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 an electric power generation facility in accordance 

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

Abatement of Air Pollution. 

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

the Department of Environmental Quality (DEQ) deemed the application complete on December 21, 2012

and solicited written public comments 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 5-80-1775 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 relieve 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 facilities 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. Therefore, 

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 KKKK 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 you may request direct consideration of the decision by the Board if the Director of the DEQ made 

the decision. Please consult the relevant regulations for additional requirements for such requests.

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

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

which to initiate an appeal of this decision by filing a Notice of Appeal with:

David K. Paylor, Director

Department of Environmental Quality

P. O. Box 1105

Richmond, VA 23218

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

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

the required content of the Notice of Appeal and for additional requirements governing appeals from 

decisions of administrative agencies.

If you have any questions concerning this permit, please contact the regional office at (804) 527-

5020.

Sincerely,

Kyle Ivar Winter, P.E.

Deputy Regional Director

KIW/AMS/52404_001_13_PSD.docx

Attachments: Permit

NSPS, Subparts 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, VA 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 21, 2012. Any changes in the permit application specifications or any existing 

facilities which alter the impact of the facility on air quality may require a permit. Failure to 

obtain such a permit prior to construction may result in enforcement action. In addition, this 

facility may be subject to additional applicable requirements not listed in this permit. 

Words or terms used in this permit shall have meanings as provided in 9 VAC 5-10-20 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 obligations 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 operating schedules. Such requests for information from the DEQ will either be 

in writing or by personal contact.

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

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

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

Virginia, and 9 VAC 5-170-60 of the 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 MMBtu/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 (natural 

gas-fired)

3,442 MMBtu/hr NSPS Subpart KKKK

NOx trading Subparts AA-II, AAA-III, 

and AAAA-IIII

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 AA-II, AAA-III, 

and AAAA-IIII

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
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

CB-1

through 

CB-11

Eleven Electrical Circuit Breakers 18,095 lb SF6 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 permit.

(9 VAC 5-80-1180 D 3)

Combined-cycle gas turbine generators and duct-fired HRSG (T-1M, T-2M, T-3M)

2. Emission Controls: Nitrogen Oxides - Nitrogen oxide (NOx) 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 NOx burners and 

selective catalytic reduction (SCR) with a NOX performance of 2.0 ppmvd at 15% O2 for 

natural gas. The low NOX 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 except during startup and shutdown, as defined in Condition 12).

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

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 accordance 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 operating.

(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 temperature 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 Monoxide – Carbon monoxide (CO) emissions from each of 

the combined cycle gas turbine generators and associated duct-fired HRSG (T-1M, T-2M, T3M) 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 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 duct-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 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) 

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

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

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

with 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 oxidation 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 (SO2) and 

sulfuric acid mist (H2SO4) 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 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) 

10. Emission Controls: Particulate Matter – Particulate Matter (PM10, PM2.5) 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 pipelinequality 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 CO2e 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 duct-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 associated duct-fired HRSG (T-1M, T-2M, T-3M

and steam turbine generator). The combined cycle gas turbine generators and associated 

duct-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 7,500 

Btu/kWh 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 limits for warm startup periods 

shall not exceed an annual average of 93 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 annual 

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 shall 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 NOx and CO emissions during each 

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

date of such event.

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

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

than when the load reaches 50% of unit output.

e. The permittee shall operate the facility so as to minimize the frequency and duration of 

startup and shutdown events. 

(9 VAC 5-50-280 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 heaters (GH-1 through GH-3)

13. Emission Controls: Nitrogen Oxides – NOx emissions from the auxiliary boiler (B-1) and 

three fuel gas heaters (GH-1 through GH-3) shall be controlled by ultra low-NOx burners

with a NOx performance of 9 ppmvd at 3% O2 for natural gas. The low NOx 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 heaters (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% 

O2. 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 manufacturer’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 maintenance 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 and 9 VAC 5-80-1705 B)

15. Emission Controls: Sulfur dioxide and sulfuric acid mist – SO2 and H2SO4 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 – PM10 and PM2.5 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 – CO2e 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 5-80-1705 B and 9 VAC 5-50-280) 

Emergency Units (EG-1, EG-2 and FWP-1)

18. Emission Controls: EG-1, FWP-1 - PM10, PM2.5, NOx, CO, SO2, VOC, and H2SO4

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 ppmw.

(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 - PM10, PM2.5, NOx, CO, SO2, VOC, and H2SO4 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 – CO2e emissions from the diesel emergency units

(EG-1 and FWP-1) shall be controlled 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 generators (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 

generators (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, over the entire life of the engine. In addition, the permittee 

may only 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 0.0005

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 Equipment Cooler – Particulate matter 

emissions from the 1,160 gallon/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 of 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 SF6) from 

the electrical circuit breakers (CB-1 through CB-11) shall be controlled by an enclosedpressure 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 turbines 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 grains per 100 standard cubic feet (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 turbines -The three combined cycle gas turbine generators and 

associated duct-fired HRSG (T-1M, T-2M, T-3M) combined shall consume no more than a 

total of 88,682 x 106scf 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 VAC 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 106scf 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 fire 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 emergency 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 permit to modify and operate.

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

32. Fuel: Fire water pump and emergency generators- 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 D975-10b 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 water 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 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)

34. Operating Hours: Emergency generators - The emergency generators (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 

emergency 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 facility 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 following:

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 credible evidence of the exceedance of emission limits.

(9 VAC 5-50-280)

37. Maintenance and Operation: Fire water pump and emergency generators – The 

permittee must maintain and operate the emergency fire pump (FWP-1) and emergency 

generators (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 manufacturer.

(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 206 x 106scf 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 1shall be operated in 

compliance with the requirements of 40 CFR 60, Subparts Dc and KKKK.

