AECOM (805)388-3775 tel

1220 Avenida Acaso (805)388-3577 fax

Camarillo, CA 93012

Memorandum

To Lisa Bingham and Joe Lapka Page 1

cc Shirley Rivera, Laurie Lile, Tom Barnett, Mike Carroll

Subject Response to EPA Comments on PHPP GHG BACT Analysis 

From Howard Balentine and Sara Head

Date July 15, 2011

A Greenhouse Gas (GHG) Best Available Control Technology (BACT) evaluation for the Palmdale 

Hybrid Power Project (PHPP) was submitted to the U.S. Environmental Protection Agency (EPA) on 

May 9, 2011. On June 27, in a meeting between EPA and the City of Palmdale and its development 

team, EPA asked a number of questions on the submitted GHG BACT Analysis. This supplement to 

the PHPP GHG BACT Analysis was prepared to address the EPA comments. Note, no written 

comments were provided by EPA, and hence the comments shown are based on the notes of the 

attendees. 

Comment 1: 

Please present GHG emission totals in short tons rather than metric tons.

Response:

Tables A-1 and A-2 contained in the GHG BACT analysis submitted to EPA are duplicated below and 

are in emission units of metric tons (MT) per year. The emissions are listed by pollutant (CO2, CH4, 

N2O, and SF6) and for carbon dioxide equivalent (CO2e) for facility total emissions by source. For 

Table A-1, the sources listed are the two combustion turbine generator/heat recovery steam 

generators (CTG/HRSG), auxiliary boiler, heat transfer fluid (HTF) heater, emergency generator, fire 

water pump, SF6 fugitive emissions, and vehicle traffic. Table A-2 presents GHG emissions for 

operational vehicle emissions from light duty diesel, heavy duty diesel, and water trucks. In response 

to EPA’s comment, Tables A-1a and A-2a were prepared that contain the same data as in the original 

Tables A-1 and A-2, but emissions are presented in units of short tons (ST -- one metric ton equals 

1.1023 short tons). 

Comment 2:

Please explain the definition of the thermal efficiency and the derivation of the GHG emission 

performance metric listed in Tables 3 and 4, and clarify whether or not the solar component was 

included quantitatively in these calculations. 
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Response:

Tables 3 and 4 were extracted directly from the California Energy Commission (CEC) Final Staff 

Assessment (FSA). The definition of thermal efficiency used by the CEC in the two tables is the 

amount of heat input required in British Thermal Units (Btu) to generate one kilowatt-hour (kWh) of 

electrical power. We assume the values in the Heat Rate column of both tables were obtained from 

the respective Application for Certification (AFC) filed with the CEC for each facility. The GHG 

performance metric listed in each table for a given facility is simply the heat rate listed in the table 

multiplied by the California Air Resources Board (ARB) defined emission factor for CO2 emissions 

from natural gas combustion, with the appropriate unit conversion factors applied. The ARB emission 

factor for CO2 emissions from natural gas combustion is 53.06 kilograms CO2 per million Btu (MMBtu) 

heat input (see Table A-1, below). The calculation of the GHG performance metric for the PHPP is as 

follows:

PHPP GHG Performance Metric = 6,970 Btu/kWh x 53.06 kg CO2 / MMBtu x MT CO2 /

1,000 kg x 1,000 kWh / MWh x MMBtu / 106 Btu

= 0.370 MT CO2 / MWh (0.408 ST CO2 / MWh)

The above GHG performance metric for the PHPP does not

The heat rate of 6,970 Btu/kWh is based on the higher heating value (HHV) of natural gas with two 

CTGs operating at 100% with no solar input and with no duct firing. A lower heat rate (and hence 

fewer emissions) would be realized for the scenario of full solar and no duct firing, and would depend 

on operating conditions (temperature, pressure, etc.). The 2008 Energy Output of 4,993 GWh shown 

for PHPP in Table 3 is based on the maximum capacity of 570 MW operating for 8,760 hours a year. 

The plant technically could reach the 570 MW capacity in at least two different ways: both CTGs 

operating at 100% with duct firing but no solar or partial firing with full solar. Actual operations and 

conditions will vary from these ideals, as well as the proportion of power generation that occurs during 

the daytime, and hence the PHPP GHG performance metric will vary, and the 0.370 MT CO2 / MWh 

[0.408 ST CO2 / MWh] would be a conservative maximum. The PHPP GHG performance is the top 

level of all power plants shown in the tables even without consideration of the solar component, and 

hence is considered to be BACT for GHG. 

include the efficiency gains associated 

with operation of the solar component of the project. 

Comment 3: 

Since the Business Purpose is used as justification for the exclusion of some GHG reduction 

measures, please define the Business Purpose of the PHPP.

Response:

The business purpose of the PHPP is to generate 570 megawatts (MW) of electrical power within the 

City of Palmdale in an efficient manner while increasing the reliability of the electrical supply for the 

City of Palmdale. As stated in the Section 4 (Alternatives) of the AFC, the Project objectives are:

• Provide an efficient, reliable and environmentally sound power generating facility to meet future 

electrical power needs of the rapidly growing City of Palmdale and surrounding areas, as well as 

provide additional generating capacity for the region and state.
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• Locate the facility within the boundaries of the City of Palmdale and under City ownership and 

control. The City can, thereby, increase its level of assurance that residential, commercial, and 

industrial power needs in the City can be met, while at the same time supplying power to the 

regional grid.

