### Environment Prepared for: Submitted by: City of Palmdale / Inland Energy AECOM Palmdale Hybrid Power Project Camarillo, CA Document #60138827-040GB May 2011



# Palmdale Hybrid Power Project Greenhouse Gas BACT Analysis

### Environment Prepared for: Submitted by: City of Palmdale / Inland Energy AECOM Palmdale Hybrid Power Project Camarillo, CA Document #60138827-040GB May 2011



# Palmdale Hybrid Power Project Greenhouse Gas BACT Analysis

_________________________________ Prepared By Howard Balentine

_________________________________ Reviewed By Sara J. Headi AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 

## Contents

1.0 Introduction

.......................................................................................................................... 1

1.1 Project Ov erview .............................................................................................................. ....... 1

1.2 Regulatory Ov erview

........................................................................................................... ... 2

1.3 BACT Evaluation Overview .................................................................................................... 3



### 2.0 Project Description and GHG Emissions ......................................................................... 5

2.1 Overview ...................................................................................................................... ........... 5

2.2 Generating Facilit y Compo nents ............................................................................................ 5

2.3 Process Desc ription ........................................................................................................... ..... 5

2.4 Energy Generation Facili ties Descrip tion ............................................................................... 7
2.4.1 Combustion Turbine-G enerators (C TGs) ............................................................... 7
2.4.2 Heat Recovery Steam Generators (HRSGs) and Steam Cycle ............................. 8 2.4.3 Auxiliary Bo iler ......................................................................................................... 8
2.4.4 Steam Turbine-Gener ator (S TG) ............................................................................ 9
2.4.5 Solar Thermal System ............................................................................................. 9
2.4.6 HTF Heat er .............................................................................................................. 9
2.4.7 Emergency Gener ator ............................................................................................. 9 2.4.8 Emergency Fire Wa ter Pump .................................................................................. 9

2.5 Operating Schedul e ............................................................................................................ .. 10

2.6 Greenhouse Gas Emissions ................................................................................................. 10



### 3.0 BACT Determination for Combustion Turbines and Duct Burners ............................12

3.1 Step1 - Identification of Avai lable Control Te chnologies ..................................................... 12 3.1.1 Carbon Capture and S equestrati on ...................................................................... 13 3.1.2 Lower Emitting Alternative Technology ................................................................. 14 3.1.3 Thermal Effi ciency ................................................................................................. 16

3.2 Step 2 - Eliminate Technica lly Infeasible Options ............................................................... 17
3.2.1 Carbon Capture and S equestrati on ...................................................................... 17 3.2.2 Lower Emitting Alternative Technology ................................................................. 19 3.2.3 Thermal Effi ciency ................................................................................................. 19

3.3 Step 3 - Rank Remaining Control Tec hnologies ................................................................. 19 3.3.1 Carbon Capture and S equestrati on ...................................................................... 20 3.3.2 Thermal Effi ciency ................................................................................................. 20

3.4 Step 4 - Evaluating the Mo st Effective Controls .................................................................. 20 3.4.1 Carbon Capture and S equestrati on ...................................................................... 20 3.4.2 Thermal Effi ciency ................................................................................................. 21ii AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 3.5 Step 5 - Select BACT ............................................................................................................ 22



### 4.0 Auxiliary Boiler and HTF Heater GHG BACT Analysis .................................................25

4.1 Step 1 - Identification of Ava ilable Control Te chnologies .................................................... 25
4.1.1 Carbon Capture and S equestrati on ...................................................................... 25
4.1.2 Thermal Effi ciency ................................................................................................. 25

4.2 Step 2 - Eliminating Techni cally Infeasible Options ............................................................. 25
4.2.1 Carbon Capture and S equestrati on ...................................................................... 26
4.2.2 Thermal Effi ciency ................................................................................................. 26

4.3 Step 3 - Rank Remaining Control Tec hnologies ................................................................. 26

4.4 Step 4 - Evaluation of Mo st Effective Contro l ...................................................................... 26