(9 VAC 5-50-400 and 9 VAC 5-50-410)

EMISSION LIMITS

40. Short-Term Emission Limits: Gas Turbines -Emissions from the operation of each 

combined-cycle gas turbine generator and associated HRSG duct burner (T-1M, T-2M, T3M), 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

PM10 (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.

PM2.5 (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  00.00112 lb/MMBtu

Nitrogen Oxides (as NO2)  2.0 ppmvd @ 15% O2 as a one-hour rolling average

Carbon monoxide

 1.5 ppmvd @ 15% O2 as a three-hour rolling average without 

duct burning

 2.4 ppmvd @ 15% O2 as a three-hour rolling average with duct 

burning

Volatile organic 

compounds

 0.7 ppmvd @ 15% O2 without duct burner firing

 1.6 ppmvd @ 15% O2 with duct burner firing

Sulfuric acid mist  0.00058 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 O2.

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 

malfunction. Periods considered startup and shutdown are defined in Condition 12 of this 

permit.

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 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 – CO2e 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 CO2e emissions for all hours in 

which power is being generated to the grid during the previous 12 months and dividing that 

value by the sum of the electrical energy output over that same period.

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

42. Annual Process Emission Limits – Emissions from the operation of each of the three 

combined cycle gas turbine generators and associated duct-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

PM10 (including condensable) 71.4 tons/yr (on a 12-month, rolling total)

PM2.5 (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 NO2)

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

CO2e 1,763,902 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:

PM10 (including condensable) 0.5 lbs/hr 2.2 tons/yr (on a 12-month, rolling total)

PM2.5 (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 NO2) 

Carbon Monoxide 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 

CO2e 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 as 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 operation of the electrical circuit breakers 

(CB-1 through CB-11) shall not exceed the limits specified below:

CO2e 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 (FWP-1)

shall not exceed the limits specified below:

PM (filterable only) 0.54 g/kW-hr

PM10(including condensable) 0.4 g/kW-hr 

PM2.5(including condensable) 0.4 g/kW-hr

Sulfur Dioxide 0.00154 lb/MMBtu

Nitrogen Oxides (as NO2) 4.0 g/kW-hr

+ Non-methane hydrocarbons

Carbon Monoxide 3.5 g/kW-hr

CO2e 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. Compliance 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

PM10(including condensable) 0.4 g/kW-hr 

PM2.5(including condensable) 0.4 g/kW-hr

Sulfur Dioxide 0.00154 lb/MMBtu

Nitrogen Oxides (as NO2) 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)

CO2e 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:

PM10(including condensable) 0.12 g/kW-hr 

PM2.5(including condensable) 0.12 g/kW-hr

Sulfur Dioxide 0.00059 lb/MMBtu

Nitrogen Oxides (as NO2) 5.84 g/kW-hr

Carbon Monoxide 174.4 g/kW-hr 7.7 tons/yr (on a 12-month rolling total)

CO2e 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 operation of the fuel gas heaters (GH-1 

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

PM10 (including condensable) 0.007 lbs/MMBtu 0.8 tons/yr (on a 12-month, rolling total)

PM2.5 (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 NO2) 

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)

Compounds 

CO2e 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 

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, 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 duct-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 Limit - Visible emissions from the emergency fire water pump (FWP-1) 

and emergency generators (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 NOx (measured as NO2), CO2 and CO from each combined cycle 

combustion turbine and associated duct-fired HRSG (T-1M, T-2M, T-3M) in ppmvd, 

corrected to 15 percent O2. CEMS for NOx shall meet the design specifications of 40 CFR 

Part 75 whereas CEMS for CO shall be installed, evaluated, and operated according to the 

monitoring requirements in 40 CFR 60.13. The CEMS shall also measure and record the 

oxygen content of the flue gas at each location where NOx 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, NOx data and CO data shall each be reduced to 1-hour block 

averages. The relative accuracy test audit (RATA) of the NOx 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 NOx and, if applicable, 

SO2 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 – Brunswick County Power Station

Registration Number: 52404

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 calibration 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 Program - 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 NOx, CO 

and CO2 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 NOx - 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 

NOx 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: NOx concentration, O2 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 Monitor Downtime for SO2 - 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 emission occurs each unit operating hour included in the period beginning on 

the date and hour of any sample for which the sulfur content of the fuel being fired in the 

combustion turbine exceeds the applicable limit and ending on the date and hour that a 

subsequent sample is taken that demonstrates compliance with the sulfur limit; 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 – Brunswick County Power Station

Registration Number: 52404

March 12, 2013

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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 include, but are not limited to 

the following information:

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

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

of excess emissions;

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 have 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 NOx and diluent monitors, the data acquisition and 

handling system must calculate and record the hourly NOx 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 O2 concentration exceeds 19.0 percent O2, a diluent cap 

value of 19.0 percent O2 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 procedures in 40 CFR 75, Subpart D are 

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

performance report required under 40 CFR 60.7(c).

(9 VAC 5-50-50, 9 VAC 5-50-410, 40 CFR 60.7(c), and 40 CFR 60.4350)
Virginia Electric and Power Company – Brunswick County Power Station

Registration Number: 52404

March 12, 2013

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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 volumetric 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 appropriate 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 5-80-1675)

61. Stack Test: Turbines - Initial performance tests shall be conducted for CO, PM10 (including 

condensable PM10), PM2.5, 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 Condition 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 but 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 5-80-1675, 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 NOx (as NO2) 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 the NOx 

concentration (in ppm). Sampling traverse points for NOx and (if applicable) diluent gas 

are to be selected following EPA Method 20 or EPA Method 1 (non-particulate 

procedures), and sampled for equal time intervals. The sampling must be performed with 

a traversing single-hole probe, or, if feasible, with a stationary multi-hole probe that 

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

documented to sample equal volumes from each hole may be used to sample 

simultaneously at the required points.