• Use solar technology to generate a portion of the facility’s power output and thereby support the 

State of California’s goal of increasing the percentage of renewable energy in the state’s 

electricity mix.

• Integrate the solar component of the Project and its combined-cycle component in a way that 

maximizes the synergies between the two technologies to increase Project efficiency. The 

PHPP will send steam (generated from the solar thermal Project component) to the HRSG that 

is part of the “conventional” combined-cycle equipment. This allows the Project to operate with 

only one steam turbine generator (STG) rather than separate STGs for the Project’s combinedcycle and solar components.

• Site the facility in a location zoned and planned for industrial use in an industrial area and with 

ready access both to adequate supplies of non-potable water to meet the facility’s process water 

needs and to a natural gas pipeline that can supply the Project, without requiring significant 

modifications to the regional gas supply system.

As stated above, the primary business objective of PHPP is to generate 570 MW of electrical power in 

an efficient and reliable manner, within the City of Palmdale. Section 3.1.2 of the PHPP GHG BACT 

Analysis dismissed some lower emitting technologies, e.g., wind, solar, geothermal, hydroelectric, 

nuclear and biomass plants because they cannot meet the above business objectives. As stated in the 

Alternatives section of the CEC’s PHPP Final Staff Assessment (p 6-6), these technologies cannot meet 

these business objectives for the following reasons:

• “California law currently prohibits the construction of any new nuclear power plants in California.

• Geothermal and hydroelectric alternatives were determined not to be viable options, as there are 

no adequate geothermal or hydrological resources located near the City of Palmdale.

• Wind power is not considered a feasible alternative as the area around City of Palmdale is not 

identified as a productive area for development of commercial wind power, and wind turbines 

may interfere with the operations of U.S. Air Force Plant 42.

• Feedstock for biomass power would likely have to be transported over long distances from 

agricultural residues in California’s Central Valley, and lacking sufficient feedstock in the greater 

Palmdale area, biomass is not a practical alternative.

• An all-solar energy facility would not fully meet the project objectives to provide a reliable source 

of power generation that would supply electrical energy night and day.” (CEC PHPP FSA, 2010), 

Additionally, a site large enough to produce 570 MW (roughly 3,000 acres) from solar only is not 

available or feasible for the City of Palmdale. 
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Comment 4: 

An emission limit is only proposed for CO2. Please demonstrate that this limit is an adequate 

surrogate for the control of other GHGs.

Response:

As stated in Section 1.3 of the PHPP GHG BACT Analysis, there are six covered GHGs under the 

GHG Tailoring Rule: Carbon dioxide (CO2), Methane (CH4), Nitrous Oxide (N2O), Hydrofluorcarbons 

(HFCs), Perfluorocarbons (PFCs), and Sulfur hexafluoride (SF6).

An emission limitation on CO2 is an adequate surrogate for the other combustion related GHGs, i.e., 

N2O and CH4. EPA natural gas combustion emission factors for CO2, CH4, and N2O are all expressed 

in common units of kg/MMBtu of heat input. The emission factors are 53.06, 0.0059, and 0.0001 

kg/MMBtu, respectively. The global warming potentials (GWP) for the three pollutants are 1.0, 21, and 

310, respectively. On a CO2e equivalent basis, a single emission factor that takes into account the 

respective GWPs can readily be computed as the sum-product of the emission factors and 

corresponding GWPs. This equivalent emission factor, adjusted for GWP of the respective 

components, is 53.21 kg CO2e/MMBtu. Therefore, an emission limit that limits the natural gas 

consumed in a power plant has the effect of limiting CO2e emissions of CO2, CH4, and N2O on a basis 

proportional to their respective GWPs. In a similar fashion, monitoring of CO2 is expected to act as a 

surrogate for these other GHGs. 

HFCs, PFCs, and SF6 are not associated with direct power production but rather are used in 

equipment that support the operation of the facility including building air conditioning equipment for 

personnel comfort, emergency protection involving fire suppression systems, and transformers, circuit 

breakers and other electrical equipment, respectively. HFCs are primarily used as a heat transfer 

medium in building air conditioning systems. PFCs are used primarily as a fire suppression agent in 

emergency fire protection systems and releases of PFCs occur during maintenance activities, from 

leakage, and during operation of the fire suppression systems in emergency situations. There are a 

number of PFCs with global warming potentials but not all are regulated as a GHG. The specific PFCs

used for a given application depends on that application and the design of the fire suppression 

equipment. It is unknown what specific PFCs may be present in fire suppression systems at the 

PHPP after it is constructed. SF6 gas is used to insulate transformers for applications where a nonflammable transformer and reliable power reception is desired in urban facilities, as well as used in 

circuit breakers. Since no oil for insulation is used, these transformers can be completely free 

structures and do not have potential for oil contamination during new installation work or system 

operation.

