-year average of the 98thpercentile of 

the daily maximum 1-hour average at each monitor within an area must not 

exceed the standard. 

® PM2.5 (24-hour) - To attain this standard, the 3-year average of the 98thpercentile 

of 24-hour concentrations at each population-oriented monitor within an area must 

not exceed the standard. 
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PM2 5 (annual) - To attain this standard, the 3-year average of the weighted annual 

mean PM25 concentrations from single or multiple community-oriented monitors 

must not exceed the standard. 

NAAQS Analysis 

The NAAQS analysis included emissions from the proposed source, emissions from 

existing sources from Virginia, West Virginia, and Maryland, and representative ambient 

background concentrations of NO2, PM25, and CO. The results of the analysis are presented 

in Tables 3 and 4 for the General Electric and Siemens turbine options, respectively, and 

demonstrate compliance with the applicable NAAQS. 

Table 3 

NAAQS Modeling - Cumulative Impact Results 

General Electric Turbines 

Pollutant Averaging 

Period 

Total 

Modeled 

Concentration 

(μm3) 

Ambient 

Background 

Concentration 

(1-1113) 

Total 

Concentration 

0-10r1 ) 

NAAQS 

NO2 1-hour 117.72 47 164.72 188 

CO 1-hour 2,273.97 2,530 4,803.97 40,000 

PM2 5 

24-hour 2.21 20 22.21 35 

Annual 0.42 9.5 9.92 15 

Table 4 

NAAQS Modeling - Cumulative Impact Results 

Siemens Turbines 

Pollutant Averaging 

Period 

Total 

Modeled 

Concentration 

(ligim3) 

Ambient 

Background 

Concentration 

(N-0113) 

Total 

Concentration 

(ligim3) 

NAAQS 

010113) 

NO2 1-hour 117.72 47 164.72 188 

PM2 5 

24-hour 1.76 20 21.76 35 

Annual 0.37 9.5 9.87 15 

PSD Increment Analysis 

The 24-hour and annual PM25 PSD increment analysis included emissions from the 

proposed source. Tables 5 and 6 below present the results of the analysis for the General 

Electric and Siemens turbine options, respectively, and show that the 24-hour and annual 

PM2 5 concentrations were below their applicable PSD increment. 
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Table 5 

PSD Increment Modeling - Cumulative Impact Results 

General Electric Turbines 

Pollutant Averaging Modeled Concentration 

Class II PSD 

Increment Period 

(41113) (11g/m3) 

24-hour 2.13 9 

PM2 5 Annual 0.25 4 

Table 6 

PSD Increment Modeling - Cumulative Impact Results 

Siemens Turbines 

Pollutant Averaging 

Period 

Modeled 

Concentration 

(11g/m3) 

Class II PSD 

Increment (μg/m3) 

PM2 5 

24-hour 1.62 9 

Annual 0.20 4 

NAAQS and PSD Increment Analyses Conclusions 

Based on AQA's review of the NAAQS and PSD increment analyses, assuming DEQ's 

regional office processing the permit application approved all of the emission estimates and 

associated stack parameters for the modeled scenarios, the proposed Stonewall CombinedCycle Project does not cause or significantly contribute to a predicted violation of any 

applicable NAAQS or Class II area PSD increment. 

Toxics Analysis 

The source is subject to the state toxics regulations at 9 VAC 5-60-300 et al. An 

analysis was conducted in accordance with the regulations and the predicted 

concentrations for each toxic pollutant were below their respective Significant Ambient Air 

Concentrations (SAAC). Tables 7 and 8 summarize the toxic pollutant modeling analysis 

results for the General Electric and Siemens turbine options, respectively. 
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Table 7 

Toxics Analysis Maximum Predicted Concentrations 

General Electric Turbines 

Toxic 

Pollutant 

Averaging 

Period 

Maximum 

Modeled Concentration 

From Project 

([tgim3) 

SAAC 

(μg/m3) 

Acrolein Annual 1.00E-04 0.46 

Formaldehyde 1-hour 3.21E-01 62.5 

Annual 4.58E-03 2.4 

Cadmium 1-hour 2.64E-03 2.5 

Annual 5.00E-05 0.1 

Chromium 1-hour 3.36E-03 2.5 

Annual 7.00E-05 0.1 

Nickel 1-hour 5.04E-03 5 

Annual 1.00E-04 0.2 

Table 8 

Toxics Analysis Maximum Predicted Concentrations 

Siemens Turbines 

Toxic 

Pollutant 

Averaging 

Period 

Maximum 

Modeled Concentration 

From Project 

(μt/m3) 

SAAC 

(11g/m3) 