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 NOx 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 completed, the permittee may use the following alternative sample point 

selection criteria for the performance test:

i. If each of the individual traverse point NOx 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 O2 from the 

mean for all traverse points, three points (located either 16.7, 50.0 and 83.3 

percent of the way across the stack or duct, or, for circular stacks or ducts greater 

than 2.4 meters (7.8 feet) in diameter, at 0.4, 1.2, and 2.0 meters from the wall) 

may be used. The three points must be located along the measurement line that 

exhibited the highest average NOx 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 NOx

concentrations is within ±2.5 percent of the mean concentration for all traverse 

points, or the individual traverse point diluent concentrations differs by no more 

than ±1ppm or ±0.15 percent O2 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 NOx emissions after the duct burner rather than 

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

test.

e. Compliance with the applicable emission limit in Condition 40 must be demonstrated at 

each tested load level. Compliance is achieved if the three-run arithmetic average NOx

emission rate at each tested level meets the applicable emission limit in Condition 40.

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

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

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

h. The permittee may use the following as alternatives 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 must be greater than 0°F during the RATA runs.
Virginia Electric and Power Company – Brunswick County Power Station

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March 12, 2013

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ii. Compliance with the applicable emission limit in Condition 40 is achieved if the 

arithmetic average of all of the NOx emission rates for the RATA runs, expressed 

in units of ppm at 15% O2, does not exceed the emission limit.

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 

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 the 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 SO2 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:

a. If the permittee chooses to periodically determine the sulfur content of the fuel 

combusted in the turbine, a representative fuel sample would be collected following 

ASTM D5287 (incorporated by reference, see 40 CFR 60.17 or by manually sampling 

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

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

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

shall be analyzed using ASTM D1072, or 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 SO2 

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 

SO2 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 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 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 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 NOx and CO from the auxiliary boiler (B-1) and fuel gas heaters (GH-1 

through GH-2) to determine compliance with the emission limits contained in Conditions 43

and 48. The tests shall be performed, reported and demonstrate compliance within 60 days 

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

unit will be operated but in no event later than 180 days after its initial start-up. 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 of test completion 

but no later than 180 days after startup of the permitted unit and shall conform to the test 

report format enclosed with this permit.

(9 VAC 5-50-30, 9 VAC 5-80-1985 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 permittee on each combustion turbine and 

associated duct burner (T-1M, T-2M, and T-3M). Each 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 conditions 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 achieving the maximum production rate at which the unit 

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

Should conditions 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 

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 VAC 5-80-1675)
Virginia Electric and Power Company – Brunswick County Power Station

Registration Number: 52404

March 12, 2013

Page 22

66. Visible Emissions Evaluation - Auxiliary Boiler and fuel gas heaters - Concurrently with 

the initial performance tests in Condition 64, Visible Emission Evaluations (VEE) in 

accordance with 40 CFR Part 60, Appendix A, Method 9, shall be conducted by the permittee 

on the auxiliary boiler (B-1) and fuel gas heaters (GH-1 through GH-3). Each test shall 

consist of 10 sets of 24 consecutive observations (at 15 second intervals) to yield a sixminute 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 compliance 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 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 

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 VAC 5-80-1675)

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 Regional Office, shall be conducted for the 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 than 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 DETERMINATION

68. Annual Performance Test – Combustion Turbines – Annual performance tests shall be 

conducted on each combustion turbine and associated duct burner (T-1M, T-2M, and T-3M) 

for SO2 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 performed either by the permittee, a service contractor retained by the permittee, the 

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

fuel shall be analyzed using ASTM D1072, or 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 SO2 

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 

SO2 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 five years after initial evaluation of the heat rate 

limit of the power blocks, the permittee shall conduct a heat rate evaluation of the power 

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 conduct 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. 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 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-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;

b. All fuel supplier certifications for the ULSD fuel used in the emergency units (EG-1and 

FWP-1);

c. Monthly and annual throughput of natural gas to the three combustion turbines and 

associated duct burners (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, shutdown, 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 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;

f. Fuel quality 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 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 logs 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 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 when requested at the appropriate locations and safe 

sampling platforms and access 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 actual 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 (3AP20)

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 construct 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 5-80-1985)

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 with 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 permittee 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 conditions of this permit;

b. To have access to and copy at reasonable times any records required to be kept under the 

terms and conditions of this permit or the State Air Pollution Control Board Regulations;

c. To inspect at reasonable times any facility, equipment, or process subject to the terms and 

conditions of this permit or the State Air Pollution Control Board Regulations; and 

d. To sample or test at reasonable times.

For purposes of this condition, the time for inspection shall be deemed reasonable during 

regular business hours or whenever the facility is in operation. Nothing contained herein 

shall make an inspection time unreasonable during an emergency.

(9 VAC 5-170-130 and 9 VAC 5-80-1180)
Virginia Electric and Power Company – Brunswick County Power Station

Registration Number: 52404

March 12, 2013

Page 27

77. Maintenance/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 consistent 

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 

equipment which affect such emissions:

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

b. Maintain an inventory of spare parts.

c. Have available written operating procedures for equipment. These procedures shall be 

based on the manufacturer's recommendations, at a minimum.

d. Train operators in the proper operation of all such equipment and familiarize the 

operators with the written operating procedures, prior to their first operation of such 

equipment. The permittee shall maintain records of the training provided including the 

names of trainees, the date of training and the nature of the training.

Records of maintenance and training shall be maintained on site for a period of five years and 

shall be made available to DEQ personnel upon request.

(9 VAC 5-50-20 E)

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 telegraph. 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 duration 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 normal 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 the previous owner. The new owner shall 

notify the Piedmont Regional Office of the change of ownership within 30 days of the 

transfer.

