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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

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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 ComplianceNR0-079-13

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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

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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) withGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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. NO x Oxides of nitrogen (NO x ) 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-NO x combustion 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 VOCGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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 CO 2 e 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. alg A Oxides of nitrogen (NO x) emissions from the auxiliary boiler (Ref. No. AB1) and the fuel gas heater (Ref. No. FGH1) shall be controlled by ultra low-NO x burners with a NOx performance of 9 ppmvd at 3% 0 2 for 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% 0 2 . 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

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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 CO 2 e 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. CO 2 e 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 (N0 x ), 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. CO 2 e 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

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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

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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 0-4 lb S0 2 /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 10 10 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 10 10cubic 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 beGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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 BurnersGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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) NO x Annual Trading Requirements —The combinedcycle power generating units (Ref. No. CCT1 & CCT2) listed in Condition 1 meet the definition of a CAIR NO x Unit and are subject to the CAIR NO x emission 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 NO x source 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 NO x Annual 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 10 8 cubic 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 10 8 cubic 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 addingGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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

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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, NO x emission concentrations, based on an hourly average, shall not exceed the NO x standards 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

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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. NO x emissions 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 NOx control 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 firingGreen 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% 02 with & 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% 0 2 with duct burner firing 1.0 ppmwv at 15% 0 2

without 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 -3

lb/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 -3

lb/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 10-4

lb/MMBtu 0.75 lb/hr with HRSG duct burner firing 0.58 lb/hr without HRSG duct burner firing Ammonia (NH 3 ) ■ 5.0 ppmvd at 15% 02

Siemens SGT6-5000F5 Air Pollutant Short-Term Emission Limits Oxides of Nitrogen (as NO 2 ) • ■ ■ 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% 0 2 with & 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% 0 2 with duct burner firing Compounds (VOCs) ■ 1.0 ppmwv at 15% 0 2 without 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 -3 lb/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 -3 lb/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 -4 lb/MMBtu ■ 0.70 lb/hr with HRSG duct burner firing ■ 0.58 lb/hr without HRSG duct burner firing Ammonia (NH 3 ) ■ 5.0 ppmvd at 15% 02

Where: ppmvd = parts per million by volume on a dry gas basis, corrected to 15 percent 0 2

. ppmwv = parts per million by volume on a wet gas basis, corrected to 15 percent 02.Green Energy Partners / Stonewall, LLC Registration Number: 73826

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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 SO 2 limit 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) 

### - CO 2 e 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 CO 2 e 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 NO 2 ) 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 (SO 2 ) 5.3 Greenhouse Gases (GHG) Carbon Dioxide Equivalent (CO2e) 2,418,273

Or:Green Energy Partners / Stonewall, LLC Registration Number: 73826

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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 (SO 2 ) 5.26 Greenhouse Gases (GHG) Carbon Dioxide Equivalent (CO 2 e) 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 0.66Green Energy Partners / Stonewall, LLC Registration Number: 73826

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PM-2.5 (Includes filterable and condensibles) 0.15 0.66 Greenhouse Gases (GHG) Carbon Dioxide Equivalent (CO 2 e) 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 (CO 2 e) 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 (CO 2 e) 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

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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 (CO 2 e) 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 99.1Green Energy Partners / Stonewall, LLC Registration Number: 73826

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condensibles Sulfur Dioxide (SO 2 ) 5.44 5.37 Greenhouse Gases (GHG) Carbon Dioxide Equivalent (CO 2 e) 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. NO x (and VOC) Offsets — The permittee shall secure NO x emission offsets if the GE 7FA.05 combustion turbines are installed, and NO x and 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 NO x 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. 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

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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 NO x (measured as NO 2 ) and carbon monoxide (CO), in parts per million by volume (ppmvd) corrected to 15 percent 0 2 , 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 NO x and 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, NO x

data and CO data shall each be reduced to one-hour rolling blocks. The relative accuracy test audit (RATA) of the NOx/0 2 CEMS 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 (NO x CEMS)— Performance evaluations of the NO x and, if applicable, SO 2

CEMS 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 andGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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 NO x and 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 NO x

and 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 NO x Continuous 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: NO x concentration, 0 2

concentration, 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 SO 2 Monitoring Systems:Green Energy Partners / Stonewall, LLC Registration Number: 73826

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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 NO x permit limit is exceeded. The report shall include for each excess emission of NOx : start time, duration, equipment involved, actual NO x emissions in ppmvd @ 15% 0 2 , 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 AgencyGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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 NO x and diluent monitors, the data acquisition and handling system must calculate and record the hourly NO x emission 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 0 2 concentration exceeds 19.0 percent 0 2 , a diluent cap value of 19.0 percent 0 2 may 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 60Green Energy Partners / Stonewall, LLC Registration Number: 73826

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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 NO 2 ) 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 NO x and (if applicable) diluent gas are to be selected following EPA Method 20 or EPA Method 1 (non particulate procedures), and sampled for equal time intervals. The sampling must be performed with a 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. NO x and 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:Green Energy Partners / Stonewall, LLC Registration Number: 73826

