commonwealth of virginia virginia department of

Commonwealth of Virginia

VIRGINIA DEPARTMENT OF ENVIRONMENTAL QUALITY VALLEY REGIONAL OFFICE

P.O. Box 3000, Harrisonburg, Virginia 22801

(540) 574-7800 FAX (540) 574-7878

Located at 4411 Early Road, Harrisonburg, Virginia

www.deq.virginia.gov Matthew J. Strickler David K. Paylor

Secretary of Natural Resources Director (804) 698-4000

Amy Thatcher Owens Regional Director

Ray Sommerfeld

Power Generation Station Director

Dominion Energy – Warren County Power Station

5000 Dominion Boulevard

Glen Allen, Virginia 23060

Location: Warren County

Registration No.: 81391

Dear Mr. Sommerfeld:

Attached is a permit to operate an electric generating facility pursuant to 9 VAC 5

Chapter 80, Article 3, of the Virginia Regulations for the Control and Abatement of Air

Pollution.

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

Notice of Violation and civil penalty. Please read all permit conditions carefully.

In evaluating the application and arriving at a final decision to issue this permit, the

Department deemed the application complete on July 30, 2015 and solicited written public

comments by placing a newspaper advertisement in the Northern Virginia Daily newspaper on

May 20, 2019. The thirty-day comment period (provided for in 9 VAC 5-80-670) expired on

June 19, 2019.

This permit approval shall not relieve Dominion Energy – Warren County Power Station

of the responsibility to comply with all other local, state and federal permit regulations.

Issuance of this permit is a case decision. The Regulations, at 9 VAC 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 permit is mailed or delivered to you. Please consult this and other

relevant provisions for additional requirements for such requests. Additionally, as provided by

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

http://www.deq.virginia.gov/

Mr. Ray Sommerfeld

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

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

David K. Paylor, Director

Department of Environmental Quality

P.O. Box 1105

Richmond, Virginia 23218

In the event that you receive this permit by mail, three days are added to the period in which to

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

http://www.courts.state.va.us/courts/scv/rules.html, for additional information including filing

dates and the required content of the Notice of Appeal.

If you have any questions concerning this permit, please contact the Jeremy Funkhouser

at [email protected] or (540) 574-7820.

Sincerely,

Janardan R. Pandey, P.E.

Air Permit Manager

Attachment: Permit

c: Marleen Gillespie, Dominion Energy Environmental Services (electronic file submission)

Director, OAPP (electronic file submission)

Manager, Data Analysis (electronic file submission)

Chief, Permits and Technical Assessment Branch (3AP11), U.S. EPA, Region III (electronic

file submission)

http://www.courts.state.va.us/courts/scv/rules.html

mailto:[email protected]

Commonwealth of Virginia

VIRGINIA DEPARTMENT OF ENVIRONMENTAL QUALITY

Federal Operating Permit

Article 3

This permit is based upon Federal Clean Air Act acid rain permitting requirements of Title IV,

federal operating permit requirements of Title V, and Chapter 80, Article 3, of the

Commonwealth of Virginia Regulations for the Control and Abatement of Air Pollution. Until

such time as this permit is reopened and revised, modified, revoked, terminated or expires, the

permittee is authorized to operate in accordance with the terms and conditions contained herein.

This permit is issued under the authority of Title 10.1, Chapter 13, §10.1-1322 of the Air

Pollution Control Law of Virginia. This permit is issued consistent with the Administrative

Process Act, and 9VAC5-80-360 through 9VAC5-80-700, of the State Air Pollution Control

Board Regulations for the Control and Abatement of Air Pollution of the Commonwealth of

Virginia.

Authorization to operate a Stationary Source of Air Pollution as described in this permit is

hereby granted to:

Permittee Name: Virginia Electric and Power Company

Facility Name: Dominion Energy – Warren County Power Station

Facility Location: 477 Kelley Drive

Front Royal (Warren County), Virginia 22630

Registration Number: 81391

This permit includes the following programs:

Federally Enforceable Requirements - Clean Air Act

Federally Enforceable Requirements - Title IV Acid Rain Program

Federally Enforceable Requirements – Cross State Air Pollution Control Rule (CSAPR)

Permit Number Effective Date Expiration Date

VRO 81391 December 1, 2019 November 30, 2024

______________________________

Deputy Regional Director

November 8, 2019_______________

Signature Date

Permit consists of 70 pages.

Permit Conditions 1 to 139.

Table of Contents consists of 1 page.


Permit Number: VRO81391

Page 2

Table of Contents

FACILITY INFORMATION .................................................................................................................... 3

EMISSION UNITS ..................................................................................................................................... 5

COMBINED CYCLE REQUIREMENTS (T-1, T-2, AND T-3) ............................................................ 9

FUEL BURNING EQUIPMENT REQUIREMENTS (B-1 AND GH-1) ............................................. 22

EMERGENCY DIESEL GENERATOR, EMERGENCY FIRE WATER PUMP, AND

EMERGENCY PROPANE GENERATOR (EG-1, EPG-1, AND FWP-1) ......................................... 26

GASOLINE DISPENSING FACILITY (GDF) REQUIREMENTS (ES-4) ........................................ 32

FACILITY-WIDE CONDITIONS .......................................................................................................... 34

INSIGNIFICANT EMISSION UNITS ................................................................................................... 36

PERMIT SHIELD & INAPPLICABLE REQUIREMENTS ............................................................... 37

GENERAL CONDITIONS ...................................................................................................................... 38

TITLE IV (PHASE II ACID RAIN PROGRAM) PERMIT ALLOWANCES AND

REQUIREMENTS .................................................................................................................................... 48

CROSS STATE AIR POLLUTION RULE (CSAPR) ........................................................................... 52

STATE-ONLY ENFORCEABLE REQUIREMENTS ......................................................................... 69

ATTACHMENT: SOURCE TEST REPORT FORMAT



Page 3

Facility Information

Permittee

Virginia Electric and Power Company

DBA: Dominion Energy – Warren County Power Station

5000 Dominion Boulevard

Glen Allen, Virginia 23060

Responsible Official

Ray Sommerfeld

Power Generation Station Director II

Acid Rain Designated Representative

Mr. Robert W. Sauer

Vice President Power Generation System Operations

Alternate Acid Rain Designated Representative

Ray Sommerfeld


Cross State Air Pollution Rule (CSAPR) Designated Representative

Mr. Robert W. Sauer

Vice President Power Generation System Operations

Alternate CSAPR Designated Representative

Ray Sommerfeld


Facility


477 Kelley Drive

Front Royal, Virginia 22630

Warren County

Contact Person

Ms. Marleen Gillespie

Environmental Consultant, Environmental Services

(803)-217-8627

Facility Description: NAICS Code: 221112 – Electric Power Generation

The Dominion Energy – Warren County Power Station is an electric power generation

facility. Electric power is generated using three combined-cycle power generating units (T-1,

T-2, and T-3), where each unit consists of one natural gas-fired combustion turbine (CT)

generator and one heat recovery steam generator (HRSG) with supplementary natural gas-

fired duct burners (DB).



Page 4

In addition to the three power generating units, the facility also operates the following

support equipment: one natural gas-fired auxiliary boiler; one natural gas-fired fuel gas

heater; one diesel-fired emergency generator; one propane-fired emergency generator; one

diesel-fired emergency fire water pump; one distillate oil storage tank; and several

insignificant emission units.

This source is located in Warren County, an attainment area for all air pollutants, and is a

Prevention of Significant Deterioration (PSD) source under 9 VAC 5-80 Article 8 of the

Virginia Regulations.

The facility is subject to the requirements of the Acid Rain permitting program and the

Cross-State Air Pollution Rule (CSAPR). The CSAPR requires certain states (including the

Commonwealth of Virginia) to significantly improve air quality by reducing power plant

emissions that contribute to ozone and/or fine particle pollution in other states. The

requirements of the CSAPR Program are incorporated into the federal operating permit.



Page 5

Emission Units

Equipment to be operated consists of:

Fuel Burning Equipment / Utility Units

Emission

Unit ID

Stack

ID

Emission Unit

Description Size/Rated Capacity1

Pollution Control

Device Description

(PCD)

PCD ID Pollutant

Controlled

Applicable

Permit Date

T-1 1

Combined-cycle

power generating

unit

one Mitsubishi natural gas-

fired combustion turbine

(CT) generator, Model M501

GAC, rated at 299,600 kW

and 2,996 million Btu per

hour heat input

Selective catalytic

reduction (SCR)

control system using

ammonia injection

SCR-1 NOx

12/17/2010,

as amended

10/24/2013,

6/17/2014,

and

12/20/2018

one heat recovery steam

generator (HRSG) with

supplementary natural gas-

fired duct burners (DB), each

duct burner with a design

rating of 500 million Btu per

hour heat input when firing

natural gas

Oxidation catalyst OXcat-1 CO, VOC



Page 6

Emission

Unit ID

Stack

ID

Emission Unit


Pollution Control

Device Description

(PCD)

PCD ID Pollutant

Controlled

Applicable

Permit Date

T-2 2

Combined-cycle

power generating

unit






hour heat input

SCR with ammonia

injection SCR-2 NOx

12/17/2010,

as amended

10/24/2013,

6/17/2014,

and

12/20/2018








natural gas


T-3 3

Combined-cycle

power generating

unit






hour heat input

SCR with ammonia

injection SCR-3 NOx

12/17/2010,

as amended

10/24/2013,

6/17/2014,

and

12/20/2018








natural gas




Page 7

Emission

Unit ID

Stack

ID

Emission Unit


Pollution Control

Device Description

(PCD)

PCD ID Pollutant

Controlled

Applicable

Permit Date

B-1 B-1 Auxiliary boiler

(Natural gas) 47.6 MMBtu/hr -- -- --

12/17/2010,

as amended

10/24/2013,

6/17/2014,

and

12/20/2018

GH-1 GH-1 Fuel gas heater

(Natural gas) 17.64 MMBtu/hr -- -- --

12/17/2010,

as amended

10/24/2013,

6/17/2014,

and

12/20/2018

EG-1 EG-1

Emergency generator

(Diesel)

October 2012

2,220 brake horsepower

(BHP) -- -- --

12/17/2010,

as amended

10/24/2013,

6/17/2014,

and

12/20/2018

FWP-1 FWP-1

Emergency fire water

pump

(Diesel)

March 2013

376 brake horsepower

(BHP) -- -- --

12/17/2010,

as amended

10/24/2013,

6/17/2014,

and

12/20/2018

EPG-1 EGP-1

Emergency generator

(Propane)

November 2011

60 kilowatts

(kW) -- -- --

12/17/2010,

as amended

10/24/2013,

6/17/2014,

and

12/20/2018



Page 8

Emission

Unit ID

Stack

ID

Emission Unit


Pollution Control

Device Description

(PCD)

PCD ID Pollutant

Controlled

Applicable

Permit Date

ST-1 ST-1 Distillate oil storage

tank 6,000 gallons -- -- --

12/17/2010,

as amended

10/24/2013,

6/17/2014,

and

12/20/2018

ES-4 -- Gasoline fuel cube 250 gallons -- -- -- --

1. Specifications included in this section are for informational purposes only and do not form enforceable terms or conditions of the

permit.

2. Rated capacity of the combustion turbines may vary based on ambient conditions.



Page 9

Combined Cycle Requirements (T-1, T-2, and T-3)

1. Limitations – Emission Controls: Nitrogen Oxides – Oxides of nitrogen (NOx) emissions

from each CT (CT-1, CT-2, & CT-3) and HRSG duct burner (DB1, DB2, & DB3) shall be

controlled by use of a two-stage, lean pre-mix dry low-NOx combustor, a selective catalytic

reduction (SCR) control system using ammonia injection, and good combustion practices.

The SCR system shall be provided with adequate access for inspection and shall be in

operation when the turbines are in normal operating mode (at all times except during

startup and shutdown, as defined in Condition 14).

(9 VAC 5-80-490 B & C and Condition 1 of the 12/17/2010 Permit, as amended

10/24/2013, 6/17/2014, and 12/20/2018)

2. Limitations – Emission Controls: Carbon Monoxide – Carbon monoxide (CO) emissions

from each CT (CT-1, CT-2, & CT-3) and HRSG duct burner (DB1, DB2, & DB3) 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

turbines are in normal operating mode (at all times except during startup and shutdown, as

defined in Condition 14).


10/24/2013, 6/17/2014, and 12/20/2018)

3. Limitations – Emission Controls: Volatile Organic Compounds – Volatile Organic

Compound (VOC) emissions from each CT (CT-1, CT-2, & CT-3) and HRSG duct burner

(DB1, DB2, & DB3) 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 turbines are in normal operating mode (at all times except

during startup and shutdown, as defined in Condition 14).


10/24/2013, 6/17/2014, and 12/20/2018)

4. Limitations – Emission Controls: Sulfuric Acid Mist – Sulfuric acid mist emissions from

each CT (CT-1, CT-2, & CT-3) and HRSG duct burner (DB1, DB2, & DB3) shall be

controlled through the use of pipeline natural gas meeting the specifications in Condition 6.


10/24/2013, 6/17/2014, and 12/20/2018)

5. Limitations – Emission Controls: Sulfur Dioxide – Sulfur dioxide emissions from each CT

(CT-1, CT-2, & CT-3) and each HRSG duct burner (DB1, DB2, & DB3) shall be

controlled through the use of pipeline natural gas meeting the specifications in Condition 6.


10/24/2013, 6/17/2014, and 12/20/2018)

6. Limitations – Fuel –The approved fuel for each CT (CT-1, CT-2, & CT-3) and each

HRSG duct burner (DB1, DB2, & DB3) is pipeline natural gas. The pipeline natural gas

shall not exceed a sulfur content of 0.00096 percent by weight (i.e., 0.32 grains per 100 dry



Page 10

standard cubic feet) on a 12-month rolling average basis, and a sulfur content of 0.0015

percent by weight (i.e., 0.50 grains per 100 dry standard cubic feet) at any time. A standard

cubic foot of gas is defined as a cubic foot of gas at standard conditions (68F and 29.92 in

Hg) as specified in 40 CFR 72.2. A change in the fuel may require a permit to modify and

operate.


10/24/2013, 6/17/2014, and 12/20/2018)

7. Limitations – Fuel Throughput – The combustion turbines (CT-1, CT-2, & CT-3) and duct

burners (DB1, DB2, & DB3) combined shall consume no more than 90,073 x 106 scf of

natural gas per year. Throughput shall be 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.


10/24/2013, 6/17/2014, and 12/20/2018)

8. Limitations – Short-Term Emission Limits - Emissions from the operation of each

combined-cycle power generating unit (T-1, T-2, & T-3) shall not exceed the limits

specified below:

Pollutant Short term emission limits

Sulfur dioxide 4.89 lb/hr

0.0014 lb/MMBtu

Where:

Short-term emission limits represent averages for a three-hour sampling period.

Limits apply at all times except during startup, shutdown, and malfunction. Periods

considered startup and shutdown are defined in Condition 14 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 5, 6, 15, and 23.

Short-term emissions of sulfur dioxide shall be calculated using the maximum sulfur

content specified in Condition 6, or sampling data collected in accordance with Condition

23.


