# COMMONWEALTH of VIRGINIA
DEPARTMENT OF ENVIRONMENTAL QUALITY

PIEDMONT REGIONAL OFFICE 4949A Cox Road, Glen Allen, Virginia 23060 (804) 527

- 5020 Fax (804) 527

- 5106 www.deq.virginia.gov Douglas W. Domenech Secretary of Natural Resources David K. Paylor Director

Michael P. Murphy Regional Director



### March 12 , 2013

Mr. Robert McKinley Vice President of Generation and Construction Virginia Electric and Power Company 5000 Dominion Blvd. Glen Allen, VA 23060

Location: Brunswick County Registration No.: 52404

Dear Mr. McKinley :

Attached is a permit to construct and operate a n electric power generati on 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 December 2 1 , 2012 and solicited written public comm ents by placing a newspaper advertisement in the Brunswick Times Gazette and Independent Messenger (Emporia) on January 2, 2013 . A public hearing was held on February 4 , 2013 . The required comment period, provided by 9 VAC 5

- 80

- 1 775 F expired on February 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 re lieve Virginia Electric and Power Company 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 (FWP

- 1) may be affected faciliti es under 40 CFR 60, New Source Performance Standard (NSPS), Subpart IIII and the propane emergency generator (EG

- 2) may be an affected facility under NSPS, Subpart JJJJ. T herefore

, these units may be subject to owner/operator requirements of the NSPS and 40 CFR 63, Maximum Achievable Control Technology, (MACT), Subpart ZZZZ,. 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 attached 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 , IIII, JJJJ and KK KK shall to be
sent to :

### Mr. Robert McKinley Registration Number: 52404

Page 2

Associate Director Office of Air Enforcement (3AP20) U.S. Environmental Protection Agency Region III 1650 Arch Street Philadelphia, PA 19103

- 2029

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

- 170

- 200 provide that you may request a formal hearing from this case decision by filing a petition with the Board within 30 days after this case decision notice was mailed or delivered to you. 9 VAC 5

- 170

- 200 provides that y ou 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 Virgin ia, 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 Depa rtment 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 Virg inia 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 (804 ) 527

- 5020.

Sincerely,

Kyle Ivar Winter , P.E. Deputy Regional Director

KIW/AMS / 52404_001_1 3 _PSD.docx

Attachments: Permit

NSPS, Subpart s Dc, IIII, JJJJ, and KKKK

, MACT Subpart ZZZZ Source Testing Report Format

cc: Director, OAPP (electronic file submission) Chief, Office of Air Enforcement and Compliance Assistance, U.S. EPA, Region III (electronic file submission) Inspector , Air Compliance

# COMMONWEALTH of VIRGINIA
DEPARTMENT OF ENVIRONMENTAL QUALITY

PIEDMONT REGIONAL OFFICE 4949A Cox Road, Glen Allen, Virginia 23060 (804) 527

- 5020 Fax (804) 527

- 5106 www.deq.virginia.gov Douglas W. Domenech Secretary of Natural Resources David K. Paylor Director

Michael P. Murphy Regional Director



### PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 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,

Virginia Electric and Power Company 5000 Dominion Boulevard Glen Allen, Virginia 23060 Registration No.: 52404 County

- Plant ID : 025

- 0037

is authorized to construct and operate

an electric power generation facility

located at

20100 Governor Harrison Parkway

, Freeman, V A 23856 (south of Rte 58, approximately 1.3 mi NE of Racume, Brunswick Co., VA)

in accordance with the Conditions of this permit.

Approved on March 12 , 2013

.

Deputy Regional Director Department of Environmental Quality

Permit consists of 28 pages. Permit Conditions 1 to 84

.

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 2

INTRODUCTION

This permit approval is based on the permit application dated December 20, 2011 , including amendment information dated March 7, 2012 , September 7, 2012

, November 5 , 2012 and December 2 1 , 2012 . Any changes in the permit application specif ications 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 ma y 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

- 10

- 2 0 of the State Air Pollution Control Board 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 obligati ons to maintain current stationary source emissions data will necessitate a prompt response by the permittee to requests by the DEQ or the Board for information to include, as appropriate: process and production data; changes in control equipment; and oper ating 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 State Air Pollution Control Board 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 at this facility consists of the following:

Equipment to be Constructed Ref

. No

. Equipment Description Rated Capacity Federal Requirements Three on one power block with three natural gas

- fired combustion turbine generators, each with a duct

- fired heat recovery steam generator (HRSG) , providing steam to a common steam turbine generator T

- 1M Mitsubishi M501 GAC combustion turbine

generator with HRSG duct burner (natural
gas

- fired) 3,442 MM Btu/hr NSPS Subpart KKKK NOx trading Subparts AA

- II

, AAA

- III, and AAAA

- IIII T

- 2M Mitsubishi M501 GAC combustion turbine

generator with HRSG duct burner (nat ural
gas

- fired) 3,442 MM Btu/hr NSPS Subpart KKKK NOx trading Subparts AA

- II, AAA

- III, and A A AA

- IIII T

- 3M Mitsubishi M501 GAC combustion turbine

generator with HRSG duct burner (natural
gas

- fired) 3,442 MM Btu/hr NSPS Subpart KKKK NOx trading Subparts AA

- II, AAA

- III, and A A AA

- IIII Ancillary Equipment B

- 1 Auxiliary Boiler (natural gas

- fired) 66.7 MM Btu/hr NSPS Subpart Dc GH

- 1 , 2, 3 Three Fuel Gas Heater s (natural gas

- fired) 8 MM Btu/hr each None

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 3

Equipment to be Constructed Ref

. No

. Equipment Description Rated Capacity Federal Requirements EG

- 1 Emergency Generator (diesel) 2200 kW NSPS Subpart IIII (non

- delegated) MACT Subpart ZZZZ (non

- delegated) EG

- 2 Emergency Generator ( propane ) 80 kW NSPS Subpart JJJJ (non

- delegated) MACT Subpart ZZZZ (non

- delegated) FWP

- 1 Fire Water Pump (diesel) 305 bhp NSPS Subpart IIII (non

- delegated) MACT Subpart ZZZZ (non

- delegated) AEC

- 1 Delugeable Auxiliary Equipment Cooler 69,600 gallons of water/hr None

IC

- 1 through 4 Four Turbine Inlet Air Chillers

(mechanical draft cooling towers) 690,000 gallons of water/hr each None

C B

- 1 through CB

- 11 Eleven Electrical Circuit Breakers 18,095 lb SF 6 None

ST

- 1 Distillate fuel oil tank 6000 gallons None 

### Specifications included in the permit under this Condition are for informational purposes only and do not form enforceable terms or conditions of the pe rmit. ( 9 VAC 5

- 80

- 1180 D 3 )

C ombined

- cycle gas turbine generators and duct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M)

2. Emission Controls : Nitrogen Oxides

- Nitrogen oxide (NO x 

### ) emissions from each of the combined cycle gas turbine generators and associated duct

- fired heat recovery steam generators ( HRSG ) (T

- 1M, T

- 2M, T

- 3M) shall be controlled by dry, low NO x 

### burners and selective catalytic reduction (SCR) with a NO X 

### performance of 2.0 ppmvd at 15% O 2 

### for natural gas. The low NO X 

### burners shall be installed and operated in accordance with manufacturer’s specifications. The SCR shall be provided with adequate access for inspection and shall be in operation when the combined cycle gas turbine generators are operating (at all times e xcept during startup and shutdown, as defined in Condition 12 )

. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 2 8 0)

3. Monitoring Devices: SCR

- Each SCR system shall be equipped with devices to continuously measure or be calculated and record ammonia feed rate, gas stream flow rate, and catalyst bed inlet gas temperature. Each monitoring device shall be installed, maintained, calibrated and operated in accordanc e with approved procedures that 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 SCR system is operatin g. (9 VAC 5

- 50

- 20 C and 9 VAC 5

- 80

- 1705 B)

4. Monitoring Device Observation : SCR

- To ensure good performance, the devices used to continuously measure or be calculated and record the ammonia feed rate, gas stream flow rate, and catalyst bed inlet temperatur e on the SCR 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

- 50H and 9 VAC 5

- 80

- 1705 B )

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 4

5. Emission Controls : Carbon Mon oxide

– Carbon m ono xide (CO) emissions from each of the combined cycle gas turbine generators and associated duct

- fired H RSG (T

- 1M, T

- 2M, T

3M) shall be controlled by an oxidation catalyst and good combustion practice s . The oxidation catalyst shall be provided with adequ ate access for inspection and shall be in operation when the combined cycle gas turbine generators are operating (at all times except during startup and shutdown, as defined in Condition 12 ). (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

6. Emission Controls : Volatile Organic Compounds

– Volatile organic compound (VOC) emissions from each of the combined cycle gas turbine generators and associated d uct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) shall be controlled by an oxidation catalyst and good combustion practices . The oxidation catalyst shall be provided with adequate access for inspection and shall be in operation when the combined cycle gas turbine genera tors are operating (at all times except during startup and shutdown, as defined in Condition 12 ). (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

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 ope rated in accordance with approved procedures that shall include, at 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 oxid ation catalyst is operating. (9 VAC 5

- 50

- 20 C, 9 VAC 5

- 50

- 280, and 9 VAC 5

- 80

- 1705 B)

8. Monitoring Device Observation : Oxidation Catalyst

- To ensure good performance, the device used to continuously measure and record the catalyst bed inlet and outlet gas temperature on the oxidation catalyst shall be observed by the permittee with a frequency sufficient to ensure good performance of the oxidation catalyst system, but not less than once per day of operation. (9 VAC 5

- 50

- 50H and 9 VAC 5

- 80

- 1705 B )

9. Emission Controls: Sulfur dioxide and sulfuric acid mist

– Sulfur dioxide (SO 2 

### ) and sulfuric acid mist (H 2 

### SO 4 

### ) emissions from each of the combined cycle gas turbine generators and associated duct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) shall be controlled by the us e of pipeline

- quality natural gas with a maximum sulfur content of 0.4 grains per 100 standard cubic feet (scf) , on a 12

- month rolling average

. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

10. Emission Controls: Particulate Matter

– Particulate Matter (PM 10 

### , PM 2.5 

### ) emissions from each of the combined cycle gas turbine generators and associated duct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) shall be controlled by good combustion practices and the use of pipeline

quality natural gas with a maximum sulfur content of 0.4 grains per 100 standard cubic feet (scf) , on a 12

- month rolling average

. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

11. Emission Controls : Greenhouse Gases

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

, as CO 2 

### e from the combined cycle gas turbine

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 5

generators and associated d uct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) shall be controlled by the use of low carbon fuel (natural gas) and high efficiency design and operation of the combined cycle gas turbine generators and asso ciated d uct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M and steam turbine generator )

. The combined cycle gas turbine generators and associated d uct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M and steam turbine generator ) shall operate at a higher heating value heat rate, at full load and corrected to ISO conditions, not to exceed 7, 5 00 Btu/kW h net (HHV) output

. Compliance with this limit shall be demonstrated as contained in Conditions 67 and 69

. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

12. Startup/Shutdown

– The short

- term emission limits contained in Condition 40 apply at all times except during periods of startup and shutdown.

a. Startup and shutdown periods are defined as follows:

i. Cold Startup

– refers to restarts made 72 hours or more after shutdown. Exclusion from the short

- term emissions limits for cold startup periods shall not exceed an annual average of 169 minutes per occurrence.

ii. Warm Startup

– refers to restarts made more than 8 but less than 72 hours after shutdown. Exclusion from the short

- term emissions limit s for warm startup periods shall not exceed an annual average of 9 3 minutes per occurrence.

iii. Hot Startup

– refers to restarts made 8 hours or less after shutdown. Exclusion from the short

- term emissions limits for hot startup periods shall not exceed an a nnual average of 43 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 turbine is cut. Exclusion from the short

- term emissions limits for shutdown sh all not exceed an annual average of 11 minutes per occurrence.

b. The permittee shall operate the CEMS during periods of startup and shutdown.

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

. The records must include calculations of NO x 

### 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.

e. The permittee shall operate the facility so as to minimize the frequency and duration of startup and shutdown events. (9 VAC 5

- 50

- 2 8 0 and 9 VAC 5

- 80

- 1705)

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 6

Auxiliary boiler (B

- 1) and fuel gas heater s (GH

- 1 through GH

- 3 )

13. Emission Controls: Nitrogen Oxides

– NO x 

### emissions from the auxiliary boiler (B

- 1) and three fuel gas heater s (GH

- 1 through GH

- 3 ) shall be controlled by ultra low

- NO x 

### burners with a NO x 

### performance of 9 ppmvd at 3% O 2 

### for natural gas. The low NO x 

### burners shall be installed and operated in accordance with manufacturer’s specifications. (9 VAC 5

- 50

- 280 and 9 VAC 5

- 80

- 1705 B)

14. Emission Controls: Carbon Monoxide and Volatile Organic Compounds

– CO and VOC emissions from the auxiliary boiler (B

- 1) and fuel gas heater s (GH

- 1 through GH

- 3 ) 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% O 2 

### . Boiler and heater operators shall be trained in the proper operation of all such equipment. Training shall consist of a review and familiarization of the manufactur er’s operating instructions, at a minimum

. The permittee shall maintain records of the required training including a statement of time, place and nature of training provided. The permittee shall have available good written operating procedures and a main tenance schedule for the boiler and heater. These procedures shall be based on the manufacturer’s recommendations, at a minimum. All records required by this condition shall be kept on site and made available for inspection by the DEQ. (9 VAC 5

- 50

- 280 an d 9 VAC 5

- 80

- 1705 B)

15. Emission Controls: Sulfur dioxide and sulfuric acid mist

– SO 2 

### and H 2 

### SO 4 

### emissions from auxiliary boiler (B

- 1) and three fuel gas heaters (GH

- 1 through GH

- 3) shall be controlled by the use of pipeline

- quality natural gas with a maximum sulfur content of 0.4 grains per 100 standard cubic feet (scf) , on a 12

- month rolling average

. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

16. Emission Controls: Particulate Matter

– PM 10 

### and PM 2.5 

### emissions from the auxiliary boiler (B

- 1) and three fuel gas heaters (GH

- 1 through GH

- 3) shall be controlled by good combustion practices and the use of pipeline

- quality natural gas with a maximum sulfur content of 0.4 grains per 100 standard cubic feet (scf) , on a 12

- month rolling average

. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

17. Emission Controls: Greenhouse Gases

– CO 2 

### e from the auxiliary boiler (B

- 1) and three fuel gas heaters (GH

- 1 through GH

- 3) shall be controlled by the use of natural gas fuel and high efficiency design and operation

. (9 VAC 5

- 80

- 170 5 B and 9 VAC 5

- 50

- 280)

Emergency Units (EG

- 1 , EG

- 2 and FWP

- 1)

18. Emission Controls: EG

- 1, FWP

- 1

- PM 10 

### , PM 2.5 

### , NO x 

### , CO, SO 2 

### , VOC, and H 2 

### SO 4 

### emissions from the diesel emergency units ( EG

- 1 and FWP

- 1 ) shall be controlled by good combustion practices and the use of ultra low sulfur diesel fuel oil with a maximum sulfur content of 15 ppm w

. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 7

19. Emission Controls: EG

- 2

- PM 10 

### , PM 2.5 

### , NO x 

### , CO, SO 2 

### , VOC, and H 2 

### SO 4 

### emissions from the propane emergency unit ( EG

- 2 ) shall be controlled by good combustion practices. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

20. Emission Controls: Greenhouse gasses

– CO 2 

### e e missions from the diesel emergency units ( EG

- 1 and FWP

- 1 ) shall be cont rolled by the use of low carbon fuel and high efficiency design and operation

. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

21. Monitoring Devices

– The permittee must install a non

- resettable hour meter on the emergency generator s (EG

- 1 and EG

- 2 ) and the emergency fire water pump (FWP

- 1) prior to the startup of each unit. The hour meters shall be provided with adequate access for inspection. (9 VAC 5

- 50

- 280 and 9 VAC 5

- 80

- 1705 B)

22. Maintenance and Operation

– The permittee must maintain and operate the emergency generator s (EG

- 1 and EG

- 2 ) and the emergency fire water pump (FWP

- 1) according to the manufacturer’s written instructions, or procedures developed by the permittee that are approved by the manufacturer, ov er the entire life of the engine. In addition, the permittee
may on l y change those settings that are approved by the manufacturer or DEQ