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i. If each of the individual transverse point NOx concentrations 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 0 2 from 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 NO x

concentration 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 NO x 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 0 2 from 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 NOx emissions 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 NO x 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 NO x emission 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 theGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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 (SO 2 ) — Combustion Turbines — Initial performance tests shall be conducted on each combined-cycle power generating unit (Ref. No. CCT1 & CCT2) for sulfur dioxide (SO 2 ) 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 SO 2 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 SO 2 and 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

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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 NOx

and 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

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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 SO 2

Performance Test — Combustion Turbines — Annual performance tests shall be conducted on each combined-cycle combustion turbine (Ref. No. CCT1 & CCT2) for sulfur dioxide (SO 2 ) 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

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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 SO 2 and 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 requestby 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:Green Energy Partners / Stonewall, LLC Registration Number: 73826

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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)Green Energy Partners / Stonewall, LLC Registration Number: 73826

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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.Green Energy Partners / Stonewall, LLC Registration Number: 73826

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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 NO x offsets 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

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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

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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

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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 airGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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 theGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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-02 a /2.06 E-02 b 8.76E-02 a / 8.88E-02 b Formaldehyde 50-00-0 7.65E-01 a /7.54E-01 b 3.09E-00a / 3.11E-00 b Cadimum 7440-43-9 6.31E-03a/5.95E-03 b 2.25E-02 a /2.25E-02 b Chromium 7440-47-3 8.04E-03 a/7.57E-03 b 2.86E-02 a 12.86E-02 b Nickel 7440-02-0 1.21E-02 a /1.14E-02 b 4.29E-02 a /4.29E-02 b

a Emissions based on GE 7FA.05

b Emissions 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 eachGreen Energy Partners / Stonewall, LLC Registration Number: 73826

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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

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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 SignificantDeterioration (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 (NO x) 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 (CO 2 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), NO 2(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 SO2 and 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 ElectricGreen 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
SO 2 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, NO N , 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 SO 2 Annual 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 producedto 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, anintermediate-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 NO x

and 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) forGreen 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. SO 2 emissions 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 Humidit y (%) 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) NO x 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

SO 2 emissions are based on conversion of all sulfur in fuel to SO 2 , so startup and shutdown do not affect SO 2 emissions 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 SO 2 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 NAGreen Energy Partners / Stonewall, LLC April 30, 2013 Page 19

NO R , CO, and SO 2

emissions 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 VOC b 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

SO 2 0.02 0.087 0.005 0.002 GHG and CO2e 8,873 38,856 2,365 10,362

a Based on emission factors from the proposed BACT emission rates for natural gas-fired boilers and heaters.

b Based 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)

tons/yr lbs/hr NO,,a 21.98 5.49 2.17 0.54 CO a 12.02 3.0 1.72 0.47 VOC a ' e 21.98 5.49 2.17 0.54 PM-10 d 1.37 0.34 0.22 0.0.00543 PM-2.5 1.37 0.34 0.22 0.0.00543Green Energy Partners / Stonewall, LLC April 30, 2013 Page 20

SO 2 b 0.025 0.0006 0.00039 0.000097 GHG and CO2e 2,630 658 415 104

a Based 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.

b lb/hr based on fuel sulfur. VOC = TOC.

d Since 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) Total Generator (EG1)

NOx 148.2" /

154.48b 3.61 0.96 5.49 0.54 159a/ 164.9 b
CO 188.6a/124.8 b 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 37.6 a/ 51.9b PM-10 (Condensa ble and filterable) 93.66 a/

94.68b 0.66 0.18
0.34 0.00543 10.27 105.2 a/ 106.1 b

PM-2.5 (Condensa ble and filterable) 93.66 a/

94.68 0.66 0.18
0.34 0.00543 3.19 98.1 a / 99.1 b

SO2 5.2 a / 5.26 6 0.0857 0.02 0.0006 0.000097 5.44a/ 5.37 b
GHG / CO2e 2,418,272 a/

2,414,2966 38,856 10,362 658 104 2,468,468 a / 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-06Green Energy Partners / Stonewall, LLC April 30, 2013 Page 22

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 April 30, 2013 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 Sig nificant PSD
Threshold Levels (tpy) Subject to

(Article 8 ) Non Attainment MNSR (Article 9) e NO„ 159 a/ 164b 40 Article 8 &Article 9 CO 207a/ 143 b 100 Article 8 VOC 38a 152 b NA" Article 9 e PM 105a / 106 b 25 Article 8 PM-10 105 a/ 106 b 15 Article 8 PM-2.5 98 a199 b NA d Article 9 SO2 5.44a/ 5.37 b 10 No GHG (CO2e) 2,468,228 a/

2,464,25 b 100,000 Article 8
Sulfuric acid mist (H2SO4) 2.87 a/ 2.81 b 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 onlyd — 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 NO N , 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 NO R

. 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)



## NG Control

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 NH3 injection system, and high NH3slip. 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 thermalNO, 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, THERMALLONO X TM, and PahlmannTM A number of other combustion turbine NO, emissions control technologies for combustion turbines are being marketed including XONONTM, LoTO,Tm, THERMALLONO X TM, 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% 0 2 ). 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.