10/24/2013, 6/17/2014, and 12/20/2018)


combined-cycle power generating unit (T-1, T-2, & T-3) shall not exceed the NSPS

Subpart KKKK limits specified below:



Page 11


Sulfur dioxide

Fuel which contains total potential sulfur emissions in excess of

0.060 lb SO2/MMBtu heat input shall not be burned per

60.4330(a)(2). Compliance is demonstrated with the fuel tariff.

The permittee is exempt from monitoring requirements since

compliance is demonstrated through the fuel tariff

(9 VAC 5-80-490 B & C and 40 CFR 60.4330(a)(2))


combined-cycle power generating unit (T-1, T-2, & T-3) shall not exceed the limits

specified below:


PM-10 (includes

condensable PM)

8.0 lb/hr without duct burner firing

14.0 lb/hr with duct burner firing

0.0027 lb/MMBtu without duct burner firing

0.0040 lb/MMBtu with duct burner firing

PM-2.5

8.0 lb/hr without duct burner firing

14.0 lb/hr with duct burner firing



Oxides of nitrogen

(as NO2)

25.3 lb/hr

2.0 ppmvd

Carbon monoxide 9.9 lb/hr and 1.5 ppmvd without duct burner firing

17.4 lb/hr and 2.4 ppmvd with duct burner firing

Volatile organic

compounds

2.6 lb/hr and 0.7 ppmvd without duct burner firing

6.1 lb/hr and 1.6 ppmvd with duct burner firing

Sulfuric acid mist

(H2SO4)



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 and carbon monoxide, which shall be calculated as a one-hour average.

Limits apply at all times except during startup, shutdown, and malfunction. Periods

considered startup and shutdown are defined in Condition 14 of this permit.


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 1, 2, 3, 4, 6, 15 and 24.



Page 12

Short-term emissions of sulfuric acid mist shall be calculated using the maximum sulfur

content specified in Condition 6, or sampling data collected in accordance with Condition

23.


10/24/2013, 6/17/2014, and 12/20/2018)


combined-cycle power generating unit (T-1, T-2, & T-3) shall not exceed the NSPS

Subpart KKKK limits specified below:

a. Nitrogen oxide (NOx):

(1) CT firing natural gas with or without duct burning: 15 ppm at 15 percent O2 or

0.43 lb/MWh on a 30-day rolling average (§60.4320).

(2) CT operating at less than 75 percent peak load and CT operating at temperatures

less than 0°F: 96 ppm at 15 percent O2 or 4.7 lb/MWh on a 30-day rolling average

(§60.4320).

(3) Excess NOx emissions shall be identified from CEMS data per §60.4350.

b. Excess emissions shall be reported for all periods of CT operation, including start-up,

shutdown, and malfunction per §60.4375(a).

(9 VAC 5-80-490 B & C and 40 CFR 60.4320)

12. Limitations – Annual Emission Limits – Total emissions from the operation of all three

combined-cycle power generating units (T-1, T-2, & T-3) including duct burners shall not

exceed 39.3 tons of sulfur dioxide (SO2) per year. Annual emission limits are derived from

the estimated overall emission contribution from operating limits, including periods of

startup and shutdown. Annual emissions shall be calculated monthly as the sum of each

consecutive 12-month period. 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 5, 6, 15, and 23. Annual emissions of sulfur dioxide

shall be calculated using the 12-month rolling average sulfur content, provided in

Condition 6, or sampling data collected in accordance with Condition 23.


10/24/2013, 6/17/2014, and 12/20/2018)

13. Limitations – Annual Emission Limits – Total emissions from the operation of all three

combined-cycle power generating units (T-1, T-2, & T-3) including duct burners shall not

exceed the limits specified below:

Pollutant Annual Emissions (tons)

PM-10

(includes condensable PM) 159.1



Page 13

PM-2.5 159.1

Oxides of Nitrogen

(as NO2) 317.7

Carbon Monoxide 348.6

Volatile Organic Compounds 181.0

Sulfuric Acid Mist (H2SO4) 30.5

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

operating limits, including periods of startup and shutdown. Annual emissions shall be

calculated monthly as the sum of each consecutive 12-month period. 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 1, 2, 3, 4, 6, 7, 15,

and 24. Annual emissions of sulfuric acid mist shall be calculated using the 12-month

rolling average sulfur content, provided in Condition 6, or sampling data collected in

accordance with Condition 23. Calculation methods shall be approved by the DEQ.


10/24/2013, 6/17/2014, and 12/20/2018)

14. Limitations – Startup/Shutdown – The short-term emission limits contained in Conditions

8 and 10 apply at all times except during periods of startup and shutdown.

a. Startup and shutdown periods are defined as follows:

(1) 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 4.2

hours per occurrence.

(2) 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 2.1 hours per occurrence.

(3) 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 1.5

hours per occurrence.

(4) Shutdown – refers to the period between the time the turbine load drops below 60

percent operating level and the fuel supply to the turbine is cut. Exclusion from

the short-term emissions limits for shutdown shall not exceed 0.5 hours per

occurrence.

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

during periods of startup and shutdown.



Page 14

c. If the SCR was not engaged during startup of a particular combustion turbine (including

ammonia injection), the failure of that startup shall not be considered a shutdown as

defined in Condition 14.a(4).

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

period.

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

startup and shutdown events.


10/24/2013, 6/17/2014, and 12/20/2018)

15. Limitations – Operating Hours: Duct Burners – Each duct burner (DB1, DB2, & DB3)

shall not operate more than 6,000 hours per year, calculated monthly as the sum of each





10/24/2013, 6/17/2014, and 12/20/2018)

16. Limitations – Duct Burner Operational Restriction – The duct burners (DB1, DB2, &

DB3) shall not operate between the hours of 10 p.m. and 5 a.m. Eastern Standard Time

(EST) during the period between September 1st and April 30th, except that the duct burners

may be operated during a Pennsylvania-New Jersey-Maryland Interconnection, LLC (PJM)

Independent System Operator’s (ISO) declared emergency. This duct burner operational

restriction is included to demonstrate that the project will not cause or contribute to an

exceedance of the applicable PM-2.5 PSD Class I increment.

(9 VAC 5-80-490 B & C, Virginia Code 10.1 1307.02., Virginia Code 10.1-1307.3 A.5,

and Condition 22 of the 12/17/2010 Permit, as amended 10/24/2013, 6/17/2014, and

12/20/2018)

17. Limitations – Pollution Prevention: Ammonia – Emissions of ammonia resulting from

unreacted ammonia emitted from the SCR (ammonia slip) shall not exceed 2 ppmvd during

steady-state conditions and 5 ppmvd during non-steady-state operations. Compliance with

the ammonia slip limit shall be determined based on a one-hour block average. Steady-

state operation is based on a steady load for the duration of the CEMS hour and is defined

as less than a 5% rate of load change within the hour. The permittee shall comply with the

approved plan for monitoring the ammonia slip and demonstrating compliance with the

ammonia slip limit from each SCR system. The permittee shall demonstrate compliance

with the ammonia slip limit at least 95% of the time the SCR is operating. Compliance

with the 95% time percentage requirement shall be calculated daily and based on a 30-day

rolling period. Alternatively, if on a given day less than 100 hours of operation has

occurred in the prior 30 days, compliance with the 95 percent limits may be based on the

most recent 100 hours of SCR operation.

(9 VAC 5-80-490 B & C, Virginia Pollution Prevention Act, § 10.1-1425.11, and



Page 15

Condition 23 of the 12/17/2010 Permit, as amended 10/24/2013, 6/17/2014, and

12/20/2018)

18. Limitations – Visible Emission Limit - Visible emissions from each combined-cycle (T-1,

T-2, & T-3) stack shall not exceed 10 percent opacity, except during one six-minute period

in any one hour in which visible emissions shall not exceed 20 percent opacity as

determined by 40 CFR 60, Appendix A, Method 9. This condition applies at all times

except during startup, shutdown (as defined in Condition 14), and malfunction.


10/24/2013, 6/17/2014, and 12/20/2018)

19. Monitoring – SCR – Each SCR system shall be equipped with devices to continuously

measure, or allow calculation of, 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 5-80-490 E and Condition 5 of the 12/17/2010 Permit, as amended 10/24/2013,

6/17/2014, and 12/20/2018)

20. Monitoring – Oxidation Catalyst – Each oxidation catalyst shall be equipped with a device

to continuously measure and record temperature at the catalyst bed inlet. 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. The permittee

shall establish a normal operating range for the temperature at the catalyst bed inlet, based

on manufacturer’s recommendations or developed from observations recorded from the

monitoring devices during normal operation. The permittee shall maintain written

documentation of this range.


6/17/2014, and 12/20/2018)

21. Monitoring – SCR – The devices used to continuously measure or allow calculation of

ammonia feed rate, gas stream flow rate, and SCR catalyst bed inlet gas temperature shall

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

SCR system but not less than once per day of operation. The permittee shall continuously

record measurements from the control equipment monitoring devices.

(9 VAC 5-80-490 E & F and Condition 7 of the 12/17/2010 Permit, as amended

10/24/2013, 6/17/2014, and 12/20/2018)

22. Monitoring – Oxidation Catalyst – The devices used to continuously measure catalyst bed

inlet temperature for each oxidation catalyst shall be observed by the permittee with a

frequency sufficient to ensure good performance of the oxidation catalyst but not less than

once per day of operation. If the temperature at the catalyst bed inlet observed is outside the



Page 16

normal operating range, the permittee shall take corrective action to restore the temperature

to within the normal operating range. The permittee shall continuously record

measurements from the control equipment monitoring devices, and any corrective measures

taken.


10/24/2013, 6/17/2014, and 12/20/2018)

23. Monitoring – Fuel Monitoring – The permittee shall use the fuel quality characteristics in

a current, valid purchase contract, tariff sheet or transportation contract for the fuel,

specifying that the total sulfur content for natural gas being fired at the electric power

generation facility meets the limitations in Condition 6, and demonstrate that potential

sulfur dioxide emissions shall not exceed the limits specified in Conditions 8 and 12.

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

permittee may:

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

day, or

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

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

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

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

c. You must monitor the total sulfur content of the fuel being fired in the turbine, except

as provided in §60.4365. The sulfur content of the fuel must be determined using total

sulfur methods described in §60.4415. Alternatively, if the total sulfur content of the

gaseous fuel during the most recent performance test was less than half the applicable

limit, ASTM D4084, D4810, D5504, or D6228, or Gas Processors Association

Standard 2377, may be used.

(9 VAC 5-80-490 E, 40 CFR 60.4365(a), 40 CFR 60.4370(b), 40 CFR 60.4370(c), 40 CFR

60.4360, and Condition 16 of the 12/17/2010 Permit, as amended 10/24/2013, 6/17/2014,

and 12/20/2018)

24. Monitoring – CEMS - Continuous Emission Monitoring Systems (CEMS) shall be

installed to measure and record the emissions of NOx (measured as NO2) and CO, in

ppmvd corrected to 15 percent O2, from each combined-cycle unit (T-1, T-2, & T-3).

CEMS for NOx shall meet the design specifications of 40 CFR 75 whereas CEMS for CO

shall be installed, evaluated, and operated according to the “Monitoring Requirements” in

40 CFR 60.13. The CEMS shall also 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

10, NOx data and CO data shall each be reduced to 1-hour block averages. The relative



Page 17

accuracy test audit (RATA) of the NOx CEMS shall be performed on a lb/MMBtu basis.

(9 VAC 5-80-490 E, 40 CFR 75, 40 CFR 60.13, 40 CFR 60.4340(b), and Condition 50 of

the 12/17/2010 Permit, as amended 10/24/2013, 6/17/2014, and 12/20/2018)

25. Monitoring – CEMS Quality Control Program – A CEMS quality control program which

is equivalent to the requirements of 40 CFR 60.13 and 40 CFR 60, Appendix F shall be

implemented for all continuous monitoring systems.

(9 VAC 5-80-490 E, 40 CFR 60.13, 40 CFR 60.4345(e), and Condition 52 of the

12/17/2010 Permit, as amended 10/24/2013, 6/17/2014, and 12/20/2018)

26. Monitoring – Excess Emissions and Monitor Downtime for NOx CEMS – For the purpose

of this permit, periods of excess emissions and monitor downtime that must be reported

under Condition 33 are defined as follows.

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

emission rate exceeds the applicable emission limit in Condition 10;

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 flow rate, steam temperature, steam pressure, or

megawatts. The steam flow rate, steam temperature, and steam pressure are only

required if the permittee uses this information for compliance purposes.

(9 VAC 5-80-490 E, 40 CFR 60.7(c), 40 CFR 60.4380, and Condition 53 of the 12/17/2010

Permit, as amended 10/24/2013, 6/17/2014, and 12/20/2018)

27. Monitoring – Excess Emissions and Monitor Downtime for SO2 – Excess emissions and

monitoring downtime are defined, for the purpose of this permit, as follows.

a. 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 and hour. 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 5-80-490 E, 40 CFR 60.7(c), and 40 CFR 60.4385, and Condition 54 of the


28. Monitoring – Excess Emissions for CEMS – For purposes of identifying excess emissions:

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



Page 18

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 5-80-490 E, 40 CFR 60.7(c), 40 CFR 60.4350, and Condition 56 of the 12/17/2010

Permit, as amended 10/24/2013, 6/17/2014, and 12/20/2018)

29. Recordkeeping – Onsite Records – The permittee shall maintain records of emissions data

and operating parameters as necessary to demonstrate compliance with this permit. The

content and format of such records shall be arranged with the DEQ. The records shall

include, but are not limited to:

a. Annual throughput of natural gas to each CT (CT-1, CT-2, & CT-3), calculated

monthly as the sum of each consecutive 12-month period.

b. Annual throughput of natural gas to each duct burner (DB1, DB2, & DB3) calculated

monthly as the sum of each consecutive 12-month period.

c. Annual hours of operation of each duct burner (DB1, DB2, & DB3) calculated monthly

as the sum of each consecutive 12-month period.

d. Time, date and duration of each startup, shutdown, and malfunction period for each

combined-cycle power generating unit (T-1, T-2, & T-3).

e. Annual number of startup and shutdown occurrences for each combined-cycle power

generating unit (T-1, T-2, & T-3), calculated monthly as the sum of each consecutive

12-month period.

f. Records to verify sulfur content of pipeline natural gas as required in Conditions 6 and

23.

g. Continuous records of heat input for each combined-cycle power generating unit (T-1,

T-2, & T-3).

h. Continuous records of power output from combined-cycle power generating units (T-1,

T-2, & T-3) and the steam turbine generator(s).

i. Emissions calculations sufficient to verify compliance with the annual emission

limitations in Condition 13, calculated monthly as the sum of each consecutive 12-

month period.



Page 19

j. Continuous monitoring system emissions data, calibrations and calibration checks,

percent operating time, and excess emissions.

k. Operation and control device monitoring records for each SCR system and each

oxidation catalyst.

l. Records for each combined-cycle unit (T-1, T-2, and T-3) showing steady-state vs. non-

steady-state operation during a given hour, the ammonia slip monitoring plan, and the

ammonia slip monitoring results as required by Condition 17.

m. Results of all stack tests, visible emission evaluations, visible emission inspection

results, and performance evaluations.

n. Records related to the CEMS quality control program as required by Condition 25.