(9 VAC 5-80-1985 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 – Emissions from the electric power generation facility shall not exceed the 

limits specified below:

Pollutant CAS# Lb/hr Tons/yr

Acrolein 107-02-8 0.040 lb/hr 0.16 tons/yr

Formaldehyde 50-00-0 1.370 lb/hr 5.88 tons/yr

Cadmium 7440-43-9 0.011 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 0.09 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 5-80-1625G)

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 

include, 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 shall 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 (indicate Ref. No. used by source in permit or registration)

3. Test Dates.

4. Tester; name, address and report date

Certification

1. Signed by team leader/certified observer (include certification date)

2. Signed by responsible company official

3. *Signed by reviewer 

Copy of approved test protocol

Summary

1. Reason for testing

2. Test dates

3. Identification of unit tested & the maximum rated capacity

4. *For each emission unit, a table showing:

a. Operating rate

b. Test Methods

c. Pollutants tested 

d. Test results for each run and the run average

e. Pollutant standard or limit 

5. Summarized process and control equipment data for each run and the average, as required by the 

test protocol

6. A statement that test was conducted in accordance with the test protocol or identification & 

discussion of deviations, including the likely impact on results

7. Any other important information

Source Operation

1. Description of process and control devices

2. Process and control equipment flow diagram

3. Sampling port location and dimensioned cross section Attached protocol includes: sketch of 

stack (elevation view) showing sampling port locations, upstream and downstream flow disturbances 

and their distances from ports; and a sketch of stack (plan view) showing sampling ports, ducts 

entering the stack and stack diameter or dimensions

Test Results

1. Detailed test results for each run

2. *Sample calculations

3. *Description of collected samples, to include audits when applicable 

Appendix

1. *Raw production data 

2. *Raw field data

3. *Laboratory reports

4. *Chain of custody records for lab samples

5. *Calibration procedures and results

6. Project participants and titles

7. Observers’ names (industry and agency)

8. Related correspondence

9. Standard procedures

 _____

* Not applicable to visible emission evaluations
ENGINEERING ANALYSIS

Source Name: Virginia Electric and Power Company – Brunswick Plant Permit No.: 52404-001

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

Date: March 8, 2013

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 407232mN). 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 (NOx), carbon monoxide (CO), volatile organic 

compounds (VOC), Particulate Matter less than 10 microns (PM10), particulate matter less than 

2.5 microns (PM2.5), and greenhouse gas [GHG or CO2 equivalents (CO2e)] over 100,000 tons/yr,

Prevention of Significant Deterioration (PSD) permitting for those pollutants - as well as sulfur 

dioxide (SO2) and sulfuric acid mist (H2SO4) 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 County 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 result 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 Available 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 

Section III.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 facility 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 is 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 SO2, PM10, PM2.5, and NO2. The maximum predicted 

concentrations 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, predicted 

impacts from CO (1-hour and 8-hour averaging periods) and SO2 (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. However, 

modeled concentrations for NO2 (1-hour and annual averaging periods), PM10 (24-hour 

averaging period), and PM2.5 (24-hour and annual averaging periods) exceeded the applicable 

SILs. Therefore, a cumulative impact analysis for these pollutants and averaging periods was 

necessary. The predicted impacts for NO2, PM10, and PM2.5 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 use 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 units 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 demonstrated 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 the 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 SO2, NO2, PM10 and CO 

were below the minimum reported levels at which damage or growth effects to vegetation may 
Engineering 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 anticipated.

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 fuel electric generation facilities is necessary if operation 

of conventional coal-fired power plants is to be reduced or replaced. Construction of cleanburning, efficient generation plants such as the proposed Dominion-Brunswick facility creates 

the potential for regional SO2 and NOx 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 which 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 

likewise 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 might reasonably be expected to 

occur during the grace period allowed by the Regulations or the permit conditions to fix 

malfunctioning air pollution control equipment: 

(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 pollution 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 include 
Engineering Analysis

March 8, 2013

Page 4

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

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 requirement to use ultralow sulfur diesel oil (no more than 0.0015 % by weight) or propane in emergency equipment 

and to monitor equipment leaks in the circuit breakers. 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 three 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 proposed fuel for the turbines and duct burners is pipeline-quality natural gas. 

Emissions from the turbines will be controlled by the use of low carbon fuels and high efficiency 

design (for GHG), clean fuels and good combustion practices (for PM10 and PM2.5), SCR 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 CO2e) and they will also be covered in 

the permit.

Table 1 - Expected emissions from the proposed facility are as follows:

Pollutant Emissions (tons/yr)

NOx 343.6

CO 477.9

SO2 51.1

VOC 314.2

PM10 218.0

PM2.5 217.6

CO2e 5,341,291.0

Sulfuric acid mist (H2SO4) 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 Table 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 CCCCC
Engineering 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 gasfired)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 SF6 None

ST-1 Distillate fuel oil tank 6000 gallons None

Combustion Turbine Generators with duct-fired Heat Recovery Steam Generators (T-1M, T2M, and T-3M) 

Combustion Turbines (CT)

The source has proposed the installation of three Mitsubishi M501 GAC class CTs in combinedcycle 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-NOx combustors 

minimize NOx formation during natural gas combustion. Hot exhaust gases from the combustion 

chamber are expanded through a multi-stage power turbine that results in energy to drive both 

the air compressor and electric power generator. 

The CTs are designed to operate in the dry low-NOx mode at loads from approximately 50 

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 additional electricity. Each HRSG will act as a heat exchanger to derive heat energy 

from the CT exhaust gas to produce steam that will be used to drive a Steam Turbine generator 

(ST). 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 

501 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 intermediate-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 steam 
Engineering Analysis

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Page 6

exhausting from the ST. 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 NOx emissions, and oxidation catalysts will be installed to control CO and VOC emissions. 

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 intermediatepressure section of the turbine, which expands to the low-pressure section. The low-pressure 

steam turbine generator 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 eliminators. 