. ( 9 VAC 5

- 50

- 280 and 9 VAC 5

- 80

- 1705 B)

Miscellaneous Processes

23. Emission Controls: Inlet Chillers

– Particulate matter emissions from the four , 11,500

- gallon/minute inlet chillers (CH

- 1 through CH

- 4) shall be controlled to a drift rate of 0.00 05 percent of the circulating water flow and a total dissolved solids content of the cooling water of no more than 1000 mg/l. The permittee shall keep a log of weekly testing for total dissolved solids content of the cooling water. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

24. Emission Controls: Delugeable Auxiliary Equ i pment Cooler

– Particulate matter emissions from the 1,160 gall on/minute delugeable auxiliary equipment cooler (AEC

- 1) shall be controlled to a drift rate of 0.010 percent of the circulating water flow and a total dissolved solids content of the cooling water of no more than 300 mg/l. The permittee shall keep a log o f weekly testing for total dissolved solids content of the cooling water. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

25. Emission Controls: Electrical breakers

– Greenhouse gas emissions (including SF 6 

### ) from the electrical circuit breakers ( CB

- 1 through CB

- 11 ) s hall be controlled by an enclosed

pressure 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. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 8

OPERATING LIMITATIONS

26. Fuel : Gas t urbines and auxiliary boiler

- The approved fuel for the combined cycle gas turbine generators and associated duct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) , fuel gas heaters (GH

- 1 through GH

- 3) and the auxiliary boiler (B

- 1) is pipeline quality natural gas with a maximum sulfur content of 0.4 gr ains per 100 s tandard c ubic f ee t (scf) . A change in the fuel may require a permit to modify and operate. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280 )

27. Fuel Throughput : Gas t urbines

- The three combined cycle gas turbine generators and associated d uct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) combined shall consume no more than a total of 88,682 x 10 6 

### scf 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

- 1705 B and 9 VAC 5

- 50

- 280 )

28. Fuel Monitoring : Gas turbines

– The permittee shall conduct tests for the total sulfur
content of the natural gas being fired at the electric power generation facility to verify that the sulfur content of the natural gas is 0.4 grains of total sulfur per 100 scf on a 12

- month rolling average in order to demonstrate that potential sulfur dioxide emissions shall not exceed the limits specified in Condition 40

. The permittee shall demonstrate compliance with the sulfur content limit in Condition 26 using one of the following:

a. Determine and record the total sulfur content of the natural gas each month. A monthly sample is not required for months when the turbines operated for 48 hours or less, or

b. Develop custom schedules for determination of the 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 CFR 60.4370(c)(1) and (c)(2), custom schedules shall be substantiated with data and shall receive prior EPA approval. (9 VA C 5

- 50

- 410

, 9 VAC 5

- 50

- 280 , 40 CFR 60.4365(a), 40 CFR 60.4370(b), and 40 CFR 60.4370(c) )

29. Fuel Throughput: Auxiliary boiler

- The auxiliary boiler (B

- 1) shall consume no more than 573 x 10 6 

### scf 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

- 1705 B and 9 VAC 5

- 50

- 280 )

30. Fuel: Diesel f

ire water pump and emergency diesel generator

- The approved fuel for the
emergency diesel fire water pump (FWP

- 1) and emergency diesel generator (EG

- 1) is ultra low sulfur diesel ( ULSD ) . A change in the fuel may require a permit to modify and operate. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280 )

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 9

31. Fuel: propane - fired e mergency generator

- The approved fuel for the emergency generator (EG

- 2) is liquid petroleum gas (LPG)(as propane). A change in the fuel may require a p ermit to modify and operate. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

32. Fuel: F ire water pump and emergency generator s

- The fuels for the fire pump (FWP

- 1) and generators (EG

- 1 and EG

- 2) shall meet the specifications below: DIESEL FUEL (ULSD) which meets the ASTM D 975

- 10b specification for S15 fuel oil : Maximum sulfur content per shipment: 0.0015%

LPG, including butane and propane, which meets ASTM specification D1835

. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

33. Operating Hours: Fire wate r pump

- The emergency fire water pump (FWP

- 1) 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 to tal for the most recently completed calendar month to the individual monthly totals for the preceding 11 months. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280)

34. Operating Hours: Emergency generator s

- The emergency generator s (EG

- 1 and EG

- 2 ) shall not operate more than 500 hours each 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

- 1705 B and 9 VAC 5

- 50

- 280)

35. Emergency Operation: Generators and fire water pump

– The operation of the emergency generators (EG

- 1 and EG

- 2) and fire water pump (FWP

- 1) is limited to
emerge ncy situations. Emergency situations include a) emergency generator use to produce power for critical networks or equipment (including power supplied to portions of the facility) when electric power from the local utility (or the normal source, if the fac ility runs on its own power production) is interrupted and b) emergency engine use to pump water in the case of fire or flood, etc. The emergency generators (EG

- 1 and EG

- 2) and fire water pump (FWP

- 1) may be operated for the purpose of maintenance checks and readiness testing, provided that the tests are recommended by federal, state, or local government, the manufacturer, the vendor, or the insurance company associated with the engine. Maintenance checks and readiness testing of such units is limited to 100 hours per calendar year for each unit. (9 VAC 5

- 80

- 1705 B and 9 VAC 5

- 50

- 280 )

36. Fuel Certification

- The permittee shall obtain a certification from the fuel supplier with each shipment of ULSD oil. Each fuel supplier certification shall include the fo llowing:

a. The name of the fuel supplier;

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 10

b. The date on which the ULSD oil was received;

c. The quantity of ULSD oil delivered in the shipment;

d. A statement that the ULSD oil complies with the American Society for Testing and Materials specifications ASTM D975 for Grades 1 or 2 Ultra Low Sulfur fuel oil, or other DEQ approved fuel specifications;

e. The sulfur content of the ULSD oil;

Fuel sampling and analysis, independent of that used for certification, as may be periodically required or conducted by DEQ may be used to determine compliance with the fuel specifications stipulated in Condition 32 . Exceedance of these specifications may be considered cred ible evidence of the exceedance of emission limits. ( 9 VAC 5

- 50

- 280 )

37. Maintenance and Operation: Fire water pump and emergency generator s

– The permittee must maintain and operate the emergency fire pump (FWP

- 1) and emergency generator s (EG

- 1 and EG

- 2 ) according to the manufacturer’s written instruction, or procedures developed by the permittee that are approved by the manufacturer, over the entire life of the engine. In addition, the permittee may only change those settings that are approved by the man ufacturer. (9 VAC 5

- 50

- 280)

38. Fuel Throughput: Fuel gas heater

- The three fuel gas heaters (GH

- 1 through GH

- 3) combined shall consume no more than a total of 20 6 x 10 6 

### scf 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

- 50

- 280 )

39. Requirements by Reference

- Except where this permit is more restrictive than the applicable requirement, the NSPS equipment as described in Condition 1 shall be operated in compliance with the requirements of 40 CFR 60 , Subpart s Dc and KKKK

. (9 VAC 5

- 50

- 400 and 9 VAC 5

- 5 0

- 410)

EMISSION LIMITS

40. Short

- Term Emission Limits : Gas Turbines

- Emissions from the operation of each combined

- cycle gas turbine generator and associated HRSG duct burn er (T

- 1M, T

- 2M, T

3M)

, shall not exceed the limits specified below:

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 11

Pollutant Short term emission limits

PM 10 

### (including condensable PM)  0.0 033 lb/MMBtu and 9.7 lb/hr as a three

- hour average without duct burn er firing

 0.0047 lb/M M Btu and 16.3 lb/hr as a three

- hour average with duct burner firing

.

PM 2.5 

### (including condensable PM)  0.0033 lb/MMBtu and 9.7 lb/hr as a three

- hour average without duct burner firing

 0.0047 lb/MMBtu and 16.3 lb/hr as a three

- hour average with duct burner firing. Sulfur dioxide  0 0.00 112 lb/MMBtu Nitrogen Oxides (as NO 2 

### )  2.0 ppmvd @ 15% O 2 

### as a one

- hour r olling average

Carbon monoxide  1. 5 ppmvd @ 15% O 2 

### as a three

- hour rolling average without duct burning

 2.4 ppmvd @ 15% O 2 

### as a three

- hour rolling average with duct burn ing Volatile organic compounds  0.7 ppmvd @ 15% O 2 

### without duct burner firing

 1. 6 ppmvd @ 15% O 2 

### with duct burner firing

Sulfuric acid mist  0.000 58 lb/MMBtu without duct burner firing

 0.00067 lb/MMBtu with duct burner firing 

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


### .
Short

- term emission limits represent averages for a three

- hour sampling period except for nitrogen oxides, which shall be calculated as a one

- hour average.

Unless otherwise specified, limits apply at all times except during startup, shutdown, and malfu nction. Periods considered startup and shutdown are defined in Condition 12 of this permit.

These emissions are derived from the estimated overal l emission contribution from operating limits. 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 2

, 5

, 6

, 26

, 49

, 52

, 61 , and 62 (9 VAC 5

- 50

- 280, 9 VAC 5

- 80

- 1705, 9 VAC 5

- 80

- 1715)

41. Emission Limits: Combustion Turbines

– CO 2 

### e emissions from the combined cycle gas turbine generators and associated duct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) shall not exceed 920 lbs/MWh ( net HHV ) calculated monthly on a 12

- operating month annual average basis. Compliance may 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 electrical energy output over that same period. ( 9 VA C 5

- 50

- 280, 9 VAC 5

- 80

- 1705, and 9 VAC 5

- 80

- 1715 )

42. Annual Process Emission Limits

– E missions from the operation of each of the three combined cycle gas turbine generators and associated d uct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) shall not exceed the limits specified below:

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 12

PM 10 

### (including condensable) 71.4 tons/yr (on a 12

- month, rolling total )



### PM 2.5 

### (including condensable) 71. 4 tons/yr (on a 12

- month, rolling total)



### Sulfur Dioxide 16.9 tons/yr (on a 12

- month, rolling total)


### Nitrogen Oxides 110.3 tons/yr (on a 12

- month, rolling total) 

### (as NO 2 

### )

Carbon Monoxide 150.3 tons/yr (on a 12

- month, rolling total)


### Volatile Organic 101.3 tons/yr (on a 12

- month, rolling total) 

### Compounds

Sulfuric Acid 10.2 tons/yr (on a 12

- month, rolling total) 

### Mist

CO 2 

### e 1,76 3

, 902 tons/yr (on a 12

- month, rolling total)


### These emissions 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 emission limits may be determined as stated in Conditions 2

, 5

, 6

, 9

, 10

, 11

, 27

, 28

, 51

, 52 and 55

. (9 VAC 5

- 50

- 280, 9 VAC 5

- 80

- 1705, and 9 VAC 5

- 80

- 1715)

43. Process Emission Limits

– Emissions from the operation of the auxiliary boiler (B

- 1) shall not exceed the limits specified below:

PM 10 

### (including condensable) 0.5 lbs/hr 2.2 tons/yr (on a 12

- month, rolling total)



### PM 2.5 

### (including condensable) 0.5 lbs/hr 2.2 tons/yr (on a 12

- month, rolling total)


### Nitrogen Oxides 0.8 lb/hr 3.2 tons/yr (on a 12

- month, rolling total) 

### (as NO 2 

### )

Carbon M onoxide 2.5 lbs/hr 10.8 tons/yr (on a 12

- month, rolling total)


### Volatile Organic 0.4 lbs/hr 1.5 tons/yr (on a 12

- month, rolling total) 

### Compounds

CO 2 

### e 34,182 tons/yr (on a 12

- month, rolling total)



### These emissions 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 emission limits may be determined a s stated in Conditions 13

, 14

, 26 and 29

. (9 VAC 5

- 50

- 280, 9 VAC 5

- 80

- 1705, and 9 VAC 5

- 80

- 1715)

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 13

44. Process Emission Limits

- Emissions from the oper ation of the electrical circuit breakers ( CB

- 1 through CB

- 11 ) shall not exceed the limits specified below:

CO 2 

### e 2,162 tons/yr (on a 12

- month rolling total )


### 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. Compliance with these emission limits may be determined as stated in Conditions 1 and 25

. ( 9 VAC 5

- 50

- 280, 9 VAC 5

- 80

- 1705, and 9 VAC 5

- 80

- 1715 )

45. Process Emission Limits

- Emissions from the operation of the fire water pump (F W P

- 1) shall not exceed the limits specified below:

PM (filterable only) 0.54 g/kW

- hr

PM 10 

### (including condensable) 0. 4 g/ kW

- hr

PM 2.5 

### (including condensable) 0. 4 g/ kW

- hr

Sulfur Dioxide 0.00154 lb/MMBtu

Nitrogen Oxides (as NO 2 ) 

### 4.0 g/ kW

- hr

+ N on

- methane hydrocarbons



### Carbon Monoxide 3.5 g/ kW

- hr

CO 2 

### e 91.2 tons/yr (on a 12

- month rolling total )


### 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. C ompliance with these emission limits may be determined as stated in Conditions 30

, 32

, 33

, 35

, 37 and 51

. ( 9 VAC 5

- 50

- 280, 9 VAC 5

- 80

- 1705, and 9 VAC 5

- 80

- 1715 )

46. Process Emission Limits

- Emissions from the operation of the diesel emergency generator (EG

- 1) shall not exceed the limits specified below:

PM (including condensable) 0.2 g/kW

- hr

PM 10 

### ( including condensable) 0. 4 g/kW

- hr

PM 2.5 

### (including condensable) 0. 4 g/kW

- hr

Sulfur Dioxide 0.00154 lb/MMBtu

Nitrogen Oxides (as NO 2 ) 

### 6.4 g/kW

- hr 7.8 tons/yr (on a 12

- month rolling total )
+ Non

- methane hydrocarbons

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 14

Carbon Monoxide 3.5 g/kW

- hr 4.3 tons /yr (on a 12

- month rolling total )



### CO 2 

### e 814.0 tons/yr (on a 12

- month rolling total )


### 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. Compliance with these emission limits may be determined as stated in Conditions 30

, 32

, 34

, 35

, 37 , and 51

. ( 9 VAC 5

- 50

- 280, 9 VAC 5

- 80

- 1705, and 9 VAC 5

- 80

- 1715 )

47. Process Emission Limits

- Emissions from the operation of the propane emergency generator (EG

- 2) shall not exceed the limits specified below:

PM 10 

### (including condensable) 0.12 g/kW

- hr

PM 2.5 

### ( including condensable) 0. 1 2 g/kW

- hr

Sulfur Dioxide 0.00 059 lb/MMBtu

Nitrogen Oxides (as NO 2 

### ) 5.84 g/kW

- hr

Carbon Monoxide 174.4 g/kW

- hr 7.7 tons/ yr (on a 12

- month rolling total )



### CO 2 

### e 37.4 tons/yr (on a 12

- month rolling total )


### 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. Compliance with these emission limits may be determined as stated in Conditions 30

, 32

, 34

, 35

, 37 , and 51

. ( 9 VAC 5

- 50

- 280, 9 VAC 5

- 80

- 1705, and 9 VAC 5

- 80

- 1715 )

48. Process Emission Limits

– Emissions from the ope ration of the fuel gas heaters (GH

- 1 through GH

- 3) combined shall not exceed the limits specified below:

PM 10 

### (including condensable) 0. 007 lbs/ MMBtu 0.8 tons/yr (on a 12

- month, rolling total)



### PM 2.5 

### (including condensable) 0. 007 lbs/ MMBtu 0.8 tons/yr (on a 12

- month, rolling total)


### Nitrogen Oxides 0. 011 lb/ MMBtu 1.2 tons/yr (on a 12

- month, rolling total) 

### (as NO 2 

### )

Carbon Monoxide 0. 9 lbs/hr 3.9 tons/yr (on a 12

- month, rolling total)


### Volatile Organic 0.6 tons/yr (on a 12

- month, rolling total) 

### Compou nds

CO 2 

### e 12,299 tons/yr (on a 12

- month, rolling total)

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 15

These emissions are derived from the estimated overall emission contribution from operating limits, including periods of startup and shutdown. Exceedance of the operating limits may be considere d credible evidence of the exceedance of emission limits. Compliance with these emission limits may be determined as stated in Conditions 2

