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Pio Pico Energy Center (SD 11-01) 

PSD Permit 

February 2014

PIO PICO ENERGY CENTER (SD 11-01)

PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

PERMIT CONDITIONS 

PROJECT DESCRIPTION 

The Pio Pico Energy Center (Project) consists of three General Electric (GE) LMS100 natural 

gas-fired combustion turbine-generators (CTGs) rated at 100 megawatt each. The Project will 

have an electrical output of 300 MW. The Project will be located in an unincorporated area of 

San Diego County known as Otay Mesa. The Project’s footprint is a 9.99 acre parcel located at 

7363 Calzada de la Fuente in the Otay Mesa Business Park. The site is located within the San 

Diego County Air Pollution Control District (SDAPCD, or District). 

This Prevention of Significant Deterioration (PSD) permit for the Project requires the use of Best 

Available Control Technology (BACT) to limit emissions of nitrogen oxides (NOX), total 

particulate matter (PM), particulate matter 10 micrometers ( m) in diameter and smaller (PM10), 

particulate matter 2.5 m in diameter and smaller (PM2.5), and greenhouse gases (GHG), to the 

greatest extent feasible. Air pollution emissions from the Project will not cause or contribute to 

violations of any National Ambient Air Quality Standards (NAAQS) or any applicable PSD 

increments for the pollutants regulated under the PSD permit. 
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EQUIPMENT LIST 

The following devices and activities are subject to this PSD permit: 

Unit ID Description 

Turbine 1 i 100 MW (nominal net) combustion turbine generator (CTG), with a maximum 

heat input rate of 903 MMBtu/hr (HHV) 

i Natural gas-fired GE Model LMS100 CTG 

i Emissions of NOX controlled by water injection, Selective Catalytic Reduction 

(SCR) 

Turbine 2 i 100 MW (nominal net) combustion turbine generator (CTG), with a maximum 

heat input rate of 903 MMBtu/hr (HHV) 

i Natural gas-fired GE Model LMS100 CTG 

i Emissions of NOX controlled by water injection, Selective Catalytic Reduction 

(SCR) 

Turbine 3 i 100 MW (nominal net) combustion turbine generator (CTG), with a maximum 

heat input rate of 903 MMBtu/hr (HHV) 

i Natural gas-fired GE Model LMS100 CTG 

i Emissions of NOX controlled by water injection, Selective Catalytic Reduction 

(SCR) 

Partial Dry 

Cooling 

System 

i Dry cooling component with a nominal 9,600 gallons per minute (GPM) 

maximum circulation rate, supplemented by 23,520 GPM wet cooling 

component. 

i Total dissolved solids (TDS) concentration in wet cooling circulation water of 

< 5,000 ppm (500 mg/L) 

i Drift eliminator with drift losses less than or equal to 0.001 percent based on 

wet cooling water circulation rate 

Circuit 

Breakers 

i 3 switchyard and 2 generator breakers containing SF6 

PERMIT CONDITIONS 

I. PERMIT EXPIRATION

As provided in 40 CFR § 52.21(r), this PSD Permit shall become invalid if construction: 

A. is not commenced (as defined in 40 CFR § 52.21(b)(9)) within 18 months after 

the approval takes effect; or 

B. is discontinued for a period of 18 months or more; or 
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C. is not completed within a reasonable time. 

II. PERMIT NOTIFICATION REQUIREMENTS

The Permittee shall notify EPA Region IX by letter or by electronic mail of the: 

A. date construction is commenced, postmarked within 30 days of such date; 

B. actual date of initial startup, as defined in 40 CFR § 60.2, postmarked within 15 

days of such date; 

C. date upon which initial performance tests will commence, in accordance with the 

provisions of Condition IX.G, postmarked not less than 30 days prior to such date. 

