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 Green house 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 A nalysis. 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 s hown are based on the notes of the attendees.

Comment 1 :
Please present GHG emission totals in short tons rather than m etric t ons.
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 (CO 2 

### , CH 4 

### , N 2 

### O, and SF 6 

### ) and for carbon dioxide equivalent (CO 2 

### e) for facility total emissions by source. For Table A

- 1, the sources listed are the two combustion turbine generato r/heat recovery steam generators (CTG/HRSG), auxiliary boiler, heat transfer fluid (HTF) heater, emergency generator, fire water pump, SF 6 

### fugitive emissions, and vehicle traffic. Table A

- 2 presents GHG emissions for operational vehicle emissions from lig ht 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 to n 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 quantitativel y in these calculations

.AECOM

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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 requir ed 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 facili ty. 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 CO 2 

### emissions from natural gas combustion, with the app ropriate unit conversion factors applied. The ARB emission factor for CO 2 

### emissions from natural gas combustion is 53.06 kilograms CO 2 

### per million Btu (MMBtu) heat input (see Table A

- 1, below). The calculation of the GHG performance metric for the PHPP i s as follows:

PHPP GHG Performance Metric = 6,970 Btu/kWh x 53.06 kg CO 2 

### / MMBtu x MT CO 2 

### / 1,000 kg x 1,000 kWh / MWh x MMBtu / 10 6 

### Btu

= 0.370 MT CO 2 

### / MWh (0.408 ST CO 2 

### / MWh)

T he 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 r ate (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 maxi mum capacity of 570 MW operating for 8,760 hours a year. The plant technically c ould 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 a nd 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 CO 2 

### / MWh [0.408 ST CO 2 

### / MWh] would be a conservative maximum. T he 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 efficienc y gains associated with operation of the solar component of the project

.

Comment 3 :
Since the Business Purpose is used as justification for the exclu sion of some GHG reduction measures, p lease define the Business Purpose of the PHPP.

Response:
The business purpose of the P HPP is to generate 570 megawatts (MW) of electrical power within the City of Palmdale in an efficient manner while increasing the re liability 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 pow er needs of the rapidly growing City of Palmdale and surrounding areas, as well as provide additional generating capacity for the region and state.AECOM

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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 p ower 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 synerg ies 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 wit h only one steam turbine generator (STG) rather than separate STGs for the Project’s combined

cycle 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 supp lies 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 o f 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, nuclea r 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:

**•** “Calif ornia 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 Forc e 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 (rou ghly 3,000 acres) from solar only is not available or feasible for the City of Palmdale.AECOM

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### Comment 4 :
An emission limit is only proposed for CO 2 

### . Please demonstrate that this limit is an adequate surrogate for the control of other GHGs

. Response:

As sta ted in Section 1.3 of the PHPP GHG BACT Analysis, there are six covered GHGs under the GHG Tailoring Rule: Carbon dioxide ( CO 2 

### ), Methane (CH 4 

### ), Nitrous Oxide (N 2 

### O), Hydrofluorcarbons (HFCs)
, Perfluorocarbons (PFCs), and Sulfur hexafluoride (SF 6 

### )

.
An emis sion limitation on CO 2 

### is an adequate surrogate for the other combustion related GHGs, i.e., N 2 

### O and CH 4 

### . EPA natural gas combustion emission factors for CO 2 

### , CH 4 

### , and N 2 

### O 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 re adily 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 CO 2 

### , CH 4 

### , and N 2 

### O on a basis proportional to their respective GWPs. In a similar fashion, monitoring of CO 2 

### is expected to act as a surrogate for these other GHGs.

HFCs
, PFCs , and SF 6 

### are no t associated with direct power production but rather are used in equi pment that support the operation of the facility including building air conditioning equipment for personnel comfort
, emergency protection involving fire suppression systems , and transfor mers , 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 relea ses 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 PFC s
u sed 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 transfo rmers for applications where a non

flammable 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 t ransformers 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 manufactu re 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 li mits or specific control strategies other than purchase of equipment that meet appropriate standards and proper maintenance are considered impracticable.AECOM

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### Comment 5 :

Table A

- 1 should list each GHG, i.e., CO 2 

### , CH 4 

### , N 2 

### O and SF 6 

### 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 CO 2 

### , CH 4 

### , N 2 

### O and SF 6 

### , in addition to CO2e (see response to comment 1).

Comment 6 :
Identify if there are any existing CO 2 

### pipelines i n 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 CO 2 

### pipelines in California. In addition, there are no CO 2 

### pipeline projects und erway 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 Revi ew Panel document can be obtained at the following link:
http://www.climatechange.ca.gov/carbon_capture_review_panel/meet ings/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 CO 2 