, 5

, 6

, 9

, 10

, 11

, 27

, 28 , and 51

. (9 VAC 5

- 50

- 280, 9 VAC 5

- 80

- 1705, and 9 VAC 5

- 80

- 1715)

49. Visible Emission Limit

- Visible emissions from the combined cycle gas turbine generators and associated d uct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) 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 the EPA Method 9 (reference 40 CFR 60, Appendix A). This condition applies at all times except during startup, shutdown (as defined in Condition 12 ) , and malfunction. (9 VAC 5

- 50

- 80 and 9 VAC 5

- 50

- 280)

50. Visible Emission Limit

- Visible emissions from the fuel gas heaters (GH

- 1 through GH

- 2) and auxiliary boiler (B

- 1) shall not exceed 10 percent opacity as determined by the EPA Method 9 (reference 40 CFR 60, Appendix A). (9 VAC 5

- 50

- 80 and 9 VAC 5

- 50

- 280)

51. Visible Emission L imit

- Visible emissions from the emergency fire water pump (FWP

- 1) and emergency generator s (EG

- 1 and EG

- 2 ) shall not exceed 10 percent opacity as determined by the EPA Method 9 (reference 40 CFR 60, Appendix A) . This condition applies at all times except during startup, shutdown, and malfunction. (9 VAC 5

- 50

- 80 and 9 VAC 5

- 50

- 280)

CEMS/

52. CEMS

- Continuous Emission Monitoring Systems (CEMS) shall be installed to measure and record the emissions of NO x 

### (measur e d as NO 2 

### ) , CO 2 

### and CO from each combine d cycle combustion turbine and associated duct

- fired HRSG (T

- 1 M , T

- 2M, T

- 3M) in ppmvd, corrected to 15 perce n t O 2


### . CEMS for NO x 

### shall meet the design specifications of 40 CFR Part 75 whereas CEMS for CO shall be installed, evaluated, and operated accordin g to the monitoring requirements in 40 CFR 6 0 .13

. The CEMS shall also measure and record the oxygen content of the flue gas at each location where NO x 

### and CO emissions are monitored and measure heat input and power output. 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 40 , NO x 

### data and CO data shall each be reduced to 1

- hour block averages. The relative accuracy test audit (RATA) of the NO x 

### CEMS shall be performed on a lb/MMBtu basis. ( 9 VAC 5

- 50

- 350 and 9 VAC 5

- 50

- 40)

53. CEMS Performance Evaluations

- Performance evaluations of the NO x 

### and, if applicable, SO 2 

### CEMS shall be conducted in accordance with 40 CFR Part 75 , Appendix A , and shall take place during the performance tests under 9 VAC 5

- 50

- 30 or within 30 days thereafter.

### Virginia Electric and Power Company

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March 12, 2013 Page 16

Two copies of the performance evaluations report shall be submitted to the Piedmont Region within 45 days of the evaluation. The continuous monitoring systems shall be installed and operational prior to conducting initial performance tests. Verification of operational status shall, as a minimum, include completion of the manufacturer's written requirements or recommendations for installation, operation and cal ibration of the device. A 30 day notification, prior to the demonstration of continuous monitoring system's performance, and subsequent notifications shall be submitted to the Piedmont Region

. ( 9 VAC 5

- 50

- 350 and 9 VAC 5

- 50

- 40)

54. CEMS Quality Control Progr am - A CEMS quality control program which is equivalent to the requirements of 40 CFR 75 Appendix B shall be implemented for all continuous monitoring systems. ( 9 VAC 5

- 50

- 350 and 9 VAC 5

- 50

- 40)

55. CEMS Emissions Data

– CEMS data shall be used to report annual emissions of NO x 

### , CO and CO 2 

### from the stack of each combined cycle combustion turbine and associated duct

- fired HRSG (T

- 1M, T

- 2M, T

- 3M) in tons/yr for the purpose of emission inventory. ( 9 VAC 5

- 50

- 50)

56. 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 58 are defined as follows:

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

- hour NO x 

### emission rate exceeds the applicable emission limit in Condition 40 ; 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, O 2 

### concentration, fuel flow rate, steam pressure, or megawatts. The steam flow rate is 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)

57. Excess Emissions and Mon itor Downtime for SO 2 

### - Continuous Monitoring Systems Excess emissions and monitoring downtime are defined, for the purpose of this permit, as follows:

a. For samples of gaseous fuel obtained using daily sampling or for proportional sampling,

an excess emis sion occurs each unit operating hour included in the period beginning on the date and hour of any sample for which the sulfur content of the fuel being fired in the combustion turbine exceeds the applicable limit and ending on the date and hour that a subs equent 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)

### Virginia Electric and Power Company

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March 12, 2013 Page 17

58. Reports for Continuous Monitoring Systems

- The permittee shall furnish written reports to the Piedmont Region of excess emissions from any process monitored by a continuous monitoring system (CEMS) on a quarterly basis, postmarked no later than the 30th day following the end of the calendar quarter. These reports shall inclu de, 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;

b. Specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the process, the nature and cause of the malfunction (if known), the corrective action taken or preventative measures adopted;

c. The date and time identifying each period during which the continuous monitoring system was inoperative except for zero and span checks and the nature of the system repairs or adjustments; and

d. When no excess emissions have occurred or the continuous monitoring systems hav e not been inoperative, repaired or adjusted, such information shall be stated in that report.

e. Excess emission reports for sulfur dioxide and nitrogen dioxide as required in 40 CFR 60.4395. (9 VAC 5

- 50

- 50)

59. 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 Part 60, Appendix A, Method 19. For any hour in which the hourly average O 2 

### co ncentration exceeds 19.0 percent O 2 

### , a diluent cap value of 19.0 percent O 2 

### may be used in the emission calculations; and

c. Only quality assured data from the CEMS shall be used to identify excess emissions. Periods where the missing data substitution proc edures 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)

### Virginia Electric and Power Company

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March 12, 2013 Page 18

INITIAL COMPLIANCE DETERMINATION

60. Emissions Testing

- 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/equipment such that volume tric flow rates and pollutant emission rates can be accurately determined by applicable test methods and providing a stack or duct that is free from excessive cyclonic flow as defined in 40 CFR 60 Appendix A . Sampling ports shall be provided at the approp riate locations (in accordance with the applicable performance specification in 40 CFR Part 60, Appendix B) and safe sampling platforms and access shall be provided. (9 VAC 5

- 50

- 30 F and 9 VAC 5

- 80

- 1 675 )

61. Stack Test : Turbines

- Initial performance tests shall be conducted for CO , PM 10 

### (including condens a ble PM 10 

### )

, PM 2.5 

### , and total VOC from each combustion turbine and associated duct burner (T

- 1M, T

- 2M, and T

- 3M) to determine compliance with the emission limits contained in Condit ion 40

. The tests shall be performed and demonstrate compliance within 60 days after achieving the maximum production rate at which the facility will be operated b ut in no event later than 180 days after start

- up of the permitted facility. 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. Tests shall be conducted 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 Piedmont Regional Office . The permittee shall submit a test protocol at least 30 days prior to testing. One copy of the test results shall be submitted to the Piedmont Regional Office within 45 days of test completion and shall conform to the test report format enclosed with this permit. (9 VAC 5

- 50

- 30, 9 VAC 5

- 80

- 1 675 , and 9 VAC 5

- 50

- 410)

62. Initial Performance Test

– Combustion Turbines

– Initial performance tests shall be conducted on each combustion turbine and associated duct burner (T

- 1M, T

- 2M, and T

- 3M) for NO x 

### (as NO 2 

### ) to determine compliance with the limits contained in Condition 40 as follows:

a. 40 CFR 60, Appendix A, Methods 7E or 20 shall be used to measure t he NO x 

### 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 traversing single

- hole probe, or, if feasible, with a stationary multi

- hole probe that samples each of the points sequentially. Alternatively, a multi

- hole probe designed and documented to sample equal volumes from each hole may be used to sample

s imultaneously at the required points.

b. Notwithstanding Condition 62 a. 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 a stratification test for NO x 

### and diluent pursuant to the procedures specified

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 19

in 40 CFR 75, Appendix A, Section 6.5.6.1(a) through (e). Once the stratification sampling is comp leted, the permittee may use the following alternative sample point selection criteria for the performance test:

i. If each of the individual traverse point NO x 

### concentrations is within ±10 percent of the mean concentration for all traverse points, or the individual traverse point diluent concentrations differs by no more than ±5ppm or ±0.5 percent O 2 

### from the mean for all traverse points, three points (located e ither 16.7, 50.0 and 83.3 percent of the way across the stack or duct, or, for circular stacks or ducts greater than 2.4 meters (7.8 feet) in diameter, at 0.4, 1.2, and 2.0 meters from the wall) may be used. The three points must be located along the meas urement 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 1 meter from the stack wall or at the stack centroid if each of the individual traverse point NO x 

### concentrations is within ±2.5 percent of the mean concentration for all traverse points, or the individual traverse point diluent concentrations differs by no more than ±1ppm or ±0.15 percent O 2 

### from the mean for all traverse points.

c. The performance test must be done at any load condition as required by 40 CFR 60.4400(b) . Testing maybe 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 NO x 

### emissions after the duct burner rather than directly after the turbine. The duct burner must be in operation during the performance
test.

e. Compliance wit h the applicable emission limit in Condition 40 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 40

.

f. The performance evaluation of the CEMS may ei ther 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 as alternativ es to the reference methods and procedures specified 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, as required by 40 CFR 60.4400(b)

. The ambient temperature m ust be greater than 0°F during the RATA runs.

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 20

ii. Compliance with the applicable emission limit in Condition 40 is achieved if the arithmetic average of all of the NO x 

### emission rates for the RATA runs, expressed in units of ppm at 15% O 2 

### , does not exceed the emission limit.

The tests shall be performe d, 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 start

- up of the permitted unit. 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 Piedmont Regional Office . The permittee shall submit a test protocol at least 30 days prior to testing. One copy of the test results shall be submitted to the Piedmont Regional Office , within 45 days after test completion but no later than 180 days after startup of the permitted unit and shall conform to th e test report format enclosed with this permit. (9 VAC 5

- 50

- 30, 9 VAC 5

- 50

- 410 , and 9 VAC 5

- 80

- 1675 )

63. Initial Performance Test

– Combustion Turbines

– Initial performance tests shall be conducted on each combustion turbine and associated duct burner (T

- 1M, T

- 2M, and T

- 3M) for SO 2 

### to determine compliance with the limits contained in Condition 40

. The permittee may use one of the following three method s (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 refer ence, 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 qualifie d agency. The samples for the total sulfur content of the fuel shall be analyzed using ASTM D1072, or alternatively D3246, D4084, D4468, D4810, D6228, D6667, or Gas Processors Association Standard 2377 (all of which are incorporated by reference, see 40 C FR 60.17).

b. 40 CFR 60, Appendix A, Methods 6, 6C, 8, or 20 shall be used to measure the SO 2 

### concentration (in parts per million (ppm)). In addition, the American Society of Mechanical Engineers (ASME) standard, ASME PTC 9

– 10

– 1981

– Part 10, “Flue and Exhaus t Gas Analyses,” 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 concentr ations. In addition, the permittee may use the manual methods for sulfur dioxide ASME PTC 19

– 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 start

- up of the permitted unit. Tests shall be conducted and reported

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 21

and data reduced as set forth in 9 VAC 5

- 50

- 30 and the test methods and procedur es 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 Piedmont Regional Office . The permittee shall submit a test protocol at least 30 days prior to testing. One copy of the tes t results shall be submitted to the Piedmont Regional Office , within 45 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

- 50

- 410 and 9 VAC 5

- 80

- 1675 )

64. Stack Test: Auxiliary boiler and fuel gas heater

- Initial performance tests shall be conducted for NO x 

### and CO from the auxiliary boiler (B

- 1) and fuel gas heaters (GH

- 1 through GH

- 2) to determine compliance with the emis sion limits contained in Conditions 43 and 48 . The tests shall be perf ormed, 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 start

- up. Tests shall be co nducted 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 Piedmont Regional Office . The permittee shall submit a test protocol at least 30 days prior to testing. One copy of the test results shall be submitted to the Piedmont Regional Office within 45 days of test completion but no later than 180 days after startup of the permitted uni t and shall conform to the test report format enclosed with this permit. (9 VAC 5

- 50

- 30, 9 VAC 5

- 80

- 1985 E, and 9 VAC 5

- 50

- 410)

65. 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 perm ittee on each combustion turbine and associated duct burner (T

- 1M, T

- 2M, and T

- 3M) . Ea ch test shall consist of 30 sets of 24 consecutive observations (at 15 second intervals) to yield a six

- minute average. At least one VEE shall be conducted for each of the operating condition s and loads for which emissions tests are required for the stack tests contained in Condition 61 . The details of the tests are to be arranged with the Piedmont Regional Office. The permittee shall submit a test protocol at least 30 days prior to testing. The evaluation shall be performed, reported, and demonstrate compliance within 60 days after ac hieving 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 prevent concurrent opacity observations, the Piedmont Regional Office 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. One copy of the test result shall be submitte d to the Piedmont Regional Office within 45 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 and 9 VAC 5

- 80

- 1 675 )

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 22

66. Visible E missions Evaluation

- Auxiliary Boiler and fuel gas heaters

- Concurrently with the initial performance tests in Condition 64 , Visible Emission Evaluations (VEE) i n accordance with 40 CFR Part 60, Appendix A, Method 9, shall be conducted by the perm ittee on the auxiliary boiler (B

- 1) and fuel gas heaters (GH

- 1 through GH

- 3) . Ea ch test shall consist of 1 0 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 Piedmont Regional Office . The permittee shall submit a test protocol at least 30 days prior to testing. The evaluation shall be performed, reported, and demonstrate compl iance within 60 days after achieving the maximum production rate at which the boiler will be operated but in no event later than 180 days after start

- up of the boiler.

Should conditions prevent concurrent opacity observations, the Piedmont Regional Offi ce 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. One copy of the test r esult shall be submitted to the Piedmont Regional Office within 45 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 and 9 VA C 5

- 80

- 1 675 )

67. 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 Piedmont Region al Office , shall be conducted for th e heat rate limit of the power blocks ( i.e., a combination of T

- 1M, T

- 2M, and T

- 3M and the steam turbine generator ) to show compliance with the heat rate limit contained in Condition 11 . 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 t han 180 days after start

- up of the permitted facility. Testing shall be conducted when combusting natural gas. The details of the tests are to be arranged with the Piedmont Regional Office. The permittee shall submit a test protocol at least 30 days prior to testing. One copy of the test results shall be submitted to the Piedmont Regional Office within 45 days of test completion 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 which specifies the actions the permittee plans to take in order to achieve the heat rate limit contained in Condition 11 . The details of this plan are to be arranged with the Piedmont Regional Office. (9 VAC 5

- 50

- 30 and 9 VAC 5

- 80

- 1675)

CONTINUING COMPLIANCE DE TERMINATION

68. Annual Performance Test

– Combusti on Turbines

– Annual performance tests shall be conducted on each combustion turbine and associated duct burner (T

- 1M, T

- 2M, and T

- 3M) for SO 2 

### to determine compliance with the limits contained in Condition 40 . The permittee may use one of the following three methods (a., b. or c. below) to conduct the performance
test:

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 23

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 manual sampling using the Gas Process Association Standard 2166 ) for natural gas. The fuel analyses may be p erformed 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 alternatively 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 parts per million (ppm)). In addition, the American Society of Mechanical Engineers (ASME) standard, ASME PTC 9

– 10

– 1981

– Part 10, “Flue and Exhaust Gas Analyses,” 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 the manual methods for sulfur dioxide ASME PTC 19

– 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 Piedmont Regional Office. The permittee shall submit a test protocol at least 30 days prior to testing. One copy of the test results shall be submitted to the Piedmont Regional Office, within 45 days after test completion and shall conform to the test report format enclosed with this permit. (9 VAC 5

- 50

- 30, 9 VAC 5

- 50

- 410)

69. Periodic Testing: Heat Rate Limit

– Every fiv e years after initial evaluation of the heat rate limit of the power blocks, the permittee shall conduct a heat rate evaluation of the pow er blocks to show compliance with the heat rate limit contained in Condition 11 . The details of the evaluation are to be arranged with the Piedmont Regional Office. (9 VAC 5

- 50

- 30 and 9 VAC 5

- 80

- 1675)

70. Stack Tests

– Upon request by DEQ, the permittee shall condu ct additional performance tests to determine compliance with the emission limits contained in this permit. The details of the tests shall be arranged with the Piedmont Regional Office. (9 VAC 5

- 50

- 30 G)

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 24

RECORDS

71. O n 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 Piedmont Region . These records shall include, but are not limited to:

a. Annual hours of operation of the emergency fire water pump (FWP

- 1) and emergency generators (EG

- 1 and EG

- 2) for emergency purposes and for maintenance checks and readiness testing , calculated monthly as the sum of each consecutive 12

- m onth 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 ;

b. All fuel supplier certifications for the ULSD fuel used in the emergency units (EG

- 1and FWP

- 1);

c. Monthly and a nnual throughput of natural gas to the three combustion turbine s and associated duct burner s (T

- 1M, T

- 2M, and T

- 3M) , 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 ;

d. Time, date and duration of each startup, shutdo wn, and malfunction period for each combustion turbine and associated duct burner (T

- 1M, T

- 2M, and T

- 3M) ;

e. Monthly and annual throughput of natural gas to the auxiliary boiler (B

- 1) and the fuel gas heaters (GH

- 1 through GH

- 3), calculated monthly as the su m 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 ;

f. Fuel quali ty records for natural gas combusted in the combustion turbine and associated duct burner (T

- 1M, T

- 2M, and T

- 3M) , auxiliary boiler (B

- 1), and fuel gas heaters (GH

- 1 through GH

- 3) ;

g. Continuous monitoring system emissions data, calibrations and calibration c hecks, percent operating time, and excess emissions ;

h. Operation and control device monitoring records for each SCR system and oxidation catalyst as required in Conditions 3 and 7 ;

i. Weekly log s of dissolved solids content of cooling water to the four inlet coolers (IC

- 1 through IC

- 4 ) and the auxiliary equipment chiller (AEC

- 1).

j. Scheduled and unscheduled maintenance, and operator training.

