Directions in this boilerplate are italicized and are … · Web viewSubpart Dc applies to steam generating units with a maximum design heat input capacity in the range of 10 MMBtu/hr

Commonwealth of VirginiaVIRGINIA DEPARTMENT OF ENVIRONMENTAL QUALITY

VALLEY REGIONAL OFFICE

STATEMENT OF LEGAL AND FACTUAL BASIS

Virginia Electric and Power Company Dominion Energy– Warren County Power Station

Warren County, VirginiaPermit No. VRO81391

The 1990 Clean Air Act Amendments required each state to develop a permit program to ensure that certain facilities have federal Air Pollution Operating Permits. As required by 40 CFR Part 70, 9 VAC 5 Chapter 80, Article 3 of the Commonwealth of Virginia Regulations for the Control and Abatement of Air Pollution, Virginia Electric & Power Company has applied for a renewal of its Federal Operating Permit for its Warren County Power Station facility. The Department has reviewed the application and has prepared a draft Federal Operating Permit. This permit is based upon Federal Clean Air Act Phase II Acid Rain permitting requirements of Title IV, federal operating permit requirements of Title V, 40 CFR Part 97 (Subparts AAAAA – CCCCC, as amended), and Chapter 80, Article 3 of the Commonwealth of Virginia Regulations for the Control and Abatement of Air Pollution.

Permit Writer: Date: DRAFTJeremy Funkhouser

(540) 574-7820

Air Permit Manager: DRAFT Date: DRAFTJanardan R. Pandey

FACILITY INFORMATION

PermitteeVirginia Electric & Power Company DBA: Dominion Energy – Warren County Power Station5000 Dominion BoulevardGlen Allen, Virginia 23060

FacilityDominion Energy – Warren County Power Station477 Kelley Drive

Front Royal, Virginia 22630Warren County

SOURCE DESCRIPTION

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 natural gas-fired combustion turbine (CT) generator and one heat recovery steam generator (HRSG) with supplementary natural gas-fired duct burners (DB). Each of the combined-cycle units (T-1, T-2, and T-3) are subject to the New Source Performance Standards (NSPS) 40 CFR 60 Subpart KKKK.

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; three turbine inlet chillers; and one distillate oil storage tank.

The natural gas-fired auxiliary boiler (B-1) is rated at 47.6 MMBtu/hr, and is subject to the requirements of 40 CFR 60 Subpart Dc. The natural gas-fired fuel gas heater (GH-1) has a rated capacity of 17.64 MMBtu/hr, and is subject to the requirements of 40 CFR 60 Subpart Dc.

The diesel-fired emergency generator, EG-1, is rated at 2,220 brake horsepower (BHP); the diesel-fired fire water pump, FWP-1, is rated at 376 BHP. Both the emergency generator (EG-1)and the fire water pump (FWP-1) are subject to the requirements of 40 CFR 60 Subpart IIII and 40 CFR 63 Subpart ZZZZ.

The propane-fired emergency generator, EPG-1, is rated at 60 kilowatts (kW) and is subject to the requirements of 40 CFR 60 Subpart JJJJ and 40 CFR 63 Subpart ZZZZ.

The facility also operates a small gasoline dispensing facility with an annual throughput of less than 10,000 gallons per year. The gasoline dispensing facility is subject to the requirements of 40 CFR 63 Subpart CCCCCC.

This source is located in Warren County, an attainment area for all pollutants, and is a Prevention of Significant Deterioration (PSD) source under 9 VAC 5-80 Article 8 of the Virginia Regulations. The initial PSD permit was issued on December 17, 2010, and was amended on October 24, 2013, June 17, 2014, and December 20, 2018.

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. The facility submitted a renewal application for the Title IV Acid Rain permit; the Title IV Acid Rain requirements are incorporated in the federal operating permit..

COMPLIANCE STATUS

A full compliance evaluation of this facility, including a site visit, was last conducted on ________. In addition, all reports and other data required by permit conditions or regulations, which are submitted to DEQ, are evaluated for compliance. Based on these compliance evaluations, the facility was not found to be in violation of any state or federal applicable requirements at this time.

EMISSION UNIT AND CONTROL DEVICE IDENTIFICATION

Please refer to the Emission Units Table in the Article 3 permit on Page 5.

EMISSIONS INVENTORY

Annual emissions summarized in the following table are derived in part from the 2017 CEDS emission report and information submitted by the facility. A copy of the report and information submitted by the facility are included as Attachment A.

2017 Pollutant Emissions (Plant-wide Total)Criteria Pollutant Tons Emitted

PM-10 76.27PM-2.5 30.96VOC 1.97NOx 189.87SO2 18.81CO 20.54NH3 21.68Lead (also a HAP) 1.1E-03Sulfuric Acid Mist (H2SO4) 0.00

DRAFT Dominion Energy – Warren County Power StationPermit Number: VRO81391

Statement of BasisPage 4

EMISSION UNIT APPLICABLE REQUIREMENTS Combined Cycle Unit Requirements (T-1, T-2, and T-3)

Limitations

The following limitations are state BACT requirements from the PSD permit issued on 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B.

Condition 1: 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.

Condition 2: 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.