These records shall be available on site for inspection by the DEQ and shall be current for

the most recent five years.

(9 VAC 5-80-490 F and Condition 57 of the 12/17/2010 Permit, as amended 10/24/2013,

6/17/2014, and 12/20/2018)

30. Testing – Annual Performance Test – Annual performance tests shall be conducted on each

combined-cycle unit (T-1, T-2, & T-3) for sulfur dioxide (SO2) to determine compliance

with the limits contained in Condition 8. 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) 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 person. 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



Page 20

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 DEQ. 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 DEQ within 45 days after

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

sampling is used to comply with the annual test for SO2, then no test protocol or test report

is required.

(9 VAC 5-80-490 E, 9 VAC 5-80-490 F, 40 CFR 60.4415(a), and Condition 66 of the


31. Testing (T-1, T-2, and T-3) - No less frequent than once each five-year period, and upon

request by the DEQ, the permittee shall perform additional performance tests for the

following pollutants using the appropriate EPA Reference Method:

Emission Unit Pollutant

T-1, T-2, or T-3

PM-10

PM-2.5

VOC

The stack testing on one unit (T-1, T-2, or T-3) will satisfy the testing requirements for the

other two units (T-1, T-2, or T-3) provided they are identical units. During the subsequent

five-year periods, the permittee shall conduct periodic monitoring on a different unit on a

rotating basis, ensuring each unit is tested prior to repeating testing on a unit.

Tests shall be conducted to determine compliance with the applicable emission limits

contained in Condition 10. The details of the tests are to be arranged with the DEQ. The

permittee shall submit a test protocol at least 30 days prior to testing. Samples taken as

required by this permit shall be analyzed in accordance with 1 VAC 30-45, Certification for

Noncommercial Environmental Laboratories, or 1 VAC 30-46, Accreditation for

Commercial Environmental Laboratories. One copy of the test results shall be submitted to

the DEQ within 60 days after test completion and shall conform to the test report format

enclosed with this permit.

(9 VAC 5-80-110)

32. Testing – Visible Emissions Evaluation – The permittee shall conduct visible emission

inspections on each combined-cycle generating unit (T-1, T-2, & T-3) stack in accordance

with the following procedures and frequencies:

a. At a minimum of once per operating week, the permittee shall determine the presence

of visible emissions. If during the inspection, visible emissions are observed, a visible

emission evaluation (VEE) shall be conducted in accordance with 40 CFR 60,

Appendix A, EPA Method 9. The VEE shall be conducted for a minimum of six

minutes. If any of the observations exceed the applicable standard, the VEE shall be

conducted for a total of 60 minutes.

b. If visible emissions inspections conducted during 12 consecutive operating weeks show

no visible emissions for a particular unit stack, the permittee may reduce the monitoring



Page 21

frequency to once per month for that unit stack. Anytime the monthly visible emissions

inspections show visible emissions, or when requested by DEQ, the monitoring

frequency shall be increased to once per week for that stack.

c. All visible emission inspections, observations and VEE results shall be recorded.


10/24/2013, 6/17/2014, and 12/20/2018)

33. Reporting – Reports for CEMS – The permittee shall furnish written reports of excess

emissions from any process monitored by a CEMS, to the DEQ on a quarterly basis,

postmarked no later than the 30th day following the end of 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, or 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;

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; and

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

60.4395.

(9 VAC 5-80-490 F, 40 CFR 60.7(c), 40 CFR 60.4375(a), 40 CFR 60.4395, and Condition

55 of the 12/17/2010 Permit, as amended 10/24/2013, 6/17/2014, and 12/20/2018)



Page 22

Fuel Burning Equipment Requirements (B-1 and GH-1)

34. Limitations – Emission Controls: Nitrogen Oxides – Oxides of nitrogen (NOx) emissions

from the auxiliary boiler (B-1) and the fuel gas heater (GH-1) shall be controlled by ultra-

low NOx burners.


10/24/2013, 6/17/2014, and 12/20/2018)

35. Limitations – Emission Controls: Carbon Monoxide and Volatile Organic Compounds -

CO and VOC emissions from the auxiliary boiler (B-1) and the fuel gas heater (GH-1) shall

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

design, construction and maintenance. 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 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 minimum.


10/24/2013, 6/17/2014, and 12/20/2018)

36. Limitations – Emission Controls: Sulfuric Acid Mist – Sulfuric acid mist emissions from

the auxiliary boiler (B-1) and the fuel gas heater (GH-1) shall be controlled through the use

of pipeline natural gas meeting the specifications in Condition 38.


10/24/2013, 6/17/2014, and 12/20/2018)

37. Limitations – Emission Controls: Sulfur Dioxide – Sulfur dioxide emissions from the

auxiliary boiler (B-1) and the fuel gas heater (GH-1) shall be controlled through the use of

pipeline natural gas meeting the specifications in Condition 38.


10/24/2013, 6/17/2014, and 12/20/2018)

38. Limitations – Fuel – The approved fuel for the auxiliary boiler (B-1) and the fuel gas

heater (GH-1) is pipeline natural gas. The pipeline natural gas shall not exceed a sulfur

content of 0.00096 percent by weight (i.e., 0.32 grains per 100 dry standard cubic feet) on a

12-month rolling average basis, and a sulfur content of 0.0015 percent by weight (i.e., 0.50

grains per 100 dry standard cubic feet), at any time. A standard cubic foot of gas is defined

as a cubic foot of gas at standard conditions (68°F and 29.92 in Hg) as specified in 40 CFR

72.2. A change in the fuel may require a permit to modify and operate.


10/24/2013, 6/17/2014, and 12/20/2018)

39. Limitations – Fuel Throughput – The auxiliary boiler (B-1) shall consume no more than

408.8 million cubic feet of natural gas per year, calculated monthly as the sum of each




Page 23




10/24/2013, 6/17/2014, and 12/20/2018)

40. Limitations – Fuel Throughput – The fuel gas heater (GH-1) shall consume no more than

151.5 million cubic feet of natural gas per year, calculated monthly as the sum of each





10/24/2013, 6/17/2014, and 12/20/2018)

41. Limitations – Emission Limits - Emissions from the operation of the auxiliary boiler (B-1)

shall not exceed the limits specified below:

Pollutant Short Term Limit Annual Limit

Nitrogen Oxides (as NO2) 0.011 lb/MMBtu 2.29 tons/yr

Carbon Monoxide 0.037 lb/MMBtu 7.71 tons/yr

PM-10/PM-2.5 0.24 lbs/hr 1.04 tons/yr

Volatile Organic Compounds 0.26 lbs/hr 1.13 tons/yr


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

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

determined as stated in Conditions 38 and 39.


10/24/2013, 6/17/2014, and 12/20/2018)

42. Limitations – Emission Limits - Emissions from the operation of the fuel gas heater (GH-

1) shall not exceed the limits specified below:


Nitrogen Oxides (as NO2) 0.011 lb/MMBtu 0.85 tons/yr

Carbon Monoxide 0.037 lb/MMBtu 2.86 tons/yr

PM-10/PM-2.5 0.13 lbs/hr 0.58 tons/yr




determined as stated in Conditions 38 and 40.



Page 24


10/24/2013, 6/17/2014, and 12/20/2018)

43. Limitations – Visible Emission Limit - Visible emissions from both the auxiliary boiler (B-

1) and the fuel gas heater (GH-1) stacks shall not exceed 10 percent opacity as determined

by reference 40 CFR 60, Appendix A, Method 9.


10/24/2013, 6/17/2014, and 12/20/2018)

44. Recordkeeping – On Site Records – The permittee shall maintain records of emissions

data and operating parameters as necessary to demonstrate compliance with this permit.

The content and format of such records shall be arranged with the DEQ. The records shall


a. Records to verify sulfur content of pipeline natural gas as required in Condition 38.

b. Monthly and annual throughput of natural gas to the auxiliary boiler (B-1) and the fuel

gas heater (GH-1) calculated monthly as the sum of each consecutive 12-month period.

c. Records of good combustion practices, scheduled and unscheduled maintenance, and

operator training as required by Condition 35.

d. Emissions calculations sufficient to verify compliance with the annual emission

limitations in Conditions 41 and 42, calculated monthly as the sum of each consecutive

12-month period. Calculation methods shall be approved by the DEQ:

e. Results of all stack tests, visible emission evaluations, visible emission inspection




(9 VAC 5-80-490 F, 40CFR 60.48c(g)(2), and Condition 57 of the 12/17/2010 Permit, as

amended 10/24/2013, 6/17/2014, and 12/20/2018)

45. Testing (B-1) - No less frequent than once each five-year period, and upon request by the

DEQ, the permittee shall perform additional performance tests for NOx from the auxiliary

boiler (B-1) using the appropriate EPA Reference Method. Tests shall be conducted to

determine compliance with the applicable emission limits contained in Condition 41. The

details of the tests are to be arranged with the DEQ. The permittee shall submit a test

protocol at least 30 days prior to testing. Samples taken as required by this permit shall be

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

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

Environmental Laboratories. One copy of the test results shall be submitted to the DEQ

within 60 days after test completion and shall conform to the test report format enclosed

with this permit.

(9 VAC 5-80-110)



Page 25

46. Testing – Visible Emissions Evaluation – Auxiliary Boiler and Fuel Gas Heater – The

permittee shall conduct visible emission inspections on the auxiliary boiler (B-1) and the

fuel gas heater (GH-1) stacks in accordance with the following procedures and frequencies:

a. At a minimum of once per operating month, the permittee shall determine the presence

of visible emissions. If during the inspection, visible emissions are observed, a visible

emission evaluation (VEE) shall be conducted in accordance with 40 CFR 60,

Appendix A, EPA Method 9. The VEE shall be conducted for a minimum of six

minutes. If any of the observations exceed 10 percent opacity, the VEE shall be

conducted for a total of 60 minutes.

b. All visible emissions inspections shall be performed when the boiler or fuel gas heater

(as applicable) is operating.

c. If visible emissions inspections conducted during 12 consecutive operating months

show no visible emissions, the permittee may reduce the monitoring frequency to once

per quarter. Anytime the quarterly visible emissions inspections show visible

emissions, or when requested by DEQ, the monitoring frequency shall be increased to

once per month.

d. All visible emission inspections, observations and VEE results shall be recorded.


10/24/2013, 6/17/2014, and 12/20/2018)



Page 26

Emergency Diesel Generator, Emergency Fire Water Pump, and Emergency

Propane Generator (EG-1, EPG-1, and FWP-1)

47. Limitations – Maintenance and Operation – The permittee must maintain and operate the

emergency generator (EG-1), the emergency fire water pump (FWP-1), and the emergency

propane generator (EPG-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. The permittee must keep records of conducted maintenance to

demonstrate compliance. In addition, the permittee may only change those settings that are

approved by the manufacturer.

(9 VAC 5-80-490 B & C, 40 CFR 60.4206, 40 CFR 60.4211, 40 CFR 60.4243, 40 CFR

60.4234, and Condition 10 of the 12/17/2010 Permit, as amended 10/24/2013, 6/17/2014,

and 12/20/2018)

48. Limitations – Fuel – The approved fuel for the emergency generator (EG-1) and the

emergency fire water pump (FWP-1) is distillate fuel oil with a maximum sulfur content

per shipment of 0.0015 percent by weight. A change in the fuel may require a permit to

modify and operate.

(9 VAC 5-80-490 B & C, 40 CFR 60.4207(b), and Condition 27 of the 12/17/2010 Permit,

as amended 10/24/2013, 6/17/2014, and 12/20/2018)

49. Limitations – Fuel – The approved fuel for the emergency propane generator (EPG-1) is

liquefied petroleum gas (LPG). A change in the fuel may require a permit to modify and

operate.


10/24/2013, 6/17/2014, and 12/20/2018)

50. Limitations – Operating Hours: Emergency 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. The

emergency fire water pump (FWP-1) shall not be operated for testing and/or maintenance

during startup of any of the combined-cycle units (T-1, T-2, or T-3), as defined by

Condition 14. The periodic testing of the emergency fire water pump shall be restricted to

the hours between 9:00 AM and 5:00 PM eastern standard time (EST).


10/24/2013, 6/17/2014, and 12/20/2018)

51. Limitations – Operating Hours: Emergency Generator - The emergency generator (EG-1)

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



to the individual monthly totals for the preceding 11 months. The emergency generator

(EG-1) shall not be operated for testing and/or maintenance during startup of any of the

combined-cycle units (T-1, T-2, or T-3), as defined by Condition 14. The periodic testing



Page 27

of the emergency generator shall be restricted to the hours between 9:00 AM and 5:00 PM

eastern standard time (EST).


10/24/2013, 6/17/2014, and 12/20/2018)

52. Limitations – Operating Hours: Emergency Propane Generator - The emergency propane

generator (EPG-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. The

emergency generator (EPG-1) shall not be operated for testing and/or maintenance during

startup of any of the combined-cycle units (T-1, T-2, or T-3), as defined by Condition 14.

The periodic testing of the emergency generator shall be restricted to the hours between

9:00 AM and 5:00 PM eastern standard time (EST).


10/24/2013, 6/17/2014, and 12/20/2018)

53. Limitations – Emergency Diesel Generator, Emergency Propane Generator, and

Emergency Fire Water Pump Operation - The operation of the emergency generator (EG-

1), the emergency fire water pump (FWP-1), and the emergency propane generator (EPG-

1) is limited to emergency situations. Emergency situations include emergency generator

use to produce power for critical networks or equipment (including power supplied to

portions of a facility) when electric power from the local utility (or the normal power

source, if the facility runs on its own power production) is interrupted and emergency

engine use to pump water in the case of fire or flood, etc. The emergency generator (EG-1),

the emergency fire water pump (FWP-1), and the emergency propane generator (EPG-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 these units is limited to 50 hours per year for each unit.

(9 VAC 5-80-490 B & C, 40 CFR 60.4211(f), 40 CFR 60.4219, 40 CFR 60.4243(d), and

Condition 33 of the 12/17/2010 Permit, as amended 10/24/2013, 6/17/2014, and

12/20/2018)

54. Limitations – Emission Limits - Emissions from the operation of the emergency fire water

pump (FWP-1) shall not exceed the limits specified below:


Nitrogen Oxides

(as NO2) 2.32 lbs/hr 0.58 tons/yr

Carbon Monoxide 0.58 lbs/hr 0.15 tons/yr





Page 28



determined as stated in Conditions 47, 50, and 64.


10/24/2013, 6/17/2014, and 12/20/2018)

55. Limitations – Emission Limits - Emissions from the operation of the emergency generator

(EG-1) shall not exceed the limits specified below:


Nitrogen Oxides

(as NO2) 23.49 lbs/hr 5.87 tons/yr








10/24/2013, 6/17/2014, and 12/20/2018)

56. Limitations – Emission Limits - Emissions from the operation of the emergency propane

generator (EPG-1) shall not exceed the limits specified below:








10/24/2013, 6/17/2014, and 12/20/2018)

57. Limitations – Emission Limits - Emissions from the operation of the emergency fire water

pump (FWP-1) shall not exceed the limits specified below:

Pollutant NSPS Standard

Particulate Matter (PM) 0.2 g/kW-hr

Non-Methane Hydrocarbons

(NMHC) + Nitrogen Oxides 4.0 g/kW-hr



Page 29


Carbon Monoxide 3.5 g/kW-hr

Compliance with these emission limits may be determined by keeping records of engine

manufacture data indicating compliance with these emission limits.