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 25

k. Results of all stack tests, visible emission evaluations, and performance evaluations.

l. Manufacturer’s instructions for proper operation of equipment.

These records shall be available for inspection by the DEQ and shall be current for the most recent five years. ( 9 VAC 5

- 50

- 50)

72. Emissions Testing

- The electric generating 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 /equipment such that volumetric flow rates and pollutant emission rates can be accurately deter mined by applicable test methods and providing a stack or duct that is free from excessive cyclonic flow as defined in 40 CFR 60 Appendix A

. Sampling ports shall be provided when requested at the appropriate locations and safe sampling platforms and acces s shall be provided. (9 VAC 5

- 50

- 30 F and 9 VAC 5

- 80

- 1180)

NOTIFICATIONS

73. Initial Notifications

- The permittee shall furnish written notification to the Piedmont Regional Office of:

a. The act ual date on which construction of the electric power generation facility commenced within 30 days after such date.

b. 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.

c. The actual start

- up date of the electric power generation facility within 15 days after such date.

d. The anticipated date of continuous monitoring system performance evaluations postmarked not less than 30 days prior to such date.

e. The anticipated date of performance tests of the combustion turbines (T

- 1M, T

- 2M, and T

- 3M), auxiliary boiler (B

- 1), and fuel gas heaters (GH

- 1 through GH

- 3), postmarked at least 30 days prior to such date.

Copies of the written notification referenced in items a through e above are to be sent to:

Associate Director Office of Air Enforcement and Compliance Assistance (3AP 2 0) U.S. Environmental Protection Agency Region III 1650 Arch Street Philadelphia, PA 19103

- 2029 (9 VAC 5

- 50

- 50 and 9 VAC 5

- 50

- 410 )

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 26

GENERAL CONDITIONS

74. Permit Invalidation

– This permit to co nstruct the electric power generation facility shall become invalid, unless an extension is granted by the DEQ, if:

a. A program of continuous construction or modification is not commenced within 18 months from the date of this permit.

b. A program of construction or modification is discontinued for a period of 18 months or more, or is not completed within a reasonable time, except for a DEQ approved period between phases of the phased construction of a new stationary source or project. (9 VAC 5

- 80

- 1 9 85 )

75. Permit Suspension/Revocation

- This permit may be suspended or revoked if the permittee:

a. Knowingly makes material misstatements in the permit application or any amendments to it;

b. Fails to comply with the conditions of this permit;

c. Fails to comply wi th any emission standards applicable to a permitted emissions unit

, ;

d. Causes emissions from the stationary source which result in violations of , or interfere with the attainment and maintenance of, any ambient air quality standard; or

e. Fails to operate in conformance with any applicable control strategy, including any emission standards or emission limitations, in the State Implementation Plan in effect at the time an application for this permit is submitted. (9 VAC 5

- 80

- 1985 F)

76. Right of Entry

- The pe rmittee shall allow authorized local, state, and federal representatives, upon the presentation of credentials:

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 con ditions 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 ti me 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 and 9 VAC 5

- 80

- 1180)

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 27

77. Maintenanc e/Operating Procedures

– At all times, including periods of start

- up, shutdown, and malfunction, the permittee shall, to the extent practicable, maintain and operate the affected source, including associated air pollution control equipment, in a manner con sistent with good air pollution control practices for minimizing emissions.

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 and process

e quipment which affect such emissions:

a. Develop a maintenance schedule and maintain records of all scheduled and non

scheduled 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 av ailable to DEQ personnel upon request. (9 VAC 5

- 50

- 20 E)

78. Record of Malfunctions

– The permittee shall maintain records of the occurrence and duration of any bypass, malfunction, shutdown or failure of the facility or its associated air pollution control equipment that results in excess emissions for more than one hour. Records shall include the date, time, duration, description (emission unit, pollutant affected, cause), corrective action, preventive measures taken and name of person generating the record. (9VAC 5

- 20

- 180 J)

79. Notification for Facility or Control Equipment Malfunction

- The permittee shall furnish notification to the Piedmont Regional Office 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 te legraph. Such notification shall be made as soon as practicable but no 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 duratio n of the breakdown, within two weeks of discovery of the malfunction. When the condition causing the failure or malfunction has been corrected and the equipment is again in operation, the permittee shall notify the Piedmont Regional Office

. (9 VAC 5

- 20

- 180 C)

80. Violation of Ambient Air Quality Standard

- The permittee shall, upon request of the DEQ, reduce the level of operation or shut down a facility, as necessary to avoid violating

### Virginia Electric and Power Company

– Brunswick County Power Station Registration Number: 52404

March 12, 2013 Page 28

any primary ambient air quality standard and shall not return to n ormal operation until such time as the ambient air quality standard will not be violated. (9 VAC 5

- 20

- 180 I)

81. 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 th e previous owner. The new owner shall notify the Piedmont Regional Office of the change of ownership within 30 days of the transfer. (9 VAC 5

- 80

- 1 985 E )

82. 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

- 1985 E )

STATE

- ONLY ENFORCEABLE REQUIREMENTS

The following terms and conditions are included in this permit to implement the requirements of 9 VAC 5

- 40

- 130 et seq., 9 VAC 5

- 50

- 130 et seq., 9 VAC 5

- 60

- 200 et seq. and/or 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.

83. Emission Limits

– E missions from the electric power generation facility shall not exceed the limits specified below:

Pollutant CAS# Lb/hr Tons/yr

Acrolein 107

- 02

- 8 0.0 40 lb/hr 0.16 tons/yr Formaldehyde 50

- 00

- 0 1.3 7 0 lb/hr 5. 88 tons/yr
Cadmium 7440

- 43

- 9 0.01 1 lb/hr 0.05 tons/yr
Chromium 7440

- 47

- 3 0.014 lb/hr 0.06 tons/yr
Nickel 7440

- 02

- 0 0.021 lb/hr 0. 0 9 tons/yr



### 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

- 1 625G )

84. 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 Piedmont Regional Office. These records shall includ e, but are not limited to the average hourly, monthly, and annual emissions (in pounds and tons) of each toxic compound listed in Condition 83 . Hourly emissions sh all be calculated monthly. Annual emissions shall be calculated monthly as the sum of each consecutive 12

- month period. These records shall be available for inspection by DEQ and current for at least the most recent five years. (9 VAC 5

- 50

- 50, and 9 VAC 5

- 80

- 1625G)

### SOURCE TESTING REPORT FORMAT

Report Cover 1. Plant name and location 2. Units tested at source (indicat e 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 test ed & 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, a s required by the test protocol 6. A statement that test was conducted in accordance with the test protocol or identification & discussion of dev iations, includi ng 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 a nd 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 sam ples 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 v isible emission evaluationsENGINEERING ANALYSIS

Source Name: Virginia Electric and Power Company

– Brunswick Plant Permit No.: 5 2 404

- 0 0 1

Source Location: Route 58 , Brunswick County
, Virginia Engineer: AMS

Date : March 8, 201 3

I

. Introduction and Background

A

. Company Background

The facility, as proposed, will be a new , combined

- cycle , natural gas

- fired, electrical power generating facility. The facility will be located on a 214

- acre parcel just south of Route 58, approximately 1.3 miles northeast of Racume in Brunswick County (UTM coordinates are Zone 18 257806mE 407232 m N ) . The nearest residence is approximately 0.5 miles to the east. The nearest schools are Brunswick Academy and Brunswick High School, approximately 5.5 to 6.5 miles away. The nearest hospital/medical center is over ten miles away in Emporia, as are the nearest senior care facilities. There are no Class I areas within 100 km of the proposed facility (see PSD section).

The area is in attainment for all pollutants. Since the source will be a major source

, with emissions over 100 tons/yr of Nitrogen Oxides ( NO x )

, carbon monoxide ( CO )

, volatile organic compounds ( VOC )

, Particulate Matter less than 10 microns ( PM 10 )

, particulate ma tter less than 2.5 microns ( PM 2.5 )

, and greenhouse gas [ GHG or CO 2 equivalents (CO 2 e)] over 100,000 tons/yr

, P revention of Significant Deterioration (P SD ) permitting for those pollutants

- as well as sulfur dioxide ( SO 2 ) and sulfuric acid mist ( H 2 SO 4 ) emissions

- will be triggered

. The source will not be major for hazardous air pollutants (HAP) , so no MACT will apply, and the source will be subject to the State Toxics Rule (6

- 5).

Site Suitability:

The facility will be located on a site which is suitable from an air pollution standpoint. The area is rural with a combination of undeveloped and transitional land (tree plantations and farms) with forest and woody wetlands. Additionally, the C ounty of Brunswick has certified that the location and operation of the facility are consistent with all applicable ordinances adopted pursuant to Chapter 22 ( § 15. 2

- 2200 et seq.) of Title 15. 2 of the Code of Virginia (see attached Local Governing Body Certification Form).

The following table shows the distances between the proposed plant site and the closest Class I areas. The Federal Land Managers were given the opportunity to comment on whether they will provide a finding of adverse impact on visibility in these Class I areas as a res ult of the proposed facility. No adverse impact on visibility was suggested.

Class I area Distance from project Shenandoah National Park 173 km James River Face Wilderness Area 180 km Dolly Sods Wilderness Area 290 km Swanquarter National Wildlife Refuge 187 km

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:Engineering Analysis

March 8, 2013 Page 2

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 VAC 5

- 50

- 280 (Best Av ailable Control Technology) and 9 VAC 5

- 60

- 320 (Toxics Rule) and have been determined to meet these standards where applicable. Please see Section III.C for a description of the Best Available Control Technology included in the permit. Please refer to Sec tion I II .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 (MMBtu) per hour, the proposed facil ity is a major stationary source according to 9 VAC 5

- 80

- 1615 C. In accordance with PSD regulations, air quality modeling was conducted to predict the maximum ambient impacts of criteria pollutants emitted by the proposed source

. Even though the source i s not within 100 km of a Class I area (an area such as a national park or wildlife sanctuary) , an analysis was done to determine compliance with PSD Class I PSD increment for SO 2 , PM 10 , PM 2.5 , and NO 2 . The maximum predicted concentration s of those pollutants were well below the Class I significant impact levels (SILs) so no addition air quality analysis was required for Class I area impact.

For the Class II (all other areas not designated as Class I areas) modeling analysis, p redicted impac ts from CO (1

- hour and 8

- hour averaging periods) and SO 2 (1

- hour, 3

- hour, 24

- hour, and annual) were below applicable modeling significant impact levels (SILs). No further analyses were required for these pollutants at the indicated averaging periods. Howev er, modeled concentrations for NO 2 (1

- hour and annual averaging period s ), PM 10 (24

- hour averaging period), and PM 2.5 (24

- hour and annual averaging periods) exceeded the applicable SILs. Therefore, a cumulative impact analysis for these pollutants and avera ging periods was necessary. The predicted impacts for NO 2 , PM 10 , and PM 2.5 from the cumulative impact analysis were less than the applicable National Ambient Air Quality Standards (NAAQS). Hence, the proposed project does not cause or significantly contribute to a predicted violation of any applicable NAAQS or Class II area PSD increment

. Results of modeling conducted for emissions from the proposed facility show compliance with the health

- based NAAQS for all 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 us e of property.

The emissions of toxic pollutants from electric generating units such as those proposed by Dominion are subject to the standards in 9 VAC 5

- 60

- 300 et seq. Dominion calculated the emissions of toxic pollutants from all of the emission unit s proposed for the site. Dominion modeled emissions of toxic pollutants for which proposed emissions exceeded the thresholds in 9 VAC 5

- 60

- 320 (acrolein, formaldehyde, cadmium, chromium, and nickel) , as well as beryllium, lead and mercury

. Modeling demon strated that proposed emissions of these toxics pollutants are well below the associated Significant Ambient Air Concentrations (SAACs).

A visibility analysis was done to assess the potential for visual plume impacts in Class II areas within 50 km of th e projected site and it was determined that the plume would not be visible within the area around the site. The facility is required to use clean

- burning fuels and air pollution control equipment, and is limited to opacity not to exceed 10% at the turbine stacks.

The results of an analysis to determine the impact of facility emissions on vegetation and soils has demonstrated that the maximum predicted concentrations of SO 2 , NO 2 , PM 10 and CO were below the minimum reported levels at which damage or growth effects to vegetation mayEngineering Analysis

March 8, 2013 Page 3

occur. And, based on the soil types in the vicinity of the proposed facility and the emissions

from the facility, no adverse impact on local soils is antici pated.

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 government official has deemed this activity not inconsistent with local ordinances. The signed Local Government Form is attached.

The proposed Dominion

- Brunswick facility will generate electricity using only clean

- burning natural gas. The availability of clean fu el electric generation facilities is necessary if operation of conventional coal

- fired power plants is to be reduced or replaced. Construction of clean

burning, efficient generation plants such as the proposed Dominion

- Brunswick facility creates the poten tial for regional SO 2 and NO x reductions resulting from displacement of older, more polluting forms of electricity generation.

The Brunswick County Board of Supervisors and the Industrial Development Authority support the construction of the facility and anticipate the placement of the facility in this location will be an economic boon to the region in terms of jobs, taxes, and the availability of natural gas that wasn’t previously available in the area.

3. The suitability of the activity to the area in whi ch it is located:

Consistent with the Board's Suitability Policy dated 9/11/87, 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 is a source of toxics emissions and has been modeled and shows compliance with the applicable SAACs. The emissions for criteria pollutants associated with this permit have l ikewise been modeled and have been shown through modeling 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.

(ii) The health impact of air quality deterioration which mi ght reasonably be expected to occur during the grace period allowed by the Regulations or the permit conditions to fix malfunctioning air 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 permit contains a requirement to notify the Piedmont Regional Office within four business hours of the discovery of any malfunction of pollu tion control equipment (Condition 78 ).