4.5 Step 5 - Select BACT ............................................................................................................ 26



### 5.0 References .................................................................................................................... .....27



## Appendices

A GHG Emissions Calculations



## List of Tables

Table 1 Generation Conf igurations and Output ................................................................................. ......... 7

Table 2 Estimated Potential Greenhouse Gas (GHG) Emissions ............................................................ 11

Table 3 Local Generation Heat Rates and 2008 Energy Outputs, Lo s Angeles Basin ........................... 23

Table 4 Local Generation Heat Rates and 2008 Energy Outputs, Big Creek/Ventura LSA ................... 24



## List of Figures

Figure 1 Process Flow Di agram ................................................................................................ .................. 6 Figure 2 Potential CO 2 Sequestration Locations by Ty pe in Southern Ca lifornia .................................... 151 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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## 1.0 Introduction

This Best Available Control Technology (BACT) evaluation was prepared for the Palmdale Hybrid Power Project (PHPP) specifically to address gr eenhouse gas (GHG) emissions from the project. A BACT analysis for criteria pollutants was submitt ed to the U.S. Environmental Protection Agency (EPA) with the original Prevention of Significant Deterioration (PSD) application on April 1, 2009. This BACT evaluation follows the EPA PSD and Titl e V Permitting Guidance for Greenhouse Gases issued in March 2011.

This Project is also subject to licensing by t he California Energy Commission (CEC) as a thermal power plant with over 50 megawatts (MW) of electr ical generation. The CEC produced a Final Staff Assessment (FSA) which was issued in December 2010 and reviewed the potential for environmental impacts from the PHPP (CEC 2010a). The FSA included a detailed review of this Project’s GHG emissions and potential affects. Be cause the FSA includes a recent, comprehensive analysis of GHG emissions, this GHG BACT analysis incorporates much of the information provided in the FSA.

As will be shown later in this do cument, the PHPP will be a new 570 MW “state-of-the art,” “hybrid” natural gas-fired combined-cycle power plant integr ated with solar thermal generating equipment. PHPP will also employ a “Rapid Start Process” , which will minimize emissions during startup and increase the efficiency of the power plant. GHG pollutants are emitted during the combustion process when fossil fuels are burned. One of the possible ways to reduce GHG emissions from fossil fuel combustion is to minim ize the use of fuel, which is achieved by using a thermally efficient process. A power plant such as PHPP is considered to ha ve met GHG BACT requirements because of its high thermal efficiency. The solar component of th e PHPP facility adds to this efficiency.


### 1.1 Project Overview
The PHPP is a 570 MW “hybrid” natural gas-fired combined-cycle power plant integrated with solar thermal generating equipment, which enhances PHPP’s overall thermal efficiency. The combinedcycle equipment utilizes two state- of-the-art (i.e., thermally effici ent) natural gas-fired combustion turbine generators (CTGs), two heat recovery steam generators (HRSGs), and one steam turbine generator (STG). The solar thermal component of the PHPP has the potential to produce up to almost 10 percent of facility total generation.

PHPP will also employ General Electric Power Sy stems (GE) Rapid Start Pr ocess (RSP) to minimize emissions during startup and increase the efficiency of the power plant. RSP allows for faster starting of the gas turbines by mitigating the restrictions of former HRSG designs. Tr aditionally, the CTGs are brought to full load slowly to li mit thermal stresses in the high-pressure (HP) steam drum of the HRSG due to the exhaust temperature of the CTGs. The new GE RSP design eliminates this restriction by modifying the steam drum design. Additional equipment to support the RSP includes an auxiliary boiler, which will supply sealing steam and allow startup of the steam turbine shortly after the gas turbines.

PHPP fully integrat es a 50 MW solar thermal generation component into the natural-gas generation component which enhances PHPP’s overall therma l efficiency. The solar generation component utilizes arrays of parabol ic collectors that use solar energy to heat a HTF). The HTF is used to boil2 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 water to generate steam. The combined-cycle equipment is integrated thermally with the solar equipment at the HRSG and both utilize the single STG that is part of the project. The solar thermal input will provide almost ten perc ent of the peak power generated by the facility during the time of day when electrical demand is highest, enhancing the peak thermal efficiency of the PHPP.