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 auxiliary 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 Heaters (GH-1 through GH-3) 

The proposed facility will include three 8.0 MMBtu/hr, natural gas-fired, fuel gas heaters. The 

heaters 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 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 turning gears, 

lube oil pumps, auxiliary cooling water pumps and water supply pumps. The emergency diesel 

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

Propane-Fired Emergency Generator (EG-2) 

The proposed facility will include an 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 house in the switchyard. The emergency propane
Engineering Analysis

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Page 7

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

Diesel-Fired Fire Water Pump (FWP-1) 

The proposed project will include a 305 bhp diesel-fired fire water pump operated as a fire water 

pump driver. The unit will be limited to 500 hours per year, including monthly testing and 

maintenance (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 (SF6) per unit. There will be a total of 11 circuit breakers located at the facility, with 

a total capacity of 18,095 lbs of SF6. Maximum annual leakage rate for SF6 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 have 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, 2011 (amended March 7, 2012, 

September 7, 2012, November 5, 2012, and 

December 21, 2012)

Date application was deemed complete December 21, 2012

Proposed construction commencement date April 2013

Proposed start-up date January, 2015

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 generators, 

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 for NOx and CO from the combined cycle units and duct 

burners will be based on CEMS data. Compliance with the annual SO2 limit will be based on fuel 

throughput and the sulfur content of the fuel. Compliance with short-term PM10, PM2.5, and VOC from 

the combustion 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 CO2e emission limits will be on a 12-month rolling total based on CEMS 

data. Short-term CO2e 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

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Page 8

Emissions 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 includes minimization 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 leakage rate of 1%.

III. Regulatory Review

The proposed project is a major new source with projected, permitted, annual emissions greater than 

100 tons of several criteria pollutants (see Table 1 in Section I.B above).

Greenhouse Gas Emissions Applicability Review: 

After July 1, 2011, new sources that have the potential to emit 100,000 tons or more of CO2e (or 

75,000 tons of CO2e if PSD is triggered by another pollutant) and modified sources with a net 

emission increase of CO2e over 75,000 tons year will be required to obtain a PSD permit. The total 

CO2e is based on taking the mass emissions of each GHG and multiplying by its Global Warming 

Potential (GWP). These GWP factors are as follows: CO2: 1; CH4: 21; N20: 310; SF6: 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 SF6.

Since the permit for the project will be issued after July 1, 2011 and it will be a PSD source for several 

other pollutants, and permitted CO2e 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 is PSD-major for PM10, PM2.5, NOx, CO, VOC and CO2e (see Table 2

below). Because one or more pollutants are subject to PSD, the other pollutants at the source (SO2, 

Lead and H2SO4) need to be evaluated for PSD at their significance level. SO2 and H2SO4 exceed 

the PSD significance level for those pollutants so the facility will be subject to PSD for SO2 and H2SO4

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?

PM10 218.0 100 Yes 15 Yes

PM2.5 217.6 100 Yes 10 Yes

NOx 343.6 100 Yes 40 Yes

CO 477.9 100 Yes 100 Yes

SO2 51.1 100 No 40 Yes

VOC 314.2 100 Yes 40 Yes

CO2e 5,341,291.0 100,000 Yes 75,000 Yes

Lead 0.02 100 No 0.6 No

H2SO4 30.4 100 No 7 Yes

*Major Threshold levels from definition of “Major stationary source” in 9 VAC 5-80-1615C
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**PSD significance values from definition of “significant” in 9 VAC 5-80-1615C

NSPS Requirements:

Subpart KKKK: The combustion turbines are subject to NSPS Subpart KKKK (Standards of 

Performance for Stationary Combustion Turbines) which requires the source to meet NOx and SO2

standards. The source must meet a NOx limit of 25 ppm when burning natural gas. The source 

proposes the use of ultra low NOx burners and SCR to control NOx emissions. NOx emissions from 

the proposed combustion turbines are expected to be around 2.0 ppmvd when burning natural gas

which is below the NSPS standard and is considered Best Available Control Technology (BACT). 

The source will put NOx CEMS on the turbine stacks to show compliance with the BACT limits. 

The source proposes using low-sulfur fuel (natural gas) to control SO2 from the turbines and duct 

burners. To be in compliance with NSPS KKKK, they must not exceed 0.06 lb SO2/MMBtu from fuel 

burning. The source has proposed a BACT emission limit of 0.00112 lb SO2/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 steamgenerating 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*: The emergency diesel fire water pump and diesel emergency generator are subject to 

NSPS Subpart IIII. The 227.4 kW diesel fire water pump is subject to a NOx + 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. The 2200 kW diesel emergency 

generator is subject to a NOx + 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 sparkignition 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 emergency units, DEQ 

has not elected to receive delegation for enforcement of these regulations, 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 ensure 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 CO2 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. Expected emissions of CO2

from the facility are around 920 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 CO2 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 requirements, as applicable. 
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*DEQ has not elected to receive delegation to enforce this federal regulation so requirements for this 

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 IV/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 IV) permitting and must 

submit an application within a year of commencing operation.

State New Source Review:

Emissions subject to Major New Source Review (Article 8 – PSD) are not subject 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

Criteria 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

MACTs have been promulgated for Combustion Turbines that are major sources of HAP (Subpart 

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 HAPs 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 HAPs 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 Subpart 

ZZZZ as an area source as per the application submitted by Dominion. The requirements for this 

unit will be to comply with NSPS Subpart IIII or NSPS Subpart JJJJ requirements, which will be 

enforced by EPA, not DEQ.
Engineering Analysis

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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:

 PM10, PM2.5, SO2 and H2SO4 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 dscf 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 is subject to more restrictive emission standards and tougher 

modeling protocol. The Brunswick plant is not located within 100 km of a Class I area, 

and 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 

Class I Significant Impact Level for SO2, PM10, PM2.5 and NO2.

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 controls 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 Appendix C in the Dominion – Brunswick application. 