Notification may be provided with the submittal of the performance test protocol 

required pursuant to Condition IX.G; and 

D. date upon which initial performance evaluation of the continuous emissions 

monitoring system (CEMS) will commence in accordance with 40 CFR §

60.13(c), postmarked not less than 30 days prior to such date. Notification may 

be provided with the submittal of the CEMS performance test protocol required 

pursuant to Condition IX.G. 

III. FACILITY OPERATION

At all times, including periods of startup, shutdown, shakedown, and malfunction, the 

Permittee shall, to the extent practicable, maintain and operate the facility that is subject 

to this PSD permit (Facility), including associated air pollution control equipment, in a 

manner consistent with good air pollution control practice for minimizing emissions. 

Determination of whether acceptable operating and maintenance procedures are being 

used will be based on information available to EPA, which may include, but is not 

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

procedures and inspection of the Facility. 

IV. MALFUNCTION REPORTING

A. The Permittee shall notify EPA at AEO_R9@epa.gov within two (2) working 

days following the discovery of any failure of air pollution control equipment or 

process equipment, or failure of a process to operate in a normal manner, which 

results in an increase in emissions above any allowable emission limit stated in 
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Section IX of this permit. 

B. In addition, the Permittee shall provide an additional notification to EPA in 

writing or electronic mail within fifteen (15) days of any such failure described 

under Condition IV.A. This notification shall include a description of the 

malfunctioning equipment or abnormal operation, the date of the initial 

malfunction, the period of time over which emissions were increased due to the 

failure, the cause of the failure, the estimated resultant emissions in excess of 

those allowed in Section IX, and the methods utilized to mitigate emissions and 

restore normal operations. 

C. Compliance with this malfunction notification provision shall not excuse or 

otherwise constitute a defense to any violation of this permit or any law or 

regulation such malfunction may cause. 

V. RIGHT OF ENTRY

The EPA Regional Administrator, and/or an authorized representative, upon the 

presentation of credentials, shall be permitted: 

A. to enter the premises where the Facility is located or where any records are 

required to be kept under the terms and conditions of this PSD Permit; 

B. during normal business hours, to have access to and to copy any records required 

to be kept under the terms and conditions of this PSD Permit; 

C. to inspect any equipment, operation, or method subject to requirements in this 

PSD Permit; and 

D. to sample materials and emissions from the source(s). 

VI. TRANSFER OF OWNERSHIP

In the event of any changes in control or ownership of the Facility, this PSD Permit shall 

be binding on all subsequent owners and operators. Within 14 days of any such change 

in control or ownership, the Permittee shall notify the succeeding owner and operator of 

the existence of this PSD Permit and its conditions by letter. The Permittee shall send a 

copy of this letter to EPA Region IX within thirty (30) days of its issuance. 

VII. SEVERABILITY
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The provisions of this PSD Permit are severable, and, if any provision of the PSD Permit 

is held invalid, the remainder of this PSD Permit shall not be affected. 

VIII. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER 

ENVIRONMENTAL LAWS

The Permittee shall construct the Project in compliance with this PSD permit, the 

application on which this permit is based, and all other applicable federal, state, and local 

air quality regulations. This PSD permit does not release the Permittee from any liability 

for compliance with other applicable federal, state and local environmental laws and 

regulations, including the Clean Air Act. 

IX. SPECIAL CONDITIONS

A. Air Pollution Control Equipment and Operation 

As soon as practicable following initial startup of each turbine (startup as defined 

in 40 CFR § 60.2) but prior to commencement of commercial operation of that 

turbine (as defined in 40 CFR § 72.2), and thereafter, except as noted below in 

Condition IX.C, the Permittee shall install, continuously operate, and maintain the 

water injection system and SCR system for control of NOX on Turbine 1, Turbine 

2, and Turbine 3. The Permittee shall also perform any necessary operations to 

minimize emissions so that emissions are at or below the emission limits specified 

in this permit. 
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B. Emission Limits 