The state NSR program as well as the PSD and Non

- Attainment programs require consideration of levels of control technology that are written into regulation to define the level of scientific and 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 that will result in reduction of emissions from the combustion turbines and associated equipment

. These includeEngineering Analysis

March 8, 2013 Page 4

technologies such as the use of clean fuels with low sulfur content , good combust ion

practices, and clean

- burning "low

- NOx" lean premix burners as well as add

- on control (SCR for NOx removal and an Oxidation Catalyst for CO, VOC, and VOC toxic pollutant control). Other measures have been included in the draft permit, such as a require ment to use ultra

low sulfur diesel oil (no more than 0.0015 % by weight) or propane in emergency equipment and to monitor equipment leaks in the circuit breaker s

. Feasibility of obtaining further emission reductions was reviewed through the rigorous "top

- down" Best Available Control Technology (BACT) requirements of PSD review. No additional controls were found to be technically and economically feasible.

B

. Proposed Project Summary

The proposed project will be a new, nominal 1400 MW combined

- cycle electrical power generating facility utilizing t hree combustion turbines each with a duct

- fired heat recovery steam generator (HRSG) with a common reheat condensing steam turbine generator (3 on 1 configuration)

. The propose d fuel for the turbines and duct burners is pipeline

- quality natural gas

. Emissions from t he turbines will be controlled by the use of low carbon fuels and high efficiency design (for GHG), clean fuels and good combustion practices (for PM 10 and PM 2.5 ), S CR and ultra low NOx burners (for NOx)

, and oxidation catalyst (for CO and VOC). A natural gas

- fired auxiliary boiler, three fuel gas heaters, an auxiliary equipment cooler, four inlet chillers , an emergency diesel fire water pump , two emergency generators and an oil storage tank are also proposed and will be subject to emission controls

. Electrical circuit breakers potentially emit GHG pollutants (expressed as carbon dioxide equivalents, or CO 2 e ) and they will also be covered in t he permit.

Table 1

- Expected emissions from the proposed facility are as follows: Pollutant Emissions (tons/yr) NO x 343.6 CO 477.9 SO 2 51.1 VOC 314.2 PM 10 218.0 PM 2.5 217.6 CO 2 e 5,341,291.0 Sulfuric acid mist (H 2 SO 4 ) 30.4 Formaldehyde 5. 88 Acrolein 0.162 Cadmium 0.049 Chromium 0.063 Nickel 0.094

Note: Emissions of regulated toxic pollutants other than formaldehyde, acrolein, cadmium, chromium, and nickel are below permitting exemption thresholds and were therefore not included in T able 1

.
C

. Process and Equipment Description

Equipment to be Constructed Ref. No

. Equipment Description Rated Capacity Federal Requirements Three on one power block with three natural gas

- fired combustion turbine generators, each with a duct

- fired heat recovery steam generator (HRSG) , providing steam to a common steam turbine generator T

- 1M Mitsubishi M501 GAC combustion turbine

generator with HRSG duct burner (natural gas

- fired) 3,442 MMBtu/hr NSPS Subpart KKKK NOx trading Subparts AAAAA, BBBBB, and CCCCCEngineering Analysis

March 8, 2013 Page 5

Equipment to be Constructed Ref. No

. Equipment Description Rated Capacity Federal Requirements T

- 2M Mitsubishi M501 GAC combustion turbine

generator with HRSG duct burner (natural gas

- fired) 3,442 MMBtu/hr NSPS Subpart KKKK NOx trading Subparts AAAAA, BBBBB, and CCCCC T

- 3M Mitsubishi M501 GAC combustion turbine

generator with HRSG duct burner (natural gas

- fired) 3,442 MMBtu/hr NSPS Subpart KKKK NOx trading Subparts AAAAA, BBBBB, and CCCCC Ancillary Equipment B

- 1 Auxiliary Boiler (natural gas

- fired) 66.7 MMBtu/hr NSPS Subpart Dc GH

- 1, 2, 3 Three Fuel Gas Heaters (natural gas

fired) 8 MMBtu/hr each None

EG

- 1 Emergency Generator (diesel) 2200 kW NSPS Subpart IIII (non

- delegated) MACT Subpart ZZZZ (non

- delegated) EG

- 2 Emergency Generator (propane) 80 kW NSPS Subpart JJJJ (non

- delegated) MACT Subpart ZZZZ (non

- delegated) FWP

- 1 Fire Water Pump (diesel) 305 bhp NSPS Subpart IIII (non

- delegated) MACT Subpart ZZZZ (non

- delegated) AEC

- 1 Delugeable Auxiliary Equipment Cooler 69,600 gallons of water/hr None

IC

- 1, 2, 3, 4 Four Turbine Inlet Air Chillers (mechanical

draft cooling towers) 690,000 gallons of water/hr each None

CB

- 1 Eleven Electrical Circuit Breakers 18,095 lb SF 6 None ST

- 1 Distillate fuel oil tank 6000 gallons None

Combustion Turbine Generators with duct

- fired Heat Recovery Steam Generators (T

- 1M, T

2M, and T

- 3M)

Combustion Turbines (CT) The source has proposed the installation of three Mitsubishi M501 GAC class CTs in combined

cycle mode.

The gas turbine is the main component of a combined

- cycle power system. First, air is filtered, cooled 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 x combustors minimize NO x 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 gene rator.

The CTs are designed to operate in the dry low

- NOx mode at loads from approximately 5 0 percent up to 100 percent rating . Operation at lower loads will only occur during start up and shutdown. The CTs will be periodically taken out of service for scheduled maintenance, or as dictated by economic or electrical demand conditions.

Heat Recovery Steam Generators (HRSG) with Duct Burners (DB)

The proposed facility will use three HRSGs, one for each CT, which will use waste heat to produce additiona l 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). Exhaust gas entering the HRSG at approximately 1,100°F will be cooled to 180 °F by the time it leaves the HRSG exhaust stack. Steam production in the HRSGs will be augmented using duct burners (DBs) that will be fired by natural gas. The proposed DBs will have a firing rate of 50 1 MMBtu/hr each. 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 int ermediate

- pressure superheater, an intermediate

- pressure evaporator, an intermediate

- pressure economizer, a low

- pressure superheater, a low

- pressure evaporator, and a low

- pressure economizer. The dry condenser will condense the steamEngineering Analysis

March 8, 2013 Page 6

exhausting from the S T. As the steam is condensed, the condensate flows to the condensate receiver tank. Control devices such as selective catalytic reduction (SCR) will be installed, to control NO x emissions, and oxidation catalysts will be installed to control CO and VOC e missions

. Steam Turbine (ST)

The proposed project includes one reheat, condensing steam turbine generator designed for variable pressure operation. The high

- pressure portion of the steam turbine generator receives high

- pressure superheated steam from the HRSGs, and exhausts to the reheat section of the HRSGs. The steam from the reheat section for the HRSGs is supplied to the intermediate

pressure section of the turbine, which expands to the low

- pressure section. The low

- pressure steam turbine generat or also receives excess low

- pressure superheated steam from the HRSGs and exhausts to the air

- cooled condenser. The steam turbine generator set is designed to produce up to approximately 610 MW of electrical output at ISO conditions with duct firing

. No pollutants are emitted from the steam turbine.

Ancillary Equipment

Turbine Inlet Air Chillers (IC

- 1 through IC

- 4 )

Four mechanical draft cooling towers will be incorporated to provide air inlet chilling for the CTs

. These devices will cool the inlet area during periods of high ambient temperature in order to increase power output and improve efficiency. Particulate matter emissions from the cooling towers associated with the inlet air chillers will be controlled by high efficiency drift elimina tors

. Auxiliary Boiler (B

- 1)

The proposed facility will include a 66.7 MMBtu/hr

, natural gas

- fired, auxiliary boiler. The auxiliary boiler will provide steam to the ST at start

- up and at cold starts to warm up the ST rotor. The steam from the auxilia ry boiler will not be used to augment the power generation of the CTs or ST. The boiler is proposed to operate 8760 hrs/yr

. NOx emissions from the boiler will be controlled by the use of ultra low NOx burners.

Fuel Gas Heater s (GH

- 1 through GH

- 3 )

The proposed facility will include three 8.0 MMBtu/hr, natural gas

- fired, fuel gas heater s

. The heater s 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 heaters are proposed to operate 8760 hrs/yr. NOx emissions from the heaters will be controlled by the use of ultra low NOx burners.

Diesel

- Fired Emergency Generator (EG

- 1)

The proposed facility will include a 2200 kW diesel

- fired emergency generat or that will be operated up to 500 hours per year (including 100 hrs of maintenance checks and readiness testing)

. The emergency generator will provide power in emergency situations for turning gears, lube oil pumps, auxiliary cooling water pumps and wate r supply pumps. The emergency diesel generator is not intended to provide sufficient power for a black start , peak shaving or non

emergency power

. Propane

- Fired Emergency Generator (EG

- 2)

The proposed facility will include a n 80 kW propane

- fired emergency generator that will be operated up to 500 hours per year (including 100 hrs of maintenance checks and readiness testing). The emergency generator will provide power in emergency situations for the uninterruptible power supply for the control hou se in the switchyard

. The emergency propaneEngineering Analysis

March 8, 2013 Page 7

generator is not intended to provide sufficient power for a black start, peak shaving or non

emergency power.

Diesel

- Fired Fire Water Pump (FWP

- 1)

The proposed project will include a 305 bhp diesel

- fired fi re water pump operated as a fire water pump driver. The unit will be limited to 500 hours per year, including monthly testing and maintenance (not to exceed 100 hours per year)

. Distillate Oil Storage Tank (ST

- 1)

The proposed project will include a 6 ,000

- gallon , fixed

- roof, horizontal, distillate oil storage tank to provide fuel for the emergency generator and fire water pump.

Circuit Breakers (CB

- 1)

The proposed project will include circuit breakers holding 1,645 lbs of the greenhouse gas sulfur hexafluoride (SF 6 ) per unit. There will be a total of 11 circuit breakers located at the facility, with a total capacity of 18,095 lbs of SF 6 . Maximum annual leakage rate for SF 6 is to be no more than 1%

. Delugeable Auxiliary Equipment Cooler (AEC

- 1)

Dominion proposes to construct a 12

- bay delugeable auxiliary equipment cooler which will cool the lubricating oil for miscellaneous equipment. Forced

- draft fans will be incorporated to provide the flow needed for the equipment cooler. The cooler will hav e four bays equipped with deluge water sprays for additional cooling during extremely hot weather, causing particulate matter emissions from drift.

D

. Project Schedule

Date permit application received in region November 29, 201 1 (amended March 7, 2012, September 7, 2012, November 5, 2012 , and December 2 1 , 2012 ) Date application was deemed complete December 2 1 , 2012 Proposed construction commencement date April 2013 Proposed start

- up date January, 201 5

II

. Emissions Calculations (see attached spreadsheets for detailed emission calculations )

Proposed emissions are primarily products of combustion from the combined cycle units and duct burners. There are also emissions from the auxiliary boiler, fuel gas heater, emergency generator s , emergency firewater pump, turbine inlet chillers, auxiliary equipment cooler, and circuit breakers

. Permitted emission limits reflect BACT (see section III.C for BACT analysis).

Compliance with the annual emission limits f or NOx and CO from the combined cycle units and duct burners will be based on CEMS data. Compliance with the annual SO 2 limit will be based on fuel throughput and the sulfur content of the fuel. Compliance with short

- term PM 10 , PM 2.5 , and VOC from the co mbustion units and duct burners will be based on stack testing. Annual emissions will be based on emission factors derived from testing along with fuel throughputs.

Compliance for the annual CO 2 e emission limits will be on a 12

- month rolling total based on CEMS data. Short

- term CO 2 e emissions from the fuel

- burning units will not be included in the permit. The turbines will also have a lb/MWh limit and a Btu/kWh heat rate limit to show compliance with the energy

- efficiency requirements for GHG BACT.Engineering Analysis

March 8, 2013 Page 8

E missions from startup and shutdown were considered in the annual permit emissions limits for the combustion turbines

, but separate limits will not be included

. During startup and shutdown, some post

- combustion controls are not working at the optimum level of control, however, during these periods, the turbines and duct burners are also not operating at their highest output and other emissions may be reduced for that reason. Therefore it is important to consider emissions during startup and shutdown in the annual total for emissions. Worst case annual emissions were based on either 8

, 760 hrs/yr with duct burning

, or 7,071 hrs/yr with duct burning plus start up and shutdown (SU/SD) emissions. The facility was not given a limit on the total number of hours of start up and shutdown, but rather the estimated amount of time was factored into the annual emission limits and, therefore, must be complied with by showing compliance with the annual emission limits. BACT applies during startup and shutdown and BACT i ncludes minimiz ation of such SU/SD events.

Emissions from the auxiliary boiler

, fuel gas heaters

, auxiliary equipment cooler, and inlet chillers were based on 8

, 760 hrs/yr operation

. The emergency generators and fire water pump are permitted to operate no more than 500 hrs/yr.

Emissions from the circuit breakers were based on a maximum annual leak age rate of 1%.

III

. Regulatory Review

The proposed project is a major new source with projected

, permitted

, annual emissions greater t han 100 tons of several criteria pollutants (see Table 1 in Section I.B above)

.
Greenhouse Gas Emissions Applicability R eview :
After July 1, 2011, new sources that have the potential to emit 100,000 tons or more of CO 2 e (or 75,000 tons of CO 2 e if PSD is triggered by another pollutant) and modified sources with a net emission increase of CO 2 e over 75,000 tons year will be required to obtain a PSD permit. The total CO 2 e is based on taking the mass emissions of each GHG and multiplying by its Gl obal Warming Potential (GWP). These GWP factors are as follows: CO 2 : 1; CH 4 : 21; N 2 0: 310; SF 6 : 23,900; HFCs: 140 to over 11,700; and PFCs: 5,210 to 9,200. The first three GHG pollutants are primarily from fuel burning and the latter pollutants are from semi

- conductor and other production processes. This facility has electrical circuit breakers which contain SF 6 .
Since the permit for the project w ill be issued after July 1, 2011 and it will be a PSD source for several other pollutants, and permitted CO 2 e emissions will be greater than 75,000 tons, the source would be subject to PSD permitting for GHG (9 VAC 5

- 85

- 40)

. PSD Permitting : The source i s PSD

- major for PM 10 , PM 2.5 , NO x , CO, VOC and CO 2 e (see Table 2 below). Because one or more pollutant s are subject to PSD, the other pollutants at the source (SO 2 , Lead and H 2 SO 4 ) need to be evaluated for PSD at their significance level. SO 2 and H 2 SO 4 exceed the PSD significance level for those pollutants so the facility will be subject to PSD for SO 2 and H 2 S O 4 in addition to the other pollutants mentioned above . The source is required to apply BACT for these pollutants. BACT for these pollutants is discussed in Section III.C.

Table 2

- PSD Permitting applicability
Pollutant Potential to Emit

(TPY) PSD Major

Threshold (TPY) * Over Major

Threshold? PSD Significance

Rate (TPY) ** PSD

Required? PM 10 218.0 100 Y es 15 Y es PM 2.5 217.6 100 Y es 10 Y es NO x 343.6 100 Y es 40 Y es CO 477.9 100 Y es 100 Y es SO 2 51.1 100 N o 40 Y es VOC 314.2 100 Y es 40 Y es CO 2 e 5, 341,291.0 100,000 Y es 75,000 Y es Lead 0.02 100 N o 0.6 N o H 2 SO 4 30.4 100 N o 7 Y es *Major Threshold levels from definition of “Major stationary source” in 9 VAC 5

- 80

- 1615CEngineering Analysis

March 8, 2013 Page 9

**PSD significance values from definition of “significant” in 9 VAC 5

- 80

- 1615C

NSPS R equirements :
Subpart KKKK: The combustion turbines are subject to NSPS S ubpart KKKK (Standards of Performance for Stationary Combustion Turbines) which require s the source to meet NO x and SO 2 standards. The source must meet a NO x limit of 25 ppm when burning natural gas . The source proposes the use of ultra low NO x burners and SCR to control NO x emissions. NO x emissions from the proposed combustion turbines are expected to be around 2.0 ppmvd when burning natural gas which is below the NSPS sta ndard and is considered Best Available Control Technology ( BACT )

. The source will put NO x CEMS on the turbine stacks to show compliance with the BACT limits

. The source proposes using low

- sulfur fuel (natural gas) to control SO 2 from the turbines and duct burners

. To be in compliance with NSPS KKKK, t hey must not exceed 0.06 lb SO 2 /MMBtu from fuel burning

. The source has proposed a BACT emission limit of 0.00112 lb SO 2 /MMBtu

. BACT is discussed in more detail in Section III.C

. Turbines regulated under NSPS Subpart KKKK are not subject to NSPS Subpart GG, and HRSGs and duct burners regulated under NSPS Subpart KKKK are not subject to NSPS Subparts Da, Db, or Dc.