Condition 3: 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.

Condition 4: 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.

Condition 14: 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 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. The condition also provides the definition of standard cubic foot of gas. The condition is more stringent than the applicable NSPS Subpart KKKK requirements; the NSPS citations have been included in the condition.

Condition 15: 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.



Condition 17: The condition establishes the short-term emission limitations for PM-10, PM-2.5, NOx, CO, VOC, and H2SO4. The condition is more stringent than the applicable NSPS Subpart KKKK requirements; the NSPS citations have been included in the condition.

Condition 18: The condition establishes the annual emission limitations for PM-10, PM-2.5, NOx, CO, VOC, and H2SO4.

Condition 19: The condition establishes the definitions of startup and shutdown.

Condition 20: Each duct burner (DB1, DB2, & DB3) shall not operate more than 6,000 hours per year, calculated monthly as the sum of each consecutive 12-month period.

Condition 21: Emissions from the operation of each duct burner (DB1, DB2, & DB3) operating independently of each combined-cycle system (T-1, T-2, & T-3) shall not exceed 54 ppm of oxides of nitrogen (expressed as NO2) at 15 percent O2. The condition has been streamlined with the NSPS requirements.

Condition 22: The condition establishes hourly and seasonal operational restrictions on the duct burners (DB1, DB2, & DB3).

Condition 23: The condition establishes emission limitations and control requirements for the ammonia slip associated with the SCR.

Condition 24: The condition establishes the visible emission limitation for each combined-cycle (T-1, T-2, & T-3).

Condition 71: 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.

Condition 73: The condition establishes the short-term emission limitations for SO2.

Condition 74: The condition establishes the annual emission limitations for SO2.

The following Virginia Administrative Codes that have specific emission requirements have been determined to be applicable:

9 VAC 5-50-80, Standard for Visible Emissions – The visible emission limitations in the



PSD permit (dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018) are more stringent than the visible emission standard in 9 VAC 5-50-80.

In addition to the limitations provided by the PSD Permit and Virginia Administrative Code, the combined-cycle units (T-1, T-2, and T-3) are subject to 40 CFR 60 Subpart KKKK (Standards of Performance for Stationary Combustion Turbines).

Subpart KKKK applies to gas turbines having a heat input at peak load equal to or greater than 10 MMBtu/hr, based on the higher heating value of the fuel fired. The subpart also applies to emissions from the associated duct burners. The rule imposes limits on NOx and SO2 emissions and monitoring and testing requirements.

The NSPS establishes the following SO2 limitations:

Discharged in to the atmosphere 0.90 pounds of SO2 per megawatt-hour (lb/MWh)) gross output; OR

Any fuel which contains total potential sulfur emissions of 0.060 lb SO2/MMBtu heat input

The PSD permit establishes a fuel sulfur content limitation of 0.0003 % by weight, and the SO2 permit limit is 0.00028 lb/MMBtu. The BACT determinations codified in the PSD permit are more stringent than the NSPS requirements during periods of normal operation. The SO2 emission limitations established in NSPS Subpart KKKK apply at all times including startup and shutdown. The facility complies with the NSPS SO2 emission limitations of 0.060 lb SO2/MMBtu heat input through fuel tariff sheets showing compliance with the limit. Since the facility utilizes the fuel tariff method for NSPS Subpart KKKK compliance the facility is exempt from the fuel monitoring requirements of NSPS Subpart KKKK. Monitoring requirements of NSPS Subpart KKKK are discussed below.

In accordance with the NSPS Subpart KKKK, the following requirements have been included in the Article 3 permit; condition numbers refer to the Article 3 permit:

Condition 9: The condition establishes the SO2 emission limitations in accordance with NSPS Subpart KKKK.

A discussion of the streamlined requirements from NSPS Subpart KKKK is provided in the Streamlined Requirements section below.

The NSPS establishes the following NOx limitations:



CT firing natural gas with or without duct burning: 15 ppm at 15 percent O2 or 0.43 lb/MWh (§60.4320).

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 (§60.4320).

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

The NOx emission limitations are on a 30-day rolling average and apply at all times including startup and shutdown. Monitoring requirements of NSPS Subpart KKKK are discussed below.

In accordance with the NSPS Subpart KKKK, the following requirements have been included in the Article 3 permit; condition numbers refer to the Article 3 permit:

Condition 11: The condition establishes the NOx emission limitations in accordance with NSPS Subpart KKKK.

A discussion of the streamlined requirements from NSPS Subpart KKKK is provided in the Streamlined Requirements section below.

Monitoring and Recordkeeping

The following monitoring and recordkeeping requirements are taken from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B:

Condition 5: 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.

Condition 6: 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.

Condition 7: 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.

Condition 8: 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. The permittee shall continuously record measurements from the control equipment monitoring devices.

Condition 16: The condition establishes the fuel monitoring requirements to demonstrate compliance with the fuel limitations (sulfur content).

Condition 50: The condition requires the installation and operation of Continuous Emission Monitoring Systems (CEMS) to measure and record NOx and CO emissions from each combined-cycle unit (T-1, T-2, & T-3). The condition has been streamlined with the NSPS requirements.