1. The Permittee shall not discharge or cause the discharge of emissions from 

each CTG (Turbine 1, Turbine 2, and Turbine 3) into the atmosphere in excess 

of the following limits. The emission limits in this condition shall apply at all 

times, except as described in Condition IX.I, and for NOx only, the alternate 

emission limits in Condition IX.C shall apply during startup and shutdown, 

after which the limits in this condition shall apply: 

Pollutant Emission Limit (per CTG) 

NOX

i 2.5 ppmvd @ 15% O2

i 1-hr average 

i 8.18 lb/hr 

PM, PM10, and 

PM2.5

i 0.0053 lb/MMBtu (HHV) 

i 5.0 lb/hr 

i PUC-quality natural gas 

(sulfur content of no 

greater than 0.25 grains per 

100 dscf on a 4-calendar 

quarter rolling average and 

not greater than 1.0 gr per 

100 dscf at any time) 

CO2

i 1,328 lbs/MWh gross 

output 

i 720 rolling operating-hour 

average 

2. CO2e emissions from the circuit breakers shall not exceed 40.2 tons per 

calendar year. 

3. The Permittee shall install, operate, and maintain enclosed-pressure SF6 

circuit breakers with a maximum annual leakage rate of 0.5% by weight. 

C. Requirements during Gas Turbine (Turbine 1, Turbine 2, and Turbine 3) 

Startup and Shutdown Periods 

The CTG NOX emission limits in Condition IX.B.1 shall not apply during CTG 

startup and shutdown periods. During these periods, the following requirements 

shall apply: 

1. The CEMS shall be in operation during each startup and shutdown period. 

2. Duration of startups and shutdowns of each CTG (Turbine 1, Turbine 2, 
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and Turbine 3) shall not exceed 30 and 11 minutes, respectively, per 

occurrence. 

3. Total number of startups shall not exceed 500 per turbine, per calendar 

year. 

4. For CTGs, “initial startup” is defined as the first fire of each unit. 

5. Startup is defined as the period beginning with ignition and ending 30 

minutes later. 

6. Shutdown is defined as the period beginning with the initiation of 

combustion turbine shutdown sequence and lasting until fuel flow is 

completely off and combustion has ceased. 

7. NOX emissions during startup or shutdown from each CTG shall not 

exceed 26.6 lb/hr based on a 1-hr average. 

8. NOx emissions from each CTG shall not exceed 22.5 pounds per startup 

event, or 6.0 pounds per shutdown event. 

D. Operational Limits

1. The annual quantity of fuel for each turbine (Turbine 1, Turbine 2, and 

Turbine 3) shall not exceed 3,914,556 MMBtu (HHV) in any 12-month 

rolling period. 

2. When a combustion turbine is operating, ammonia shall be injected whenever 

the SCR catalyst outlet temperature exceeds 575 degrees F. 

3. The cooling tower drift rate shall not exceed 0.001%; and the maximum total 

dissolved solids (TDS) shall be less than 5,000 ppm. 

4. Within 60 days after achieving normal operation, but not later than 180 days 

after the initial startup of equipment, each CTG (Turbine 1, Turbine 2, and 

Turbine 3) shall achieve an initial heat rate at full load that does not exceed 

9,196 Btuhhv/kWhgross. 

5. The circuit breakers shall be equipped with a 10% by weight leak detection 

system. The leak detection system shall be calibrated in accordance with 

manufacturer’s specifications. The manufacturer’s specifications and records 

of all calibrations shall be maintained on site. 

6. The Permittee shall prepare and follow a Maintenance Plan for each CTG. 

The Maintenance Plan shall follow manufacturer’s written instructions or 

operator-developed procedures that provide, to the extent practicable, for the 

maintenance and operation of the turbine in a manner consistent with good air 
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pollution control practice for minimizing emissions. The Maintenance Plan 

shall include, but not be limited to, the following requirements: 

a. Annual maintenance shall be performed no less frequently than once every 

four calendar quarters and shall include: 

i. Generator testing 

ii. Boroscope inspection of turbine passes 

iii. Control system check 

b. Major overhaul shall be conducted as recommended by the manufacturer, 

at every 25,000 operating hours (or other period recommended in writing 

by the manufacturer). 