Subpart Dc: The 66.7 MMBtu/hr auxiliary boiler is subject to NSPS Subpart Dc Standards of Performance for Small Industrial

- Commercial

- Institutional Steam Generating Units as a steam

generating unit between 10 and 100 MMBtu/hr. Since it will be burning natural gas only

, it will be required to keep records of the amount of fuel burned each calendar month. The three 8 MMBtu/hr fuel gas heaters are not subject to this part.

Subpart IIII * : T he emergency diesel fire water pump and diesel emergency generator a re subject to NSP S Subpart IIII

. The 227.4 kW diesel fire water pump is subject to a NO x + non

- methane hydrocarbon (NMHC) limit of 4 .0 g/ kW

- hr, a PM limit of 0. 2 g/ kW

- hr , a CO limit of 3.5 g/ kW

- hr, and a requirement to use ULSD with no more than 15 ppm sulfur content. Th e 2200 kW diesel emergency generator is subject to a NO x + NMHC limit of 6.4 g/kW

- hr, a PM limit of 0.2 g/kW

- hr, a CO limit of 3.5 g/kW

- hr, and a requirement to use ULSD with no more than 15 ppm sulfur content.

Subpart JJJJ * : The emergency propane

- fired generator is subject to NSPS Subpart JJJJ for spark

ignition internal combustion engines , with a requirement to use certified engines and maintain them properly

.

* Although the source must be in compliance with the requirements for these emer gency units

, DEQ has not elected to receive delegation for enforcement of th e s e regulation s , so no requirements specific to this regulation will be included in this permit (but will be referenced in the permit cover letter)

. BACT limits will be used to en sure the NSPS standards are met.

Subpart TTTT (proposed)

. A new NSPS (Subpart TTTT) could possibly be in place before this source constructs the turbines so the turbines could be subject to that subpart. The proposed standard is a CO 2 emission limit of 1,000 lb/MWh (gross annual average considering all operation), although a range has been examined that covers 950

- 1100 lb/MWh. E xpected emissions of CO 2 from the facility are around 9 2 0 lb/MWh at maximum operating capacity, so it is expected that, on an annual average, the source will be able to meet the proposed 1,000 lb/MW

- hr CO 2 standard. When the source conducts Part 75 monitoring for Acid Rain, it will fulfill the proposed monitoring requirements for NSPS Subpart TTTT.

MACT Requirements :
Subpart ZZZZ * : The emergency diesel fire water pump and emergency generators are also subject to MACT Subpart ZZZZ (40 CFR 63.6590.c.1) for area sources of HAP

. Compliance with this MACT is met by complying with NSPS Subpart IIII or NSPS Subpart JJJJ requiremen ts , as applicable

.Engineering Analysis

March 8, 2013 Page 10

* DEQ has not elected to receive delegation to enforce th is federal regulation so requirements for th is specific regulation will not be included in the permit but will be referenced in the permit cover letter

.

Non

- applicable Subparts : As an area HAP source, the facility will not be subject to MACT Subpart YYYY for turbines or MACT Subpart Q for cooling towers.

Other:

Cross State Air Pollution Rule (CSAPR) /Clean Air Interstate Rule (CAIR) On August 21, 2012, the United States Court of Appeals for the D.C. Circuit vacated CSAPR but continued to leave CAIR in place pending EPA’s promulgation of a replacement rule that complies with the courts’ rulings. Virginia at this time will implement the CSAPR requirements through the federal implementation plan (FIP) as per Chapter 291 of the 2011 Virginia Acts of Assembly and 40 CFR 97.

Title I V/ Acid Rain Permit The source will also be subject to the Acid Rain permit regulations but will seek an Acid Rain permit at a later date. The source will be subject to Article 3 Federal Operating ( Title I V ) permitting and must submit a n application within a year of commencing operation.

State New Source Review :

Emissions subject to Major New Source Review (Article 8

– PSD ) are not subjec t to Article 6 New Source Review as per 9 VAC 5

- 80

- 1100H

. The only pollutant which is not subject to PSD is lead. The total lead emissions from the facility are 0.02 tons/yr. This is below the exemption rate for lead in 9 VAC

- 5

- 80

- 1320C, so emissions of lead will not be subject to Article 6 regulations.

A

. Criteria Pollutants

C riteria pollutant modeling was conducted to ensure that the facility will not violate the NAAQS (see section IA above, under site suitability)

.
PSD increment The PSD increment modeling showed that the concentrations for all pollutants and averaging periods were below the applicable PSD increments (see modeling memo attachment)

.

B

. Toxic Pollutants

MACT s ha ve been promulgated for Combustion Turbines that are major sources of HAP ( S ubpart YYYY National Emission Standards for Hazardous Air Pollutants for Stationary Combustion Turbines ) and for cooling towers at major sources of HAP (Subpart Q National Emission Standards for Hazardous Air Pollutants For Industrial Process Cooling Towers)

. HAP emissions from this facility will be below major levels, so there will be no MACT requirements for the Combustion Turbines or Cooling Towers and , therefore, the State Toxics Rule (Rule 6

- 5, 9 VAC 5

- 60

- 300) will apply

. The source will need to demonstrate that they are minor for HAPs

. The only HAP s that exceed the exemption rate in 9 VAC 5

- 60

- 300 are acrolein, formaldehyde

, cadmium, chromium and nickel

. Emission limits for these HAPs will appear in a State Only section of the permit

. Modeling has shown that emissions of these HAP s will not exceed the Standard Ambient Air Concentration (SAAC ) (see modeling memo attachment)

. The emergency diesel fire water pump and emergency generators are subject to MACT S ubpart ZZZZ as an area source as per the application submitted by Dominion . The requirements for this unit will be to comply with NSPS S ubpart IIII or NSPS Subpart JJJJ requirements, which will be enforced by EPA, not DEQ.Engineering Analysis

March 8, 2013 Page 11

C

. Control Technology

Note: Although this plant will be very similar to the electric power plant permitted in Warren County in 2010, emissions are slightly different for the following reasons:

 PM 10 , PM 2.5 , SO 2 and H 2 SO 4 emissions are slightly higher due to the level of sulfur in the natural gas supplied to the Brunswick County area. Warren County natural gas has a sulfur content of 0.1 gr/100 ds cf and Brunswick County has a sulfur content of up to 0.4 gr/dscf.

 The Warren County plant is at a higher altitude (almost 600 ft above MSL) than the Brunswick plant (250 ft above MSL). At lower elevations, turbines experience higher air pressure and higher temperatures

. The higher temperatures reduce efficiency, while the higher pressure actually boosts power output , so both scenarios have an impact on emissions

.

 The Warren County plant is located very near to a Class I area (Shenandoah National Park) and therefore i s subject to more restrictive emission standards and tougher modeling protocol. The Brunswick plant is not located within 100 km of a Cla ss I area,

an d the Federal Land Managers stated that no impact to a Class I area was expected from this project, however an analysis was done to determine compliance with the Class I PSD increment. This analysis showed that the facility emissions would be below the Cl ass I Significant Impact Level for SO 2 , PM 10 , PM 2.5 and NO 2 .
PSD BACT : Sources that are subject to PSD permitting, must apply BACT to those pollutants that triggered PSD permitting (see Table 2 in Section III). The determination of BACT usually involves a top

- down method:

Step 1

– Identify all possible control technologies ; Step 2

– Eliminate technically infeasible options ; Step 3

– Rank the technically feasible control technologies based upon emission reduction potential ; Step 4

– Evaluate ranked con trols based on energy, environmental, and/or economic considerations ; and Step 5

– Select BACT.

PSD procedures require that the BACT cost feasibility analysis be based upon recent permit determinations for similar facilities. Federal guidance is clear that there can be no fixed or "bright line" cost established as representative of BACT. Rather, the cost of reducing emissions, expressed in dollars per ton, is to be compared with the cost incurred by other sources of the same industry type. A listing of BACT determinations from the RACT/BACT/LAER Clearinghouse for similar facilities is included as Appe ndix C in the Dominion

– Brunswick application.

1. Greenhouse gasses: In this case, CO 2 e emissions from the proposed facility trigger PSD permitting (on both a mass basis and CO 2 e basis, see Table 2 above) so BACT must be determined for CO 2 e

. CO 2 e is a re latively new regulated pollutant so there are few determinations in the RACT/BACT/LAER Clearinghouse to compare.

a. Combustion Turbines

i. Possible Control Technologies (Step 1) :

 Carbon capture and sequestration/storage: One such technology that is being discussed to control CO 2 is Carbon Capture and Sequestration /Storage (CCS). CCS consists of concentrating/ capturing CO 2 from exhaust and transporting it to a location where it can be stored fo r a long time

, deep in the gr ound. It is being demonstrated on pilot

- scale power plant projects and on other types of facilities around the world

.Engineering Analysis

March 8, 2013 Page 12

 Efficient power generation: Another strategy being used to minimize CO 2 emissions

is to maximize the energy efficiency and performance of the turbines (i.e., minimize the amount of fuel combusted to produce the desired amount of electricity)

. This has been the most accepted BACT for natural gas, combined

- cycle plants. By using more efficient turbines and including the st eam system to capture heat from the exhaust

, energy efficiency is maximized and CO 2 emissions can be minimized.

 Using low carbon fuel, like natural gas instead of coal

, can reduce GHG.

 Using renewable energy or alternative energy sources

- such as s olar t hermal

e lectric, p hotovoltaics, l andfill g as, w ind, b iomass, h ydroelectric, nuclear, g eothermal

e lectric, e nergy from w aste, a naerobic d igestion, t idal e nergy, and w ave e nergy

- reduces the use of fossil fuels.

ii. Technical feasib ility and availability of control technologies (Step 2) :

CCS

- Although the carbon capture technology is available and technically feasible for some applications (such as natural gas processing industries and petroleum refining), it is not a proven option for a natural gas, combin ed cycle combustion turbine whose exhaust is characterized by high flow and low CO 2 concentration (and certainly not for other fuel combustion sources such as boilers, fuel gas heaters or emergency generators)

. There are no instances that could be found of CCS being used on such a facility. CO 2 transport poses a problem as well. The proposed location does not appear to be geologically ideal for CCS but could offer some marginal options

. Areas in southwest Virg inia are more promising for this aspect of CCS but a pipeline does not currently exist. CO 2 storage in geologic formation underground must be carefully considered as there is some uncertainty as to the impact of such technology on the groundwater. The CC S technology can cause a significant energy penalty (estimated to be up to 15%) which could cause the units to have to burn more fuel and create more air pollution than would otherwise be emitted, and/or reduced power output. C C S works best on larger unit s, especially coal burning units, which have the potential to emit CO 2 in larger concentrations than this plant , and that are located near sequestration areas

. The feasibility and availability of CCS for the proposed power facility is marginal, at best.

Efficient power generation is technically feasible and available for this project.

Low carbon fuels are technically feasible and available for this project

Renewable/alternative energy sources

– For investor

- owned utilities, Virginia has a Renewable Portfolio Standard goal of 15% of base year (2007) sales of alternative energy by the year 2025 . And in 2012, legislation was passed to encourage research and development of renewable and alternative energy source ( www.dsireusa.org ). Virginia also has legislation (Virginia Mandatory Utility Green Power Option) that allows customers the option to purchase 100% renewable energy from a utility. Dominion participates in this program by buying cer tificates from renewable energy facilities. Although not mandated by regulation, Virginia is trying to establish a market for energy that reduces the carbon emissions from power generation. Brunswick County , however, is not an ideal location for either wind power or solar power generation , nor is it practical for hydro power, tidal power, or wave power

. Nuclear power has been demonstrated in Virginia but is not within the scope of this project and would require signi ficant design changes

. Geothermal electric production is not viable in Virginia. And

, although renewable energy (i.e., biomass) reduces the need for fossil fuels, the combustion of most other sources of carbon does not result in a reduction of CO 2 emissio ns in the shortEngineering Analysis

March 8, 2013 Page 13

term. ( http://www.energy.vt.edu/vept/index.asp ) . Therefore, DEQ finds that, at this

point in time, renewable or alternative energy options are not available or technically feasible on a large scale in Brunswick County and that the use of alternative fuels and nuclear power would be considered redefining the source.

iii. Rank GHG control technologies (Step 3):

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 % control efficiency . Since energy efficiency plays a role in emissions

, one must compare efficiency limits based on output ( Btu / k Wh or lb/kWh ) ra ther 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

. O n ly a handful of CCT have been permitted for GHG so a quick comparison can be made. As can be seen in Table 3 below , this project is a bit larger than most of the other, recently permitted or proposed NGCC projects. Keeping in mind that thermal efficiency increases with larger turbines, and the net heat rate (Btu/kWh) decreases, the BACT level pro posed for the 1400 MW Brunswick plant and the other permitted or proposed 180

- 1,000 MW plants is 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 a 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 (see discussion of the proposed BACT in Section 5 of Dominion ’s application for a detailed list of energy efficient practices that are proposed )

. More recently permitted plants have considered degradation, while earlier permitted plants may not have.

Table 3

– Comparison of GHG BACT determinations Facility Type GHG BACT limits Basis Dominion VA

- Brunswick , VA 1400 MW NGCC 7 5 00 Btu/kWh (net HHV) and 920 lb/MWh Thermal Efficiency Cricket Valley Energy Ctr , NY 1000 MW NGCC 7605 Btu/kWh (net H HV) and 950 lb/MWh Thermal Efficiency Hess Newark Energy Center, NJ 655 MW NGCC 7522 Btu/kWh (net HHV) w/o DB and 887 lb/MWh (gross) Thermal Efficiency

CPV Valley Energy, NY 630 MW NGCC 7605 Btu/kW (LHV) w/o DB and 950 lb/MWh Thermal Efficiency PacifiCorp Lake Side , UT 629 MW NGCC 6918 Btu/kW (HHV) and 950 lb/MWh (gross) Thermal Efficiency Russell City Energy Ctr , CA 600 MW NGCC 7730 Btu/kWh and 242 tons/hr Thermal Efficiency LCRA Ferguson replacement , TX 5 9 0 MW NGCC 7720 Btu/kWh (net HHV) and 918 lb/MWh Thermal Efficiency Sevier Power Company, UT 580 MW NGCC 7515 Btu/kWh and 1,958,558 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/kWh and 895 lb/MWh Thermal Efficiency

Deer Park (Calpine) Energy Center, 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

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. One study 1 predicted that a natural gas

- fired power plant that had a CO 2 e mission rate of

1 Rubin, Edward S and Haibo Zhai. The Cost of Carbon Capture and Storage for Natural Gas Combined Cycle Power Plants. Environ. Sci. Technol. 46:3076

- 3084 (2012)Engineering Analysis

March 8, 2013 Page 14

803 lb/MWh could reduce emissions to 94 lb/MWh by adding CCS, but at a cost of

$1336/kW.

iv. BACT determination for GHG

- m ost effective c ontrols (Step 4):

Of the technologies mentioned in Step 1 above, construction of a carbon capture control, transport and storage system for CO 2 gas in the Brunswick County region would be cost

- prohibitive. A recent study suggested that a dding CCS technology could increase plant construction costs up to $200 million 2

. Dominion calculated that construc tion of a pipeline to transport the collected CO 2 would be $250 million alone

. These factors, and the cost from a 15

- 20 % energy penalty which increases fuel usage, would make CCS economically infeasible at this time (see Section 5 of Dominion’s application for a more in

- depth analysis )

. The remaining technologies, namely e fficient power generation and the use of low carbon fuel s, are proposed for this facility and are accepted as BACT. Due to differences in size, m anufacturer, configuration, cooling practice, elevation, and the method used to determine the heat rate among the permitted power plants across the country, some variability in BACT determinations is expected, however, DEQ determine s that the proposed emission level of CO 2 e and level of energy efficiency

are BACT for this facility

. The plant will be required to operate at a higher heating value heat rate of no more than 7,500 Btu/KWh (based on a degradation estimate * for a new 6