1. Greenhouse gasses: In this case, CO2e emissions from the proposed facility trigger PSD 

permitting (on both a mass basis and CO2e basis, see Table 2 above) so BACT must be 

determined for CO2e. CO2e is a relatively 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 CO2 is Carbon Capture and Sequestration/Storage (CCS). CCS 

consists of concentrating/capturing CO2 from exhaust and transporting it to a location

where it can be stored for a long time, deep in the ground. It is being demonstrated 

on pilot-scale power plant projects and on other types of facilities around the world. 
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Page 12

 Efficient power generation: Another strategy being used to minimize CO2 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 steam system to capture heat from the 

exhaust, energy efficiency is maximized and CO2 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 solar thermal 

electric, photovoltaics, landfill gas, wind, biomass, hydroelectric, nuclear, geothermal 

electric, energy from waste, anaerobic digestion, tidal energy, and wave energy -

reduces the use of fossil fuels.

ii. Technical feasibility 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, combined cycle combustion 

turbine whose exhaust is characterized by high flow and low CO2 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. CO2 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 Virginia are more promising for this aspect of 

CCS but a pipeline does not currently exist. CO2 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 CCS 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. CCS works best on larger units, especially 

coal burning units, which have the potential to emit CO2 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 certificates 

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 significant 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 CO2 emissions in the short 
Engineering 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/kWh or 

lb/kWh) rather than mass limits based on heat input (lb/MMBtu). This is because, as 

a unit gets older and less efficient, it may still meet a lb/MMBtu limit while, at the 

same time, using more fuel to achieve its heat input need, therefore increasing 

emissions. Only 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 proposed 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 7500 Btu/kWh (net HHV) and 920 lb/MWh Thermal Efficiency

Cricket Valley Energy Ctr, NY 1000 MW NGCC 7605 Btu/kWh (net HHV) and 950 lb/MWh Thermal Efficiency

Hess Newark Energy Center, NJ 655 MW NGCC 7522 Btu/kWh (net 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 590 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 

study1predicted that a natural gas-fired power plant that had a CO2 emission 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

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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- most effective controls (Step 4):

Of the technologies mentioned in Step 1 above, construction of a carbon capture 

control, transport and storage system for CO2 gas in the Brunswick County region 

would be cost-prohibitive. A recent study suggested that adding CCS technology 

could increase plant construction costs up to $200 million2. Dominion calculated that 

construction of a pipeline to transport the collected CO2 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 efficient power generation and the use of low 

carbon fuels, are proposed for this facility and are accepted as BACT. Due to 

differences in size, manufacturer, 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 

determines that the proposed emission level of CO2e 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 CO2e at an average annual rate 

not to exceed 920 lb CO2e/MWh (which reflects a 119.12 lb CO2/MMBtu average 

monitored emission rate at similar facilities adjusted by a 3% margin to account for 

emissions from SU/SD and low load 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 1.012 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. Auxiliary Boiler and Fuel Gas Heaters

CCS for control of the emissions of CO2e 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 CO2 controls are not technically feasible for emergency generators so BACT for 

the fire pump will be fuel-efficient design and a limit of 500 operating hours/yr.

d. Electrical Breakers 

The electrical circuit breakers contain SF6 which is a GHG. There is a small potential for 

these sealed units to release SF6 from leaks. Although an alternative to the SF6 would be 

to use oil or air-blast circuit breakers, which would not have the potential to release SF6, 

this technology is being replaced by the sealed SF6 circuit breakers due to the superior 

insulating and arc-quenching capabilities of the SF6 type units. The oil and air-blast units 

are also larger than the SF6 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 SF6 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 will 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 SF6 Leak Rates from High 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 Consulting), June 2006.
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March 8, 2013

Page 15

SF6 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. NOx Control

a. Combustion Turbines with duct-fired HRSG

i. Step 1 - Combustion turbines and the associated duct burners generate most of the 

NOx emissions from the facility. The following control technologies were identified by 

Dominion as applicable to NOx treatment for combined-cycle combustion turbines: 

• Selective Catalytic Reduction (SCR) 

• SCONOXTM 

• Selective Non-Catalytic Reduction (SNCR) and Non-Selective Catalytic Reduction 

(NSCR) 

• Dry Low-NOx (DLN) Combustors 

• Water or Steam Injection 

• XONONTM, LoTOxTM, THERMALLONOxTM, and PahlmannTM 

ii. Step 2 – The technical feasibility and availability of each technology is discussed 

below:

SCR is a process that involves post combustion removal of NOx from the flue gas 

with a catalytic reactor. In the SCR process, ammonia injected into the turbine 

exhaust gas reacts with nitrogen oxides and oxygen to form nitrogen and water. SCR 

converts nitrogen oxides to nitrogen and water through several possible reactions 

that take place on the surface of a catalyst. The function of the catalyst is to 

effectively lower the activation energy of the NOx 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 NH3

injection system, and high NH3 slip. SCR using ammonia as a reagent represents the 

state-of-the art for back end gas turbine NOx removal from base load, combinedcycle turbines. SCR is technically feasible and available

SCONOXTM is an emerging post-combustion technology that removes NOx from the 

exhaust gas stream after formation in the combustion turbine. SCONOXTM employs a 

potassium carbonate bed that adsorbs NOx 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 NOx emission reductions of 90% or 

more for combustion turbine application, and it is currently operating on several small 

natural gas-fired turbines. The most notable advantage of SCONOXTM over SCR is 

that it reduces NOx 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 NOx control. Similar to 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 cleaning and other maintenance. SCONOX is available 

but not technically feasible for a plant of this size.
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The two other back-end catalytic reduction technologies, SNCR and NSCR, have 

been used to control emissions from certain other combustion process applications. 