Any air conditioning, fire suppression system or electrical equipment that are installed at PHPP will 

meet standards in place for such equipment at the time of manufacture for leak rates of HFCs, PFCs 

and SF6 during operation, maintenance or standby. PHPP will follow applicable procedures to 

minimize release of any covered GHGs during maintenance activities. Because of the negligible 

emissions of these GHGs, emission limits or specific control strategies other than purchase of 

equipment that meet appropriate standards and proper maintenance are considered impracticable. 
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Comment 5: 

Table A-1 should list each GHG, i.e., CO2, CH4, N2O and SF6 separately, in addition to CO2e.

Response:

Tables A-1 and A-2 (and new Tables A-1a and A-2a) list emissions separately by source and 

separately by CO2, CH4, N2O and SF6, in addition to CO2e (see response to comment 1).

Comment 6: 

Identify if there are any existing CO2 pipelines in California.

Response:

The Technical Advisory Committee for the California Carbon Capture and Storage Review Panel 

stated in an August 2010 report that there are no existing CO2 pipelines in California. In addition, 

there are no CO2 pipeline projects underway in California subject to the California Environmental 

Quality Act (CEQA), based on a search of the CEQA State Clearinghouse CEQAnet database 

maintained by the California Office of Planning and Research. The California Carbon Capture and 

Storage Review Panel document can be obtained at the following link:

http://www.climatechange.ca.gov/carbon_capture_review_panel/meetings/2010-08-

18/white_papers/Carbon_Dioxide_Pipelines.pdf

We also contacted the Department of Oil, Gas, and Geothermal Resources (DOGGR) and facility 

operators in Kern County, and did not find existing CO2 pipelines in California.

Comment 7:

What information was used as the basis for the discussion of the feasibility of Carbon Capture and 

Sequestration (CCS) with respect to the Hyperion Energy Center project GHG BACT findings?

Response:

An internet search was conducted to identify other potentially relevant GHG BACT evaluations. The 

attached Publication by the law firm of Vinson & Elkins was the source of the information cited in the 

PHPP GHG BACT Analysis. Other information was not readily available for this proposed project. 

Comment 8:

Please express the CO2 BACT limit in terms of tons per year.

Response:

Section 3.5, Step 5 – Select BACT in the submitted BACT analysis establishes a BACT limit of 

930,000 metric tons of CO2 per year per combustion turbine generating unit, rounded to two significant 

figures. When converted to short tons, the BACT limit for each combustion turbine generating unit is 

1,020,000 shorts tons per year, rounded to three significant figures. As presented in response to 
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comment 4, this BACT limit is equivalent to 53.21 kg CO2e/MMBtu (117.2 lb CO2e/year) per each 

combustion turbine unit per year.

Comment 9:

Provide more specifics on what measures will be taken to maximize thermal efficiency in the 

combustion turbines (see EPA Whitepaper).

Response:

The EPA Whitepaper entitled “Available and Emerging Technologies for Reducing Greenhouse Gas 

Emissions from Coal-Fired Electric Generating Units” was reviewed. No GHG emission reduction 

measures were identified in this EPA document that are applicable to the PHPP combustion turbines. 

The EPA Whitepaper document is designed to 

...summarize readily available information on control techniques and measures 

to mitigate greenhouse gas emissions from specific industrial sectors. 

As stated in the document title, the EPA whitepaper is focused exclusively on efficiency improvements 

in coal-fired electric generating units (EGUs). Gas-fired combustion turbines are not addressed in the 

document. 

The PHPP is proposed to use General Electric’s (GE) advanced gas turbine technology with Rapid 

Start Process. GE has touted (press release in 2009 at http://www.reuters.com/article/2009/10/27/usutilities-ge-idUSTRE59Q2AS20091027) that “a typical combined-cycle plant using two new 7FA gas 

turbines with a single steam turbine would save $2.1 million per year at a gas price of $6 per million 

British thermal units, compared to a plant with GE's existing 7FA turbine. The more efficient power 

plant would also avoid emissions of 19,000 metric tons of CO2 annually compared to the earlier 

version, the equivalent of the heat-trapping emissions of nearly 3,800 cars, according to GE. We have 

amassed technological advances from across our expansive portfolio of power generating and aviation 

turbines and delivered them in this upgraded 7FA turbine," said John Reinker, general manager of gas 

turbine products for GE Energy. Natural gas power plants emit only about half the CO2 of traditional 

coal-fired plants.”

In general, use of natural gas as fuel is considered to be the lowest-emitting and most thermally 

efficient method of fossil-fuel fired power generation. Purchase of new advanced, gas-fired technology 

will be PHPP’s primary strategy to maximize the thermal efficiency of the combustion turbines. Proper 

maintenance of the equipment, as defined by the manufacturer, is necessary and required by the 

permits (see CEC Condition of Certification AQT-2) to meet all of the applicable pollutant emissions 

standards and limits that will be imposed at PHPP, and will be performed.

Comment 10:

Provide more specifics on what measures will be taken to maximize the thermal efficiency of the 

auxiliary boiler and heater (see EPA Whitepaper).