According to the CEC (2010a), the operation of PHPP would enhance the overall efficiency of the electricity system operation in California and thereby reduce GHG emissions by providing the following necessary functions:

 PHPP would provide flexible, dispatchable power necessary to integrate some of the growing generation from intermittent renewable sour ces, such as wind and solar generation.

 PHPP would displace some less efficient local generation in the dispatch order of gas-fired facilities that are requir ed to provide electricity.

 PHPP would facilitate to some degree the repl acement of high GHG emitting (e.g., out-ofstate coal) electricity generation that must be phased out to meet the State’s Emissions Performance Standard (EPS) as required by SB 1368.

 PHPP could facilitate to some extent the r eplacement of generation provided by aging and once-through cooling power plants.

 PHPP would utilize the General Electric Powe r Systems (GE) Rapid Start Process (RSP) to allow for fast startup capability.

 PHPP, while located outside Big Creek/Ventura and the Los Angeles Local Reliability Areas (LRAs), could help a load-serving entity (LSE) meet resource adequacy (RA) requirements in these areas.

Addition of the high thermal efficiency of PHPP’s generation to the state’s electricity system would displace other less efficient, higher GHG-emitting generation and facilitate the integration of renewable resources. Because the project’s GHG emissions per megawatt-hour (MWh) would be lower than those of other power plants that the project woul d displace, the addition PHPP would contribute to a reduction of the California and overall Wester n Electricity Coordinating Council system GHG 1 emissions and GHG emission rate average. T hus, although PHPP would emit GHG emissions, the high thermal efficiency of PHPP and the system build-out of renewable resources in California would result in a net cumulative reduction of GHG emi ssions from new and existing fossil resources (CEC 2010a).


### 1.2 Regulatory Overview
On May 13, 2010 EPA issued the greenhouse gas (GHG) permitting rule officially known as “Prevention of Significant Deteri oration and Title V Greenhouse Gas Tailoring Rule” (or in short form, GHG Tailoring Rule) to regulate the six GHG pollutants codified at 40 CFR Parts 51, 52, 70 and 71. Beginning January 2, 2011, GHGs are regulated New Source Review (NSR) pollutants under the Prevention of Significant Deterioration (PSD) majo r source permitting program when they are emitted by new sources or modifications. Beginning July 1, 2011, any source which has a potential to emit GHG in amount greater than 100,000 tons per year (tpy) of carbon dioxide equivalent (CO 2 e) will be

1 Fuel-use closely correlates to the efficiency of and carbon dioxide (CO 2 ) emissions from natural gas-fired power

plants. And since CO 2 emissions from the fuel combustion dominate GHG emissions from power plants, the terms CO 2 and GHG are used interchangeably in this document.3 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 considered a major source and is required to under go PSD permitting, including preparation of a BACT analysis for GHG emissions. In addition, pursuant to 40 CFR Part 98, facilities that emit more than 25,000 metric tons (MT) of CO 2 e emissions per year are required to file annual emission reports for GHG emissions. The PHPP has the potential to emit more than 100,000 MT CO 2 e, and as such is subject to the GHG Tailoring Rule.

The State of California has also adopted a number of laws related to GHG requirements, including emissions and performance standards that are rele vant to GHG BACT analyses. In September 2006, Governor Schwarzenegger signed Assemb ly Bill (AB) 32, the Californ ia Global Warming Solutions Act of 2006. AB32 establishes regulatory, reporting , and market mechanisms to achieve quantifiable reductions in GHG emissions and a cap on statewi de GHG emissions. Senate Bill (SB) 1368 is the companion bill of AB32 and required the California Pu blic Utilities Commission (CPUC) to establish a GHG emission performance standard for base load ge neration from investor owned utilities by February 1, 2007. The CEC was required to esta blish a similar standard for local publicly owned utilities by June 30, 2007. These standards cannot exceed the GHG emission rate from a base load combined-cycle natural gas-fired plant of 1,100 pounds per megawatt-hour (MWh). The legislation further requires that all electricity provided to California, including imported electricity, must be generated from plants that meet the stan dards set by the CPUC and the CEC.