(9 VAC 5-80-490 B & C, 40 CFR 60.4205 (c), 40 CFR 60.4211(c), and Condition 37 of the


58. Limitations – Emission Limits - Emissions from the operation of the emergency generator

(EG-1) shall not exceed the limits specified below:


Particulate Matter (PM) 0.2 g/kW-hr



Carbon Monoxide 3.5 g/kW-hr


manufacture data indicating compliance with these emission limits

(9 VAC 5-80-490 B & C, 40 CFR 60.4205 (b), 40 CFR 60.4211(c), and Condition 38 of


59. Limitations – Emission Limits - Emissions from the operation of the emergency propane

generator (EPG-1) shall not exceed the limits specified below:




Carbon Monoxide 519 g/kW-hr


manufacture data indicating compliance with these emission limits.

(9 VAC 5-80-490 B & C, 40 CFR 60.4231 (c), 40 CFR 60.4233 (c), and Condition 39 of


60. Limitations – Visible Emission Limit - Visible emissions from the emergency generator

(EG-1), the emergency fire water pump (FWP-1), and the emergency propane generator

(EPG-1) shall not exceed 10 percent opacity as determined by 40 CFR 60, Appendix A,

Method 9. This condition applies at all times except during startup, shutdown, and

malfunction.



Page 30


10/24/2013, 6/17/2014, and 12/20/2018)

61. Limitations - The emergency generator (EG-1), the emergency fire water pump (FWP-1),

and the emergency propane generator (EPG-1) must meet the requirements of 40 CFR 63

Subpart ZZZZ by meeting the respective requirements of 40 CFR 60, Subpart IIII and 40

CFR 60 Subpart JJJJ.

(9 VAC 5-80-490 B & C, 40 CFR 63.6590 (c), 40 CFR 60 Subpart IIII, and 40 CFR 60

Subpart JJJJ)

62. Monitoring – Fuel Certification - The permittee shall obtain a certification from the fuel

supplier with each shipment of distillate oil. Each fuel supplier certification shall include

the following.

a. The name of the fuel supplier;

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

c. The volume of distillate oil delivered in the shipment; and

d. The sulfur content of the distillate 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 48, as applicable. Exceedance of these

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


6/17/2014, and 12/20/2018)

63. Monitoring – Monitoring Devices – The permittee shall install a non-resettable hour meter

on the emergency generator (EG-1) 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 5-80-490 E, 40 CFR 60.4209, and Condition 9 of the 12/17/2010 Permit, as

amended 10/24/2013, 6/17/2014, and 12/20/2018)

64. Recordkeeping – On Site Records - The permittee shall maintain records of emissions data


content and format of such records shall be arranged with the DEQ. The records shall


a. Emissions calculations sufficient to verify compliance with the annual emission

limitations in Conditions 54, 55, and 56, calculated monthly as the sum of each

consecutive 12-month period. Calculation methods shall be approved by the DEQ.



Page 31

b. Annual hours of operation for the emergency fire water pump (FWP-1), the emergency

generator (EG-1), and the emergency propane generator (EPG-1) for emergency

purposes, calculated monthly as the sum of each consecutive 12-month period.

c. Records of time, date, and duration of operation for the emergency fire water pump

(FWP-1), the emergency generator (EG-1), and the emergency propane generator

(EPG-1) for maintenance checks and readiness testing and the operational status of

each combined-cycle unit (T-1, T-2, and T-3) during those maintenance checks and

readiness testing.

d. Annual hours of operation for the emergency fire water pump (FWP-1), the emergency

generator (EG-1), and the emergency propane generator (EPG-1) for maintenance

checks and readiness testing, calculated monthly as the sum of each consecutive 12-

month period.

e. All fuel supplier certifications for the emergency units (FWP-1 & EG-1).

f. Records of engine manufacturer data as required by Conditions 57, 58, and 59.

g. Records of conducted maintenance as required by Condition 47.

h. Results of all stack tests, visible emission evaluations, visible emission inspection




(9 VAC 5-80-490 F and Condition 57 of the 12/17/2010 Permit, as amended 10/24/2013,

6/17/2014, and 12/20/2018)



Page 32

Gasoline Dispensing Facility (GDF) Requirements (ES-4)

65. Limitations – MACT CCCCCC – The facility must, at all times, operate and maintain

any affected source, including associated air pollution control equipment and monitoring

equipment, in a manner consistent with safety and good air pollution control practices for

minimizing emissions. Determination of whether such operation and maintenance

procedures are being used will be based on information available to DEQ which may

include, but is not limited to, monitoring results, review of operation and maintenance

procedures, review of operation and maintenance records, and inspection of the source.

(9 VAC 5-80-110, 40 CFR 63.11111, and 40 CFR 63.11115)

66. Limitations – MACT CCCCCC – In accordance with 40 CFR 63 Subpart CCCCCC for

gasoline dispensing facilities with monthly throughput less than 10,000 gallons of gasoline:

a. The permittee must not allow gasoline to be handled in a manner that would result in

vapor releases to the atmosphere for extended periods of time. Measures to be taken

include, but are not limited to, the following:

(1) Minimize gasoline spills;

(2) Clean up spills as expeditiously as practicable;

(3) Cover all open gasoline containers and all gasoline storage tank fill-pipes with a

gasketed seal when not in use; and

(4) Minimize gasoline sent to open waste collection systems that collect and transport

gasoline to reclamation and recycling devices, such as oil/water separators.

b. The permittee is not required to submit notifications or reports as specified in 40 CFR

63.11125, 40 CFR 63.11126, or 40 CFR 63 Subpart A, but you must have records

available within 24 hours of a request by DEQ to document your gasoline throughput.

c. Portable gasoline containers that meet the requirements of 40 CFR Part 59, subpart F,

are considered acceptable for compliance with (a)(3) of this condition.

If the throughput of the gasoline dispensing facility ever exceeds an applicable throughput

threshold in 40 CFR 63.11111, the gasoline dispensing facility will remain subject to the

requirements for sources above the threshold, even if the throughput later falls below the

applicable throughput threshold.

(9 VAC 5-80-110 and 40 CFR 63.11116)

67. Monitoring - MACT CCCCCC GDF Requirements - The permittee shall monitor the

monthly throughput of gasoline to the GDF. Monthly throughput is the total volume of

gasoline loaded into, or dispensed from, all the gasoline storage tanks located at a single

affected GDF. If an area source has two or more GDF at separate locations within the area

source, each GDF is treated as a separate affected source.

(9VAC5-80-490, 9VAC5-60-100 and 40 CFR 63.11111(h))



Page 33

68. Recordkeeping – MACT CCCCCC – The permittee must keep applicable records as

specified in 40 CFR 63.11116(b) and 40 CFR 63.11125(d). The records shall include:

a. Records of the occurrence and duration of each malfunction of operation (i.e., process

equipment) or the air pollution control and monitoring equipment.

b. Records of actions taken during periods of malfunction to minimize emissions in

accordance with 40 CFR 63.11115(a), including corrective actions to restore

malfunctioning process and air pollution control and monitoring equipment to its

normal or usual manner of operation.

c. Documentation of gasoline throughput.

The permittee shall maintain records of emission data and operating parameters as

necessary to demonstrate compliance with this permit. These records shall be available for

inspection by the DEQ and shall be current for the most recent five years.

(9 VAC 5-80-110, 40 CFR 63.11111(b), 40 CFR 63.11115, 40 CFR 63.11116(b), and 40

CFR 63.11125(d))



Page 34

Facility-Wide Conditions

69. Limitations – 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, monitoring

devices, and process equipment which affect such emissions:

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

scheduled maintenance.

b. Maintain an inventory of spare parts.

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

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

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

operators with the written operating procedures. The permittee shall maintain records

of the training provided including the names of trainees, the date of training and the

nature of the training.


6/17/2014, and 12/20/2018)

70. Recordkeeping – Records 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.

(9 VAC 5-80-490 and Condition 79 of the 12/17/2010 Permit, as amended 10/24/2013,

6/17/2014, and 12/20/2018)

71. Testing – Testing/Monitoring Ports - The permitted facility shall be constructed so as to

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

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

emission rates can be accurately determined by applicable test methods and providing stack

or duct that is free from cyclonic flow. Test ports shall be provided in accordance with the

applicable performance specification (reference 40 CFR Part 60, Appendix B).


6/17/2014, and 12/20/2018)

72. Testing – Stack Testing – Upon request by the DEQ, the permittee shall conduct additional

performance tests to demonstrate compliance with the emission limits contained in this

permit. The details of the tests shall be arranged with the DEQ.



Page 35


6/17/2014, and 12/20/2018)



Page 36

Insignificant Emission Units

73. Insignificant Emission Units – The insignificant emission units are presumed to be in

compliance with all requirements of the Clean Air Act as may apply. Based on this

presumption, no monitoring, recordkeeping or reporting shall be required for these

emission units in accordance with 9 VAC 5-80-490.

The following emission units at the facility are identified in the application as insignificant

emission units under 9 VAC 5-80-720:

Emission

Unit No.

Emission Unit

Description Citation

Pollutant(s) Emitted

(9 VAC 5-80-720 B)

Rated Capacity

(9 VAC 5-80-720 C)

IC-1

Turbine Inlet

Chiller Cooling

Tower

9 VAC 5-80-720 B PM 600,000 gal/hr

IC-2

Turbine Inlet

Chiller Cooling

Tower

9 VAC 5-80-720 B PM 600,000 gal/hr

IC-3

Turbine Inlet

Chiller Cooling

Tower

9 VAC 5-80-720 B PM 600,000 gal/hr

FC-1 Diesel Fuel Cube 9 VAC 5-80-720 B VOC 250 gal

FC-2 Diesel Fuel Cube 9 VAC 5-80-720 B VOC 250 gal

FC-3 Kerosene Fuel

Cube 9 VAC 5-80-720 B VOC 500 gal

ST-1 Distillate oil

storage tank 9 VAC 5-80-720 B VOC 6,000 gal

These emission units are presumed to be in compliance with all requirements of the federal

Clean Air Act as may apply. Based on this presumption, no monitoring, recordkeeping, or

reporting shall be required for these emission units in accordance with 9 VAC 5-80-490.

(9 VAC 5-80-720 and 9 VAC 5-80-490 C, E, and F)



Page 37

Permit Shield & Inapplicable Requirements

74. Permit Shield and Inapplicable Requirements - Compliance with the provisions of this

permit shall be deemed compliance with all applicable requirements in effect as of the

permit issuance date as identified in this permit. This permit shield covers only those

applicable requirements covered by terms and conditions in this permit and the following

requirements which have been specifically identified as being not applicable to this

permitted facility:

There are no inapplicable requirements identified in the permit application.

Nothing in this permit shield shall alter the provisions of §303 of the federal Clean Air Act,

including the authority of the administrator under that section, the liability of the owner for

any violation of applicable requirements prior to or at the time of permit issuance, or the

ability to obtain information by (i) the administrator pursuant to §114 of the federal Clean

Air Act, (ii) the Board pursuant to §10.1-1314 or §10.1-1315 of the Virginia Air Pollution

Control Law, or (iii) the Department pursuant to §10.1-1307.3 of the Virginia Air Pollution

Control Law.

(9 VAC 5-80-500)



Page 38

General Conditions

75. Federal Enforceability – All terms and conditions in this permit are enforceable by the

administrator and citizens under the federal Clean Air Act, except those that have been

designated as only state-enforceable.

(9 VAC 5-80-490 N)

76. Permit Expiration – This permit has a fixed term of five years. The expiration date shall

be the date five years from the date of issuance. Unless the owner submits a timely and

complete application for renewal to the Department consistent with the requirements of 9

VAC 5-80-430, the right of the facility to operate shall be terminated upon permit

expiration.

(9 VAC 5-80-430 B, C and F, 9 VAC 5-80-490 D and 9 VAC 5-80-530 B)

77. Permit Expiration – The permit can be set to expire for a period of less than five years if

required to bring the enforcement period into concurrence with other permitting programs.


78. Permit Expiration – The owner shall submit an application for renewal at least six months

but no earlier than eighteen months prior to the date of permit expiration.


79. Permit Expiration – If an applicant submits a timely and complete application for an

initial permit or renewal under this section, the failure of the source to have a permit or the

operation of the source without a permit shall not be a violation of Article 3, Part II of 9

VAC 5 Chapter 80, until the Board takes final action on the application under 9 VAC 5-80-

510.


80. Permit Expiration – No source shall operate after the time that it is required to submit a

timely and complete application under subsections C and D of 9 VAC 5-80-430 for a

renewal permit, except in compliance with a permit issued under Article 3, Part II of 9

VAC 5 Chapter 80.


81. Permit Expiration – If an applicant submits a timely and complete application under

section 9 VAC 5-80-430 for a permit renewal but the Board fails to issue or deny the

renewal permit before the end of the term of the previous permit, (i) the previous permit

shall not expire until the renewal permit has been issued or denied and (ii) all the terms and

conditions of the previous permit, including any permit shield granted pursuant to 9 VAC

5-80-500, shall remain in effect from the date the application is determined to be complete

until the renewal permit is issued or denied.


82. Permit Expiration – The protection under subsections F 1 and F 5 (ii) of section 9 VAC 5-

80-430 F shall cease to apply if, subsequent to the completeness determination made

pursuant to section 9 VAC 5-80-430 D, the applicant fails to submit by the deadline



Page 39

specified in writing by the Board any additional information identified as being needed to

process the application.


83. Recordkeeping and Reporting – All records of monitoring information maintained to

demonstrate compliance with the terms and conditions of this permit shall contain, where

applicable, the following:

a. The date, place as defined in the permit, and time of sampling or measurements.

b. The date(s) analyses were performed.

c. The company or entity that performed the analyses.

d. The analytical techniques or methods used.

e. The results of such analyses.

f. The operating conditions existing at the time of sampling or measurement.

(9 VAC 5-80-490 F)

84. Recordkeeping and Reporting – Records of all monitoring data and support information

shall be retained for at least five years from the date of the monitoring sample,

measurement, report, or application. Support information includes all calibration and

maintenance records and all original strip-chart recordings for continuous monitoring

instrumentation, and copies of all reports required by the permit.

(9 VAC 5-80-490 F)

85. Recordkeeping and Reporting – The permittee shall submit the results of monitoring

contained in any applicable requirement to DEQ no later than March 1 and September 1

of each calendar year. This report must be signed by a responsible official, consistent with

9 VAC 5-80-430 G, and shall include:

a. The time period included in the report. The time periods to be addressed are January 1

to June 30 and July 1 to December 31.

b. All deviations from permit requirements. For purposes of this permit, deviations


(1) Exceedance of emissions limitations or operational restrictions;

(2) Excursions from control device operating parameter requirements, as documented

by continuous emission monitoring, periodic monitoring, or compliance assurance

monitoring which indicates an exceedance of emission limitations or operational

restrictions; or,



Page 40

(3) Failure to meet monitoring, recordkeeping, or reporting requirements contained in

this permit.

c. If there were no deviations from permit conditions during the time period, the permittee

shall include a statement in the report that “no deviations from permit requirements

occurred during this semi-annual reporting period.”