### pipelines in California.

Comment 7:

What informat ion 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 relevan t 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 t he CO 2 

### 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 CO 2 

### per year per combustion turbine generating unit, rounded to two significant figur es. 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 toAECOM

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### comment 4, this BACT limit is equivalent to 53.21 kg CO2e/MM Btu (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 “Avai lable and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal

- Fired Electric Generating Units” was reviewed . N o GHG emission reduction measures were identified in th is 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 exc lusively 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 Pro cess. GE has touted (press release in 2009 at http://www.reuters.com/article/2009/10/27/us

utilities

- 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 CO 2 

### 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, g eneral manager of gas turbine products for GE Energy. Natural gas power plants emit only about half the CO 2 

### of traditional coal

- fired plants.”
In general, use of natural gas as fuel is considered to be the lowest

- emitting and most thermally efficient meth od of fossil

- fuel fired power generation. Purchase of new advanced , gas
- fired technology wi ll be PHPP’s primary strategy to maximize the thermal efficiency of the combustion turbines. Proper maintenance of the equipment, as defined by the manufacturer, i s 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 measur es 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 I nstitutional Boilers” was reviewed and no additional GHGAECOM

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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 avail able 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 l imited 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 CO 2 

### re duction benefit will result in a very high cost per ton of CO 2 

### incremental reduction and the applicable add

- on controls have be en eliminated from further consideration in the PHPP GHG BACT A nalysis. 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, t here is a presumption that the measures list ed in the EPA Whitepaper Table 1 will be incorporated into new manufactured boilers and heaters such as burner s using new technologies, modern computer optimized instrumentation and controls, and new designs that increase efficiency. PHPP’s use of new, ef ficient equipment, fired exclusively with pipeline quality natural

- gas, and with limited hours of operation, constitute s BACT for GHG.

D etermining GHG emissions from the boiler and heater can be done based on operating hours

. Operating hours can be accura tely 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 SF 6 

### 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 heate r is responsible for 99.7 percent of facility GHG CO 2 

### e emissions. Because of the negligible cumulative amount of CO2e emitted by SF 6 

### leakage and other minor sources, any analysis of the cost per ton of controlled GHG emissions will yield a very large numb er 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 facil ity, i.e., the emergency generator engine, the fire water pump engine, or SF 6 

### leakage. However, discussed as follows, PHPP satisfies BACT for internal combustion engines and SF 6 

### leakage.AECOM

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### The internal combustion engines at PHP P will include an emergency generator and a fire water pump engine. These engines will have the potential to emit combustion related greenhouse gases (CO 2 

### , CH 4 

### , and N 2 

### O)

. Control of GHG emissions from diesel engines is achieved by burning clean fuels, op timizing 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 o f 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 engine s 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. T he only means to reduce GHG emissions from a diesel

- fired internal combustion engine is to impr ove 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 avail able, 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 e ngines. . When there are no other options to evaluate in a BACT analysis, the 5 step top down process is not needed.

D etermining 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 (SF 6 

### ) via leaks. The reduction in leakage of SF 6 

### 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 SF 6 

### . The current guaranteed emission factor for leakage of SF 6 

### used in the emission computations given in Appendix A of the PHPP GHG BACT A nalysis 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 SF 6 

### will meet the current standard s set by EPA, and guaranteed by the manufacturer, for leakage of SF 6 

### for that equipment as of the date of the purchase of the equipment. The SF 6 

### leakage rate guaranteed by the manufacturer thereby e stablishes GHG BACT. For the PHPP application, there is estimated to be 160 pounds of SF 6 

### within electrical equipment. Therefore, BACT for SF 6 

### from electrical equipment is 0.5 percent per year, or for PHPP, or a maximum emission of 10 short tons per year CO2e. SF 6 

### Leakage

1 

### BAAQMD Additional Statement of Basis for the Draft Federal PSD Permit for the Russell City Energy Center, Aug ust 2009.AECOM

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### STEP 1 **: Identify Control Technologies for SF** 6
Step 1 of the Top

- Down BACT analysis is to identify all feasible control technologies.