Condition 52: 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. The condition has been streamlined with the NSPS requirements.

Condition 53: The condition establishes the definitions of periods of excess emissions and monitor downtime for the NOx CEMS in accordance with Subpart KKKK. The condition has been streamlined with the NSPS requirements.

Condition 54: The condition establishes the definitions of periods of excess emissions and monitor downtime for SO2 in accordance with Subpart KKKK. The condition has been streamlined with the NSPS requirements.

Condition 56: The condition establishes criteria for operation and identification of periods of excess emissions. The condition has been streamlined with the NSPS requirements.

Condition 57: The condition establishes the recordkeeping requirements.



The compliance strategy for the facility includes continuous monitoring of NOx and CO, proper operation and maintenance of the equipment, the use of low sulfur fuels, and good combustion practices.

The monitoring device requirements (Conditions 5 and 7 of the PSD permit) for the SCR requiring continuously measurement, calculation of, or record of the ammonia feed rate, gas stream flow rate, and catalyst bed inlet gas temperature establish a means of demonstrating continuous compliance with the requirement to control NOx emissions from each CT (CT-1, CT-2, & CT-3) and HRSG duct burner (DB1, DB2, & DB3).

The monitoring device requirements (Conditions 6 and 8 of the PSD permit) for the oxidation catalyst requiring continuously measurement and record of the temperature at the catalyst bed inlet establish a means of demonstrating continuous compliance with the requirement to control CO and VOC emissions from each CT (CT-1, CT-2, & CT-3) and HRSG duct burner (DB1, DB2, & DB3).

The recordkeeping requirement for operation and control device monitoring records for each SCR system and each oxidation catalyst provides a means of continuous demonstration that the control devices are operating properly.

The requirement for 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 provide a means of demonstrating compliance with the emission limitations and control requirements for the ammonia slip associated with the SCR.

The fuel monitoring requirement (Condition 16 of the PSD permit) provides a means to demonstrate continuous compliance with the fuel sulfur limitations for each CT (CT-1, CT-2, & CT-3) and HRSG duct burner (DB1, DB2, & DB3) as well as the short-term and annual SO2 and H2SO4 emission limitations. The facility is required to keep records of the fuel certifications, including purchase contracts or tariff sheets, to demonstrate continued compliance with the fuel certification requirements. As an alternative means of demonstrating compliance, the facility can determine 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. The recordkeeping requirements for, not only the fuel sulfur content, but also the annual throughputs of natural gas provides a means of demonstrating continuous compliance with the annual SO2 and H2SO4 emission limitations. In lieu of demonstrating compliance with the SO2 emission limitations through fuel monitoring, the PSD permit also allows for determination through annual stack testing; details of the annual stack testing are provided in Condition 66 of the PSD permit.

The requirements for the installation and operation requirements (Conditions 50 through 56) associated with the CEMS for NOx and CO provide a means of demonstrating continuous compliance with the emission limitations contained in the permit. The CEMS performance evaluation condition (Condition 51 of the PSD permit) was not included in the Title V permit; the condition has already been fulfilled.



The primary fuel for each of the combined-cycle units (T-1, T-2, & T-3) is pipeline natural gas. The permit also requires good combustion practices, and proper operation and maintenance. As long as the combined-cycle units (T-1, T-2, & T-3) are properly maintained and operated, PM-10 and PM-2.5emission limits, as well as opacity limits, should not be violated. The permit conditions requiring good combustion practices and records of maintenance and training, provide a reasonable assurance of compliance with the PM-10, PM-2.5, and opacity standards.

In addition the facility is required to perform additional Visible Emission Observations on the combined-cycle units (T-1, T-2, & T-3) in accordance with Condition 68 of the PSD permit. The requirement for additional visible emission observations provides a means of demonstrating continuous compliance with the opacity limits for the combined-cycle units (T-1, T-2, & T-3). At a minimum of once per 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. If visible emissions inspections conducted during 12 consecutive weeks show no visible emissions for a particular unit stack, the permittee may reduce the monitoring frequency to once per month for that unit stack. Anytime the monthly visible emissions inspections show visible emissions, or when requested by DEQ, the monitoring frequency shall be increased to once per week for that stack.

The recordkeeping requirements for the annual hours of operation of each duct burner (DB1, DB2, & DB3), calculated monthly, provides a means of demonstrating compliance with the hourly and seasonal operational restrictions.

Records of the annual throughput of natural gas, continuous records of heat input, and records of power output for combined-cycle units (T-1, T-2, & T-3), in addition to the time, date and duration of each startup, shutdown, and malfunction period for each, provide an additional means of calculating and demonstrating compliance with the annual emission limitations.

Compliance with the visible emission limitations for any emissions unit may also be determined through visible emission evaluations, conducted upon request by the Department and/or the EPA. Testing requirements are discussed in further detail below.

In addition to the monitoring and recordkeeping requirements taken from the PSD permit, the facility is also subject to the monitoring and recordkeeping requirements from NSPS Subpart KKKK. Monitoring and recordkeeping requirements from Subpart KKKK include fuel sulfur monitoring, the installation of CEMS, and requirements for excess emission reports. As discussed above, the monitoring and recordkeeping requirements taken from the PSD permit are more stringent. The regulatory citations for the NSPS are streamlined with the applicable PSD permit requirements in the Article 3 permit. A discussion of the streamlined requirements is provided in the Streamlined Requirements section below.