### 1.3 BACT Evaluation Overview
BACT requirements are intended to ensure that a pro posed project will incorporate control systems that reflect the latest demonstrated practical techni ques for that particular facility. BACT is defined under the Clean Air Act as follows (Section 169(3), 42 United States Code Section 7479(3)):

The term “best available control technol ogy” means an emission limitation based on the maximum degree of reduction of each pollutant subject to regulation under this chapter emitted from or which results from any major emitting facility, which the permitting authority, on a case-by-case basis, taking into account energy, environmental, and economic impacts and ot her costs, determines is achievable for such facility through application of production processes and available methods, systems, and techniques, including fuel cl eaning, clean fuels, or treatment or innovative fuel combustion techniques for control of each such pollutant. BACT is defined as the emission control means an emission limitation (including opacity limits) based on the maximum degree of r eduction which is achievable for each pollutant, taking into account energy, environmental, and economic impacts, and other costs. ....

A BACT analysis must be pollutant and emission unit specific with res pect to each pollutant subject to a BACT review. The analysis must evaluate the entire range of demonstrated options, including alternatives that may be transferable or innovative. The level of detail in the control options analysis should vary with the relative m agnitude of the emissions reduction achievable. A BACT analysis is performed in a top-down manner in which all applic able control technologies are evaluated based on their effectiveness and then ranked by decreasing level of control. Once ranked, control technologies on the list are eliminated one by one based on in feasibility due to energy, environmental, and economic impacts, and other costs. The first contro l technology in the ranked list that cannot be so eliminated is then defined as BACT for that pollutant and process.4 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 For a facility subject to the GHG Tailoring Rule, the six covered GHG pollutants are:

 Carbon dioxide (CO2),

 Nitrous oxide (N2O),

 Methane (CH4),

 Hydrofluorocarbons (HFCs),

 Perfluorocarbons (PFCs), and

 Sulfur hexafluoride (SF6).

EPA guidance for a “top-down” BACT analysis requires reviewing the possible control options starting with the best control efficiency. In the course of the BACT analysis, one or more options may be eliminated from consideration because they are demon strated to be technically infeasible or have unacceptable energy, economic, or environmental impacts on a case-by-case (site-specific) basis.

The steps required for a “top-down” BACT review are given below:

1. Identify available control technologies;

2. Eliminate technically infeasible options;

3. Rank remaining technologies;

4. Evaluate remaining technologies (in terms of economic, energy, and environmental impacts); and

5. Select BACT (the most efficient technology that cannot be rejected for economic, energy, or environmental impact reasons).

This document presents a more detail Project Descrip tion in Section 2, including the GHG emissions expected from the facility. The top-down GHG BACT determination for the PHPP combustion turbines and duct burners in provided in Section 3. The BACT determination for the auxiliary boiler and HTF heater is provided in Section 4.5 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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## 2.0 Project Description and GHG Emissions

2.1 Overview
The City of Palmdale proposes to construct and oper ate the PHPP. The PHPP is expected to supply power to the rapidly growing Southern California mark et. The City has contra cted with Inland Energy, Inc. to develop the Project.

The PHPP consists of a hybrid of natural gas-f ired combined-cycle generating equipment integrated with solar thermal generating equipment to be developed on a site in the northern portion of the City of Palmdale. The combined-cycle equipment utiliz es two natural gas-fired CTGs, two HRSGs, and one STG. The solar thermal equipment utilizes arrays of parabolic collectors to collect heat used to generate steam. The combined-cycle equipment is integrated thermally with the solar equipment at the HRSG, and both utilize the single STG to generate power.