However, both of these technologies have limitations that make them inappropriate 

for application to combustion turbines. SNCR requires a flue gas exit temperature in 

the range of 1,300 to 2,100 °F, with an optimum operating temperature zone between 

1,600 and 1,900 °F. Simple-cycle combustion turbines have exhaust temperatures of 

approximately 1,100 °F, and combined-cycle turbines have exhaust temperatures 

much lower than simple-cycle turbines. Therefore, additional fuel combustion or a 

similar energy supply would be needed to create exhaust temperatures compatible 

with SNCR operation. This temperature restriction and related economic 

considerations make SNCR infeasible and inappropriate for the proposed combustion 

turbines. NSCR is only effective in controlling fuel-rich reciprocating engine emissions 

and requires the combustion gas to be nearly depleted of oxygen (<4% by volume) to 

operate properly. Since combustion turbines operate with high levels of excess 

oxygen (typically 14 to 16% O2 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 

temperature, 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 combustors. 

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 NOx

formation 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 technology for minimizing NOx 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. 

XONONTM, 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 the 

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 available 

technology suitable for controlling CTs of the size proposed at the Dominion 

Brunswick site. 
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iii. Step 3 – Ranking of available NOx controls

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

combined cycle power generating facility for controlling NOx are dry low NOx

combustion to minimize NOx formation and post-combustion treatment with SCR.

iv. Step 4 - BACT Determination: Selective Catalytic Reduction (SCR) and Dry Low-NOx

(DLN) Combustors 

Dominion has proposed a combination of the remaining identified control options for 

NOx: dry low-NOx combustion and selective catalytic reduction (SCR). The proposed 

Mitsubishi M501 GAC turbines use a two-stage premixed combustion design 

resulting in uncontrolled NOx emissions of 15 ppmvd at 15% O2 when firing natural 

gas, the fuel proposed for use by Dominion. The draft permit proposes use of SCR to 

control NOx emissions from the CTs to the following level (at 15% 02): 

• 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 2011, approximately 15 projects were permitted at 2.0 ppmvd at 15% 

O2, including two LAER determinations. Recent PSD permits at 2.0 ppmvd at 15% 

O2 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 was one project that was 

permitted at a NOx emission rate of 1.5 ppmvd at 15% O2 in the year 2000. However, 

this project has not been built and therefore, 1.5 ppmvd at 15% O2 has not been 

demonstrated as achievable in practice. With that one exception, the proposed limits 

are as stringent as any listed in EPA's RACT/BACT/LAER Clearinghouse (RBLC) for 

electric generating facilities. 

b. Auxiliary boiler and Fuel Gas Heaters

i. List of control technologies

• Front end NOx reduction technologies (low excess air, low NOx burners, ultra low 

NOx burners)

• SCR

ii. Technical feasibility and availability of NOx Control

• All technologies are feasible and available

iii. Ranking of technologies

• The best NOx reduction could be achieved using both front end and add-on NOx

reduction technologies

• Alternatively, ultra low NOx burners are the best front end technology for reducing 

NOx emissions

iv. BACT determination

• The use of SCR in conjunction with ultra low NOx 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 Dominion that ultra low NOx burners are BACT for both units

c. Emergency Generators/Fire water pump

Although add-on controls such as SCR are used to control NOx 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 NOx limit for the 80 kW propane emergency generator of 4.3 g/hp-hr 

based on manufacturer estimates. The facility proposes a limit of NOx+NMHC on the 
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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 NOx+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 NOx emissions, the primary factors influencing the generation of CO emissions are 

temperature and residence time within the combustion zone. Variations in fuel carbon content 

have relatively little effect on overall CO emissions. Generally the effect of the combustion 

zone temperature and residence time on CO emissions generation is the exact opposite of 

their effect on NOx emissions generation. Higher combustion zone temperatures and 

residence times lead to more complete combustion and lower CO emissions, but higher NOx

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 react with oxygen present in the exhaust stream, converting it to 

carbon dioxide. No supplementary reactant is used in conjunction with an oxidation 

catalyst. The oxidation of CO to CO2 utilizes the excess air present in the turbine 

exhaust; and the activation energy required for the reaction to proceed is lowered in 

the presence of the catalyst. Technical factors relating to this technology include the 

catalyst reactor design, optimum operating temperature, back pressure loss to the 

system, catalyst life, and potential collateral increases in emissions of PM10 and 

H2SO4 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 lateral 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 percent loss in power 

output and fuel efficiency or approximately 0.1 percent loss in power output for each 

1.0 inch of water pressure loss. 

Catalyst systems are subject to loss of activity over time. Since the catalyst itself is 

the most costly part of the installation, the cost of catalyst replacement should be 

considered on an annualized basis. Catalyst life may vary from the manufacturer's 
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typical 3-year guarantee to a 5- to 6-year predicted life. Periodic testing of catalyst 

material is necessary to predict annual catalyst life for a given installation. 

Oxidation catalysts have been employed successfully for two decades on natural gas 

combustion turbines. An oxidation catalyst is considered to be technically feasible for 

application to this project. 

Good combustion practices consisting primarily of controlled fuel/air mixing and 

adequate temperature and gas residence time are used to minimize the formation of 

CO. 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% O2): 

• 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 have been permitted at CO emission 

rates below 2 ppmvd at 15% O2. Typically, CO emission rates of 2 ppmvd at 15% O2

to 3.5 ppmvd at 15% O2 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% O2 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% O2 without duct burning, and 2.4 ppmvd at 15% O2 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/MMBtu 
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• 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 

infeasible

• 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 Generators 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 maintenance 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/hp-hr for the propane unit.