Testing

The following testing requirements are from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B:

Condition 63: Compliance Demonstration: Duct Burners – The permittee shall determine compliance with the NSPS NOx emission limits for the duct burners by complying with the short-term emission limitations. The condition has been streamlined with the NSPS requirements.

Condition 66: The condition establishes the annual fuel or stack testing requirements for SO2.

Condition 67: 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.

Condition 68: The condition establishes the requirements and time frames for Visible Emission Evaluations.

The requirement for subsequent visible emission observations was addressed in the monitoring and recordkeeping section above.

The initial performance testing, found in Conditions 59 through 62, and 64 through 65, of the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018, have already been fulfilled. The initial stack testing also fulfills the NSPS Subpart KKKK testing requirements. A summary of the initial stack testing results are provided as Attachment D.

No additional testing is required for emissions of NOx or CO due to the use of CEMS. Fuel sampling or stack testing, as provided in Condition 66 of the PSD permit satisfies the testing requirements to demonstrate compliance with the SO2 permit limitations.

Upon request the permittee shall conduct additional performance tests to demonstrate compliance with the emission limits contained in the permit.

Compliance Assurance Monitoring (CAM)

Units subject to the Acid Rain Program or units subject to emission limitations or standards that apply under an emissions trading program are exempt from the requirements of 40 CFR Part 64, Compliance Assurance Monitoring (CAM). Dominion Energy – Warren County Power Station



is subject to the Acid Rain Program and CSAPR. In addition the facility employs NOx and CO CEMS as discussed in the monitoring and recordkeeping section above.

Reporting

The following reporting requirements are from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B:

Condition 55: The condition establishes the reporting requirements for CEMS excess emission reports.

The excess emission reporting requirements from 40 CFR 60 Subpart KKKK (§60.4375) have been streamlined with PSD permit requirement in the Article 3 permit.

Streamlined Requirements

The following requirements from 40 CFR 60 Subpart KKKK (Standards of Performance for Stationary Combustion Turbines) for the three combined-cycle power generating units (T-1, T-2, and T-3) have been streamlined in the Article 3 permit as follows:

Citation Requirement Streamlined Reason

40 CFR 60.4333(a) Operate and maintain equipment

General condition in Article 3 Permit (Condition 105, “Startup,

Shutdown and Malfunction”) includes the requirement.

40 CFR 60.4340 (b) NOx CEMSNOx CEMS requirements are

addressed in Condition 51 of the PSD Permit

40 CFR 60.4345 NOx CEMS requirementsNOx CEMS requirements are

addressed in Conditions 52 and 56 of the PSD Permit

40 CFR 60.4350 NOx Excess EmissionExcess emissions are addressed in Conditions 17 and 56 of the

PSD Permit40 CFR 60.436540 CFR 60.4370 Monitoring sulfur content of fuel Fuel monitoring is addressed in

Condition 16 of the PSD Permit

40 CFR 60.4375 CEMS ReportingReporting requirements are


40 CFR 60.4380 Excess Emissions and Monitor Downtime for NOx CEMS

Excess Emissions and Monitor Downtime for NOx CEMS is


40 CFR 60.4385 Excess Emissions and Monitor Downtime for SO2 CEMS

Excess Emissions and Monitor Downtime for SO2 CEMS is



Citation Requirement Streamlined Reasonaddressed in Condition 54 of the

PSD Permit

40 CFR 60.4395 ReportingReporting requirements are


40 CFR 60.4400 Compliance Demonstration: Duct Burners

The compliance demonstration is addressed in Condition 63 of the

PSD Permit

40 CFR 60.4415 Subsequent performance tests for sulfur

Subsequent performance tests for sulfur is addressed in Condition

66 of the PSD Permit



EMISSION UNIT APPLICABLE REQUIREMENTS Fuel Burning Equipment Requirements (B-1 and GH-1)

Limitations

The following limitations are state BACT requirements from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B.

Condition 11: 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.

Condition 12: 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.

Condition 13: 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.

Condition 43: 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. The condition also provides the definition of standard cubic foot.

Condition 44: 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 consecutive 12-month period.

Condition 45: 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 consecutive 12-month period.

Condition 46: The condition provides the short-term and annual emission limitations for the auxiliary boiler (B-1).



Condition 47: The condition provides the short-term and annual emission limitations for the fuel gas heater (GH-1).

Condition 48: 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.

Condition 72: 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.

In addition to the requirements of the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018, the auxiliary boiler (B-1) and fuel gas heater (GH-1) are subject to 40 CFR 60 Subpart Dc (Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units).

Subpart Dc applies to steam generating units with a maximum design heat input capacity in the range of 10 MMBtu/hr to 100 MMBtu/hr for which construction began after June 9, 1989. The auxiliary boiler and the fuel gas heater meet the applicability criteria of the rule and are subject to its requirements. Since the units are natural gas-fired the units are only subject to recordkeeping requirements. The applicable recordkeeping requirements (§60.48c) for natural gas burning units were incorporated into the PSD permit and have been streamlined into the Article 3 permit. A discussion of the streamlined requirements is provided in the Streamlined Requirements section below.