, 695 Btu/kWh unit

– HHV/net), and emit CO 2 e at an average annual rate not to exceed 920 lb CO 2 e/MWh (which reflects a 119.12 lb CO 2 /MMBtu average monitored emission rate at similar facilities adjusted by a 3% margin to account for emissions from SU/SD and low l oad operation)

- both of which fall into the range of BACT of recently issued or drafted GHG PSD permits (see Table 3 above)

. *The degradation estimate is based on a 3.4% performance margin of the combustion turbines, a 1.2% degradation margin for the auxiliary power, and a 7.1% degradation margin for the steam turbine system

– 6695 x 1.034 x 1.0 12 x 1.071 = 7500 Btu/kWh net HHV

. And 119.2 lb/MMBtu x 7500 Btu/kWh x 1.03 x 1,000 kWh/MW x 1 MMBtu/1,000,000 Btu = 920.2 lb/MWh HHV net

.

b. Aux iliary Boiler and Fuel Gas Heaters CCS for control of the emissions of CO 2 e from these smaller fuel

- burning units is not technically feasible or available. BACT for these units will be the use of low carbon fuel and energy efficient design and operation.

c. Emergency generators and fire water pump Add

- on CO 2 controls are not technically feasible for emergency generators so BACT for the fire pump will be fuel

- efficien t design and a limit of 5 00 operating hours/yr

.

d. Electrical Breakers The electrical circuit breakers contain SF 6 which is a GHG. There is a small potential for these sealed units to release SF 6 from leaks. Although an alternative to the SF 6 would be to use oil or air

- blast circuit breakers, which would not have the potential to release SF 6 , thi s technology is being replaced by the sealed SF 6 circuit breakers due to the superior insulating and arc

- quenching capabilities of the SF 6 type units. The oil and air

- blast units are also larger than the SF 6 units, generate more noise, and the dielectric oil is flammable and also has adverse environmental impact if released. Studies have shown that the leakage rate for SF 6 from these circuit breakers is between 0.2 and 2.5 percent over the lifetime of the unit. 3 Therefore, BACT for the circuit breakers w ill be to minimize

2 Fishbeck, Paul S, David Gerard, and Sean T McCoy. Sensitivity analysis of the build decision for carbon capture and sequestration projects. Greenhouse Gas Sci. Technol. 2:36

- 45 (2012) 3 SF 6 Leak Rates from H

igh Voltage Circuit Breakers

– U.S. EPA Investigates Potential Greenhouse Gas Emissions Source , J. Blackman (U.S. EPA, Program Manager, SF6 Emission Reduction Partnership for Electric Power Systems), M. Averyt (ICF Consulting), and Z. Taylor (ICF Consultin g), June 2006.Engineering Analysis

March 8, 2013 Page 15

SF 6 leakage by using an enclosed

- pressure circuit breaker with no more than a 1.0

percent annual leakage rate and a leak detection system.

2. NO x Control

a. Combustion Turbines with duct

- fired HRSG

i. Step 1

- Combustion turbines and the assoc iated duct burners generate most of the NO x emissions from the facility. The following control technologies were identified by Dominion as applicable to NO x 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 x (DLN) Combustors • Water or Steam Injection • XONONTM, LoTOxTM, THERMALLONOxTM, and PahlmannTM

ii. Step 2

– The technical feasibility and availabi lity of each technology is discussed below:

SCR is a process that involves post combustion removal of NO x 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 re actions that take place on the surface of a catalyst. The function of the catalyst is to effectively lower the activation energy of the NO x decomposition reaction. Technical factors related to this technology include increased turbine backpressure, exhaust temperature materials limitations, thermal shock/stress during rapid starts, catalyst masking/blinding, reported catalyst failure due to "crumbling", design of the NH 3 injection system, and high NH 3 slip. SCR using ammonia as a reagent represents the stat e

- of

- the art for back end gas turbine NO x removal from base load, combined

cycle turbines. SCR is technically feasible and available

SCONOXTM is an emerging post

- combustion technology that removes NO x from the exhaust gas stream after formation in the com bustion turbine. SCONOXTM employs a potassium carbonate bed that adsorbs NO x 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 x emission reductions of 90% or more for combustion turbine application, and it is currently operating on several small natural gas

- fired turbines. The mo st notable advantage of SCONOXTM over SCR is that it reduces NO x 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 x control. Similar t o SCR, SCONOXTM only operates within a specific temperature range.

SCONOX 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 clea ning and other maintenance. SCONOX is available but not technically feasible for a plant of this size

.Engineering Analysis

March 8, 2013 Page 16

The t wo 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 simila r 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 effect ive 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% O 2 in the exhaust), NSCR is infeasible and inappropriate for the proposed combustion turbines.

DLN combustion control techniques reduce NOx emissions without injecting water or steam (hence "dry"). DLN combustors are designed to control peak combustion tempera ture, combustion zone residence time, and combustion zone free oxygen, thereby minimizing thermal NOx formation. This is accomplished by producing a lean, pre

- mixed flame that burns at a lower flame temperature and excess oxygen levels than conventional co mbustors.

DLN combustors have been employed successfully for natural gas

- fired combustion turbines for more than fifteen years. DLN combustors are available and technically feasible.

Water or steam injection is also designed to control peak combustion temperature, combustion zone residence time, and combustion zone free oxygen, thereby minimizing thermal NOx formation. This technology involves the injection of water or steam into the high temperature region of the flame, which minimizes thermal NO x form ation by quenching peak flame temperature.

Water and steam injection has been employed successfully for nearly thirty years, for both natural gas and oil

- fired combustion turbines. Water and steam injection remains the state

- of

- the

- art combustion technol ogy for minimizing NO x emissions for oil

- fired combustion turbines.

Water injection is considered to be available and technically feasible for combustion turbines for natural gas and oil firing operations but would not be employed with DLN burners.

XON ONTM, LoTOxTM, THERMALLONOxTM, and PahlmannTM

A number of other combustion turbine NOx emissions control technologies for combustion turbines are being marketed including XONONTM, LoTOxTM, THERMALLONOxTM, and PahlmannTM. None of these technologies has reached th e commercial development stage for large combustion turbines that will be fired with natural gas, and thus none are considered to be technically feasible for application to this project. DEQ concurs that these technologies are not yet commercially availabl e technology suitable for controlling CTs of the size proposed at the Dominion Brunswick site.Engineering Analysis

March 8, 2013 Page 17

iii. Step 3

– Ranking of available NO x controls

The most effective technologies that are available for a large natural gas

- fired, combined cycle power generating facility for controlling NO x are dry low NO x combustion to minimize NO x formation and post

- combustion treatment with SCR.

iv. Step 4

- BACT Determination: Selective Catalytic Reduction (SCR) and Dry Low

- NO x (DLN) Combustors

Dominion has proposed a combination of the remaining identified control options for NO x : dry low

- NO x combustion and selective catalytic reduction (SCR). The proposed Mits ubishi M501 GAC turbines use a two

- stage premixed combustion design resulting in uncontrolled NO x emissions of 15 ppmvd at 15% O 2 when firing natural gas, the fuel proposed for use by Dominion. The draft permit proposes use of SCR to control NO x emissions from the CTs to the following level (at 15% 0 2 ):

• 2.0 ppmvd with or without duct burning

Compliance with the limits is to be based on a one

- hour block average.

From 2007 to 20 11 , approximately 15 projects were permitted at 2.0 ppmvd at 15% O 2 , including two LAER determinations. Recent PSD permits at 2 .0 ppmvd at 15% O 2 include a December 17, 2010 permit for a CCT in Warren County, Virginia, and a September 1, 2011 permit for a Texas Power Plant. There wa s one project that was permitted at a NO x emission rate of 1.5 ppmvd at 15% O 2 in the year 2000. However, this project has not been built and therefore, 1.5 ppmvd at 15% O 2 has not been demonstrated as achievable in practice. With that one exception, the proposed limits are as stringent as any l isted in EPA's RACT/BACT/LAER Clearinghouse (RBLC) for electric generating facilities.

b. Auxiliary boiler and Fuel Gas Heaters i. List of control technologies

• Front end NO x reduction technologies (low excess air, low NO x burners, ultra low NO x burners)

• SCR ii. Technical feasibility and availability of NO x Control

• All technologies are feasible and available iii. Ranking of technologies

• The best NO x reduction could be achieved using both front end and add

- on NO x reduction technologies

• Alternatively, ultra low NO x burners are the best front end technology for reducing NO x emissions iv. BACT determination

• The use of SCR in conjunction with ultra low NO x burners has been determined to be economically infeasible for the auxiliary boiler and fuel gas heaters at costs exceeding $64,000 per ton for the boiler and $289,000 per ton for the fuel gas heaters

. • DEQ concurs with Domin ion that ultra low NO x burners are BACT for both units

c. Emergency Generators/Fire water pump Although add

- on controls such as SCR are used to control NO x on larger generators, if necessary to meet national standards for emissions, the proposed emissions from the emergency units at this facility can meet these standards without add

- on controls. The facility proposes a NO x limit for the 80 kW propane emergency generator of 4.3 g/hp

- hr based on manufacturer estimates. The facility proposes a limit of NO x +NMHC on theEngineering Analysis

March 8, 2013 Page 18

2200kW diesel emergency generator (EG

- 1) of 6.4 g/kW

- hr on ULSD. And the 305 hp

diesel fire water pump (FWP

- 1) has a proposed NO x +NMHC limit of 4.0 g/kW

- hr. This is in compliance with NSPS standards for newer diesel engines of those sizes and is considered BACT for those units

.

3. Carbon Monoxide Control

- 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 x emissions, the primary factors influencing the generation of CO emissions are temperature and res idence 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.

a. Combustion Turbines

i. Possible Control Technologies (Step 1)

• Oxidation Catalyst

• Good Combustion Practices

ii. Available and feasible (Step 2)

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 re act 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 CO 2 utilizes the excess air present in the turbine exhaust; and the activati on energy 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, an d potential collateral increases in emissions of PM 10 and H 2 SO 4 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 1100 °F. At lower temperatures, CO conversion efficiency falls off rapidly. Above 1200 °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 la teral distribution (it is important to evenly distribute gas flow across the catalyst) and proper operating temperature at base load design conditions. Operation at partial 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 pe rcent 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 th e installation, the cost of catalyst replacement should be considered on an annualized basis. Catalyst life may vary from the manufacturer'sEngineering Analysis

March 8, 2013 Page 19

typical 3

- year guarantee to a 5

- to 6

- year predicted life. Periodic testing of catalyst

material is necessary to pr edict 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. Good combustion practices are technically feasible for this project.

iii. Ranking of technologies for CO control (Step 3)

The most effective technologies that are available for a large natural gas

- fired, combined cycle power generating facility for controlling CO are good combustion practices to control the formation of CO, and oxidation catalyst as a post

- combustion treatment.

iv. BACT (Step 4)

Dominion has proposed a combination of control options for CO : oxidation catalyst and good combustion practices. The draft permit proposes use of oxidation catalyst and good combustion practices to control CO emissions from the CTs to the following level (at 15% O 2 ):

• 1.5 ppmvd without duct burning

• 2.4 ppmvd with duct burning

Compliance with the limits is to be based on a one

- hour block average. As shown in EPA's RBLC, only a few projects h ave been permitted at CO emission rates below 2 ppmvd at 15% O 2 . Typically, CO emission rates of 2 ppmvd at 15% O 2 to 3.5 ppmvd at 15% O 2 are determined to be BACT and LAER. The higher CO emission rates generally account for the higher emissions associated with duct burning.

The most recent BACT determinations in the RBLC have been around 1.5 ppmvd at 15% O 2 or higher. The most relevant BACT determination was for the 2010 permit for the Warren County, Virginia power plant with BACT emissions set at 1.5 ppmvd at 15% O 2 without duct burning, and 2.4 ppmvd at 15% O 2 with duct burning. DEQ concurs that the proposed oxidation catalyst control

, along with good combustion practices

, constitute BACT for CO from the CTs.

b. Auxiliary Boiler and Fuel Gas Heaters

i. List of control technologies (Step 1)

• Good combustion practices

• Oxidation catalyst

ii. Technical feasibility and availability of CO Control (Step 2)

• Good combustion practices are feasible and available for these units

• Oxidation catalyst is feasible and available for these units

iii. Ranking of technologies (Step 3)

• Good combustion practices can result in emissions from the units of 0.037 lb/MMBtuEngineering Analysis

March 8, 2013 Page 20

• Oxidation catalyst could reduce emissions further to about 0.006 lb/MMBtu

iv. BACT determination (Step 4)

• Oxidation catalyst used in conjunction with good combustion practices reduces CO emissions from the boiler by only 9 tons/yr at a cost of $10,000 per ton, and, for the fuel gas heaters, 1.1 tons/yr at $65,000 per ton, making it economically in feasible

• Good combustion practices results in CO emissions that are consistent with BACT at similar facilities . DEQ concurs with Dominion that good combustion practices are BACT for CO from the auxiliary boiler and fuel gas heaters.

c. Emergency Generato rs and Fire Water Pump The control of CO from the emergency units can be achieved without the use of add

- on CO controls which can be problematic on stationary combustion units

. The units can meet NSPS standards for engines through proper operation and mai ntenance of the units, and burning of cleaner fuels. Therefore BACT for CO from the emergency unit will be the use of clean fuel and the proper operation and maintenance of the units to keep CO emissions at 2.611 g/hp

- hr for the diesel units and 129.1 g/h p

- hr for the propane unit.

4. SO 2 and sulfuric acid mist

– primarily formed from the combustion of sulfur

- containing fuels

, with a small contribution of H 2 SO 4 from the SCR and Oxidation catalyst controls.

a. Combustion Turbines The use of low

- sulfur fuels is the only feasible and available technology to reduce SO 2 and H 2 SO 4 emissions from a natural gas combustion turbine. Flue gas desulfurization is only feasible on plants that produce much larger quantities of SO 2 and H 2 SO 4 and would produce a significant pr essure drop that would require an induced draft fan, potentially causing air/fuel mixing problems . The best low

- sulfur fuel is natural gas which is what is proposed at this facility. The sulfur content of the natural gas is dependent on the location from which the gas is piped. The sulfur content of the natural gas to be used in Brunswick County is 0.4 gr/100 dscf (levels across the country can range from 0.2 gr to 2.0 gr/100 dscf) and cannot be controlled by Dominion. DEQ concurs with the proposed

use of pipeline quality natural gas to achieve the following BACT rates:

• 0.00112 lb/MMBtu for SO 2
• 0.00058 lb/MMBtu for H 2 SO 4 without duct burning

• 0.00067 lb/MMBtu for H 2 SO 4 with duct burning

b. Auxiliary boiler and fuel gas heaters The only feasible control for SO 2 and H 2 SO 4 from the auxiliary boiler and fuel gas heaters is the use of pipeline quality natural gas.

c. Emergency generators The use of ultra low sulfur diesel in the diesel generators (S = 15 ppm) and the use of propane in the propane genera tor at 500 hrs/yr are considered BACT for SO 2 and H 2 SO 4 from the emergency units.

5. VOC

- Formation of VOC emissions are 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.

a. Combustio n Turbines

i. List of possible VOC controls for combustion turbines (Step 1)Engineering Analysis

March 8, 2013 Page 21

• Oxidation catalyst

• Good combustion practices

ii. Available and Feasible technologies (Step 2)

An oxidation catalyst is a post

- combustion technology that removes VOC from the exh aust 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 available and 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. This option is available and technically feasible.

iii. Ranking of technologies for VOC control (Step 3) The most ef fective technologies that are available for a large

, natural gas

- fired, combined cycle power generating facility for controlling VOC are good combustion practices to control the formation of VOC, and oxidation catalyst as a post

combustion treatment.

iv. BAC T (Step 4) VOC emission rates for recently permitted combined

- cycle facilities are typically in the range of 1.0 ppmvd at 15% O 2 to 2.0 ppmvd at 15% O 2 as shown in Dominion's summary of EPA's RBLC. The emission limits at the higher end of the range reflect the higher emissions associated with duct burning. However, there are a few projects with both higher and lower emission rates. Most of the projects with emission rates below 1.0 ppmvd at 15% O 2 have not been built. The 2010 permit for the Warren County power plant set BACT limits for VOC from the turbines at 0.7 ppmvd at 15% O 2 without duct burning, and 1.6 ppmvd at 15%O 2 with duct burning.