The Project will have a nominal el ectrical output of 570 MW and commercial operation is planned for two and a half to three years after permitting is comp lete. The solar thermal input will provide almost ten percent of the peak power generated by the Pr oject during the daily periods of highest energy demand.


### 2.2 Generating F acility Components
The major components of the Project include:

 Two natural gas-fired CTGs equipped with dry low-NOX (DLN) combustors and evaporative inlet air coolers,

 Two natural gas-fired HRS Gs equipped with duct burners,

 Selective catalytic reduction (SCR) and oxid ation catalyst emissions control systems,

 One STG,

 Approximately 251-acre solar thermal array fi eld with a solar steam boiler and associated auxiliary systems and equipment;

 One wet cooling tower;

 Auxiliary boiler, HTF heater, and fire water pump module;

 Water tanks and brine crystallizer facilities;

 A 230-kilovolt (kV) switchyard; and

 An operations building that incorporates cont rol, warehouse, maintenance, and administrative functions.


### 2.3 Process Description
A Process Flow Diagram of the facility is shown in Figure 1. The CTGs and duct burners are fueled exclusively with pipeline natural gas. The duc t burners provide additional heat, which enable the HRSGs to produce more steam in order to obtain peak output from the STG.7 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 At full load, each CTG generates approximately 154 MW (gross) at average ambient conditions. Heat from the CTG exhausts is used in the HRSGs to gener ate steam and to reheat steam. With the CTGs at full load and the duct burners and solar field out-of-service, the HRSGs produce sufficient steam for operation of the STG at an output of 169 MW (gross) at average ambient conditions, which results in an overall plant output of approximately 477 MW (gro ss) (see Table 1). With the CTGs at full load and the duct burners in-service, the HRSGs produce suff icient steam for operation of the STG at its peaking output of 267 MW (gross) at average ambien t conditions, which results in an overall plant gross output of approximately 563 MW (net). It is expected that approximately 3 to 5 percent of the total annual energy generation from the PHPP will come from the renewable solar generation.



### Table 1 Generation Configurations and Output

Configuration Output (MW) Full Load (average ambient conditions)/No Duct Burners/No Solar 477 Full Load (average ambient conditions )/Full Duct Burners/No Solar 563 Full Load (average ambient conditions)/ Partial Duct Burners/Full Solar 563 Full Load (average ambient conditions )/No Duct Burners/Full Solar 527

Overall, annual availability of the PHPP is expected to be in the range of 90 to 95 percent. The design of the Project provides for operating flexibility (the ability to rapidly startup, shutdown, turn down and provide peaking output), so operations may be readily adapted to changing market conditions. Included in this flexibility is the ability of the Project to startup the combined-cycle system in approximately one-half the time of the industry st andard for combined-cycle plants in the United States.

The “Rapid Start Process” (RSP) offered by G eneral Electric Power Systems (GE), the planned supplier of the Project’s combustion equipment, allo ws for faster starting of the gas turbines by mitigating the restrictions of former HRSG designs. Traditionally, the CTGs are brought to full load slowly to limit thermal stresses in the high-pressu re (HP) steam drum of the HRSG due to the exhaust temperature of the CTGs. The new GE RSP design el iminates this restrictio n by modifying the steam drum design. Additional equipment to support the RSP includes an auxiliary boiler, which will supply sealing steam and allow startup of the steam turbine shortly after the gas turbines.


### 2.4 Energy Generation Facilities Description
This section describes the major energy generatio n components of the proposed PHPP including the CTGs, HRSGs, STG, and solar thermal system.



### 2.4.1 Combustion Turbine-Generators (CTGs)
Thermal energy is produced in each of the two CT Gs through the combustion of natural gas. The thermal energy is then converted into mechanical energy by the CTG turbine that drives the CTG compressor and electric generator. The CTGs propos ed for the PHPP employ ‘F’ technology supplied by GE Power Systems. Each CTG consists of a heavy duty, single shaft, combustion turbinegenerator, and associated auxiliary equipment. The CTGs are equipped with DLN combustors designed for natural gas combustion.8 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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### 2.4.2 Heat Recovery Steam Generators (HRSGs) and Steam Cycle
In the combined-cycle configuration, each CTG will exhaust through a dedicated HRSG. Each of the two trains will consist of one CTG and one HRSG. Both CTG- HRSG trains will feed steam into a common STG, a standard 2-on-1 configuration.