The regulatory citations for the NSPS are streamlined with the applicable PSD permit requirements in the Article 3 permit.



Condition 16: The condition provides the fuel monitoring options to determine the fuel sulfur content of the natural gas.

Condition 57: The condition establishes the recordkeeping requirements.

The recordkeeping requirements include:

- Fuel sulfur content : The recordkeeping requirement establishes a means of demonstrating compliance with the fuel sulfur content of the pipeline natural gas, as



required in Condition 43 of the PSD permit. The requirement establishes a means of calculating SO2 and H2SO4 emissions.

- Monthly and Annual Fuel Throughput : The recordkeeping requirement establishes a means of demonstrating compliance with the fuel throughput limitations for both the auxiliary boiler (B-1) and fuel gas heater (GH-1), as well as the annual emission limitations. The fuel throughput recordkeeping requirement is streamlined with the requirements of §60.48c.

- Records of good combustion practices : The recordkeeping requirement establishes a means of demonstrating compliance with the requirement to control the auxiliary boiler (B-1) and the fuel gas heater (GH-1) through good combustion practices.

- Emissions calculations : The recordkeeping requirement establishes a means of demonstrating compliance with short-term and annual emission limitations provided in the permit. Emission Factors and Calculation Methods are provided as Attachment C.

- Testing Results : This recordkeeping requirement establishes a means of demonstrating compliance with the testing requirements.

The fuel monitoring requirement (Condition 16 of the PSD permit) provides a means to demonstrate continuous compliance with the fuel sulfur limitations established for the auxiliary boiler (B-1) and the fuel gas heater (GH-1).

Emission calculations, using the Emission Factors and Calculation Methods as provided as Attachment C, in addition to the fuel throughput recordkeeping, provide a means of demonstrating continuous compliance with the hourly and annual emission limitations provided in the permit.

The recordkeeping requirement for good combustion practices satisfies the continuous compliance demonstration for the control of CO and VOC emissions from the auxiliary boiler (B-1) and the fuel gas heater (GH-1). The permittee shall have available good written operating procedures and a maintenance schedule for the boiler and heater.

The requirement for additional visible emission observations, provided in the testing section below, provides a means of demonstrating continuous compliance with the opacity limits for the auxiliary boiler (B-1) and fuel gas heater (GH-1). At a minimum of once per 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 the applicable standard, the VEE shall be conducted for a total of 60 minutes. If visible emissions inspections conducted during 12 consecutive months show no visible emissions for a particular unit stack, the permittee may reduce the monitoring frequency to once per quarter for that unit stack. Anytime the quarterly visible emissions inspections show visible emissions, or when requested by DEQ, the monitoring frequency shall be increased to once per month for that stack.



Testing

The following testing requirements are from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B:


Condition 69: The condition establishes the requirements and time frames for Visible Emission Evaluations.

The requirement for subsequent visible emission observations was addressed in the monitoring and recordkeeping section above.

The initial performance testing, found in Conditions 62 and 65, of the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018, have already been fulfilled for the fuel gas heater (GH-1). Performance testing for the fuel gas heater was conducted in December 2014. Given that the unit demonstrated compliance with the emission limitations, no subsequent performance tests are required at this time. A summary of the initial stack testing results are provided as Attachment D.

The initial performance testing, found in Conditions 62 and 65, of the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018, have already been fulfilled. Performance testing for the auxiliary boiler (B-1) was conducted at 78% load during the December 2014 performance tests, and again at a maximum load (91%) in May 2015. Each round of performance testing included NOx and CO.

Given that the auxiliary boiler (B1) has conducted performance testing at two loads, and has demonstrated compliance with the emission limitations, no subsequent performance tests are required at this time. Upon request the permittee shall conduct additional performance tests to demonstrate compliance with the emission limits contained in the permit. A summary of the initial stack testing results are provided as Attachment D.


CAM is not applicable to the auxiliary boiler (B-1) or the fuel gas heater (GH-1); the units do not meet the applicability criteria in §64.2(a)(2) or (3). The units do not utilize control devices to meet emission limitations, nor do the units have potential pre-controlled emissions greater than the major source thresholds.




The following requirements from 40 CFR 60 Subpart Dc (Standards of Performance for Stationary Combustion Turbines) for the auxiliary boiler (B-1) and the fuel gas heater (GH-1) have been streamlined in the Article 3 permit:


40 CFR 60.48c (g)(2) Monthly fuel throughput records Included in Condition 57 of the PSD Permit



EMISSION UNIT APPLICABLE REQUIREMENTS Emergency Units (EG-1, FWP-1, and EPG-1)

Limitations

The following limitations are state BACT requirements from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B.

Condition 10: The permittee must maintain and operate the emergency generator (EG-1) and the emergency fire water pump (FWP-1) according to the manufacturer's written instructions, or procedures developed by the permittee that are approved by the manufacturer, over the entire life of the engine. In addition, the permittee may only change those settings that are approved by the manufacturer. The condition was streamlined with the requirements of NSPS Subpart IIII.