The applicant has proposed to control VOC using good combustion practices and an oxidation catalyst for the combustion turbines . The oxidation catalyst is proposed for the dual purpose of controlling CO emissions and VOC emissions. The applicant proposed VOC limits, based on 3 5 % control by an oxidation catalyst, as follows, all at 15% O 2 and as CH 4 (cal culated as a three

- hour average):

• 0.7 ppmvd without duct burner firing • 1.6 ppmvd with duct burner firing

DEQ concurs that t he use of good combustion control and an oxidation catalyst represent BACT for VOC control for the proposed combustion turbi nes.

b. Auxiliary boiler and fuel gas heaters i. List of control technologies (Step 1)

• Good combustion practices

• Oxidation catalyst

ii. Technical feasibility and availability of VOC Control (Step 2)

• Good combustion practices are feasible and available for these units

• Oxidation catalyst is feasible and available for these units

iii. Ranking of technologies (Step 3)Engineering Analysis

March 8, 2013 Page 22

• Oxidation catalyst used in conjunction with good combustion practices would achieve the best control rate.

• Good combustion practices alo ne can result in emissions of VOC from the units of 0.0 05 lb/MMBtu

iv. BACT determination (Step 4) VOC emissions from the boiler and fuel gas heaters without o xidation catalyst would be 0.005 lb/MMBtu which results in a combined total of 2.0 tons/yr from bot h units. It would not be economically feasible to reduce emissions further with add

- on controls. Good combustion practices results in VOC emissions that are consistent with BACT at similar facilities at 0.005 lb/MMBtu . DEQ concurs with Dominion that good combustion practices are BACT for VOC from the auxiliary boiler and fuel gas heaters.

c. Emergency generators and fire water pump The use of good combustion practices in the emergency generators a nd operating at 500 hrs /yr are considered BACT for VOC from the emergency units.

d. Fuel Tank VOC emissions from the diesel fuel tank are estimated to be only 7.5 lbs/yr. The use of a fixed roof tank to hold diesel fuel is BACT for this type of unit.

6. Particulate Matter Controls (PM 10 and PM 2.5 , including condensable)

– Particulate matter emissions 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 em issions, which contribute to PM 10 and PM 2.5 but not PM, are attributable primarily to the formation of sulfates and possibly organic compounds.

a. Combustion Turbines

i. List of PM control technologies (Step 1)

• Low ash/low sulfur fuel

• Add

- on controls such as ESP, scrubbers or baghouses

• Proper combustion controls

ii. Available and technically feasible technologies (Step 2)

The use of low

- ash fuels, like natural gas, propane, and ultra low sulfur diesel fuel are

re adily available and technically feasible to use in combined cycle turbines.

Add

- on PM controls (such as ESPs, scrubbers or baghouses) are not recommended for combustion turbines burning natural gas because the PM particles are quite small (<1 micron) and the air volume is quite l arge, thus diluting PM. Add

- on controls are not available nor technically feasible for a combustion turbine.

The use of low

- ash fuel (natural gas) and good combustion practices are widely accepted as PSD BACT for PM 10 and PM 2.5 f rom combustion.

iii. Ranking of PM 10 and PM 2.5 control technologies (Step 3) The most stringent particulate control method demonstrated for gas turbines is the use of low ash and low sulfur fuel with good combustion practices . No add

- on control technologies are listed in EPA's RBLC. Proper combustion control and the firing ofEngineering Analysis

March 8, 2013 Page 23

fuels with negligible or zero ash content and a low sulfur content for the combustion

turbines is the only control method listed.

iv. BACT for PM 10 and PM 2 .5 (Step 4) The pipeline quality natural gas in this region contains 0.4 gr/100 dscf which impacts the PM 10 and PM 2.5 emissions from fuel

- burning (compared to the 0.1 gr/100 dscf to be used at the similar plant in Warren County, VA) . In addition, the use of SCR and oxidation catalyst to control other air pollutants can contribute to PM 10 and PM 2.5 emissions. For this reason, BACT from this facility will be slightly higher than BACT for PM 10 and PM 2.5 from the Warren County plant. The applicant proposes the use of good combustion practices for the combustion turbines at the following BAC T rates for PM 10 and PM 2.5 :

PM 10
• 9 .7 lb/hr (0.0033 lb/MMBtu) without duct burner firing (3

- hour average)

• 16.3 lb/hr (0.0047 lb/MMBtu) with duct burner firing (3

- hour average)

PM 2.5 • 9.7 lb/hr (0.0033 lb/MMBtu) without duct burner firing (3

- hour average) • 16.3 lb/hr (0.0047 lb/MMBtu) with duct burner firing (3

- hour average)

DEQ concurs that the use of good combustion practices represent s BACT for PM 10 and PM 2.5 control for the proposed combustion turbines.

b. Auxiliary Boiler and Fuel Gas Heaters Particulate matter emissions from the boiler and fuel gas heater s are a combination of filterable and condensable particulate. Good combustion practices and limiting fuel use to only pipeline quality natural gas are proposed by the applicant as BACT for PM 10 and PM 2.5 emissions from the auxiliary boiler and fuel gas hea ter s . DEQ agrees that this constitutes BACT for particulate emissions from the boiler and heater s

. Short

- term PM 10 and PM 2.5 emissions from the auxiliary boiler and the fuel gas heater s will be limited to 0. 007 lbs/ MMBtu . Annual PM 10 and PM 2.5 emissions fr om the auxiliary boiler will be limited to 2.2 tons/yr while emissions from the fuel gas heater s will be limited to 0.8 tons/yr.

c. Fire Pump and emergency generators Possible PM controls for an emergency generator consist of the following: catalysts, including diesel particulate filters, clean fuels and good combustion practices. Of these, catalysts are not used for units that are only run on an as

- needed basis, making them not technically feasible for this unit. Therefore, PSD BACT for PM 10 and PM 2. 5 from the emergency generator units shall be the use of clean fuels (i.e., ULSD or propane ) and good combustion practices to achieve the following emission limits: Unit BACT Limit

PM 10 PM 2.5 EG

- 1 0.298 g/hp

- hr 0.298 g/hp

- hr EG

- 2 0.0194 g/hp

- hr 0.0194 g/hp

- hr FWP

- 1 0.298 g/hp

- hr 0.298 g/hp

- hr

d. Cooling Tower s Cooling towers produce drift, which is composed of fine water droplets that may contain dissolved solids and thus contribute to PM 10 and PM 2.5 emissions. The only feasible particulate matter controls for cooling towers is to use water with low total dissolved solids content and drift eliminators. The facility will use clean cooling water with drift eliminators in the inlet chillers and clean cooling water in the AEC

.

i. Auxiliary Equipment CoolerEngineering Analysis

March 8, 2013 Page 24

BACT for PM from the AEC will be to keep dissolved solids below 300 mg/l and to

achieve a drift rate of 0.0 1 percent of the circulating water flow (equivalent to 0 .0008 TPY of PM 10 and PM 2.5 .

ii. Inlet Chillers BACT for PM from the Inlet Chillers will be to keep dissolved solids below 1,000 mg/l and to achieve a drift rate of 0.0 005 percent of the circulating water flow (equivalent to 0.029 TPY of PM 10 and 9.46 x 10 - 5 TPY of PM 2.5 .

Table 4 below summarizes BACT for the facility:

Pollutant Primary BACT Control Compliance

NO x Turbine

2.0 ppmvd @ 15% O 2 (1

- hour avg.) DLN burners SCR Annual fuel throughput Stack test NOx CEMS Auxiliary Boiler and fuel gas heaters 9 ppmvd DLN burners Annual fuel throughput Stack test Emergency Generators EG

- 1 6.4 g/kW

- hr NOX+NMHC FWP

- 1 4.0 g/kW

- hr NOX+NMHC EG

- 2 5.84 g/kW

- hr Good combustion practices Annual hours of operation

SO 2 Turbine

0.00112 lb/MMBtu Low sulfur fuel Fuel monitoring, stack test

Auxiliary boiler and fuel gas heaters 0.00112 lb/ MMBtu Low sulfur fuel Fuel monitoring

Emergency generators 0.00154 lb/MMBtu (diesel) 0.00059 lb/MMBtu (propane) ULSD fuel with 15 ppm S Or propane fuel Fuel certification and hours of operation

H 2 SO 4 Turbine

0.00058 lb/MMBtu without DB 0.00067 lb/MMBtu with DB Low sulfur fuel Fuel monitoring, stack test

Auxiliary boiler and fuel gas heaters 0.00857 lb.MMBtu Pipeline quality natural gas and 5% oxidation of S to H 2 SO 4 Fuel monitoring

Emergency generators (see SO 2 ) (see SO2) Fuel monitoring

CO Turbine

1.5 ppmvd without DB (3

- hour avg.) 2.4 ppmvd with DB (3

- hour avg.) Oxidation catalyst Good combustion practices CO CEMS

Auxiliary boiler and fuel gas heaters 50 ppmvd Clean fuel and g ood combustion practices Stack test

Emergency generators 3.5 g/kW

- hr (diesel) 174.4 g/kW

- hr (propane) Good combustion practices Fuel monitoring

PM 10 and PM 2.5 Turbine

9.7 lbs/hr (0.00 33 lb/MMBtu) without DB (3

- hour avg.) 16.3 lbs/hr (0.0047 lb/MMBtu) with DB (3

- hour avg.) Low sulfur/carbon fuel and g ood combustion practices S tack test

Auxiliary boiler and fuel gas heaters 0.007 lb/MMBtu Low sulfur/carbon fuel and good combustion practices Fuel throughput

Emergency generators 0. 40 g/ kW

- hr (diesel) 0.12 g/kW

- hr (propane) Low sulfur fuel and good combustion practices Hours of operation

Turbine Chiller Drift rate of 0.0005% of circulating water flow and TDS of no more than 1,000 mg/l Low total dissolved solids (TDS) and drift eliminators Weekly water quality testing for TDS

Auxiliary Cooler Drift rate of 0.01% and TDS content of no more than 300 mg/l Low TDS Weekly water quality testing for TDS

VOC Turbine

0.7 ppmvd without (3

- hour avg.) 1.6 ppmvd with DB (3

- hour avg.) Oxidation catalyst Good combustion practices stack test and CO CEMS compliance

Auxiliary boiler and fuel gas heater 0.005 lb/MMBtu Clean fuel and good combustion practices Fuel throughput

Emergency generators (see NOx limit) Hours of operationEngineering Analysis

March 8, 2013 Page 25

Pollutant Primary BACT Control Compliance

CO 2 e Turbine

7, 5 00 Btu/kWh (HHV net ) and 920 lb/MWh Energy efficient combustion practices and low GHG fuels ASME Performance Test Code on Overall Plant Performance (PTC 46) and CO 2 CEMS (Part 75) and maintenance

. Auxiliary boiler and fuel gas heaters 117 lb/MMBtu Pipeline quality natural gas and fuel

- efficient design and operation Manufacturer specifications and maintenance

. Emergency Units 0.00661 lb/MMBtu Fuel

- efficient design fuel usage monitoring

Electrical Circuit breakers <1% leakage rate Enclosed

- pressure type breaker and leak detection Audible alarm with decreased pressure.

The proposed control strateg ies are considered to be the Best Available Control Technology (BACT) for this source type and are more stringent than NSPS standards

.

IV

. Initial Compliance Determination

A

. Testing

– stack testing is required for NO x , SO 2 , CO, VOC, PM 10 , and PM 2.5 from the turbines and NO x and CO from the auxiliary boiler and fuel gas heaters to show compliance with the BACT limit s

. An initial compliance test using ASME Performance Test Code on Overall Plant Performance (ASME PTC 46

- 1996) (or equivalent) is to be conducted on the turbine power blocks to show compliance with the heat rate limit of 7, 5 00 Btu/kWh (HHV net ).

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. 4 grain or less of total sulfur per 100 stand ard cubic feet. Alternatively, per 40 CFR 60.4370, the permit allows Dominion to determine the sulfur content of the natural gas by testing using two custom monitoring schedules or an EPA

- approved schedule. The permit also requires the permittee to obtain fuel supplier certification for each shipment of distillate oil used in the emergency units.

B

. VEEs

– an initial VEE will be required for the combustion turbines

.

V

. Continuing Compliance Determination

A

. CEMS

– will be required for NO x (NSPS) and is also proposed for CO and CO 2 . Requirements for CEMS performance evaluations, quality assurance, and excess emissions reports will be included in the permit.

The permit require s that the CT stacks be equipped with CEMS meeting the requirements of 40 CFR Part 75 (Acid Rain program) for NO x . In addition to providing a means to demonstrate compliance with the permit NO x limits, the CEMS will satisfy the NSPS Subpart KKKK requirement to monitor NO x 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 Dominion to conduct extensive, continuous monitoring of key operational parameters on the control devices to assure p roper operation and performance

.

B

. Recordkeeping

– The following records will be k ept by the permittee for the most recent five years:

a. Annual hours of operation of the emergency fire water pump (FWP

- 1) and emergency generators (EG

- 1 and EG

- 2) for emergency purposes and for maintenance checks and readiness testing, calculated monthly as the sum of each consecutive 12

- month period. Compliance for the consecutive 12

- month period shall be demonstrated monthly by addingEngineering Analysis

March 8, 2013 Page 26

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

the preceding 11 months;

b. All fuel supplier certifications for the ULSD fuel used in the emergency units (EG

- 1and FWP

- 1);

c. Monthly and a nnual throughput of natural gas to the three combustion tu rbine s and associated duct burner s (T

- 1M, T

- 2M, and T

- 3M) , 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 c alendar month to the individual monthly totals for the preceding 11 months;

d. Time, date and duration of each startup, shutdown, and malfunction period for each combustion turbine and associated duct burner (T

- 1M, T

- 2M, and T

- 3M) ;

e. Monthly and annual throug hput of natural gas to the auxiliary boiler (B

- 1) and the fuel gas heaters (GH

- 1 through GH

- 3), 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 to tal for the most recently completed calendar month to the individual monthly totals for the preceding 11 months ;

f. Fuel quality records for natural gas combusted in the combustion turbine and associated duct burner (T

- 1M, T

- 2M, and T

- 3M) ;

g. Continuous monito ring system emissions data, calibrations and calibration checks, percent operating time, and excess emissions ;

h. Operation and control device monitoring records for each SCR system and oxidation catalyst as required in Conditions 3 and 7 ;

i. Weekly log s of dissolved solids content of cooling water to the four inlet coolers (IC

- 1 through IC

- 4) and the auxiliary equipment chiller (AEC

- 1).

j. Scheduled and unscheduled maintenance, and operator training.

k. Results of all stack tests, visible emission evaluation s, and performance evaluations.

l. Manufacturer’s instructions for proper operation of equipment.

C

. Further Testing

a. A nnual testing for SO 2 can be done instead of fuel monitoring.

b. A fter the initial test for heat rate of the p ower block, an additional test is required every five year s

.

VI

. Public Participation

The applicant held a public information session on March 8 , 2012 at the High School in Lawrenceville, Brunswick Co unty to provide the community with information about the project.

Pursuant to 9 VAC 5

- 80

- 1775 (Article 8) of the Regulations, the proposed project is subject to a public comment period of at least 30 days, followed by a public hearing.

A n information mee ting and public hearing is scheduled to be held on February 4, 2013 at the Meherrin Library, Brunswick Branch , followed by 15 more days of public comment.Engineering Analysis

March 8, 2013 Page 27

The following documents are attached:

A

. Public hearing notice

B

. Public hearing opening statement

C

. Public briefing

D

. Virginia Register notice

E

. Documents concerning public comment period

VII

. Other Considerations

A

. File Consistency Review

– This is the first permit action for this source

B

. PRO Policy Consistency Review

– A review of similar combustion turbine permits proposed or issued in the USA was conducted. The most recent boilerplate was used for this permit.

C

. Confidentiality

– The source has not claimed confidentiality of any data.

D. Permit History

– This is the first permit issue d for this source

VIII

. Recommendations

Based on the information submitted, it is recommended that this permit be issued. Recommendations and limitations are provided in the draft permit letter.

Regional Engineer: Date:

Reviewing Engineer: Date:

Attachments: Permit application

Local Governing Body Certification Form Calculation sheets Modeling Memo Public Participation documents