Response:

The EPA Whitepaper entitled “Available and Emerging Technologies for Reducing Greenhouse Gas 

Emissions from Industrial, Commercial, and Institutional Boilers” was reviewed and no additional GHG 
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emission reduction measures were identified in the EPA document that are applicable to the PHPP 

auxiliary boiler and HTF heater. The EPA Whitepaper document is designed to:

...summarize readily available information on control techniques and measures 

to mitigate greenhouse gas emissions from specific industrial sectors. 

However, the document is focused entirely on GHG emission reduction measures for existing

It should be noted that the HTF heater and the auxiliary boilers are not continuous-use devices but 

rather have limited operating cycles based on their specialized functions. The HTF heater will only 

operate during colder periods for no more than 1,000 hours per year to prevent the HTF fluid from 

solidifying, while the auxiliary boiler will operate for no more than 500 hours per year to provide 

preheat steam during startup conditions only. Due to their limited duty cycles, there would be very 

limited benefit of any potential new add-on controls beyond those inherent in a newly-constructed 

device. The limited CO2 reduction benefit will result in a very high cost per ton of CO2 incremental 

reduction and the applicable add-on controls have been eliminated from further consideration in the 

PHPP GHG BACT Analysis. 

industrial, commercial, and institutional (ICI) boilers, as stated in the paragraph introducing the table 

that summarizes available GHG emission reduction measures from ICI sources. 

For PHPP, there is a presumption that the measures listed in the EPA Whitepaper Table 1 will be 

incorporated into new manufactured boilers and heaters such as burners using new technologies, 

modern computer optimized instrumentation and controls, and new designs that increase efficiency. 

PHPP’s use of new, efficient equipment, fired exclusively with pipeline quality natural-gas, and with 

limited hours of operation, constitutes BACT for GHG. 

Determining GHG emissions from the boiler and heater can be done based on operating hours. 

Operating hours can be accurately measured, and the amount of greenhouse gas equivalents can be 

calculated based on well-established emissions factors. Both the boiler and HTF heater at PHPP are 

required by the CEC and AVAQMD permit to include non-resettable hour timers.

Comment 11:

Please address GHG BACT for internal combustion engines and SF6 leakage.

Response:

As shown in Table A-1a, the combustion of natural gas for project power production from the 

combustion turbines and associated duct burners, auxiliary boiler, and HTF heater is responsible for 

99.7 percent of facility GHG CO2e emissions. Because of the negligible cumulative amount of CO2e 

emitted by SF6 leakage and other minor sources, any analysis of the cost per ton of controlled GHG 

emissions will yield a very large number given the very small denominator (i.e., emission reduction) 

and very large numerator (i.e., cost of control) in the cost effectiveness equation. Therefore, a full 

GHG BACT analysis was not performed for the negligible GHG emission sources at this facility, i.e., 

the emergency generator engine, the fire water pump engine, or SF6 leakage. However, discussed as 

follows, PHPP satisfies BACT for internal combustion engines and SF6 leakage. 
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The internal combustion engines at PHPP will include an emergency generator and a fire water pump 

engine. These engines will have the potential to emit combustion related greenhouse gases (CO2, 

CH4, and N2O). Control of GHG emissions from diesel engines is achieved by burning clean fuels, 

optimizing the combustion technology to minimize the amount of fuel used during operation, and by 

minimizing operation of the engines. There are no add-on post-combustion controls for GHG 

emissions which are currently technically feasible for diesel engines

Internal Combustion Engines

1

Both of these PHPP engines will be limited to operate for 50 or fewer hours per year for weekly 

readiness testing, and produce trivial amounts of CO2e when compared to the combustion turbine 

generators. The engines will comply with the current Federal and California Tier level at the time of 

purchase. In addition, fire water pump engines must meet applicable National Fire Protection 

Association (“NFPA”) standards for reserve horsepower capacity, engine cranking systems, engine 

cooling systems, fuel type instrumentation and control and exhaust systems. The only means to 

reduce GHG emissions from a diesel-fired internal combustion engine is to improve the efficiency of 

the engine, which is the overall objective of establishing Tier categories for an engine. The 

procurement of a specialty engine that exceeds the applicable Tier level efficiency, if commercially 

available, would not be cost effective because of the trivial amount of GHG reduction that would result 

and the high cost of the specialty engine. Therefore, GHG BACT for the PHPP internal combustion 

engines is the applicable Tier category/emission standard as of the time of purchase of the engines.

. When there are no other 

options to evaluate in a BACT analysis, the 5 step top down process is not needed. 

Determining GHG emissions from these engines can be done based on operating hours. Operating 

hours can be accurately measured, and the amount of greenhouse gas equivalents can be calculated 

based on well-established emissions factors. Both engines are required by the CEC and AVAQMD 

permit to include non-resettable hour timers.