Condition 27: 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. The condition was streamlined with the requirements of NSPS Subpart IIII.

Condition 28: The approved fuel for the emergency propane generator (EPG-1) is liquefied petroleum gas (LPG).

Condition 29: The condition establishes the operating hour limitations for the fire water pump (FWP-1).

Condition 30: The condition establishes the operating hour limitations for the emergency generator (EG-1).

Condition 31: The condition establishes the operating hour limitations for the emergency propane generator (EPG-1).

Condition 33: The condition establishes limitations on the operation of the emergency generator (EG-1), the emergency fire water pump (FWP-1), and the emergency propane generator (EPG-1). The condition was streamlined with the requirements of NSPS Subpart IIII and NSPS Subpart JJJJ.

Condition 34: The condition establishes the short-term and annual emission



limitations for the emergency fire water pump (FWP-1).

Condition 35: The condition establishes the short-term and annual emission limitations for the emergency generator (EG-1).

Condition 36: The condition establishes the short-term and annual emission limitations for the emergency propane generator (EPG-1).

Condition 37: The condition establishes the NSPS limitations for the fire water pump (FWP-1). The condition was streamlined with the requirements of NSPS Subpart IIII.

Condition 38: The condition establishes the NSPS limitations for the emergency generator (EG-1). The condition was streamlined with the requirements of NSPS Subpart IIII.

Condition 39: The condition establishes the NSPS limitations for the propane emergency generator (EGP-1). The condition was streamlined with the requirements of NSPS Subpart JJJJ.

Condition 40: The condition establishes the visible emission limitations for the emergency generator (EG-1), the emergency fire water pump (FWP-1), and the emergency propane generator (EPG-1).

In addition to the requirements of the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018, the diesel-fired emergency generator (EG-1) and fire water pump (FWP-1) are subject to 40 CFR 60 Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion Engines. NSPS Subpart IIII applies to compression ignition internal combustion engines. The diesel-fired emergency generator (EG-1) and fire water pump (FWP-1) meet the applicability criteria of the rules and are subject to the requirements. The applicable requirements for each unit were incorporated into the PSD permit and have been streamlined into the Article 3 permit. A discussion of the streamlined requirements is provided in the Streamlined Requirements section below.

In addition to the requirements of the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018, the propane-fired emergency generator (EPG-1) is subject to 40 CFR 60 Subpart JJJJ, Standards of Performance for Stationary Spark Ignition Internal Combustion Engines. NSPS Subpart JJJJ applies to spark ignition internal combustion engines. The propane-fired emergency generator (EPG-1) meets the applicability criteria of the rules and is subject to the requirements. The applicable requirements for the unit were incorporated into the PSD permit and have been streamlined into the Article 3 permit. A discussion of the streamlined requirements is provided in the Streamlined Requirements section below.

The diesel-fired emergency generator (EG-1), fire water pump (FWP-1), and propane-fired



emergency generator (EPG-1) are all also subject to 40 CFR 63 Subpart ZZZZ, National Emission Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines. MACT Subpart ZZZZ applies to all reciprocating internal combustion engines. However, each of the units is subject to Regulations under 40 CFR Part 60, and are subject only to limited requirements under MACT Subpart ZZZZ, in accordance with 40 CFR 63.6590 (c). The following limitation is established in the Article 3 permit; the condition number refers to the Article 3 permit:

Condition 62: 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.

The regulatory citations for the NSPS and MACT are streamlined with the applicable PSD permit requirements in the Article 3 permit.



Condition 9: The permittee must 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. The condition was streamlined with the requirements of NSPS Subpart IIII.

Condition 32: The condition outlines the fuel certification requirements for shipments of distillate oil. The condition was streamlined with the requirements of NSPS Subpart IIII

The requirement to install a non-resettable hour meter on emergency generator (EG-1) and the emergency fire water pump (FWP-1) establishes a means of demonstrating compliance with the limitations on the operation of the emergency generator (EG-1) and the emergency fire water pump (FWP-1) in addition to the annual emission limitations.

The recordkeeping requirements include:

- Emission Calculations : The recordkeeping requirement for emission calculations for the emergency generator (EG-1), the emergency fire water pump (FWP-1), and the emergency propane generator (EPG-1) establish a means of demonstrating continuous



compliance with the emission limitations in the permit. Emission factors are provided in Attachment C.

- Hours of operation/Type of operation : The recordkeeping requirement establishes a means of demonstrating compliance with the annual emission limitations and the operational limitation for the emergency generator (EG-1), the emergency fire water pump (FWP-1), and the emergency propane generator (EPG-1). The recordkeeping requirement also establishes a means of demonstrating compliance with the daylight hour restrictions, as well as the operational restrictions established in NSPS Subpart IIII and NSPS Subpart JJJJ.

- Fuel supplier certifications : The fuel supplier certifications establish a means of demonstrating compliance with the fuel sulfur content limitations in the permit. The fuel certifications also establish a means of demonstrating compliance with the NSPS IIII fuel limitations.