(9 VAC 5-80-490 F)

86. Annual Compliance Certification – Exclusive of any reporting required to assure

compliance with the terms and conditions of this permit or as part of a schedule of

compliance contained in this permit, the permittee shall submit to EPA and DEQ no later

than March 1 each calendar year a certification of compliance with all terms and

conditions of this permit including emission limitation standards or work practices. The

compliance certification shall comply with such additional requirements that may be

specified pursuant to §114(a)(3) and §504(b) of the federal Clean Air Act. This

certification shall be signed by a responsible official, consistent with 9 VAC 5-80-430 G,

and shall include:

a. The time period included in the certification. The time period to be addressed is

January 1 to December 31.

b. The identification of each term or condition of the permit that is the basis of the

certification.

c. The compliance status.

d. Whether compliance was continuous or intermittent, and if not continuous,

documentation of each incident of non-compliance.

e. Consistent with subsection 9 VAC 5-80-490 E, the method or methods used for

determining the compliance status of the source at the time of certification and over the

reporting period.

f. Such other facts as the permit may require to determine the compliance status of the

source.

g. One copy of the annual compliance certification shall be sent to EPA at the following

address:

[email protected]

(9 VAC 5-80-490 K.5)

87. Permit Deviation Reporting – The permittee shall notify the DEQ as soon as practicable,

but no later than four daytime business hours after discovery, of any deviations from permit

requirements which may cause excess emissions for more than one hour, including those



Page 41

attributable to upset conditions as may be defined in this permit. In addition, within 14

days of the discovery, the permittee shall provide a written statement explaining the

problem, any corrective actions or preventative measures taken, and the estimated duration

of the permit deviation. Owners subject to the requirements of 9 VAC 5-40-50 C and 9

VAC 5-50-50 C are not required to provide the written statement prescribed in this

paragraph for facilities subject to the monitoring requirements of 9 VAC 5-40-40 and 9

VAC 5-50-40. The occurrence should also be reported in the next semi-annual compliance

monitoring report pursuant to Condition 85 of this permit.

(9 VAC 5-80-490 F.2)

88. Failure/Malfunction Reporting – In the event that any affected facility or related air

pollution control equipment fails or malfunctions in such a manner that may cause excess

emissions for more than one hour, the owner shall, as soon as practicable but no later than

four daytime business hours after the malfunction is discovered, notify the DEQ, by

facsimile transmission, telephone or telegraph of such failure or malfunction and shall

within 14 days of discovery provide a written statement giving all pertinent facts, including

the estimated duration of the breakdown. Owners subject to the requirements of 9 VAC 5-

40-50 C and 9 VAC 5-50-50 C are not required to provide the written statement prescribed

in this paragraph for facilities subject to the monitoring requirements of 9 VAC 5-40-40

and 9 VAC 5-50-40. When the condition causing the failure or malfunction has been

corrected and the equipment is again in operation, the owner shall notify the DEQ.

(9 VAC 5-20-180 C)

89. Failure/Malfunction Reporting – The emission units that have continuous monitors

subject to 9 VAC 5-40-50 C and 9 VAC 5-50-50 C are not subject to the two week written

notification.

(9 VAC 5-20-180 C, 9 VAC 5-40-50, and 9 VAC 5-50-50)

90. Failure/Malfunction Reporting – The emission units subject to the reporting and the

procedure requirements of 9 VAC 5-40-50 C and the procedures of 9 VAC 5-50-50 C are:

a. T-1

b. T-2

c. T-3

(9 VAC 5-20-180 C, 9 VAC 5-40-50, and 9 VAC 5-50-50)

91. Failure/Malfunction Reporting –Each owner required to install a continuous monitoring

system subject to 9 VAC 5-40-41 or 9 VAC 5-50-410 shall submit a written report of excess

emissions (as defined in the applicable emission standard) to the board for every calendar

quarter. All quarterly reports shall be postmarked by the thirtieth day following the end of

each calendar quarter and shall include the following information:



Page 42

a. The magnitude of excess emissions computed in accordance with 40 CFR 60.13(h) or 9

VAC 5-40-41 B 6, any conversion factors used, 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 source. The nature and cause of any 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 the report.

(9 VAC 5-20-180 C, 9 VAC 5-40-50, and 9 VAC 5-50-50)

92. Failure/Malfunction Reporting – All emission units not subject to 9 VAC 5-40-50 C and

9 VAC 5-50-50 C must make written reports within 14 days of the malfunction occurrence.

(9 VAC 5-20-180 C, 9 VAC 5-40-50, and 9 VAC 5-50-50)

93. Severability – The terms of this permit are severable. If any condition, requirement or

portion of the permit is held invalid or inapplicable under any circumstance, such invalidity

or inapplicability shall not affect or impair the remaining conditions, requirements, or

portions of the permit.

(9 VAC 5-80-490 G.1)

94. Duty to Comply – The permittee shall comply with all terms and conditions of this permit.

Any permit noncompliance constitutes a violation of the federal Clean Air Act or the

Virginia Air Pollution Control Law or both and is grounds for enforcement action; for

permit termination, revocation and reissuance, or modification; or, for denial of a permit

renewal application.

(9 VAC 5-80-490 G.2)

95. Need to Halt or Reduce Activity not a Defense – It shall not be a defense for a permittee

in an enforcement action that it would have been necessary to halt or reduce the permitted

activity in order to maintain compliance with the conditions of this permit.

(9 VAC 5-80-490 G.3)

96. Permit Modification – A physical change in, or change in the method of operation of, this

stationary source may be subject to permitting under State Regulations 9 VAC 5-80-360, 9

VAC 5-80-1100, 9 VAC 5-80-1790, or 9 VAC 5-80-2000 and may require a permit

modification and/or revisions except as may be authorized in any approved alternative

operating scenarios.

(9 VAC 5-80-490 G, 9 VAC 5-80-490 L, 9 VAC 5-80-550, and 9 VAC 5-80-660)



Page 43

97. Property Rights – The permit does not convey any property rights of any sort, or any

exclusive privilege.

(9 VAC 5-80-490 G.5)

98. Duty to Submit Information – The permittee shall furnish to the Board, within a

reasonable time, any information that the Board may request in writing to determine

whether cause exists for modifying, revoking and reissuing, or terminating the permit or to

determine compliance with the permit. Upon request, the permittee shall also furnish to the

Board copies of records required to be kept by the permit and, for information claimed to

be confidential, the permittee shall furnish such records to the Board along with a claim of

confidentiality.

(9 VAC 5-80-490 G.6)

99. Duty to Submit Information – Any document (including reports) required in a permit

condition to be submitted to the Board shall contain a certification by a responsible official

that meets the requirements of 9 VAC 5-80-430 G.9.

(9 VAC 5-80-490 K.1)

100. Duty to Pay Permit Fees – The owner of any source for which a permit under 9 VAC 5-

80-360 through 9 VAC 5-80-700 was issued shall pay permit fees consistent with the

requirements of 9 VAC 5-80-310 through 9 VAC 5-80-350. The actual emissions covered

by the permit program fees for the preceding year shall be calculated by the owner and

submitted to the Department by April 15 of each year. The calculations and final amount

of emissions are subject to verification and final determination by the DEQ.

(9 VAC 5-80-490 H)

101. Fugitive Dust Emission Standards – During the operation of a stationary source or any

other building, structure, facility, or installation, no owner or other person shall cause or

permit any materials or property to be handled, transported, stored, used, constructed,

altered, repaired, or demolished without taking reasonable precautions to prevent

particulate matter from becoming airborne. Such reasonable precautions may include, but

are not limited to, the following:

a. Use, where possible, of water or chemicals for control of dust in the demolition of

existing buildings or structures, construction operations, the grading of roads, or the

clearing of land;

b. Application of asphalt, oil, water, or suitable chemicals on dirt roads, materials

stockpiles, and other surfaces which may create airborne dust; the paving of roadways

and the maintaining of them in a clean condition;

c. Installation and use of hoods, fans, and fabric filters to enclose and vent the handling of

dusty material. Adequate containment methods shall be employed during sandblasting

or other similar operations;



Page 44

d. Open equipment for conveying or transporting material likely to create objectionable

air pollution when airborne shall be covered or treated in an equally effective manner at

all times when in motion; and,

e. The prompt removal of spilled or tracked dirt or other materials from paved streets and

of dried sediments resulting from soil erosion.

(9 VAC 5-40-20 E, 9 VAC 5-50-90, and 9 VAC 5-50-50)

102. Startup, Shutdown, and Malfunction – At all times, including periods of startup,

shutdown, soot blowing, and malfunction, owners shall, to the extent practicable, maintain

and operate any affected facility including associated air pollution control equipment in a

manner consistent with air pollution control practices for minimizing emissions.

Determination of whether acceptable operating and maintenance procedures are being used

will be based on information available to the Board, which may include, but is not limited

to, monitoring results, opacity observations, review of operating and maintenance

procedures, and inspection of the source.

(9 VAC 5-40-20 E, and 9 VAC 5-50-20 E)

103. Alternative Operating Scenarios – Contemporaneously with making a change between

reasonably anticipated operating scenarios identified in this permit, the permittee shall

record in a log at the permitted facility a record of the scenario under which it is operating.

The permit shield described in 9 VAC 5-80-500 shall extend to all terms and conditions

under each such operating scenario. The terms and conditions of each such alternative

scenario shall meet all applicable requirements including the requirements of 9 VAC 5

Chapter 80, Article 3.

(9 VAC 5-80-490 J)

104. Inspection and Entry Requirements – The permittee shall allow DEQ, upon presentation

of credentials and other documents as may be required by law, to perform the following:

a. Enter upon the premises where the source is located or emissions-related activity is

conducted, or where records must be kept under the terms and conditions of the permit.

b. Have access to and copy, at reasonable times, any records that must be kept under the

terms and conditions of the permit.

c. Inspect at reasonable times any facilities, equipment (including monitoring and air

pollution control equipment), practices, or operations regulated or required under the

permit.

d. Sample or monitor at reasonable times substances or parameters for the purpose of

assuring compliance with the permit or applicable requirements.

(9 VAC 5-80-490 K.2)

105. Reopening For Cause – The permit shall be reopened by the Board if additional federal



Page 45

requirements become applicable to a major source with a remaining permit term of three

years or more. Such reopening shall be completed no later than 18 months after

promulgation of the applicable requirement. No such reopening is required if the effective

date of the requirement is later than the date on which the permit is due to expire, unless the

original permit or any of its terms and conditions has been extended pursuant to 9 VAC 5-

80-430 F.

a. The permit shall be reopened if the Board or the administrator determines that the

permit contains a material mistake or that inaccurate statements were made in

establishing the emissions standards or other terms or conditions of the permit.

b. The permit shall be reopened if the administrator or the Board determines that the

permit must be revised or revoked to assure compliance with the applicable

requirements.

c. The permit shall not be reopened by the Board if additional applicable state

requirements become applicable to a major source prior to the expiration date

established under 9 VAC 5-80-490 D.

(9 VAC 5-80-490 L)

106. Permit Availability – Within five days after receipt of the issued permit, the permittee

shall maintain the permit on the premises for which the permit has been issued and shall

make the permit immediately available to DEQ upon request.

(9 VAC 5-80-510 G)

107. Transfer of Permits – No person shall transfer a permit from one location to another, or

from one piece of equipment to another.

(9 VAC 5-80-520)

108. Transfer of Permits – In the case of a transfer of ownership of a stationary source, the

new owner shall comply with any current permit issued to the previous owner. The new

owner shall notify the Board of the change in ownership within 30 days of the transfer and

shall comply with the requirements of 9 VAC 5-80-560.

(9 VAC 5-80-520)

109. Transfer of Permits – In the case of a name change of a stationary source, the owner shall

comply with any current permit issued under the previous source name. The owner shall

notify the Board of the change in source name within 30 days of the name change and shall

comply with the requirements of 9 VAC 5-80-560.

(9 VAC 5-80-520)

110. Permit Revocation or Termination for Cause – A permit may be revoked or terminated

prior to its expiration date if the owner knowingly makes material misstatements in the

permit application or any amendments thereto or if the permittee violates, fails, neglects or

refuses to comply with the terms or conditions of the permit, any applicable requirements,

or the applicable provisions of 9 VAC 5 Chapter 80 Article 3. The Board may suspend,



Page 46

under such conditions and for such period of time as the Board may prescribe, any permit

for any of the grounds for revocation or termination or for any other violations of these

regulations.

(9 VAC 5-80-490 G & L, 9 VAC 5-80-640 and 9 VAC 5-80-660)

111. Duty to Supplement or Correct Application – Any applicant who fails to submit any

relevant facts or who has submitted incorrect information in a permit application shall,

upon becoming aware of such failure or incorrect submittal, promptly submit such

supplementary facts or corrections. An applicant shall also provide additional information

as necessary to address any requirements that become applicable to the source after the date

a complete application was filed but prior to release of a draft permit.

(9 VAC 5-80-430 E)

112. Stratospheric Ozone Protection – If the permittee handles or emits one or more Class I or

II substances subject to a standard promulgated under or established by Title VI

(Stratospheric Ozone Protection) of the federal Clean Air Act, the permittee shall comply

with all applicable sections of 40 CFR Part 82, Subparts A to F.

(40 CFR Part 82, Subparts A-F)

113. Asbestos Requirements – The permittee shall comply with the requirements of National

Emissions Standards for Hazardous Air Pollutants (40 CFR 61) Subpart M, National

Emission Standards for Asbestos as it applies to the following: Standards for Demolition

and Renovation (40 CFR 61.145), Standards for Insulating Materials (40 CFR 61.148), and

Standards for Waste Disposal (40 CFR 61.150).

(9 VAC 5-60-70 and 9 VAC 5-80-490 A)

114. Accidental Release Prevention – If the permittee has more, or will have more than a

threshold quantity of a regulated substance in a process, as determined by 40 CFR 68.115,

the permittee shall comply with the requirements of 40 CFR Part 68.

(40 CFR Part 68)

115. Changes to Permits for Emissions Trading – No permit revision shall be required under

any federally approved economic incentives, marketable permits, emissions trading and

other similar programs or processes for changes that are provided for in this permit.

(9 VAC 5-80-490 I)

116. Emissions Trading – Where the trading of emissions increases and decreases within the

permitted facility is to occur within the context of this permit and to the extent that the

regulations provide for trading such increases and decreases without a case-by-case

approval of each emissions trade:

a. All terms and conditions required under 9 VAC 5-80-490, except subsection N, shall be

included to determine compliance.

b. The permit shield described in 9 VAC 5-80-500 shall extend to all terms and conditions

that allow such increases and decreases in emissions.



Page 47

c. The owner shall meet all applicable requirements including the requirements of 9 VAC

5-80-360 through 9 VAC 5-80-700.