## NG control

### 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% 0 2 which is higher than the 1.0

### Green Energy Partners / Stonewall, LLC April 30, 2013 Page 33

ppmvd at 15% 0 2

guarantees 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% 0 2

which 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% 0 2 . 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 NO x emissions generation. Higher combustion zone temperatures and residence times lead to more complete combustion and lower CO emissions, but higher NO x 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% 0 2 as 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% 0 2 . 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% 0 2 . 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% O 2 for compliance.

Typically, CO emission rates of 2 ppmvd at 15% 02 to 3.5 ppmvd at 15% 02

are 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 -3

lb/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 10'3

lb/MMBtu at full load

Unlike NO N , 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 SO 2 and 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 SO 2 and 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 SO 2 and 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% 0 2 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 NO x . 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 CO 2 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 MW 1400 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 CO 2 e/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 qualitynatural 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 SO 2 from 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 SO 3

by 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 peryear. 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 alimitation 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 (40CFR 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

SO 2 emissions 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 SO 2 emissions and monitoring and testing requirements. Using the most conservative assumptions, the NO, limit in Subpart KKKK is 15 ppm at 15% 02 and the SO 2

limit 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 SO2 permit 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 pei iiiit.



### • 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 NO R , 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 NO x emissions 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 thenatural 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 SO 2 (unless an alternative method of determining SO 2 emissions 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 SO 2 emission 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.

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## 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-NO x burners);

• 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 NO x , 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 NO R) 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 NO x Budget Trading Program (9 VAC 5 Chapter 140 Part I "Regulations for Emissions Trading — NO x Budget Trading Program") became effective in 2002. This program required that applicable units participate in a regional NO x ozone 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 — NO x Annual Trading Program"; Part III, "Regulations for Emissions Trading — NO x Ozone 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 NO x ozone 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 NO x emissions 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 ShutdownsTable 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 NO 2 ), 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 8 th Floor 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 Greenwayin 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 emitDEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

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. NO x and 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 PM

2 5NAAQS. 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 PM2 5.

• The area is eventually redesignated as attainment for PM25.

As a result, an air quality analysis was also performed for PM 2 5 to demonstrate that the projected PM2 5 emissions from the proposed facility will not cause or significantly contribute to a violation of any applicable PM2 5 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.

### DEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

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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.DEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

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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 (1 1 0 11 ) 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), PM2 5 (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

### DEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

December 14, 2012 Page 5 of 14

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 NO2 SIL 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), NO 2 , and PM2. 5 

### and the PSD increment for PM 2. 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.

• NO 2 (1-hour) - To attain this standard, the 3-year average of the 98th percentile 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 98 th percentile of 24-hour concentrations at each population-oriented monitor within an area must not exceed the standard.DEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

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PM2 5 (annual) - To attain this standard, the 3-year average of the weighted annual mean PM2

5 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 (μm 3 ) Ambient Background Concentration (1- 1113 ) Total

Concentration 0- 1 0r 1 ) 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 (ligim 3 ) Ambient Background Concentration (N-0 113 ) Total Concentration (ligim 3 ) NAAQS 01 0 113 )

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 PM 2 5 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.DEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

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Table 5 PSD Increment Modeling - Cumulative Impact Results

General Electric Turbines

Pollutant Averaging Modeled Concentration Class II PSD

Increment Period (4

1113 ) (1 1 g/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 andassociated 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.DEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

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Table 7 Toxics Analysis Maximum Predicted Concentrations

General Electric Turbines

Toxic Pollutant Averaging

Period Maximum

Modeled Concentration From Project ([tgim 3 ) 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/m 3 ) SAAC

(1 1 g/m 3 )

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, PM 10 , 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.DEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

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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
PM 1 0 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 fromsecondary 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

### DEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

December 14, 2012 Page 12 of 14

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 PM 10 , PM 2 5, 

### and NO2

was required. A preliminary modeling analysis for PM 1 0, 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 )
PM 1 0 24-hour 0.1117 0.3

Annual 0.0029 0.2

PM25 24-hour 0.1117 0.07

Annual 0.0029 0.06 NO 2 Annual 0.0025 0.1DEQ Air Quality Analyses Review Stonewall Combined-Cycle Project

December 14, 2012 Page 13 of 14

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), PM 1 0 (24-hour and annual averaging periods), and PM2 5 (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 PM 2. 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 PM 2

5 PSD increment analysis included emissions from the proposed source and nearby PM

2. 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 (1-4 1 T 13 ) 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 FormVIRGINIA 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: 

# 6-3-dm /

, r
The unclerSigneci

f ocal 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:

S ir hp

.---< Type or ;ZYYtct 

### re' e print name: Title: CD v h+ • ,s ei

County, city I t P or town: 1-1

01) 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