4. SO2 and sulfuric acid mist – primarily formed from the combustion of sulfur-containing fuels, 

with a small contribution of H2SO4 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 SO2

and H2SO4 emissions from a natural gas combustion turbine. Flue gas desulfurization is 

only feasible on plants that produce much larger quantities of SO2 and H2SO4 and would 

produce a significant pressure 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 SO2

• 0.00058 lb/MMBtu for H2SO4 without duct burning

• 0.00067 lb/MMBtu for H2SO4 with duct burning

b. Auxiliary boiler and fuel gas heaters

The only feasible control for SO2 and H2SO4 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 generator at 500 hrs/yr are considered BACT for SO2 and H2SO4

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. Combustion Turbines

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

exhaust gas stream after formation in the combustion turbine. In the presence of a 

catalyst, VOC will react with oxygen present in the exhaust stream, converting it to 

carbon dioxide and water vapor. The performance of an oxidation catalyst is affected 

by the VOCs that are actually emitted. No supplementary reactant is used in 

conjunction with an oxidation catalyst. An oxidation catalyst is considered to be 

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 effective 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 postcombustion treatment.

iv. BACT (Step 4)

VOC emission rates for recently permitted combined-cycle facilities are typically in 

the range of 1.0 ppmvd at 15% O2 to 2.0 ppmvd at 15% O2 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% O2 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% O2 without duct burning, and 1.6 ppmvd at 15%O2 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 35% control by an oxidation catalyst, as follows, all at 

15% O2 and as CH4 (calculated as a three-hour average): 

• 0.7 ppmvd without duct burner firing 

• 1.6 ppmvd with duct burner firing 

DEQ concurs that the use of good combustion control and an oxidation catalyst 

represent BACT for VOC control for the proposed combustion turbines. 

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)
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• Oxidation catalyst used in conjunction with good combustion practices would 

achieve the best control rate.

• Good combustion practices alone can result in emissions of VOC from the units 

of 0.005 lb/MMBtu 

iv. BACT determination (Step 4)

VOC emissions from the boiler and fuel gas heaters without oxidation catalyst would 

be 0.005 lb/MMBtu which results in a combined total of 2.0 tons/yr from both 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 and 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 (PM10 and PM2.5, 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 emissions, which contribute to PM10 and 

PM2.5 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 

readily 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 large, 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 PM10 and PM2.5 from combustion.

iii. Ranking of PM10 and PM2.5 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 of 
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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 PM10 and PM2.5 (Step 4)

The pipeline quality natural gas in this region contains 0.4 gr/100 dscf which impacts 

the PM10 and PM2.5 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 PM10 and PM2.5

emissions. For this reason, BACT from this facility will be slightly higher than BACT 

for PM10 and PM2.5 from the Warren County plant. The applicant proposes the use of 

good combustion practices for the combustion turbines at the following BACT rates

for PM10 and PM2.5:

PM10

• 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)

PM2.5

• 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 represents BACT for PM10

and PM2.5 control for the proposed combustion turbines. 

b. Auxiliary Boiler and Fuel Gas Heaters

Particulate matter emissions from the boiler and fuel gas heaters 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 PM10 and 

PM2.5 emissions from the auxiliary boiler and fuel gas heaters. DEQ agrees that this 

constitutes BACT for particulate emissions from the boiler and heaters. Short-term PM10

and PM2.5 emissions from the auxiliary boiler and the fuel gas heaters will be limited to 

0.007 lbs/MMBtu. Annual PM10 and PM2.5 emissions from the auxiliary boiler will be 

limited to 2.2 tons/yr while emissions from the fuel gas heaters 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 PM10 and PM2.5 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

PM10 PM2.5

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 Towers

Cooling towers produce drift, which is composed of fine water droplets that may contain 

dissolved solids and thus contribute to PM10 and PM2.5 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 Cooler
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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 0.01 percent of the circulating water flow (equivalent to 0.0008 TPY 

of PM10 and PM2.5.

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 0.0005 percent of the circulating water flow (equivalent to 0.029

TPY of PM10 and 9.46 x 10-5TPY of PM2.5.

Table 4 below summarizes BACT for the facility:

Pollutant Primary BACT Control Compliance

NOx

Turbine

2.0 ppmvd @ 15% O2 (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

SO2

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

H2SO4

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 

H2SO4

Fuel monitoring

Emergency generators (see SO2) (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 good 

combustion practices

Stack test

Emergency generators

3.5 g/kW-hr (diesel)

174.4 g/kW-hr (propane)

Good combustion practices Fuel monitoring

PM10 and 

PM2.5

Turbine

9.7 lbs/hr (0.0033 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 

good combustion practices

Stack 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 operation
Engineering Analysis

March 8, 2013

Page 25

Pollutant Primary BACT Control Compliance

CO2e

Turbine

7,500 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 

CO2 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 strategies 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 NOx, SO2, CO, VOC, PM10, and PM2.5 from the turbines and 

NOx and CO from the auxiliary boiler and fuel gas heaters to show compliance with the BACT 

limits. 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 7,500 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 standard 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 NOx (NSPS) and is also proposed for CO and CO2. Requirements 

for CEMS performance evaluations, quality assurance, and excess emissions reports will be 

included in the permit.

The permit requires that the CT stacks be equipped with CEMS meeting the requirements of 40 

CFR Part 75 (Acid Rain program) for NOx. In addition to providing a means to demonstrate 

compliance with the permit NOx limits, the CEMS will satisfy the NSPS Subpart KKKK 

requirement to monitor NOx 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 proper operation and 

performance. 

B. Recordkeeping – The following records will be kept 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 adding 
Engineering 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 annual throughput of natural gas to the three combustion turbines and 

associated duct burners (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, shutdown, 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 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;

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 monitoring 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 logs 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 evaluations, and performance evaluations.

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

C. Further Testing

a. Annual testing for SO2 can be done instead of fuel monitoring. 

b. After the initial test for heat rate of the power block, an additional test is required every five 

years.

VI. Public Participation

The applicant held a public information session on March 8, 2012 at the High School in Lawrenceville, 

Brunswick County 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. 

An information meeting 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.
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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 issued 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