(9 VAC 5-80-490 I)



Page 48

Title IV (Phase II Acid Rain Program) Permit Allowances and Requirements

117. Phase II Acid Rain Program - Statutory and Regulatory Authorities - In accordance

with the Air Pollution Control Law of Virginia §10.1-1308 and §10.1-1322, the

Environmental Protection Agency (EPA) Final Full Approval of the Operating Permits

Program (Titles IV and V) published in the Federal Register December 4, 2001, Volume

66, Number 233, Rules and Regulations, Pages 62961-62967 and effective November 30,

2001, and Title 40, the Code of Federal Regulations §§72.1 through 76.16, the

Commonwealth of Virginia Department of Environmental Quality (DEQ) issues this permit

pursuant to 9VAC5 Chapter 80, Article 3 of the Virginia Regulations for the Control and

Abatement of Air Pollution (Federal Operating Permit Article 3).

(9 VAC 5-80-490)

118. Phase II Acid Rain Program - Permit Requirements

a. The designated representative of each affected source and each affected unit at the

source shall:

(1) Submit a complete Acid Rain Permit application and acid rain compliance plan

under 40 CFR Part 72 in accordance with the deadlines specified in 40 CFR

72.30; and

(2) Submit in a timely manner any supplemental information that the permitting

authority determines is necessary in order to review an Acid Rain permit

application and issue or deny an Acid Rain permit.

b. The owners and operators of each affected source and each affected unit at the source

shall:

(1) Operate the unit in compliance with a complete Acid Rain permit application or a

superseding Acid Rain permit issued by the permitting authority; and

(2) Have an Acid Rain Permit.

(9 VAC 5-80-420, 9 VAC 5-80-430, 9 VAC 5-80-490 and 40 CFR Part 72.9(a))

119. Phase II Acid Rain Program - Monitoring Requirements

a. The owners and operators and, to the extent applicable, designated representative of

each affected source and each affected unit at the source shall comply with the

monitoring requirements as provided in 40 CFR Part 75.

b. The emissions measurements recorded and reported in accordance with 40 CFR Part 75

shall be used to determine compliance by the source or unit, as appropriate, with the

Acid Rain emissions limitations and emissions reduction requirements for sulfur

dioxide and nitrogen oxides under the Acid Rain Program.



Page 49

c. The requirements of 40 CFR Part 75 shall not affect the responsibility of the owners

and operators to monitor emissions of other pollutants or other emissions characteristics

at the unit under other applicable requirements of the federal Clean Air Act and other

provisions of the operating permit for the source.

(9 VAC 5-80-490 and 40 CFR 72.9(b))

120. Phase II Acid Rain Program - Sulfur Dioxide Requirements - Total Annual Phase II

SO2 Allocations - Because emission units T-1, T-2, T-3 were not eligible for SO2

allowance allocations by the U.S. EPA under Section 405 of the Clean Air Act and the

Acid Rain Program, no allocations were assigned in 40 CFR Part 73, Table 2.

(9 VAC 5-80-420, 9 VAC 5-80-490 and 40 CFR Parts 72 and 73)

121. Phase II Acid Rain Program - Nitrogen Oxides Requirements - The owners and

operators of Emission Units T-1, T-2, and T-3 shall comply with the applicable Acid Rain

emissions limitation for NOX.

a. NOX Requirements: None. The Emission Units (T-1, T-2, and T-3) do not burn coal so

there are no NOX emission limits.

(9VAC5-80-490 and 40 CFR 72.9(d))

122. Phase II Acid Rain Program - Excess Emissions Requirements

a. The designated representative of an affected source that has excess emissions in any

calendar year shall submit a proposed offset plan, as required under 40 CFR Part 77.

b. The owners and operators of an affected source that has excess emissions in any

calendar year shall:

(1) Pay without demand the penalty required, and pay upon demand the interest on

that penalty, as required by 40 CFR Part 77; and

(2) Comply with the terms of an approved offset plan, as required by 40 CFR Part 77.

(9 VAC 5-80-420, 9 VAC 5-80-490 and 40 CFR 72.9(e))

123. Phase II Acid Rain Program - Recordkeeping and Reporting Requirements

a. Unless otherwise provided, the owners and operators of the source and each affected

unit at the source shall keep on site at the source each of the following documents for a

period of 5 years from the date the document is created. This period may be extended

for cause, at any time prior to the end of 5 years, in writing by the Administrator or

permitting authority:

(1) The certificate of representation for the designated representative for the source

and each affected unit at the source and all documents that demonstrate the truth



Page 50

of the statements in the certificate of representation, in accordance with 40 CFR

72.24; provided that the certificate and documents shall be retained on site at the

source beyond such 5-year period until such documents are superseded because of

the submission of a new certificate of representation changing the designated

representative;

(2) All emissions monitoring information, in accordance with 40 CFR Part 75,

provided that to the extent that 40 CFR Part 75 provides for a 3-year period for

recordkeeping, the 3-year period shall apply;

(3) Copies of all reports, compliance certifications, and other submissions and all

records made or required under the Acid Rain Program; and,

(4) Copies of all documents used to complete an Acid Rain permit application and

any other submission under the Acid Rain Program or to demonstrate compliance

with the requirements of the Acid Rain Program.

b. The designated representative of an affected source and each affected unit at the source

shall submit the reports and compliance certifications required under the Acid Rain

Program, including those under 40 CFR Part 72 Subpart I and 40 CFR Part 75.

(9 VAC 5-80-420, 9 VAC 5-80-490 and 40 CFR 72.9(f))

124. Phase II Acid Rain Program - Liability

a. Any person who knowingly violates any requirement or prohibition of the Acid Rain

Program, a complete Acid Rain permit application, an Acid Rain permit, or an

exemption under 9VAC5-80-390 or 9VAC5-80-400 and 40 CFR 72.7 or 72.8,

including any requirement for the payment of any penalty owed to the United States,

shall be subject to enforcement pursuant to section 113(c) of the federal Clean Air Act

and by the board pursuant to §§ 10.1-1316 and 10.1-1320 of the Code of Virginia.

b. Any person who knowingly makes a false, material statement in any record,

submission, or report under the Acid Rain Program shall be subject to criminal

enforcement pursuant to section 113(c) of the federal Clean Air Act and 18 U.S.C. 1001

and by the board pursuant to §§ 10.1-1316 and 10.1-1320 of the Code of Virginia.

c. No permit revision shall excuse any violation of the requirements of the Acid Rain

Program that occurs prior to the date that the revision takes effect.

d. Each affected source and each affected unit shall meet the requirements of the Acid

Rain Program.

e. Any provision of the Acid Rain Program that applies to an affected source (including a

provision applicable to the designated representative of an affected source) shall also

apply to the owners and operators of such source and of the affected units at the source.



Page 51

f. Any provision of the Acid Rain Program that applies to an affected unit (including a

provision applicable to the designated representative of an affected unit) shall also

apply to the owners and operators of such unit.

g. Each violation of a provision of the Acid Rain Program regulations (40 CFR Parts 72,

73, 74, 75, 76, 77, and 78) by an affected source or affected unit, or by an owner or

operator or designated representative of such source or unit, shall be a separate

violation of the federal Clean Air Act.

(9 VAC 5-80-420, 9 VAC 5-80-490 and 40 CFR 72.9(g))

125. Phase II Acid Rain Program - Effect on Other Authorities - No provision of the Acid

Rain Program, an Acid Rain permit application, an Acid Rain permit, or an exemption

under 9VAC5-80-390 or 9VAC5-80-400 and 40 CFR 72.7 or 72.8 shall be construed as:

a. Except as expressly provided in Title IV of the federal Clean Air Act, exempting or

excluding the owners and operators and, to the extent applicable, the designated

representative of an affected source or affected unit from compliance with any other

provision of the federal Clean Air Act, including the provisions of title I of the federal

Clean Air Act relating to applicable National Ambient Air Quality Standards or State

Implementation Plans;

b. Limiting the number of allowances a source can hold; provided, that the number of

allowances held by the source shall not affect the source's obligation to comply with

any other provisions of the federal Clean Air Act;

c. Requiring a change of any kind in any State law regulating electric utility rates and

charges, affecting any State law regarding such State regulation, or limiting such State

regulation, including any prudence review requirements under such State law;

d. Modifying the Federal Power Act or affecting the authority of the Federal Energy

Regulatory Commission under the Federal Power Act; or,

e. Interfering with or impairing any program for competitive bidding for power supply in

a State in which such program is established.

(9 VAC 5-80-420, 9 VAC 5-80-490 and 40 CFR 72.9(h))



Page 52

Cross State Air Pollution Rule (CSAPR)

126. Cross State Air Pollution Rule (CSAPR) – The permittee shall comply with all

applicable CSAPR requirements (40 CFR Part 97, Subparts AAAAA – DDDDD) by the

compliance date specified in 40 CFR 97, Subparts AAAAA – DDDDD, as amended.

(40 CFR Part 97, Subparts AAAAA - DDDDD and 9 VAC 5-80-490)

127. CSAPR – The Transport Rule (TR) subject units, and the unit-specific monitoring

provisions, at this source are identified in the following table. These units are subject to the

applicable requirements for the TR NOX Annual Trading Program (40 CFR Part 97,

Subpart AAAAA), TR NOX Ozone Season Trading Program (40 CFR Part 97, Subpart

BBBBB), and TR SO2 Group 1 Trading Program (40 CFR Part 97, Subpart CCCCC).

Unit ID: T-1, T-2, and T-3

Parameter

Continuous

emission

monitoring system

or systems (CEMS)

requirements

pursuant to 40 CFR

Part 75, subpart B

(for SO2

monitoring) and 40

CFR Part 75,

subpart H (for NOX

monitoring)

Excepted

monitoring

system

requirements

for gas- and

oil-fired units

pursuant to 40

CFR Part 75,

appendix D

Excepted

monitoring

system

requirements

for gas- and

oil-fired

peaking units

pursuant to 40

CFR Part 75,

appendix E

Low Mass

Emissions

excepted

monitoring

(LME)

requirements

for gas- and

oil-fired units

pursuant to 40

CFR 75.19

EPA-approved

alternative

monitoring

system

requirements

pursuant to 40

CFR Part 75,

Subpart E

SO2 X

NOX X

Heat

input X

(40 CFR Part 97, Subpart AAAAA – CCCCC and 9 VAC 5-80-490)

128. CSAPR – The above description of the monitoring used by a unit does not change, create

an exemption from, or otherwise affect the monitoring, recordkeeping, and reporting

requirements applicable to the unit under 40 CFR 97.430 through 97.435 (TR NOX Annual

Trading Program), 97.530 through 97.535 (TR NOX Ozone Season Trading Program), and

97.630 through 97.635 (TR SO2 Group 1 Trading Program). The monitoring,

recordkeeping and reporting requirements applicable to each unit are included below in the

standard conditions for the applicable TR trading programs.

(9 VAC 5-80-490 and 40 CFR 97)

129. CSAPR – Owners and operators must submit to the Administrator a monitoring plan for



Page 53

each unit in accordance with 40 CFR 75.53, 75.62 and 75.73, as applicable. The monitoring

plan for each unit is available at the EPA’s website at

https://www.epa.gov/airmarkets/clean-air-markets-monitoring-plans-part-75-sources.

(9 VAC 5-80-490 and 40 CFR 97)

130. CSAPR –Owners and operators that want to use an alternative monitoring system must

submit to the Administrator a petition requesting approval of the alternative monitoring

system in accordance with 40 CFR part 75, subpart E and 40 CFR 75.66 and 97.435 (TR

NOX Annual Trading Program), 97.535 (TR NOX Ozone Season Trading Program), and/or

97.635 (TR SO2 Group 1 Trading Program). The Administrator’s response approving or

disapproving any petition for an alternative monitoring system is available on the EPA’s

website at https://www.epa.gov/airmarkets/part-75-petition-responses.

(9 VAC 5-80-490 and 40 CFR 97)

131. CSAPR – Owners and operators that want to use an alternative to any monitoring,

recordkeeping, or reporting requirement under 40 CFR 97.430 through 97.434 (TR NOX

Annual Trading Program), 97.530 through 97.534 (TR NOX Ozone Season Trading

Program), and/or 97.630 through 97.634 (TR SO2 Group 1 Trading Program) must submit

to the Administrator a petition requesting approval of the alternative in accordance with 40

CFR 75.66 and 97.435 (TR NOX Annual Trading Program), 97.535 (TR NOX Ozone

Season Trading Program), and/or 97.635 (TR SO2 Group 1 Trading Program). The

Administrator’s response approving or disapproving any petition for an alternative to a

monitoring, recordkeeping, or reporting requirement is available on EPA’s website at

https://www.epa.gov/airmarkets/part-75-petition-responses.

(9 VAC 5-80-490 and 40 CFR 97)

132. CSAPR – The descriptions of monitoring applicable to the unit included above meet the

requirement of 40 CFR 97.430 through 97.434 (TR NOX Annual Trading Program), 97.530

through 97.534 (TR NOX Ozone Season Trading Program), and 97.630 through 97.634 (TR

SO2 Group 1 Trading Program), and therefore minor permit modification procedures, in

accordance with 40 CFR 70.7(e)(2)(i)(B) or 71.7(e)(1)(i)(B), may be used to add or change

this unit’s monitoring system description.

(9 VAC 5-80-490 and 40 CFR 97)

CSAPR – TR NOX Annual Trading Program requirements (40 CFR 97.406, Subpart

AAAAA

133. CSAPR – TR NOX Annual Trading Program - The following conditions must be

adhered to for T-1, T-2, and T-3, which are subject to the CSAPR NOX Annual Trading

Program:

a. Designated representative requirements.

The owners and operators shall comply with the requirement to have a designated

representative, and may have an alternate designated representative, in accordance with

40 CFR 97.413 through 97.418.

https://www.epa.gov/airmarkets/clean-air-markets-monitoring-plans-part-75-sources

https://www.epa.gov/airmarkets/part-75-petition-responses

https://www.epa.gov/airmarkets/part-75-petition-responses



Page 54

b. Emissions monitoring, reporting, and recordkeeping requirements.

(1) The owners and operators, and the designated representative, of each TR NOX

Annual source and each TR NOX Annual unit at the source shall comply with the

monitoring, reporting, and recordkeeping requirements of 40 CFR 97.430 (general

requirements, including installation, certification, and data accounting,

compliance deadlines, reporting data, prohibitions, and long-term cold storage),

97.431 (initial monitoring system certification and recertification procedures),

97.432 (monitoring system out-of-control periods), 97.433 (notifications

concerning monitoring), 97.434 (recordkeeping and reporting, including

monitoring plans, certification applications, quarterly reports, and compliance

certification), and 97.435 (petitions for alternatives to monitoring, recordkeeping,

or reporting requirements).

(2) The emissions data determined in accordance with 40 CFR 97.430 through 97.435

shall be used to calculate allocations of TR NOX Annual allowances under 40

CFR 97.411(a)(2) and (b) and 97.412 and to determine compliance with the TR

NOX Annual emissions limitation and assurance provisions under paragraph (c)

below, provided that, for each monitoring location from which mass emissions are

reported, the mass emissions amount used in calculating such allocations and

determining such compliance shall be the mass emissions amount for the

monitoring location determined in accordance with 40 CFR 97.430 through

97.435 and rounded to the nearest ton, with any fraction of a ton less than 0.50

being deemed to be zero.

c. NOX emissions requirements.