- Engine Information / Manufacturer Data : The required engine information and manufacturer data detailed in the permit, establishes a means of demonstrating compliance with the NSPS IIII and NSPS JJJJ limitations for the emergency generator (EG-1), the emergency fire water pump (FWP-1), and the emergency propane generator (EPG-1).

- Conducted maintenance : The required maintenance records establishes a means on demonstrating compliance with the NSPS IIII and NSPS JJJJ requirements to operate and maintain the units in accordance with the manufacturer’s written instructions for the emergency generator (EG-1), the emergency fire water pump (FWP-1), and the emergency propane generator (EPG-1).

- Results of all stack tests and visible emission evaluations : This recordkeeping requirement establishes a means of demonstrating compliance with the testing requirements discussed below.

Testing

The following testing requirements from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B.



CAM is not applicable to the emergency generator (EG-1), the emergency fire water pump (FWP-1), or the emergency propane generator (EPG-1); the units do not meet the applicability criteria in §64.2(a)(2) or (3). The units do not utilize control devices to meet emission



limitations, nor do the units have potential pre-controlled emissions greater than the major source thresholds.


The following requirements from 40 CFR 60 Subpart IIII (Standards of Performance for Compression Ignition Internal Combustion Engines) for the diesel-fired emergency generator (EG-1) have been streamlined in the Article 3 permit:

Citation Requirement Streamlined Reason40 CFR 60.4205

40 CFR 60.4211(c)Emission standards for

emergency stationary RICEIncluded in Condition 38 of the

PSD Permit

40 CFR 60.4207 (b) Fuel requirements Included in Condition 27 of the PSD Permit

40 CFR 60.420640 CFR 60.4211(a)

Maintenance requirements and changes to emission-related

settings

Included in Condition 9 of the PSD Permit

40 CFR 60.4211 (f) Operational limitations Included in Condition 33 of the PSD Permit

The following requirements from 40 CFR 60 Subpart IIII (Standards of Performance for Compression Ignition Internal Combustion Engines) for the fire water pump (FWP-1) have been streamlined in the Article 3 permit:

Citation Requirement Streamlined Reason40 CFR 60.4205

40 CFR 60.4211(c)Emission standards for fire pump

enginesIncluded in Condition 37 of the

PSD Permit

40 CFR 60.4207 (b) Fuel requirements Included in Condition 27 of the PSD Permit

40 CFR 60.420640 CFR 60.4211(a)

Maintenance requirements and changes to emission-related

settings


40 CFR 60.4211 (f) Operational limitations Streamlined with Condition 33 of the PSD Permit

The following requirements from 40 CFR 60 Subpart JJJJ (Standards of Performance for Spark Ignition Internal Combustion Engines) for the propane-fired emergency generator (EPG-1) have been streamlined in the Article 3 permit:


40 CFR 60.4231 (c)40 CFR 60.4233 (c)

Emission Standards - Phase 1 emission standards in 40 CFR 90.103, applicable to class II

engines


40 CFR 60.4234 Maintenance requirements and Streamlined with Condition 10 of




changes to emission-related settings

the PSD Permit and included in Condition 49 of the Article 3

Permit

40 CFR 60.4243 (d) Operational limitations

Streamlined with Condition 33 of the PSD Permit and included in

Condition 55 of the Article 3 Permit

EMISSION UNIT APPLICABLE REQUIREMENTS

Gasoline Dispensing Facility

Limitations

The gasoline fuel cube (ES-4) is subject to the requirements of 40 CFR 63 Subpart CCCCCC - National Emission Standards for Hazardous Air Pollutants for Source Category: Gasoline Dispensing Facilities. The following limitations are established in accordance with the MACT Standards; condition numbers below refer to the Title V permit:

Condition 68: 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.

Condition 69: The requirements for gasoline dispensing facilities with a throughput of less than 10,000 gallons per month are included in this permit Condition.

Monitoring, Recordkeeping, and Reporting

The following monitoring, recordkeeping, and reporting requirements are taken from 40 CFR 63 Subpart CCCCCC. The following requirements are established in accordance with the MACT Standards; condition numbers below refer to the Title V permit:

Condition 70: Monitoring - 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.

Condition 71: Recordkeeping - The condition establishes the other recordkeeping requirements – requirements include: malfunction records, actions



during malfunction, and documentation of gasoline throughput.

The monitoring, recordkeeping, and reporting requirements established in the MACT provide a means of demonstrating continuous compliance with the limitations.

EMISSION UNIT APPLICABLE REQUIREMENTS

Facility-Wide Conditions

Limitations

The following facility-wide limitation is taken from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B:

Condition 78: The condition establishes the maintenance and operating procedures for the facility.

The Source Reduction and Emission Offset condition from the PSD permit (Condition 26 of the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018) was not included in the Article 3 permit; the condition has been fulfilled. See Attachment E for the DEQ’s offset response letter, dated December 16, 2013.


The following recordkeeping requirements are taken from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B:

Condition 79: The condition requires the facility to 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.

Condition 57: The condition establishes the recordkeeping requirements for the facility.

The recordkeeping requirement for scheduled and unscheduled maintenance and operator training establishes a means of demonstrating compliance with the maintenance and operating procedures for the facility.