Acrolein Annual 8.00E-05 0.46 

Formaldehyde 1-hour 3.18E-01 62.5 

Annual 4.35E-03 2.4 

Cadmium 1-hour 2.44E-03 2.5 

Annual 5.00E-05 0.1 

Chromium 1-hour 3.11E-03 2.5 

Annual 7.00E-05 0.1 

Nickel 1-hour 4.66E-03 5 

Annual 1.00E-04 0.2 

Additional Impact Analysis 

In accordance with the PSD regulations, additional impact analyses were performed to 

assess the impacts from the proposed facility on visibility, vegetation and soils, and the 

potential for and impact of secondary growth. These analyses are discussed below. 
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Visibility 

A screening modeling analysis using the VISCREEN model was conducted to assess the 

potential for visual plume impacts in Class II areas within 50 kilometers (km) of the project 

site. A review of National Parks and other potential areas of interest near the project site 

was conducted. It was determined that Manassas National Battlefield Park is the closest 

area of potential interest. Manassas National Battlefield Park is approximately 23 km 

southeast of the project site. 

The visibility screening modeling approach followed guidance provided in EPA's Workbook 

for Plume Visual Impact Screening and Analysis (Revised) (October 1992; EPA-454/R-92-

023). The two visibility metrics that were evaluated in the VISCREEN modeling analysis 

are: 

Plume contrast (ICI): Contrast can be defined at any wavelength as the relative 

difference in the intensity (called spectral radiance) between the viewed object 

(e.g., plume) and its background (e.g., sky). Plume contrast results from an 

increase or decrease in light transmitted from the viewing background through the 

plume to the observer. 

Plume perceptibility (AE): A parameter used to characterize the perceptibility of 

a plume on the basis of the color difference between the plume and a viewing 

background such as the sky, a cloud, or a terrain feature. 

The VISCREEN results were developed for the worst-case normal operating scenario. All 

results were below the significance criteria in the nearest Class II area. Therefore, the plume 

is expected to be imperceptible against the background sky and the terrain in the Manassas 

National Battlefield Park. 

The visibility in the area near the proposed facility will be protected by operational 

requirements, such as air pollution controls and clean burning fuels, and stringent limits on 

visible emissions that are incorporated into the draft permit. 

Vegetation and Soils 

An analysis on sensitive vegetation types with significant commercial or recreational value 

was conducted. The analysis compared maximum predicted concentrations from the 

proposed facility against a range of injury thresholds found in various peer-reviewed 

research articles as well as criteria contained in the EPA document A Screening 

Procedure for the Impacts of Air Pollution Sources on Plants, Soils, and Animals (EPA, 

1980). Tables 9 and 10 show the maximum modeled concentrations for NO2, PM10, and CO 

for the General Electric and Siemens turbine options, respectively, were all below the 

respective thresholds (i.e., the minimum reported levels at which damage or growth effects 

to vegetation may occur). As a result, no adverse impacts on vegetation are expected. 
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Table 9 

Comparison of Vegetation Sensitivity Thresholds to Maximum Modeled 

Concentrations from the Stonewall Combined-Cycle Project 

General Electric Turbines 

Pollutant Averaging 

Period 

Maximum Modeled 

Concentration From 

Proposed Facility 

(μg/m3) 

Sensitive Vegetation 

Threshold 

(μg/m3) 

NO2 

1-hour 14.71 280 

4-hour 99.98 3,760 

1-month 1.34 564 

Annual 0.97 94 

PM10 24-hour 2.89 150 

CO 1-week 23.24 1,800,000 

Table 10 

Comparison of Vegetation Sensitivity Thresholds to Maximum Modeled 

Concentrations from the Stonewall Combined-Cycle Project 

Siemens Turbines 

Pollutant Averaging 

Period 

Maximum Modeled 

Concentration From 

Proposed Facility 

(μg/m3) 

Sensitive Vegetation 

Threshold 

(μg/m3) 

NO2 

1-hour 14.68 280 

4-hour 99.98 3,760 

1-month 1.34 564 

Annual 0.96 94 

PM10 24-hour 2.72 150 

CO 1-week 23.24 1,800,000 

The impact of the emissions on soils in the vicinity of the proposed project was evaluated. 

The soil type was determined from data collected from the United States Department of 

Agriculture's Natural Resources Conservation Service (NRCS) Soil Survey Geographic 

(SSGUGO) database and the NRCS Web Soil Survey tool. The soil types within Loudoun 

County, Virginia and Montgomery County, Maryland were examined. 
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The predominant soil types for Loudon County are a variety of silt loams. In Montgomery 

County, the predominate soil types are also a variety of silt loams, with some small areas of 

sandy foams. 

The soil types in these counties are generally considered to have a moderate to high 

buffering capacity and have adequate capacity to absorb acidic deposition without changing 

the soil pH. Based on the soil types and quantity of emissions from the proposed project, no 

adverse impact on local soils is anticipated. 