Each HRSG is a horizontal, natural circulation type unit with three pressure levels of steam generation and reheat loop. Super-heated high pressure (H P) steam at 1,800 pounds per square inch gauge (psig) and 1,050 degrees Fahrenheit (°F) is produced in the HRSG and flows to the steam turbine throttle inlet. The exhausted cold reheat steam is mixed with intermediate pressure steam andreintroduced into the HRSG through the reheat loop. The hot reheat steam flows to the intermediatepressure section of the STG, and then to the low-pr essure (LP) section of the STG. LP steam from the HRSG also flows to the LP section of the STG. The STG drives an electric generator. Each HRSG has a 550 million British thermal units per hour (MMBtu/hr) natural gas-fired duct burner.

In the proposed hybrid configuration with the solar thermal component integrated into the PHPP, additional HP steam is produced during daylight hours from heat collected via the solar array. The solar array heats the HTF that is used to produce HP steam in a heat exchanger. This HP steam is introduced into the combined-cycle system via injection into the HP drum of the HRSG. This steam is then superheated in the HRSG superheaters along with the HP steam produced within the HRSG evaporator.

The STG exhaust steam is condensed in the de-aeratin g surface condenser with water from a multicell wet cooling tower. Makeup water to the cooling tower will be tertiary-treated reclaimed water.

As noted earlier, the PHPP is designed with GE’s RSP, which will allow the CTG to reach base load more quickly, reducing startup emissions. Since e mission rates of some pollutants (e.g., NOx, CO, VOC) are higher during startup than during normal steady-state operations, RSP facilitates lower overall emissions per MW-hour produced. The RS P reduces CTG startup times by more than 50 percent during cold starts, with smaller reductions in startup time and corresponding emissions during warm and hot starts. The RSP does not affect STG startup times.

To facilitate the RSP approach, the HRSG design is modified compared to a conventional HRSG design. Typical HRSG designs limit the CTG star t rate due to the exhaust temperature heating the steam drum too quickly. This limitation is caused by thermal stress limitations on the HP steam drum due to the shell thickness. To avoid this limitation, a modified drum design is used that allows for thinner wall thickness. This revised design is achieved by elongating the steam drum and reducing its diameter, which leaves the steam drum volu me relatively unchanged compared to conventional designs.



### 2.4.3 Auxiliary Boiler
Another limiting factor for startup of combined-cycle equipment is the ability to draw a vacuum on the condenser, which is necessary to commence STG st artup. The PHPP will use one 110 MMBtu/hr, natural gas-fired auxiliary boiler to facilitate rapid st artup by providing STG sealing steam prior to CTG startup, thereby allowing the condenser vacuum to be established and the condenser be in a condition ready to accept steam as soon as it is available. This also avoids the need to vent considerable steam to the atmosphere while waiting for condenser vacuum to be established following CTG startup.9 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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### 2.4.4 Steam Turbine-Generator (STG)

Steam from the HRSGs is sent to the STG. Th e steam expands through the STG turbine blades to drive the steam turbine, which in turn drives the generator. The PHPP’s STG is a “reheat” type and is equipped with accessories required to provide efficient, safe, and reliable operation.



### 2.4.5 Solar Thermal System
The PHPP 50 MW solar field is made up of a larg e field of diurnal, single-axis-tracking parabolic trough solar collectors. The solar field is modular in nature and comprises many parallel rows of solar collectors, normally aligned on a north-south horizont al axis. Each solar collector has a linear parabolic-shaped reflector (referred to as the Heat Co llection Element) that focuses the sun’s direct beam radiation on a linear receiver located at the focus of the parabola. The collectors track the sun from east to west during the diurnal cycle to ens ure maximum focusing of incident sunlight on the linear receiver.