E. Fuel Use 

1. To fire Turbines 1, 2 and 3, the Permittee shall use only Public Utilities 

Commission (PUC)-pipeline quality natural gas with a sulfur content that (1) 

is less than or equal to 0.25 grains per 100 dscf on a four-calendar quarter 

rolling average, and (2) shall not at any time exceed 1.0 grains per 100 dscf. 

2. For each turbine, the Permittee shall keep a monthly record of the quantity of 

natural gas used in Turbine 1, Turbine 2, and Turbine 3. 

3. The Permittee shall sample and record the sulfur content of the natural gas 

fuel on a quarterly basis. As an alternative, the Permittee may obtain 

laboratory analysis of sulfur content from the fuel supplier on a quarterly 

basis, if the Permittee can demonstrate that the fuel tested is representative of 

fuel delivered to the facility. 

4. The fuel sulfur content of the natural gas shall be determined using any of the 

following test methods: ASTM D1072, D3246, D4468, D5504 or D6667. 

F. Continuous Emissions Monitoring System (CEMS) for Turbines 

1. Before Turbines 1, 2, and 3 commence commercial operation (as defined in 

40 CFR § 72.2), the Permittee shall install and calibrate CEMS to measure 

stack gas NOX, and O2 concentrations and a continuous monitoring system 

(CMS) to monitor exhaust gas flow and moisture content and to calculate 

CO2 emission rates to demonstrate compliance with the emission limits in 

Conditions IX.B.1, IX.C.7, and IX.C.8. CO2 emissions shall be calculated 

using the procedures set forth in 40 CFR Part 75. 

2. The CEMS and CMS required by this permit shall be installed, calibrated, 
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operated, audited, tested, and maintained in accordance with the 

manufacturers’ recommendations and the appropriate performance standards 

and quality assurance requirements in the appendices of either 40 CFR part 

60 or 40 CFR part 75. 

3. The Permittee shall reduce CEMS and CMS data to one-hour averages in a 

manner meeting the specifications in 40 CFR § 60.13(h) for all operating 

hours, including startup and shutdown. For startup and shutdown periods, 

the permittee shall record emission rates in one-minute increments. 

4. No later than 90 days after commencement of commercial operation, the 

Permittee shall submit to EPA a CEMS and CMS quality assurance plan. 

The plan shall specify how the Permittee will demonstrate compliance with 

emission limits in Conditions IX.B.1, IX.C.7, and IX.C.8, including 

emission limits that apply during startup and shutdown. 

5. The Permittee shall perform for each CEMS: 

a. Daily calibration checks, 

b. Quarterly linearity checks with a relative accuracy within ± 5%, and 

c. Relative accuracy test audits (RATA) during every fourth consecutive 

operating quarter (a calendar quarter in which there are at least 168 

clock hours during which a turbine combusts any fuel, either for part 

of the hour or for the entire hour), or during every 8th consecutive 

calendar quarter, whichever occurs first. The monitors shall meet a 

Relative Accuracy of less than 20%. 

6. The Permittee shall perform initial RATAs no later than the initial 

performance test for the associated emission unit. 

7. The Permittee shall submit RATA test plans and reports of RATA test 

results to EPA as described in Condition IX.G.1.h. 