Growth 

The work force for the proposed facility is expected to range from 600 to 700 jobs during 

various phases of the construction. It is expected that a significant regional construction 

force is already available to build the proposed facility. Therefore, it is anticipated that no 

new housing, commercial, or industrial construction will be necessary to support the 

Stonewall Combined-Cycle Project during the two-year construction schedule. The 

proposed facility will also require approximately 25 to 30 permanent positions. It is 

assumed that individuals that already live in the region will perform a number of these jobs. 

No new housing requirements are expected for any new personnel moving to the area. In 

addition, due to the small number of new individuals expected to move into the area to 

support the Stonewall Combined-Cycle Project and the existence of some commercial 

activity in the area, new commercial construction would not be necessary to support the 

permanent work force. Additionally, no significant level of industrial related support will be 

necessary for the Stonewall Combined-Cycle Project. Therefore, industrial growth is not 

expected. 

Based on the growth expectations discussed above, no new significant emissions from 

secondary growth during the construction and operation phases of the Stonewall CombinedCycle Project are anticipated. 

C. Class I Area Modeling Analysis 

The FLMs are provided reviewing authority of Class I areas that may be affected by 

emissions from a proposed source by the PSD regulations and are specifically charged with 

protecting the Air Quality Related Values (AQRVs) within the Class I areas. The closest 

Class I area to the proposed facility is Shenandoah National Park (SNP). It is approximately 

57 km from the proposed facility. The other Class I areas within 300 km of the proposed 

facility, but located at a distance greater than 57 km, are Dolly Sods Wilderness Area, 

Otter Creek Wilderness Area, James River Face Wilderness Area, and Brigantine National 

Wildlife Refuge. 

Modeling guidance contained in the Federal Land Managers 'Air Quality Related Values 

Work Group (FLAG) Phase I Report — Revised (2010) provides screening criteria for 

determining whether a source may be excluded from performing a Class I area AQRV 
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modeling analysis. The FLMs may consider excluding a source from modeling if its total 

SO2, NOx, PM10, and H2SO4 annual emissions (in tons per year, based on 24-hour 

maximum allowable emissions) divided by the distance (in km) from the Class I area is less 

than or equal to 10. The sum of the emissions for the proposed project is not expected to 

exceed approximately 317.2 tons per year (tpy). Therefore, the FLAG 2010 screening 

criteria for SNP is 5.6 (317.2 tpy/57 km). The screening criteria for all other Class I areas is 

less than 5.6 because these areas are located at a distance greater than 57 km. As a result, 

the USFS, the FWS, and the NPS each stated in an e-mail dated June 20, 2012, June 20, 

2012, and July 3, 2012, respectively, that an AQRV analysis was not required since the 

project is not expected to show any significant additional impacts to AQRVs. 

However, even though an AQRV analysis was not required to be conducted, an analysis to 

assess compliance with the Class I PSD increments for PM10, PM25, and NO2was required. 

A preliminary modeling analysis for PM10, PM2 5, and NO2 was conducted to determine 

whether or not the predicted maximum ambient air impacts in the closest Class I area (i.e., 

SNP) were above the Class I SILs. This analysis was limited to only SNP because the 

impacts will be higher relative to the other Class I areas since its proximity to the proposed 

facility is nearly 100 km closer than the other Class I areas. The emissions used in the Class 

I area modeling were the same as those used for the Class II area modeling. A more refined 

air quality modeling analysis (i.e., cumulative impact analysis) would be required to assess 

compliance with the Class I PSD increments for impacts predicted to be equal to or above 

the Class I SIL. No additional air quality analysis would be required for pollutants when the 

proposed project's impacts were less than the SIL. 

Tables 11 and 12 below present the proposed facility's maximum predicted ambient air 

concentrations for PM10, PM2 5, and NO2 for the General Electric and Siemens turbine 

options, respectively, in Shenandoah National Park. 

Table 11 

Summary of Maximum Predicted Concentrations from the Proposed 

Facility in Shenandoah National Park 

General Electric Turbines 

Pollutant Averaging 

Period 

Maximum Predicted 

Concentration From 

Proposed Facility 

(Ng/m3) 

Class I 

. Significant 

Impact 

Level 

(Ng/m3) 

PM1 0 

24-hour 0.1117 0.3 

Annual 0.0029 0.2 

PM25 

24-hour 0.1117 0.07 

Annual 0.0029 0.06 

NO2 Annual 0.0025 0.1 
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Table 12 

Summary of Maximum Predicted Concentrations from the Proposed 

Facility in Shenandoah National Park 

Siemens Turbines 

Pollutant Averaging 

Period 

Maximum Predicted 

Concentration From 

Proposed Facility 

(μg/m3) 

Class I 

Significant 

Impact 

Level 

(Pg/m3) 

PM10 24-hour 0.1002 0.3 

Annual 0.0026 0.2 

PM2.5 

24-hour 0.1002 0.07 

Annual 0.0026 0.06 

NO2 Annual 0.0024 0.1 

The modeling results for NO2 (annual averaging period), PM10 (24-hour and annual 

averaging periods), and PM25 (annual averaging period) were less than the applicable SILs 

for both turbine options. Therefore, a cumulative impact analysis to assess compliance with 

the Class I PSD increments was not required for these pollutants and their averaging periods. 