The Project transformers and circuit breakers will have the potential for fugitive emissions of sulfur 

hexafluoride (SF6) via leaks. The reduction in leakage of SF6 from electrical equipment/transformers is 

inherent in the design of the electrical component and is not amenable to aftermarket controls due to 

the nature of the electrical system containing the SF6. The current guaranteed emission factor for 

leakage of SF6 used in the emission computations given in Appendix A of the PHPP GHG BACT 

Analysis is 0.5 percent per year, and can be as low as 0.2 percent per year (but not guaranteed). The 

electrical equipment (transformers and circuit breakers) purchased for the PHPP that contains SF6 will 

meet the current standards set by EPA, and guaranteed by the manufacturer, for leakage of SF6 for 

that equipment as of the date of the purchase of the equipment. The SF6 leakage rate guaranteed by 

the manufacturer thereby establishes GHG BACT. For the PHPP application, there is estimated to be 

160 pounds of SF6 within electrical equipment. Therefore, BACT for SF6 from electrical equipment is 

0.5 percent per year, or for PHPP, or a maximum emission of 10 short tons per year CO2e. 

SF6 Leakage 

 

1 BAAQMD Additional Statement of Basis for the Draft Federal PSD Permit for the Russell City Energy 

Center, August 2009. 
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STEP 1: Identify Control Technologies for SF6 

Step 1 of the Top-Down BACT analysis is to identify all feasible control technologies. 

One alternative considered is to use a technology that does not employ SF6 dielectric material in the 

circuit breakers. For instance, use of a dielectric oil or compressed air (“air blast”) circuit breakers, 

which historically were used in high-voltage installations prior to the development of SF6 breakers. 

However, this technology is considered out-dated, takes more space, and is not as reliable.

Another alternative considered is to substitute another, non-greenhouse-gas substance for SF6 as the 

dielectric material in the breakers. SF6 has become the predominant insulator and arc quenching 

substance in circuit breakers today because of its superior capabilities. There are ongoing research 

efforts to identify alternative materials and technologies to replace the properties of SF6 in circuit 

breakers without the potential for GHG emissions; however no such material or technology has been 

developed as of this time1

.

Another control measure considered is to use state-of-the-art technology that uses SF6 but with leak 

detection to limit fugitive emissions. In comparison to older SF6 circuit breakers, modern breakers are 

designed as a totally enclosed-pressure system with far lower potential for SF6 emissions. The best 

modern equipment can be guaranteed to leak at a rate of no more than 0.5% per year (by weight). In 

addition, the effectiveness of leak-tight closed systems can be enhanced by equipping them with a 

density alarm that provides a warning when 10% of the SF6 (by weight) has escaped. The use of an 

alarm identifies potential leak problems before the bulk of the SF6 has escaped, so that it can be 

addressed proactively in order to prevent further release of the gas.

STEP 2: Eliminate Technically Infeasible Options 

As noted above, the use of outdated air blast or oil technology is not considered feasible as a practical 

matter due to its inferior performance, need for larger area, and other factors. 

Use of a substitute for SF6 is also considered infeasible, since no viable alternates are available. 

According to a report released by the EPA SF6 Partnership (as cited by BAAQMD for Russell City), 

“[n]o clear alternative exists for this gas that is used extensively in circuit breakers, gas-insulated 

substations, and switch gear, due to its inertness and dielectric properties.” Research and 

development efforts have focused on finding substitutes for SF6 that have comparable insulating and 

arc quenching properties in high-voltage applications. While some progress has reportedly been made 

using mixtures of SF6 and other inert gases (e.g., nitrogen or helium) in lower-voltage applications, 

most studies have concluded, “that there is no replacement gas immediately available to use as an 

SF6 substitute for high-voltage applications. Therefore, this alternative is eliminated as technically 

infeasible. 

Enclosed-pressure SF6 circuit breakers with leak detection, which are far smaller than oil/air-blast 

breakers for the same application, are feasible for this PHPP.

STEP 3: Rank Control Technologies 

Only feasible alternatives are ranked, and in this case, only one feasible alternative was found. 

According to information from circuit breaker manufacturers, this equipment can be guaranteed to 

achieve a leak rate of 0.5% or less. This leak rate meets the maximum leak rate standard established 

by the International Electrotechnical Commission (“IEC”). This leak rate performance will be further 

enhanced by an alarm system to alert operators to potential leak problems as soon as they emerge. 
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STEP 4: Evaluate Most Effective Controls and Economic Impacts and Document Results 

Step 4 of the top-down analysis involves consideration of the ancillary energy, environmental and 

economic impacts associated with using the top-ranked control technologies. Oil/air-blast circuit 

breakers were eliminated at the start of this analysis as not technically feasible due to being outdated 

technology. The use of the larger oil/air-blast breakers would have significant ancillary environmental 

impacts that would offset its greenhouse gas benefits, even if it were feasible. Oil/air-blast breakers 

would require additional land to be devoted to the project, would generate additional noise, and would 

increase the risks of accidental releases of dielectric fluid and/or associated fires. By contrast, 

according to the National Institute for Standards and Technology, SF6 “offers significant savings in 

land use, is aesthetically acceptable, has relatively low radio and audible noise emissions, and 

enables substations to be installed in populated areas close to the loads.” Accordingly, even if oil/airblast breakers were not eliminated at the start of the top-down analysis, they would not surpass the 

choice of SF6 breakers in Step 4 because of their adverse ancillary environmental impacts. 