8. The Permittee shall maintain the following records for at least five years 

from the date of origin: 

a. One-hour averages calculated pursuant to Condition IX.G.3, 

b. The results of all calibration and linearity checks, and 

c. RATA test plans and reports of test results. 
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G. Performance Tests

1. Stack Tests 

a. Within 60 days after achieving normal operation, but not later than 180 

days after the initial startup of equipment, the Permittee shall conduct 

performance tests (as described in 40 CFR § 60.8) as follows: 

i. NOX, CO2, PM, PM10, and PM2.5 emissions from each gas turbine 

(Turbine 1, Turbine 2, and Turbine 3). The Permittee shall also 

conduct subsequent performance tests during every fourth consecutive 

operating quarter (a calendar quarter in which there are at least 168 

clock hours during which a turbine combusts any fuel, either for part 

of the hour or for the entire hour), or during every 8th consecutive 

calendar quarter, whichever occurs first. 

ii. PM, PM10, and PM2.5 emissions from the cooling tower. 

iii. Heat rate performance according to the requirements of the American 

Society of Mechanical Engineers Performance Test Code on Overall 

Plant Performance (ASME PTC 22). The Permittee shall also conduct 

subsequent performance tests during every fourth consecutive 

operating quarter (a calendar quarter in which there are at least 168 

clock hours during which a turbine combusts any fuel, either for part 

of the hour or for the entire hour), or during every 8th consecutive 

calendar quarter, whichever occurs first. 

b. The Permittee shall submit a performance test protocol to EPA no later 

than 30 days prior to the test to allow review of the test plan and to arrange 

for an observer to be present at the test. The performance test shall be 

conducted in accordance with the submitted protocol, and any changes 

required by EPA. 

c. Performance tests shall be conducted in accordance with the test methods 

set forth in 40 CFR § 60.8 and 40 CFR Part 60 Appendix A, as modified 

below. In lieu of the specified test methods, equivalent methods may be 

used with prior written approval from EPA: 

i. EPA Methods 1-4 and 7E for NOX emissions measured in ppmvd 

ii. EPA Methods 1-4, 7E, and 19 for NOX emissions measured on a heat 

input basis 

iii. EPA Methods 1-4 and 3A for CO2 emissions 

iv. EPA Method 5 for filterable PM, PM10 and PM2.5, and Method 202 for 

condensable PM10 and PM2.5, collecting a minimum of 120 dry 

standard cubic feet per test run (4 hours). In lieu of Method 202, the 

Permittee may use EPA Conditional Test Method CTM-039. 
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v. Modified Method 306 or Cooling Technology Institute Acceptance 

Test Code (ATC 140) - Isokinetic Drift Measurement Test Code for 

Water Cooling Tower (also referred to as the Heated Bead Isokinetic 

test procedure) for PM emissions from the wet cooling tower, and 

vi. the provisions of 40 CFR § 60.8 (f). 

d. The initial performance test conducted after initial startup shall use the test 

procedures for a “high NO2 emission site,” as specified in San Diego Test 

Method 100, to measure NOX emissions. The source shall be classified as 

either a “low” or “high” NO2 emission site based on these test results. If 

the emission source is classified as a: 

i. “high NO2 emitting site,” then each subsequent performance test shall 

use the test procedures for a “high NO2 emission site,” as specified in 

San Diego Test Method 100. 

ii. “low NO2 emitting site,” then the test procedures for a “high NO2

emission site,” as specified in San Diego Test Method 100, shall be 

performed once every five years to verify the source's classification as 

a “low NO2 emission site.”

e. The performance test methods for NOX emissions specified in Condition 

IX.G.1.c.i and ii., may be modified as follows: 

i. Perform a minimum of 9 reference method runs, with a minimum time 

per run of 21 minutes, at a single load level, between 90 and 100 

percent of peak (or the highest physically achievable) load, and 

ii. Use the test data both to demonstrate compliance with the applicable 

NOX emission limit and to provide the required reference method data 

for the RATA of the CEMS. 

f. Upon written request and adequate justification from the Permittee, EPA 

may waive a specific annual test and/or allow for testing to be done at less 

than maximum operating capacity. 

g. For performance test purposes, sampling ports, platforms, and access shall 

be provided on the emission unit exhaust system in accordance with the 

requirements of 40 CFR § 60.8(e). 

h. The Permittee shall furnish EPA with a written report of the results of 

performance tests within 60 days of completion. 