However, a cumulative impact analysis for PM2.5 (24-hour averaging period) for both 

turbine options was conducted because the preliminary modeling analysis results exceeded 

the applicable SIL. 

PSD Increment Analysis 

The 24-hour PM25 PSD increment analysis included emissions from the proposed source 

and nearby PM2.5 increment consuming sources. Table 12 presents the results of the 

analysis for both the General Electric and Siemens turbine options and shows that the 24-

hour PM2.5 concentrations for both turbine options were below the applicable PSD 

increment. 

Table 12 

PSD Increment Modeling - Cumulative Impact Results for Shenandoah National Park 

Turbine Option Pollutant Averaging 

Period 

Modeled 

Concentration 

(1-41T13) 

Class I PSD 

Increment 

(lig/m3) 

General Electric 

PM2 5 

1.250 

Siemens 24-hour 2 1.249 
DEQ Air Quality Analyses Review 

Stonewall Combined-Cycle Project 

December 14, 2012 

Page 14 of 14 

Summary of Class I Area Analysis 

Based on AQA's review of the Class I area modeling analyses, the proposed Stonewall 

Combined-Cycle Project does not cause or significantly contribute to a predicted violation 

of any applicable Class I area PSD increment. 
ATTACHMENT D: 

Local Government Body Form 
VIRGINIA DEPARTMENT OF ENVIRONMENTAL DUALITY AIR I' 

NORTHERN

S 

,,: MAY 1 9 2010 LOCAL GOVERNING BODY CERTIFICATION FORM 

Facility Name: 

Green Energy Partners/Stonewall Energy Plant 

Registration Numbe : -- 

Rr:r

-

4II' NA — 

- 

New Source , 

3 i") 

Applicant's Name: 

Green Energy Partners/Stonewall, LLC 

Name of Contact Person at the site: 

Jordan Dimoff, Project Manager 

Applicant's Mailing address: 

Andrews Community Investment Corp. 

P.O. Box 660, 

Hamilton, Virginia 20159 

540-338-9040 

Contact Person Telephone Number: 

Facility location (also attach map): 

Four miles south, southeast of Leesburg, north of the Dulles Toll Road, adjacent Gant Lane and 

Cochran Mill Road 

Facility type, and list of activities to be conducted: 

Power Generation 

The applicant is in the process of completing an application for an air pollution control permit froth the Virginia 

Department of Environmental Quality. In accordance with § 10.1-1321.1. Title 10.1, Code of Virginia (1950), as amended, 

before such a permit application can be considered complete, the applicant must obtain a certification from the governing 

body of the county, city or town in which the facility is to be located that the location and operation of the facility are 

consistent with all applicable ordiqances adopted pursuant to Chapter 22 (§§ 15.2-2200 et seq.) of Title 15.2. The 

undersigned requests tha n a Orizffl rep • sentativ of the local governing body sign the certification below. 

Applicant' % fR signaturfi.: / Y' 

Date: 

/,r 6-3-dm 

The unclerSignecifocal gover ne# representative certifies to the consistency of the proposed location and operation of 

the facility idescpibed above with aft applicable local ordinances adopted pursuant to Chapter 22 (§§15.2-2200 et seq.) of 

Title 15.2. 31:111'e Code of Virginia (1950) as amended, as follows: 

(Check one ock) 

The proposed facility is fully consistent with all applicable local ordinances. 

I I The proposed facility is inconsistent with applicable local ordinances; see attached information. 

Signature of 

authorized local 

government 

representative: 

Date: 

Sir hp 

.---< Type or 

;ZYYtct re' e print name: 

Title: CDv h+ • 

,s ei 

County, city I t P 

or town: 1-101) CiPli h ..1-.) 1))14N1 

)THE LOCAL GOVERNMENT REPRESENTATIVE SHOULD FORWARD THE SIGNED CERTIFICATION TO 

THE APPROPRIATE DEQ REGIONAL OFFICE AND SEND A COPY TO THE APPLICANT.) 

Page Revised April 15, 2002 FORM 7