(1) TR NOX Annual emissions limitation.

(a) As of the allowance transfer deadline for a control period in a given year,

the owners and operators of each TR NOX Annual source and each TR NOX

Annual unit at the source shall hold, in the source's compliance account, TR

NOX Annual allowances available for deduction for such control period

under 40 CFR 97.424(a) in an amount not less than the tons of total NOX

emissions for such control period from all TR NOX Annual units at the

source.

(b) If total NOX emissions during a control period in a given year from the TR

NOX Annual units at a TR NOX Annual source are in excess of the TR NOX

Annual emissions limitation set forth in paragraph (c)(1)(a) above, then:

(i) The owners and operators of the source and each TR NOX Annual unit

at the source shall hold the TR NOX Annual allowances required for

deduction under 40 CFR 97.424(d); and

(ii) The owners and operators of the source and each TR NOX Annual unit

at the source shall pay any fine, penalty, or assessment or comply with



Page 55

any other remedy imposed, for the same violations, under the Clean

Air Act, and each ton of such excess emissions and each day of such

control period shall constitute a separate violation of 40 CFR part 97,

subpart AAAAA and the Clean Air Act.

(2) TR NOX Annual assurance provisions.

(a) If total NOX emissions during a control period in a given year from all TR

NOX Annual units at TR NOX Annual sources in the state exceed the state

assurance level, then the owners and operators of such sources and units in

each group of one or more sources and units having a common designated

representative for such control period, where the common designated

representative’s share of such NOX emissions during such control period

exceeds the common designated representative’s assurance level for the

state and such control period, shall hold (in the assurance account

established for the owners and operators of such group) TR NOX Annual

allowances available for deduction for such control period under 40 CFR

97.425(a) in an amount equal to two times the product (rounded to the

nearest whole number), as determined by the Administrator in accordance

with 40 CFR 97.425(b), of multiplying— (A) The quotient of the amount by

which the common designated representative’s share of such NOX emissions

exceeds the common designated representative’s assurance level divided by

the sum of the amounts, determined for all common designated

representatives for such sources and units in the state for such control

period, by which each common designated representative’s share of such

NOX emissions exceeds the respective common designated representative’s

assurance level; and (B) The amount by which total NOX emissions from all

TR NOX Annual units at TR NOX Annual sources in the state for such

control period exceed the state assurance level.

(i) The owners and operators shall hold the TR NOX Annual allowances

required under paragraph (c)(2)(a) above, as of midnight of November

1 (if it is a business day), or midnight of the first business day

thereafter (if November 1 is not a business day), immediately after

such control period.

(ii) Total NOX emissions from all TR NOX Annual units at TR NOX

Annual sources in the State during a control period in a given year

exceed the state assurance level if such total NOX emissions exceed the

sum, for such control period, of the state NOX Annual trading budget

under 40 CFR 97.410(a) and the state’s variability limit under 40 CFR

97.410(b).

(iii) It shall not be a violation of 40 CFR part 97, subpart AAAAA or of the

Clean Air Act if total NOX emissions from all TR NOX Annual units at

TR NOX Annual sources in the during a control period exceed the state

assurance level or if a common designated representative’s share of



Page 56

total NOX emissions from the TR NOX Annual units at TR NOX

Annual sources in the state during a control period exceeds the

common designated representative’s assurance level.

(iv) To the extent the owners and operators fail to hold TR NOX Annual

allowances for a control period in a given year in accordance with

paragraphs (c)(2)(a)(i) through (iii) above,

a) The owners and operators shall pay any fine, penalty, or

assessment or comply with any other remedy imposed under the

Clean Air Act; and

b) Each TR NOX Annual allowance that the owners and operators fail

to hold for such control period in accordance with paragraphs

(c)(2)(a) through (c) above and each day of such control period

shall constitute a separate violation of 40 CFR part 97, subpart

AAAAA and the Clean Air Act.

(3) Compliance periods.

(a) A TR NOX Annual unit shall be subject to the requirements under paragraph

(c)(1) above for the control period starting on the later of January 1, 2015, or

the deadline for meeting the unit's monitor certification requirements under

40 CFR 97.430(b) and for each control period thereafter.

(b) A TR NOX Annual unit shall be subject to the requirements under paragraph

(c)(2) above for the control period starting on the later of January 1, 2017 or



(4) Vintage of allowances held for compliance.

(a) A TR NOX Annual allowance held for compliance with the requirements

under paragraph (c)(1)(a) above for a control period in a given year must be

a TR NOX Annual allowance that was allocated for such control period or a

control period in a prior year.

(b) A TR NOX Annual allowance held for compliance with the requirements

under paragraphs (c)(1)(b)(i) and (2)(a) through (c) above for a control

period in a given year must be a TR NOX Annual allowance that was

allocated for a control period in a prior year or the control period in the

given year or in the immediately following year.

(5) Allowance Management System requirements. Each TR NOX Annual allowance

shall be held in, deducted from, or transferred into, out of, or between Allowance

Management System accounts in accordance with 40 CFR part 97, subpart

AAAAA.



Page 57

(6) Limited authorization. A TR NOX Annual allowance is a limited authorization to

emit one ton of NOX during the control period in one year. Such authorization is

limited in its use and duration as follows:

(a) Such authorization shall only be used in accordance with the TR NOX

Annual Trading Program; and

(b) Notwithstanding any other provision of 40 CFR part 97, the Administrator

has the authority to terminate or limit the use and duration of such

authorization to the extent the Administrator determines is necessary or

appropriate to implement any provision of the Clean Air Act.

(7) Property right. A TR NOX Annual allowance does not constitute a property right.

d. Title V permit revision requirements.

(1) No title V permit revision shall be required for any allocation, holding, deduction,

or transfer of TR NOX Annual allowances in accordance with 40 CFR part 97,

subpart AAAAA.

(2) This permit incorporates the TR emissions monitoring, recordkeeping and

reporting requirements pursuant to 40 CFR 97.430 through 97.435, and the

requirements for a continuous emission monitoring system (pursuant to 40 CFR

part 75, subparts B and H), an excepted monitoring system (pursuant to 40 CFR

part 75, appendices D and E), a low mass emissions excepted monitoring

methodology (pursuant to 40 CFR 75.19), and an alternative monitoring system

(pursuant to 40 CFR part 75, subpart E). Therefore, the Description of TR

Monitoring Provisions table for units identified in this permit may be added to, or

changed, in this title V permit using minor permit modification procedures in

accordance with 40 CFR 97.406(d)(2) and 70.7(e)(2)(i)(B) or 71.7(e)(1)(i)(B).

e. Additional recordkeeping and reporting requirements.

(1) Unless otherwise provided, the owners and operators of each TR NOX Annual

source and each TR NOX Annual unit at the source shall keep on site at the source

each of the following documents (in hardcopy or electronic format) for a period of

5 years from the date the document is created. This period may be extended for

cause, at any time before the end of 5 years, in writing by the Administrator.

(a) The certificate of representation under 40 CFR 97.416 for the designated

representative for the source and each TR NOX Annual unit at the source

and all documents that demonstrate the truth of the statements in the

certificate of representation; provided that the certificate and documents

shall be retained on site at the source beyond such 5-year period until such

certificate of representation and documents are superseded because of the

submission of a new certificate of representation under 40 CFR 97.416

changing the designated representative.



Page 58

(b) All emissions monitoring information, in accordance with 40 CFR part 97,

subpart AAAAA.

(c) Copies of all reports, compliance certifications, and other submissions and

all records made or required under, or to demonstrate compliance with the

requirements of, the TR NOX Annual Trading Program.

(2) The designated representative of a TR NOX Annual source and each TR NOX

Annual unit at the source shall make all submissions required under the TR NOX

Annual Trading Program, except as provided in 40 CFR 97.418. This requirement

does not change, create an exemption from, or otherwise affect the responsible

official submission requirements under a title V operating permit program in 40

CFR parts 70 and 71.

f. Liability.

(1) Any provision of the TR NOX Annual Trading Program that applies to a TR NOX

Annual source or the designated representative of a TR NOX Annual source shall

also apply to the owners and operators of such source and of the TR NOX Annual

units at the source.

(2) Any provision of the TR NOX Annual Trading Program that applies to a TR NOX

Annual unit or the designated representative of a TR NOX Annual unit shall also


g. Effect on other authorities.

No provision of the TR NOX Annual Trading Program or exemption under 40 CFR

97.405 shall be construed as exempting or excluding the owners and operators, and the

designated representative, of a TR NOX Annual source or TR NOX Annual unit from

compliance with any other provision of the applicable, approved state implementation

plan, a federally enforceable permit, or the Clean Air Act.

(9 VAC 5-80-490 and 40 CFR 97.406)

CSAPR –TR NOX Ozone Season Trading Program Requirements (40 CFR 97.506, Subpart

BBBBB)

134. CSAPR –TR NOX Ozone Season Trading Program - The following conditions must be

adhered to for T-1, T-2, and T-3, which are subject to the CSAPR NOX Ozone Season

Trading Program:




40 CFR 97.513 through 97.518.




Page 59

(1) The owners and operators, and the designated representative, of each TR NOX

Ozone Season source and each TR NOX Ozone Season unit at the source shall

comply with the monitoring, reporting, and recordkeeping requirements of 40

CFR 97.530 (general requirements, including installation, certification, and data

accounting, compliance deadlines, reporting data, prohibitions, and long-term

cold storage), 97.531 (initial monitoring system certification and recertification

procedures), 97.532 (monitoring system out-of-control periods), 97.533

(notifications concerning monitoring), 97.534 (recordkeeping and reporting,

including monitoring plans, certification applications, quarterly reports, and

compliance certification), and 97.535 (petitions for alternatives to monitoring,

recordkeeping, or reporting requirements).


shall be used to calculate allocations of TR NOX Ozone Season allowances under

40 CFR 97.511(a)(2) and (b) and 97.512 and to determine compliance with the

TR NOX Ozone Season emissions limitation and assurance provisions under

paragraph (c) below, provided that, for each monitoring location from which mass

emissions are reported, the mass emissions amount used in calculating such

allocations and determining such compliance shall be the mass emissions amount

for the monitoring location determined in accordance with 40 CFR 97.530

through 97.535 and rounded to the nearest ton, with any fraction of a ton less than

0.50 being deemed to be zero.

c. NOX emissions requirements.

(1) TR NOX Ozone Season emissions limitation.


the owners and operators of each TR NOX Ozone Season source and each

TR NOX Ozone Season unit at the source shall hold, in the source's

compliance account, TR NOX Ozone Season allowances available for

deduction for such control period under 40 CFR 97.524(a) in an amount not

less than the tons of total NOX emissions for such control period from all TR

NOX Ozone Season units at the source.

(b) If total NOX emissions during a control period in a given year from the TR

NOX Ozone Season units at a TR NOX Ozone Season source are in excess of

the TR NOX Ozone Season emissions limitation set forth in paragraph

(c)(1)(a) above, then:

(i) The owners and operators of the source and each TR NOX Ozone

Season unit at the source shall hold the TR NOX Ozone Season

allowances required for deduction under 40 CFR 97.524(d); and

(ii) The owners and operators of the source and each TR NOX Ozone

Season unit at the source shall pay any fine, penalty, or assessment or

comply with any other remedy imposed, for the same violations, under



Page 60

the Clean Air Act, and each ton of such excess emissions and each day

of such control period shall constitute a separate violation of 40 CFR

part 97, subpart BBBBB and the Clean Air Act.

(2) TR NOX Ozone Season assurance provisions.

(a) If total NOX emissions during a control period in a given year from all TR

NOX Ozone Season units at TR NOX Ozone Season sources in the state

exceed the state assurance level, then the owners and operators of such

sources and units in each group of one or more sources and units having a

common designated representative for such control period, where the

common designated representative’s share of such NOX emissions during

such control period exceeds the common designated representative’s

assurance level for the state and such control period, shall hold (in the

assurance account established for the owners and operators of such group)

TR NOX Ozone Season allowances available for deduction for such control

period under 40 CFR 97.525(a) in an amount equal to two times the product

(rounded to the nearest whole number), as determined by the Administrator

in accordance with 40 CFR 97.525(b), of multiplying—

(i) The quotient of the amount by which the common designated

representative’s share of such NOX emissions exceeds the common

designated representative’s assurance level divided by the sum of the

amounts, determined for all common designated representatives for

such sources and units in the state for such control period, by which

each common designated representative’s share of such NOX

emissions exceeds the respective common designated representative’s

assurance level; and

(ii) The amount by which total NOX emissions from all TR NOX Ozone

Season units at TR NOX Ozone Season sources in the state for such

control period exceed the state assurance level.

(b) The owners and operators shall hold the TR NOX Ozone Season allowances

required under paragraph (c)(2)(i) above, as of midnight of November 1 (if

it is a business day), or midnight of the first business day thereafter (if

November 1 is not a business day), immediately after such control period.

(c) Total NOX emissions from all TR NOX Ozone Season units at TR NOX

Ozone Season sources in the state during a control period in a given year

exceed the state assurance level if such total NOX emissions exceed the sum,

for such control period, of the State NOX Ozone Season trading budget

under 40 CFR 97.510(a) and the state’s variability limit under 40 CFR

97.510(b).

(d) It shall not be a violation of 40 CFR part 97, subpart BBBBB or of the Clean

Air Act if total NOX emissions from all TR NOX Ozone Season units at TR



Page 61

NOX Ozone Season sources in the state during a control period exceed the

state assurance level or if a common designated representative’s share of

total NOX emissions from the TR NOX Ozone Season units at TR NOX

Ozone Season sources in the state during a control period exceeds the

common designated representative’s assurance level.

(e) To the extent the owners and operators fail to hold TR NOX Ozone Season


paragraphs (c)(2)(a) through (c) above,

(i) The owners and operators shall pay any fine, penalty, or assessment or

comply with any other remedy imposed under the Clean Air Act; and

(ii) Each TR NOX Ozone Season allowance that the owners and operators

fail to hold for such control period in accordance with paragraphs

(c)(2)(a) through (c) above and each day of such control period shall

constitute a separate violation of 40 CFR part 97, subpart BBBBB and

the Clean Air Act.


(a) A TR NOX Ozone Season unit shall be subject to the requirements under

paragraph (c)(1) above for the control period starting on the later of May 1,

2015 or the deadline for meeting the unit's monitor certification

requirements under 40 CFR 97.530(b) and for each control period thereafter.

(b) A TR NOX Ozone Season unit shall be subject to the requirements under

paragraph (c)(2) above for the control period starting on the later of May 1,

2017 or the deadline for meeting the unit's monitor certification

requirements under 40 CFR 97.530(b) and for each control period thereafter.


(a) A TR NOX Ozone Season allowance held for compliance with the

requirements under paragraph (c)(1)(a) above for a control period in a given

year must be a TR NOX Ozone Season allowance that was allocated for such

control period or a control period in a prior year.