2. Cooling Tower Total Dissolved Solids Testing 

a. The Permittee shall perform weekly tests of the blow-down water quality 

using an EPA-approved method. This weekly test shall not be required for 

any 7-day period in which the wet cooling tower is not in operation, 

provided that the Permittee maintains a log of wet cooling tower 
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operation. 

b. The Permittee shall maintain a log that contains the date and result of each 

blow-down water quality test, and the resulting mass emission rate. This 

log shall be maintained onsite for a minimum of five years and shall be 

provided to EPA and District personnel upon request. 

c. The Permittee shall calculate the PM, PM10, and PM2.5 emission rates 

using an EPA-approved calculation based on the TDS and water 

circulation rate. 

d. The Permittee shall conduct all required cooling tower water quality tests 

in accordance with an EPA-approved test and emissions calculation 

protocol. Thirty (30) days prior to the first such test, the Permittee shall 

provide a written test and emissions calculation protocol for EPA review 

and approval, and send a copy to the District. 

e. A maintenance procedure shall be established that states how often and 

what procedures will be used to ensure the integrity of the drift 

eliminators, to ensure that the TDS limits are not exceeded, and to ensure 

compliance with recirculation rates. This procedure is to be kept onsite 

and made available to EPA and District personnel upon request. The 

Permittee shall promptly report any deviations from this procedure. 

H. Recordkeeping and Reporting 

1. The Permittee shall maintain a file of all records, data, measurements, reports, 

and documents related to operation of the Facility. All records shall be in a 

permanent form suitable for inspection. 

2. The Permittee shall maintain CEMS records that include the following: the 

occurrence and duration of any startup, shutdown, or malfunction, 

performance testing, evaluations, calibrations, checks, adjustments, 

maintenance, duration of any periods during which a CEMS is inoperative, 

and corresponding emission measurements. 

3. The Permittee shall maintain records of the hours of operation for each turbine 

(Turbine 1, Turbine 2, and Turbine 3), on a monthly basis. 

4. The Permittee shall maintain records and submit a written report of all excess 

emissions and any other noncompliance with permit conditions to EPA for 

each six-month reporting period from January 1 to June 30 and from July 1 to 

December 31, except when more frequent reporting is specifically required by 

an applicable subpart, or EPA, on a case-by-case basis, determines that more 

frequent reporting is necessary to accurately assess the compliance status of 

the source. The report shall be postmarked by the 30th day following the end 

of each semi-annual period and shall include the following: 
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a. Time intervals, data and magnitude of the excess emissions, the nature 

and cause (if known), corrective actions taken and preventive 

measures adopted; 

b. Applicable time and date of each period during which the CEMS was 

inoperative (monitor down-time), except for zero and span checks, and 

the nature of CEMS repairs or adjustments; 

c. A statement in the report of a negative declaration; that is, a statement 

when no excess emissions occurred or when the CEMS has not been 

inoperative, repaired, or adjusted; 

d. Any failure to conduct any required source testing, monitoring, or 

other compliance activities; and 

e. Any violation of limitations on operation, including but not limited to 

restrictions on hours of operation. 

5. Excess emissions shall be defined as any period in which any turbine exceeds 

any emission limits set forth in this permit. 

6. A period of monitor down-time shall be defined as any unit operating clock 

hour in which sufficient data are not obtained by the CEMS to validate the 

hour for NOX, CO2, or O2, while the CEMS is also meeting the requirements 

of Condition IX.F.3. 

7. Excess emissions indicated by the CEM system, source testing, or compliance 

monitoring shall be considered violations of the applicable emission limit for 

the purpose of this permit. 

8. All records required by this PSD Permit shall be retained for not less than five 

years following the date of such measurements, maintenance, reports, and/or 

records. 