The HTF is heated up to approximately 740  F as it circulates through the receiver and returns to a series of heat exchangers, where the HTF is used to generate HP steam. At the PHPP, these heat exchangers are located in the power block area. To integrate the solar and combined-cycle Project components, the solar-generated HP steam is injected in the HP steam section of a HRSG where it is superheated.

The Project will require periodic ve hicle travel over the unpaved portions of the solar field to perform routine maintenance including mirror washing, main tenance inspections and r epairs of the piping network, herbicide application and dus t suppressant application.



### 2.4.6 HTF Heater
To eliminate the problem of the HTF freezing during cold winter nights, one 40 MMBtu/hr, natural gasfired HTF heater will be installed and used as needed to ensure that the temperature of the HTF fluid in the system stays above 54°F whenev er the solar steam unit is off-line.



### 2.4.7 Emergency Generator
The emergency diesel generator will supply electrical power to the power plant critical services in the event of a total power outage of the switchyard and th e plant. The plant critical services will include battery chargers, turning gear, lubricating oil sy stems, Distributed Contro l System and Programmable Logic Controller controls and critical lighting. Th e generator will be standby rated at 2,000 kilowatt (kW), at 480 volts. The emergency diesel generator will be periodically tested to confirm it’s mechanical, electrical and control equipment integr ity. The emergency generator system will be synchronized with the normal auxiliary power system fr om time to time to test its total output power into the system. This emergency diesel engine will operate for a maximum of 50 hours per year for testing and maintenance.



### 2.4.8 Emergency Fire Water Pump
The Project will include an emer gency diesel-fired fire water pump rated at approximately 135 kW. This emergency diesel engine will operate for a maximum of 50 hours per year for testing and maintenance.10 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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### 2.5 Operating Schedule
The power plant will be operated up to seven days per week, 24 hours per day. When the plant is not operating, personnel will be present as necessary for maintenance, to prepare the plant for startup, and/or for site security.



### 2.6 Greenhouse Gas Emissions
The primary GHG of concern for the PHPP is CO 2 . This report primarily presents the GHG BACT analysis for CO 2 emissions, as CH 4 , N 2 O and SF 6 emissions are insignificant, at less than 0.3 percent of facility GHG CO 2 e emissions. No sources with HFCs or PFCs pollutants are identified with this Project.

The primary sources of GHG emissions would be the natural gas-fired combustion turbines with duct burners, the auxiliary boiler and the HTF heater. There would also be a small amount of GHG emissions from maintenance vehicles required to wash mirror surfaces and otherwise maintain the facility, diesel fuel combusti on in the emergency fire water pump and emergency generator engines, and SF 6 emissions from electrical component equipment.

Appendix A presents the GHG emission calculations for the PHPP taken from the PHPP Application for Certification (AFC) as submitt ed to the California Energy Commission in July 2008. All emissions are converted to metric tons of CO 2 -equivalents (CO 2 e) and totaled. Electricity generation GHG emissions are dominated by CO 2 emissions from natural gas comb ustion. The remaining PHPP GHG emissions of CH 4 , N 2 O, and SF 6 contribute only 0.3 percent of the total CO 2 e emissions due to facility operation, notwithstanding the relatively high gl obal warming potentials (GWPs) of these three compounds.

The proposed project would be permitted, on an annual basis, to emit approximately 1,850,000 metric tons of CO 2 e per year if operated at its maximum permit ted level. This annual emission estimate is based on 8,760 hours of operation of the combustion turb ines at full load plus operation of the duct burners for an additional 2,000 hours. Operation of the solar array to generate electricity would reduce the greenhouse emissions of the facility below the above estimated emission rate.