(b) A TR NOX Ozone Season allowance held for compliance with the

requirements under paragraphs (c)(1)(b)(i) and (2)(a) through (c) above for a

control period in a given year must be a TR NOX Ozone Season allowance

that was allocated for a control period in a prior year or the control period in

the given year or in the immediately following year.

(5) Allowance Management System requirements. Each TR NOX Ozone Season

allowance shall be held in, deducted from, or transferred into, out of, or between

Allowance Management System accounts in accordance with 40 CFR part 97,

subpart BBBBB.



Page 62

(6) Limited authorization. A TR NOX Ozone Season allowance is a limited

authorization to emit one ton of NOX during the control period in one year. Such

authorization is limited in its use and duration as follows:

(a) Such authorization shall only be used in accordance with the TR NOX

Ozone Season Trading Program; and

(b) Notwithstanding any other provision of 40 CFR part 97, subpart BBBBB,

the Administrator has the authority to terminate or limit the use and duration

of such authorization to the extent the Administrator determines is necessary

or appropriate to implement any provision of the Clean Air Act.

(7) Property right. A TR NOX Ozone Season allowance does not constitute a property

right.



or transfer of TR NOX Ozone Season allowances in accordance with 40 CFR part

97, subpart BBBBB.






methodology (pursuant to 40 CFR 75.19), and an alternative monitoring system

(pursuant to 40 CFR part 75, subpart E). Therefore, the Description of TR





(1) Unless otherwise provided, the owners and operators of each TR NOX Ozone

Season source and each TR NOX Ozone Season unit at the source shall keep on

site at the source each of the following documents (in hardcopy or electronic

format) for a period of 5 years from the date the document is created. This period

may be extended for cause, at any time before the end of 5 years, in writing by the

Administrator.


representative for the source and each TR NOX Ozone Season unit at the

source and all documents that demonstrate the truth of the statements in the






Page 63




subpart BBBBB.



requirements of, the TR NOX Ozone Season Trading Program.

(2) The designated representative of a TR NOX Ozone Season source and each TR

NOX Ozone Season unit at the source shall make all submissions required under

the TR NOX Ozone Season Trading Program, except as provided in 40 CFR

97.518. This requirement does not change, create an exemption from, or

otherwise affect the responsible official submission requirements under a title V

operating permit program in 40 CFR parts 70 and 71.

f. Liability.

(1) Any provision of the TR NOX Ozone Season Trading Program that applies to a

TR NOX Ozone Season source or the designated representative of a TR NOX

Ozone Season source shall also apply to the owners and operators of such source

and of the TR NOX Ozone Season units at the source.

(2) Any provision of the TR NOX Ozone Season Trading Program that applies to a

TR NOX Ozone Season unit or the designated representative of a TR NOX Ozone

Season unit shall also apply to the owners and operators of such unit.


No provision of the TR NOX Ozone Season Trading Program or exemption under 40

CFR 97.505 shall be construed as exempting or excluding the owners and operators,

and the designated representative, of a TR NOX Ozone Season source or TR NOX

Ozone Season unit from compliance with any other provision of the applicable,

approved state implementation plan, a federally enforceable permit, or the Clean Air

Act.

(9 VAC 5-80-490 and 40 CFR 97.506)

CSAPR - TR SO2 Group 1 Trading Program Requirements (40 CFR 97.606, Subpart

CCCCC)

135. CSAPR - TR SO2 Group 1 Trading Program – The following conditions must be

adhered to for T-1, T-2, and T-3, which are subject to the CSAPR SO2 Group 1 Trading

Program:




Page 64



40 CFR 97.613 through 97.618.


(1) The owners and operators, and the designated representative, of each TR SO2

Group 1 source and each TR SO2 Group 1 unit at the source shall comply with the

monitoring, reporting, and recordkeeping requirements of 40 CFR 97.630 (general

requirements, including installation, certification, and data accounting,

compliance deadlines, reporting data, prohibitions, and long-term cold storage),

97.631 (initial monitoring system certification and recertification procedures),

97.632 (monitoring system out-of-control periods), 97.633 (notifications

concerning monitoring), 97.634 (recordkeeping and reporting, including

monitoring plans, certification applications, quarterly reports, and compliance

certification), and 97.635 (petitions for alternatives to monitoring, recordkeeping,

or reporting requirements).


shall be used to calculate allocations of TR SO2 Group 1 allowances under 40

CFR 97.611(a)(2) and (b) and 97.612 and to determine compliance with the TR

SO2 Group 1 emissions limitation and assurance provisions under paragraph (c)

below, provided that, for each monitoring location from which mass emissions are

reported, the mass emissions amount used in calculating such allocations and

determining such compliance shall be the mass emissions amount for the

monitoring location determined in accordance with 40 CFR 97.630 through

97.635 and rounded to the nearest ton, with any fraction of a ton less than 0.50

being deemed to be zero.

c. SO2 emissions requirements.

(1) TR SO2 Group 1 emissions limitation.


the owners and operators of each TR SO2 Group 1 source and each TR SO2

Group 1 unit at the source shall hold, in the source's compliance account,

TR SO2 Group 1 allowances available for deduction for such control period

under 40 CFR 97.624(a) in an amount not less than the tons of total SO2

emissions for such control period from all TR SO2 Group 1 units at the

source.

(b) If total SO2 emissions during a control period in a given year from the TR

SO2 Group 1 units at a TR SO2 Group 1 source are in excess of the TR SO2

Group 1 emissions limitation set forth in paragraph (c)(1)(a) above, then:



Page 65

(i) The owners and operators of the source and each TR SO2 Group 1 unit

at the source shall hold the TR SO2 Group 1 allowances required for

deduction under 40 CFR 97.624(d); and

(ii) The owners and operators of the source and each TR SO2 Group 1 unit

at the source shall pay any fine, penalty, or assessment or comply with

any other remedy imposed, for the same violations, under the Clean

Air Act, and each ton of such excess emissions and each day of such

control period shall constitute a separate violation 40 CFR part 97,

subpart CCCCC and the Clean Air Act.

(2) TR SO2 Group 1 assurance provisions.

(a) If total SO2 emissions during a control period in a given year from all TR

SO2 Group 1 units at TR SO2 Group 1 sources in the state exceed the state

assurance level, then the owners and operators of such sources and units in

each group of one or more sources and units having a common designated

representative for such control period, where the common designated

representative’s share of such SO2 emissions during such control period

exceeds the common designated representative’s assurance level for the

state and such control period, shall hold (in the assurance account

established for the owners and operators of such group) TR SO2 Group 1

allowances available for deduction for such control period under 40 CFR

97.625(a) in an amount equal to two times the product (rounded to the

nearest whole number), as determined by the Administrator in accordance

with 40 CFR 97.625(b), of multiplying—

(i) The quotient of the amount by which the common designated

representative’s share of such SO2 emissions exceeds the common

designated representative’s assurance level divided by the sum of the

amounts, determined for all common designated representatives for

such sources and units in the state for such control period, by which

each common designated representative’s share of such SO2 emissions

exceeds the respective common designated representative’s assurance

level; and

(ii) The amount by which total SO2 emissions from all TR SO2 Group 1

units at TR SO2 Group 1 sources in the state for such control period

exceed the state assurance level.

(b) The owners and operators shall hold the TR SO2 Group 1 allowances

required under paragraph (c)(2)(a) above, as of midnight of November 1 (if

it is a business day), or midnight of the first business day thereafter (if

November 1 is not a business day), immediately after such control period.

(c) Total SO2 emissions from all TR SO2 Group 1 units at TR SO2 Group 1

sources in the state during a control period in a given year exceed the state



Page 66

assurance level if such total SO2 emissions exceed the sum, for such control

period, of the state SO2 Group 1 trading budget under 40 CFR 97.610(a) and

the state’s variability limit under 40 CFR 97.610(b).

(d) It shall not be a violation of 40 CFR part 97, subpart CCCCC or of the Clean

Air Act if total SO2 emissions from all TR SO2 Group 1 units at TR SO2

Group 1 sources in the state during a control period exceed the state

assurance level or if a common designated representative’s share of total

SO2 emissions from the TR SO2 Group 1 units at TR SO2 Group 1 sources

in the state during a control period exceeds the common designated

representative’s assurance level.

(e) To the extent the owners and operators fail to hold TR SO2 Group 1


paragraphs (c)(2)(a) through (c) above,

(i) The owners and operators shall pay any fine, penalty, or assessment or

comply with any other remedy imposed under the Clean Air Act; and

(ii) Each TR SO2 Group 1 allowance that the owners and operators fail to

hold for such control period in accordance with paragraphs (c)(2)(a)

through (c) above and each day of such control period shall constitute

a separate violation of 40 CFR part 97, subpart CCCCC and the Clean

Air Act.


(a) A TR SO2 Group 1 unit shall be subject to the requirements under paragraph




(b) A TR SO2 Group 1 unit shall be subject to the requirements under paragraph





(a) A TR SO2 Group 1 allowance held for compliance with the requirements

under paragraph (c)(1)(a) above for a control period in a given year must be

a TR SO2 Group 1 allowance that was allocated for such control period or a

control period in a prior year.

(b) A TR SO2 Group 1 allowance held for compliance with the requirements

under paragraphs (c)(1)(b)(i) and (2)(a) through (c) above for a control

period in a given year must be a TR SO2 Group 1 allowance that was



Page 67

allocated for a control period in a prior year or the control period in the

given year or in the immediately following year.

(5) Allowance Management System requirements. Each TR SO2 Group 1 allowance

shall be held in, deducted from, or transferred into, out of, or between Allowance

Management System accounts in accordance with 40 CFR part 97, subpart

CCCCC.

(6) Limited authorization. A TR SO2 Group 1 allowance is a limited authorization to

emit one ton of SO2 during the control period in one year. Such authorization is

limited in its use and duration as follows:

(a) Such authorization shall only be used in accordance with the TR SO2 Group

1 Trading Program; and

(b) Notwithstanding any other provision of 40 CFR part 97, subpart CCCCC,

the Administrator has the authority to terminate or limit the use and duration

of such authorization to the extent the Administrator determines is necessary

or appropriate to implement any provision of the Clean Air Act.

(7) Property right. A TR SO2 Group 1 allowance does not constitute a property right.



or transfer of TR SO2 Group 1 allowances in accordance with 40 CFR part 97,

subpart CCCCC.






methodology (pursuant to 40 CFR part 75.19), and an alternative monitoring

system (pursuant to 40 CFR part 75, subpart E), Therefore, the Description of TR





(1) Unless otherwise provided, the owners and operators of each TR SO2 Group 1

source and each TR SO2 Group 1 unit at the source shall keep on site at the source

each of the following documents (in hardcopy or electronic format) for a period of

five years from the date the document is created. This period may be extended for

cause, at any time before the end of 5 years, in writing by the Administrator.



Page 68


representative for the source and each TR SO2 Group 1 unit at the source

and all documents that demonstrate the truth of the statements in the







subpart CCCCC.



requirements of, the TR SO2 Group 1 Trading Program.

(2) The designated representative of a TR SO2 Group 1 source and each TR SO2

Group 1 unit at the source shall make all submissions required under the TR SO2

Group 1 Trading Program, except as provided in 40 CFR 97.618. This

requirement does not change, create an exemption from, or otherwise affect the

responsible official submission requirements under a title V operating permit

program in 40 CFR parts 70 and 71.

f. Liability.

(1) Any provision of the TR SO2 Group 1 Trading Program that applies to a TR SO2

Group 1 source or the designated representative of a TR SO2 Group 1 source shall

also apply to the owners and operators of such source and of the TR SO2 Group 1

units at the source.

(2) Any provision of the TR SO2 Group 1 Trading Program that applies to a TR SO2

Group 1 unit or the designated representative of a TR SO2 Group 1 unit shall also



No provision of the TR SO2 Group 1 Trading Program or exemption under 40 CFR

97.605 shall be construed as exempting or excluding the owners and operators, and the

designated representative, of a TR SO2 Group 1 source or TR SO2 Group 1 unit from

compliance with any other provision of the applicable, approved state implementation

plan, a federally enforceable permit, or the Clean Air Act.

(9 VAC 5-80-490 and 40 CFR 97.606)



Page 69

State-Only Enforceable Requirements

136. State-Only Enforceable Requirements - The following terms and conditions are not

required under the federal Clean Air Act or under any of its applicable federal

requirements, and are not subject to the requirements of 9 VAC 5-80-690 concerning

review of proposed permits by EPA and draft permits by affected states.

(9 VAC 5-80-490 N)

137. Limitations – Emission Limits - Emissions from the electric power generation facility shall

not exceed the limits specified below:

Pollutant CAS# Hourly Limit Annual Limit

Acrolein 107-02-8 0.0406 lbs/hr 0.176 tons/yr

Formaldehyde 50-00-0 1.48 lbs/hr 6.34 tons/yr

Cadmium 7440-43-9 0.0115 lbs/hr 0.00551 tons/yr

Chromium 7440-47-3 0.0146 lbs/hr 0.00702 tons/yr

Nickel 7440-02-0 0.0219 lbs/hr 0.0105 tons/yr

Annual emissions shall be calculated monthly as the sum of each consecutive 12-month

period.

(9 VAC 5-80-490 N and Condition 84 of the 12/17/2010 Permit, as amended 10/24/2013,

6/17/2014, and 12/20/2018)

138. Limitations - Emission Limits – The permittee shall determine compliance with the toxic

pollutants emission limits in Condition 137 as follows:

a. To calculate hourly toxic compound emissions from the electric power generation

facility:

100

100

1

CECFE

n

i

iit

……………….. Equation 1

Where:

Et = Emission rate of toxic compound (t) (lbs/hr)

Fi = Emission factor of toxic compound (t) for each unit (i) utilized during the

time period (lb/MMBtu)

Ci = Capacity of each unit (i) utilized during the time period (MMBtu/hr)



Page 70

CE = Control efficiency of volatile toxic compounds by the oxidation catalyst (%)

[30 is accepted reduction unless records demonstrate a different value]

b. To calculate annual toxic compound emissions from the electric power generation

facility:

lb

tonCETCFE

n

i

iiit2000

1

100

100

1

……………….. Equation 2

Where:

Et = Emission rate of toxic compound (t) (tons/year)

Fi = Emission factor of toxic compound (t) for each unit (i) utilized during the

time period (lb/MMBtu)

Ci = Capacity of each unit (i) utilized during the time period (MMBtu/hr)

Ti = Hours of operation for each unit (i) utilized during the time period (hours)

CE = Control efficiency of volatile toxic compounds by the oxidation catalyst (%)

[30 is accepted reduction unless records demonstrate a different value]

Annual emissions shall be calculated monthly as the sum of each consecutive 12-month

period.


6/17/2014, and 12/20/2018)

139. Recordkeeping - On Site Records - The permittee shall maintain records of emissions data


content and format of such records shall be arranged with the DEQ. These records shall


a. Total hours that each unit operates on a monthly basis.

b. Average hourly, monthly and annual emissions (in pounds and tons) of each toxic

compound listed in Condition 137. Toxic compound emissions shall be calculated as

shown in Condition 138. 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 the DEQ and shall be current for at least



6/17/2014, and 12/20/2018)

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 evaluation

commonwealth of virginia virginia department of

Documents