STEP 5: Select BACT 

Based on this top-down analysis, the only technically feasible control technologies for SF6 circuit 

breakers are the use of state-of-the-art, totally enclosed-pressure equipment equipped with leak 

detection systems. Totally enclosed-pressure systems can be guaranteed with a leakage rate less 

than 0.5% by weight per year. Density alarms can also be used in conjunction with such systems to 

identify SF6 leaks quickly so that corrective actions can be taken in time to limit the release. The use of 

enclosed-pressure SF6 circuit breakers equipped with leak detection is the only technically feasible 

and available GHG control technologies for the Project.

Fugitive emissions are, by their nature, very difficult to monitor directly as they are not emitted from a 

discrete emissions point. Fugitive SF6 emissions can be estimated accurately, however, by measuring 

“top-ups”, i.e., the replacement of lost SF6 with new product. One can conservatively assume that the 

amount of SF6 that has leaked and entered the atmosphere is the amount that has to be topped up to 

maintain a full SF6 level. 
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Table A-1 Estimated Potential Greenhouse Gas (GHG) Emissions

Source

Annual Usage Emission Factor GHG Emissions Total CO2 

Equivalents 

(c)

MMBtu/yr gallons/yr

CO2 CH4 N2O CH4 N2O CO2 CH4 N2O SF6

kg GHG/MMBtu (a) kg GHG/gallon (b) metric tons/year

CTG/HRSG 1 17,356,845 -- 53.06 0.0059 0.0001 -- -- 920,954 102 1.74 924,000

CTG/HRSG 2 17,356,845 -- 53.06 0.0059 0.0001 -- -- 920,954 102 1.74 924,000

Auxiliary 

Boiler

50,000 -- 53.06 0.0059 0.0001 -- -- 2,653 0.30 5.00E-03 2,660

HTF Heater 40,000 -- 53.06 0.0059 0.0001 -- -- 2,122 0.24 4.00E-03 2,130

Emergency 

Generator

341 2,633 73.15 -- -- 0.0003 0.0001 25 2.63E-04 2.63E-04 25

Fire Water 

Pump Engine

50 390 73.15 -- -- 0.0003 0.0001 4 3.90E-05 3.90E-05 4

SF6 in circuit 

breakers

3.63E-04 8.67

Vehicles 10 1.00E-03 1.19E-03 10.3

TOTAL 1,846,722 205 3.48 3.63E-04 1,852,000

Notes: 

(a) Table C.6, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

(b) Table C.7, Industrial Sector, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

(c) Rounded to three significant digits, however, emission limits should be rounded up to two significant digits. 

Diesel fuel heat content, British thermal units (Btu)/gallon - 129,500

Global warming potential of CH4, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008 - 21

Global warming potential of N2O, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008 - 310

Global warming potential of SF6, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008 - 23900
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Table A-2 GHG Emissions from On-Site Vehicular Traffic – Operation

Activity Amount Units

Heavy-duty truck trips 136 miles/yr

Light-duty vehicle trips 19,200 miles/yr

Water rinse truck 600 miles/yr

Heavy heavy -duty truck gas mileage 5.37 mpg

Light-duty vehicle gas mileage 19.1 mpg

Reference: EMFAC2007 V2.3 November 1, 2006, KCAPCD Burden 2009

Activity Annual 

Miles 

Traveled

Annual 

Fuel Use

Emission Factor 

Category

Emission Factor GHG Emissions

CO2 CH4 N2O CO2 CH4 N2O CO2e

miles/yr gal/yr kg/gal g/mile g/mile metric tons/year

Heavy-duty truck trips 136 25 HDT diesel 1996+ 

model year

9.96 0.06 0.05 0.25 0.0000 0.0000 0.25

Light-duty truck trips 19,200 1,003 LDT gasoline 2000+ 

model year

8.55 0.05 0.06 8.6 0.0010 0.0012 9.0

Water rinse truck 600 112 HDT diesel 1996+ 

model year

9.96 0.06 0.05 1.11 0.0000 0.0000 1.12

Total 19,936 1,141 9.95 0.00 0.00 10.33

Key: GHG = greenhouse gas; mpg = miles per gallon; HDT = Heavy duty truck; LDT = Light duty truck; gal = gallons; kg = kilogram; g = gram; yr = year.
AECOM

60138827-040GB-S July 2011

13

Table A-1a Estimated Potential Greenhouse Gas (GHG) Emissions (short tons/year)

Source

Annual Usage Emission Factor GHG Emissions Total CO2 

Equivalents 

(c)