9. The Permittee shall measure and record the following for each CTG (Turbine 

1, Turbine 2, and Turbine 3) on an hourly basis: 

a. Gross energy output (MWhgross); 

b. Pounds of CO2 per gross energy output (lb CO2/MWhgross); 

c. The 720-operating hour rolling average emission rate of lb 

CO2/MWhgross based on the average hourly recordings. 

10. The Permittee shall maintain a log describing maintenance and repair 

activities, including the following information: 

a. Date of activity 

b. Description of activity 

c. For scheduled maintenance, the elapsed time, hours of 
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turbine operation, or other applicable measure since the 

activity was last performed. 

d. For scheduled maintenance, the elapsed time, hours of 

turbine operation, or other applicable measure until the 

activity should next be performed. 

11. The Permittee shall calculate the SF6 emissions due to leakage from the 

circuit breakers by using the mass balance in equation DD-1 at 40 CFR Part 

98, Subpart DD on an annual basis. Records of such calculations shall be 

maintained on site. 

I. Shakedown Periods 

The combustion turbine emission limits and requirements in Conditions IX.B, 

IX.C and IX.D shall not apply during combustion shakedown periods. Shakedown 

is defined as the period beginning with initial startup as defined in Condition 

IX.C.4 and ending no later than initial performance testing, during which the 

Permittee conducts operational and contractual testing and tuning to ensure the 

safe, efficient and reliable operation of the plant. The shakedown period shall not 

exceed 90 consecutive days. The requirements of Section III of this permit shall 

apply at all times. 

X. AGENCY NOTIFICATIONS 

All correspondence as required by this Approval to Construct must be sent to: 

A. Director, Air Division (Attn: AIR-5) 

EPA Region IX 

75 Hawthorne Street 

San Francisco, CA 94105-3901 

Email: AEO_R9@epa.gov

Fax: (415) 947-3579 

With a copy to: 

B. Air Pollution Control Officer 

San Diego County Air Pollution Control District 

10124 Old Grove Road 

San Diego, CA 92131-1649 

Fax: (858) 586-2701 
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XI. ACROYNMS AND ABBREVIATIONS

Act Clean Air Act [42 U.S.C. Section 7401 et seq.] 

Agency U.S. Environmental Protection Agency 

BACT Best Available Control Technology 

BTU British thermal units 

CAA Clean Air Act [42 U.S.C. Section 7401 et seq.] 

CEMS Continuous Emissions Monitoring System 

CMS Continuous Monitoring System 

CFR Code of Federal Regulations 

CO Carbon Monoxide 

CO2e Carbon Dioxide Equivalent 

CTG Combustion Turbine Generator 

GE General Electric 

GHG Greenhouse Gas (Greenhouse Gases) 

g/hp-hr grams per horsepower-hour 

gr/scf Grains per Standard Cubic Feet 

EAB Environmental Appeals Board 

EPA U.S. Environmental Protection Agency 

GHG Greenhouse Gases 

HHV Higher Heating Value 

HP Horsepower 

kW Kilowatts of electrical power 

kWhr Kilowatt-hour 

mg/L Milligrams per liter 

μg/m3 Microgram per Cubic Meter 

MMBTU Million British thermal units 

MW Megawatts of electrical power 

NAAQS National Ambient Air Quality Standards 

NESHAPS National Emission Standards for Hazardous Air Pollutants 

NMHC Non-methane Hydrocarbons 

NO Nitrogen oxide or nitric oxide 

NO2 Nitrogen dioxide 

NOx Oxides of Nitrogen (NO + NO2) 

NP National Park 

NSPS New Source Performance Standards, 40 CFR Part 60 

NSR New Source Review 

O2 Oxygen 

PM Total Particulate Matter 

PM2.5 Particulate Matter less than 2.5 micrometers ( m) in diameter 

PM10 Particulate Matter less than 10 micrometers ( m) in diameter 

PPEC Pio Pico Energy Center 

PPM Parts per Million 
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PPMVD Parts per Million by Volume, on a Dry basis 

PSD Prevention of Significant Deterioration