One alternative considered is to u se a technology that does not employ SF 6 

### d i e l e c t r i c m a t e r i a l in the circuit breakers. For instance, use of a dielectric oil or compressed air (“air blast”) circuit breaker s , which historically were used in high

- voltage installations prior to the development of SF 6 

### breakers. However, this technology is considered out

- d ated, 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. SF 6 

### has become the predominant insulator and arc quenching substance i n circuit breakers today because of its superior capabilities. There are ongoing research efforts to identify alternative materials and technologies to replace the properties of SF 6 

### in circuit breakers without the potential for GHG emissions; however no s uch material or technology has been developed as of this time 1



### .
Another control measure considered is to use state

- of

- the

- art technology that uses SF 6 

### but with leak detection to limit fugitive emissions. In comparison to older SF 6 

### circuit breakers, modern breakers are designed as a totally enclosed

- pressure system with far lower potential for SF 6 

### 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 cl osed systems can be enhanced by equipping them with a density alarm that provides a warning when 10% of the SF 6 

### (by weight) has escaped. The use of an alarm identifies potential leak problems before the bulk of the SF 6 

### has escaped, so that it can be addres sed 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, nee d for larger area, and other factors.

Use of a substitute for SF 6 

### is also considered infeasible, since no viable alternates are available. According to a report released by the EPA SF 6 

### Partnership (as cited by BAAQMD for Russell City)
, “[n]o clear altern ative 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 SF 6 

### that have com parable insulating and arc quenching properties in high

- voltage applications. While some progress has reportedly been made using mixtures of SF 6 

### and other inert gases ( e.g ., nitrogen or helium) in lower

- voltage applications, most studies have concluded, “t hat there is no replacement gas immediately available to use as an SF 6 

### substitute for high

- voltage applications. T herefore , thi s alternative is eliminated as technically infeasible.

E nclosed

- pressure SF 6 

### 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 ci rcuit 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.AECOM

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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. O il/air

- blast circuit breakers were eliminated at the start of this analysis as not technically feasible due to being outdated technology. T he 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, woul d 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, SF 6 

### “offers significant savings in land use, is aes thetically acceptable, has relatively low radio and audible noise emissions, and enables substations to be installed in populated areas close to the lo ads.” Accordingly, even if oil/air

blast breakers were not eliminated at the start of the top

- down analys is, they would not surpass the choice of SF 6 

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

STEP 5 **: Select BACT**

Based on this top

- down analysis, t he only technically feasible control technologies for SF 6 

### 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 conjunctio n with such systems to identify SF 6 

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

- pressure SF 6 

### circuit breakers equipped with leak detection is the only technically feasible and available GHG contro l 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 SF 6 

### emissions can be estimated accurately, however, by measuring “top

- ups”, i.e
., the replacement of lost SF 6 

### with new product. One can conservatively assume that the amount of SF 6 

### that has leaked and entered the atmosphere is the amount that has to be topped up to maintain a full SF 6 

### level.AECOM

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### Table A

- 1 Estimated Potential Greenhouse Gas (GHG) Emissions

Source Annual Usage Emission Factor GHG Emissions Total CO 2 Equivalents (c) MMBtu/yr gallons/yr CO 2 CH 4 N 2 O CH 4 N 2 O CO 2 CH 4 N 2 O SF 6
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

SF 6 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 CH 4 , Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

- 21 Global warming potential of N 2 O, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

- 310 Global w arming potential of SF 6 , Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

- 23900AECOM

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### Table A

- 2 GHG Emissions from On

- Site Vehicular Traffic

– Operation
Activity Amount Units
Heavy

- duty truck trips 136 mile s/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 T raveled Annual Fuel Use Emission Factor Category Emission Factor GHG Emissions

CO 2 CH 4 N 2 O CO 2 CH 4 N 2 O CO 2 e

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



### Ke y: GHG = greenhouse gas; mpg = miles per gallon; HDT = Heavy duty truck; LDT = Light duty truck; gal = gallons; kg = kilogra m; 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 Emi ssion Factor GHG Emissions Total CO 2 Equivalents (c) MMBtu/yr gallons/yr CO 2 CH 4 N 2 O CH 4 N 2 O CO 2 CH 4 N 2 O SF 6
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

CT G/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 Ge nerator 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

SF 6 in circuit breakers 4.00E

- 04 9.56

Vehicles 11.0 1.10E

- 03 1.31E

- 03 11.4

T OTAL 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 CH 4 , Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

- 21 Global warming potential of N 2 O, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

- 310 Global warming potential of SF 6 , Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008

- 23900AECOM

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 Ann ual Fuel Use Emission Factor Category Emission Factor GHG Emissions

CO 2 CH 4 N 2 O CO 2 CH 4 N 2 O CO 2 e

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 0.27 6

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: G HG = 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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# Publication

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 Lawyers
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10First 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 Hyperionrefinery 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. 11

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