MMBtu/yr gallons/yr

CO2 CH4 N2O CH4 N2O CO2 CH4 N2O SF6

kg GHG/MMBtu (a) kg GHG/gallon (b) short tons/year

CTG/HRSG 1 17,356,845 -- 53.06 0.0059 0.0001 -- -- 1,020,000 112 1.92 1,020,000

CTG/HRSG 2 17,356,845 -- 53.06 0.0059 0.0001 -- -- 1,020,000 112 1.92 1,020,000

Auxiliary 

Boiler 50,000 -- 53.06 0.0059 0.0001 -- -- 2,920 3.31E-01 5.51E-03 2,930

HTF Heater 40,000 -- 53.06 0.0059 0.0001 -- -- 2,340 2.65E-01 4.41E-03 2,350

Emergency 

Generator 341 2,633 73.15 -- -- 0.0003 0.0001 27.6 8.70E-04 2.90E-04 27.6

Fire Water 

Pump Engine 50 390 73.15 -- -- 0.0003 0.0001 4.41 1.29E-04 4.30E-05 4.41

SF6 in circuit 

breakers 4.00E-04 9.56

Vehicles 11.0 1.10E-03 1.31E-03 11.4

TOTAL 2,040,000 0 0 0 2,040,000

Notes: 

(a) Table C.6, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

(b) Table C.7, Industrial Sector, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

(c) Rounded to three significant digits, however, emission limits should be rounded up to two significant digits. 

Diesel fuel heat content, British thermal units (Btu)/gallon - 129,500

Global warming potential of CH4, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008 - 21

Global warming potential of N2O, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008 - 310

Global warming potential of SF6, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008 - 23900
AECOM

60138827-040GB-S July 2011

14

Table A-2a GHG Emissions from On-Site Vehicular Traffic – Operation (short tons/year)

Activity Amount Units

Heavy-duty truck trips 136 miles/yr

Light-duty vehicle trips 19,200 miles/yr

Water rinse truck 600 miles/yr

Heavy heavy -duty truck gas mileage 5.37 mpg

Light-duty vehicle gas mileage 19.1 mpg

Reference: EMFAC2007 V2.3 November 1, 2006, KCAPCD Burden 2009

Activity Annual 

Miles 

Traveled

Annual 

Fuel Use

Emission Factor 

Category

Emission Factor GHG Emissions

CO2 CH4 N2O CO2 CH4 N2O CO2e

miles/yr gal/yr kg/gal g/mile g/mile short tons/year

Heavy-duty truck trips 136 25 HDT diesel 1996+ 

model year 9.96 0.06 0.05 0.276 0.0000 0.0000 0.276

Light-duty truck trips 19,200 1,003 LDT gasoline 2000+ 

model year 8.55 0.05 0.06 9.50 0.0011 0.0013 9.92

Water rinse truck 600 112 HDT diesel 1996+ 

model year 9.96 0.06 0.05 1.22 0.0000 0.0000 1.23

Total 19,936 1,141 11.0 0.0011 0.0013 11.4

Key: GHG = greenhouse gas; mpg = miles per gallon; HDT = Heavy duty truck; LDT = Light duty truck; gal = gallons; kg = kilogram; g = gram; yr = year.
First Greenhouse Gas PSD Permits Issued by State Regulatory Agencies

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First Greenhouse Gas PSD Permits Issued by State Regulatory Agencies

V&E U.S. Environmental Law Update E-communication, March 21, 2011

On January 2, 2011, EPA’s Tailoring Rule first required certain stationary sources to obtain prevention of

significant deterioration (PSD) permits for their greenhouse gas (GHG) emissions. Accordingly, over the

last few months, the first Best Available Control Technology (BACT) determinations for GHG emissions

have been completed by state agencies as part of the PSD permitting process. Most notably, the

Louisiana Department of Environmental Quality (LDEQ) finalized a PSD permit addressing BACT for

GHG emissions from Nucor Steel’s direct reduced iron facility and the South Dakota Department of

Environment and Natural Resources (SD-DENR) proposed a PSD permit addressing GHG BACT for

Hyperion Energy’s greenfield petroleum refinery project. 

LDEQ Issues PSD Permit Addressing GHG Emissions from Nucor Steel’s Direct Reduced Iron

Facility

On January 27, 2011, LDEQ issued the nation’s first PSD permit containing GHG emission limitations to

Nucor Steel for the construction of a direct reduced iron facility that will supply Nucor’s existing pig iron

plant. The permit contains GHG BACT limitations for package boilers and the main flue gas stack. For

the package boilers, LDEQ determined that BACT for GHG emissions would be satisfied by

implementing good combustion practices, which decrease fuel use and increase combustion efficiency.

These practices “typically entail introducing the proper ratio of combustion air to the fuel, maintaining a

minimum temperature in the firebox of the combustor, or a minimum time of fuel and air residence in the

combustion zone.” For the main flue gas stack, LDEQ determined that good combustion practices, acid

gas separation, and energy integration were all required elements of BACT for GHG emissions. Overall,

the permit specified BACT for GHG emissions as a limitation on the amount of natural gas consumed for

every ton of direct reduced iron produced over a 12-month rolling-average.