Testing



The following facility-wide testing requirements are taken from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B:

Condition 58: 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).


GENERAL CONDITIONS

The permit contains general conditions required by 40 CFR Part 72 and 9 VAC 5-80-490, that apply to all acid rain operating permit sources. These include requirements for submitting semi-annual monitoring reports and an annual compliance certification report. The permit also requires notification of deviations from permit requirements or any excess emissions, including those caused by upsets, within four daytime business hours.

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

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 issues Phase II Acid Rain permits pursuant to 9 VAC 5 Chapter 80, Article 3 of the Virginia Regulations for the Control and Abatement of Air Pollution (Article 3 Federal Operating Permit (FOP)).

The facility’s current Article 3 FOP (which includes the facility’s Title V federal operating permit provisions) expired December 31, 2018. The application for renewal of Article 3 FOP was received June 14, 2018. The provisions of the Phase II Acid Rain permit are included as part of this permit.

CROSS STATE AIR POLLUTION RULE (CSAPR)



The applicable requirements of the Cross-State Air Pollution Rule (CSAPR) – also referred to as the Transport Rule (TR) - are incorporated into the permit (Conditions 128 through 137). Specifically, the permittee is subject to the following CSAPR requirements: the TR NOx Annual Trading Program (40 CFR Part 97, Subpart AAAAA), the TR NOx Ozone Season Trading Program (40 CFR Part 97, Subpart BBBBB), and the TR SO2 Group 1 Trading Program (40 CFR Part 97, Subpart CCCCC).

STATE ONLY APPLICABLE REQUIREMENTS

The following State-Only Applicable Requirements are taken from the PSD permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018. The condition numbers below are from the PSD permit; a copy of the permit is enclosed in Attachment B.

Condition 84: The condition establishes the hazardous air pollutant emission limitations for the facility.

Condition 85: The condition establishes the equations used to demonstrate compliance with the hazardous air pollutant emission limitations for the facility.

Condition 86: The condition establishes the recordkeeping requirements to demonstrate compliance with the hazardous air pollutant emission limitations for the facility.

In addition to the State-Only Applicable Requirements from the PSD Permit, the following State Only Applicable Requirement is established in the Article 3 Permit; the condition number below refers to the Article 3 permit:

Condition 138: The State-Only 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 5-80-290 concerning review of proposed permits by EPA and draft permits by affected states.

FUTURE APPLICABLE REQUIREMENTS

None were identified by the applicant.

INAPPLICABLE REQUIREMENTS



The facility did not identify any additional inapplicable requirements in their application.

The following requirements have been identified as inapplicable:

40 CFR 63, Subpart DDDDD, National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers Major Sources has been identified as being not applicable to the facility. The facility is an area source of HAPs; therefore the Boiler MACT for Major Sources is not applicable.

40 CFR 63, Subpart JJJJJJ, National Emission Standards for Hazardous Air Pollutants for Industrial, Commercial, and Institutional Boilers Area Sources has been identified as being not applicable to the auxiliary boiler (B-1) or the pipeline heater (GH-1). The auxiliary boiler (B-1) and pipeline heater (GH-1) are both natural gas-fired and are excluded from MACT Subpart JJJJJJ.

Greenhouse Gas (GHG) Permitting Requirements:There are no applicable GHG permitting requirements

COMPLIANCE PLAN

No compliance plan was included in the application or in the permit.

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

Pollutant(s) Emitted(9 VAC 5-80-720 B)

Rated Capacity(9 VAC 5-80-720 C)

IC-1 Turbine Inlet Chiller Cooling Tower PM 600,000 gal/hr



FC-1 Diesel Fuel Cube VOC 250 gal

FC-2 Diesel Fuel Cube VOC 250 gal

FC-3 Kerosene Fuel Cube VOC 500 gal

ST-1 Distillate oil storage tank 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.

CONFIDENTIAL INFORMATION

The permittee did not submit a request for confidentiality. All portions of the permit application are suitable for public review.

PUBLIC PARTICIPATION

A public notice regarding the draft permit was placed in the Northern Virginia Daily newspaper, in Strasburg, Virginia, on __________. All persons on the Title V mailing list were sent a copy of the public notice by either electronic mail or in letters on ________. The affected states of Maryland and West Virginia were sent a copy of the public notice by either electronic mail or in letter on _____________.

The 30-day public comment period runs from _________ to __________.

The EPA was sent a copy of the draft permit and notified of the public notice on ____________.

ATTACHMENTS



Name of Attachment Contents of AttachmentAttachment A - 2017 Annual Emissions Update

Attachment B - Prevention of Significant Deterioration (PSD) Permit dated 12/17/2010, as amended 10/24/2013, 6/17/2014, and 12/20/2018

Attachment C - Emission Factors and Calculation Methods

Attachment D - Initial Stack Testing Summaries

Attachment E - DEQ’s Offset Response Letter, dated December 16, 2013

Copies of the Attachments are available upon request. Please contact Jeremy Funkhouser at [email protected].

mailto:[email protected]

Documents

Directions in this boilerplate are italicized and are … · Web viewSubpart Dc applies to steam generating units with a maximum design heat input capacity in the range of 10 MMBtu/hr