It is particularly noteworthy that EPA Region 6 provided comments on LDEQ’s draft permit for the Nucor

facility criticizing LDEQ’s BACT analysis for, among other things, failing to consider carbon capture and

sequestration (CCS) as an available control technology. Specifically, EPA requested that LDEQ provide

a basis for why CCS was not considered an available control technology or, alternatively, if it was

considered available, why it was not considered technically feasible. In response to EPA’s comments,

LDEQ explained that it had considered both dedicated sequestration (injection of CO into an on-site or

nearby geological formation) and transport and sequestration as part of its BACT analysis. Specifically,

LDEQ explained that because it had determined that there are no promising geological formations for

CO injection and storage “at or very near” the facility location, it concluded that dedicated sequestration

was technically infeasible. As for transport and sequestration, LDEQ explained that while there is an

existing, dedicated CO pipeline in the general area of the proposed facility, it concluded that “the

feasibility of connecting to [the] CO pipeline, both from a logistical and an economic perspective, is, at

best, unknown.” LDEQ also expressed concern over imposing a permit condition that would require

Nucor to contract with a specific, unregulated third party for the transport of CO , stating that such a

condition, “regardless of the individual circumstances, is beyond the scope of the BACT

determination.” According to LDEQ, it is for this reason that transport and sequestration was eliminated

from further consideration in the BACT analysis.

South Dakota Proposes PSD Permit Addressing GHG Emissions from Hyperion Energy’s

Petroleum Refinery Project

On February 14, 2011, SD-DENR issued a draft PSD permit for a 400,000 barrel per day greenfield

petroleum refinery proposed by Hyperion Energy. The permit covers the refinery and an associated

integrated gasification combined cycle (IGCC) plant that will power the refinery’s operations. As

discussed in its statement of basis for the permit, SD-DENR conducted an extensive analysis of BACT

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First Greenhouse Gas PSD Permits Issued by State Regulatory Agencies

http://www.velaw.com/resources/FirstGreenhouseGasPSDPermitsIssuedStateRegulatoryAgencies.aspx[7/1/2011 6:39:07 PM]

for GHG emissions, including consideration of CCS. According to SD-DENR’s analysis, the

implementation of CCS at the Hyperion refinery would require an additional 400 Megawatts (MW) of

power generation capacity for gas drying and boosting, and these additional energy demands would

have to be met by increasing the size of the IGCC facility or building a separate power facility solely for

CCS operations. SD-DENR further concluded that the additional power generation capacity required to

run CCS would significantly increase emissions of conventional pollutants, increase energy demands,

and emit 23 percent of the GHG emissions that the CCS was designed to capture. Ultimately, SDDENR rejected CCS as BACT for GHG emissions based on these factors and its high costs.

The other GHG control options considered by SD-DENR in its BACT analysis were eliminating selective

catalytic reduction (SCR), terrestrial sequestration through the planting of vegetation on vacant portions

of the site, and implementation of good combustion practices. Because elimination of SCR would

increase NO emissions, SD-DENR determined that it did not constitute BACT for GHG emissions.

SD-DENR also eliminated terrestrial sequestration after concluding that its contribution to reducing GHG

emissions would be “negligible.”

To determine whether Hyperion’s other proposed measures, which included good combustion practices

and energy efficiency measures incorporated into the plant design, were BACT, SD-DENR determined

that it needed to compare Hyperion’s projected GHG emissions to those of other refineries. Accordingly,

SD-DENR calculated the GHG emissions for each barrel of crude oil refined for facilities in California

using the California state emissions inventory and data from the Energy Information Administration, and

ultimately concluded that the most appropriate refinery for comparison was Chevron’s El Segundo

refinery because it had the lowest emission rate per barrel of refined product. Through its comparison,

SD-DENR found that Hyperion’s projected GHG emissions per barrel of crude oil refined were equivalent

to those of Chevron’s El Segundo facility, and therefore concluded that Hyperion’s proposed measures

constitute BACT for GHG emissions.

On March 3, 2011 EPA Region 8 requested that SD-DENR extend the comment period on the Hyperion

refinery draft PSD permit for 15 days to allow time for EPA Region 8 to coordinate the review of SDDENR’s GHG BACT analysis with EPA’s regional and headquarters personnel to ensure national

consistency. In response, SD-DENR extended the deadline for public comments on the Hyperion draft

permit to April 1, 2011.

For more information, please contact Vinson & Elkins lawyers Chris Thiele or Margaret Peloso.

Visit our website to learn more about V&E's Environmental practice, or e-mail one of the practice

contacts. 

1 For a full explanation of the GHG permitting requirements for stationary sources under EPA’s “Tailoring Rule” see 

 Paulina Williams and Jenifer Sutter, 2010: EPA Completes First Major Greenhouse Gas Rulemaking Initiatives, 

 14 V&E Climate Change Report 1 (2011). 

2 PSD-LA-751, Authorization to Construct and Operate a New Facility/Modified Major Source, Jan. 27, 2011. 

3 Id. at 38.

4 Id. at 50.

5 Id. at 50.

6 Letter from Jeffery Robinson, EPA Region 6, to Tegan Treadway, LDEQ, Jan. 7, 2011 at 6.

7 LDEQ Office of Environmental Services, Public Comments Response Summary at 30.

8 Id.

9 Id. at 31.

10 Id.

11 Statement of Basis at 38.

12 Id. at 39-40.

13 Id.

14 Id. at 37.

15 Id. at 40.

16 Id.

17 Id. at 43.

18 Id. at 44.

19 Letter from Deborah Lebow-Aal, EPA Region 8, to Brian Gustafson, SD-DENR, March 3, 2011.

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