As discussed above, the combustion of natural gas for project power production from the combustion turbines and associated duct burners, auxiliary boile r, and HTF heater is responsible for 99.7 percent of facility GHG CO 2 e emissions. Based on these emission es timates, a GHG BACT analysis was not performed for the negligible GHG emission sources at this facility, i.e., the emergency generator engine, the emergency fire water pump engine, SF 6 leakage, or vehicle emissions.11 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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### Table 2 Estimated Potential Greenhouse Gas (GHG) Emissions

Emissions Source Operational GHG Emissions a (MTCO 2 e/yr)

CTG/HRSG 1 w/duct burner 924,000

CTG/HRSG 2 w/duct burner 924,000
Auxiliary Boiler 2,660

HTF Heater 2,130 Emergency Generator 25
Emergency Fire Water Pump 4 Sulfur Hexafluoride (SF6) Leakage 9 Vehicles (includes mirror washing) 10 Total Project GHG Emissions (MTCO2e/yr) b 1,850,000
Estimated Annual Energy Output (MWh/yr) c 4,993,200

Estimated Annualized GHG Pe rformance (MTCO2/MWh) 0.370 Estimated Annualized GHG Performance (MTCO2e/MWh) 0.371 a. One metric ton (MT) equals 1.1 short tons or 2,204.6 pounds or 1,000 kilograms b. The facility emissions are rounded to three si gnificant figures. Note that the emissions contribution from the emergency equipment, SF 6 leakage, and vehicles are less than the round-off error for the combustion turbines/duct burners emissions. c. Annualized basis uses the project owner’s assumed maximum operating basis. Sources: PHPP AFC 2008 and CEC 2010a, including CEC staff analysis for estimated energy output.12 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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## 3.0 BACT Determination for Co mbustion Turbines and Duct Burners

This section presents the top-down GHG BACT determ ination for the combustion turbines and duct burners. The BACT determination for the auxiliary boiler and HTF heater is given in the next section.


### 3.1 Step1 - Identification of Available Control Technologies
The proposed combustion turbines will operate in combined-cycle mode. In a combined-cycle configuration, hot exhaust from the CTG is ducted through a HRSG, which is also fired, to produce steam to drive a steam turbine generator. Sinc e the combustion turbine and HRSG are coupled together in a combined-cycle configuration, and ex haust through a single stack, they are considered to be one combustion train for purposes of the evaluation of GHG emissions control.

Publicly-available information on emission cont rol technologies for Combined Cycle Combustion Turbines was reviewed for step one of this analys is. Databases reviewed included South Coast Air Quality Management District (SCA QMD) BACT/lowest achievable emission rate (LAER) Guidelines, the Bay Area Air Quality Management District (BAAQMD) BACT Guidelines, EPA’s Reasonably Available Control Technology/BACT/LAER Clearingho use (RBLC), and the recent or pending projects in the CEC database. SCAQMD did not list any specific determinations for GHG BACT in their guidelines and BAAQMD had only one determination for the Russell City Energy Center. An internet search found one other GHG BACT analyses for natur al gas-fired combined-cycl e facilities, Portland General Electric Company’s Carty Po wer Plant (SLR International, 2010).

In addition, GHG BACT analyses were found for tw o Integrated Gasification Combined-Cycle (ICGG) facilities:

 Hyperion Energy Center, BACT Review fo r Greenhouse Gas Emissions, RTP Environmental Consultants, October 2010.

 PurGen One Facility, Revised PSD Application, December 2010.

The U.S. Department of Energy (DOE) websit e also contained applicable information regarding available CO 2 control technologies which are discussed below.

For review of the CO 2 control technologies for PHPP’s CTGs/ HRSGs, the following list of potentially applicable technologies available is evaluated (listed in alphabetical order):

 Carbon Capture and Sequestration (CCS ) (DOE Website, EPA 2010b, CEC 2009)

 Lower Emitting Alternative Technology ( EPA 2010b, National Laboratory Directors 1997)

 Thermal Efficiency (EPA 2010b)

Each of these technologies is further discussed in the following subsections.13 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 

### 3.1.1 Carbon Capture and Sequestration
CCS is a multiple step process which involves capturing of CO 2 emissions, transportation of CO 2 emissions to the sequestration site, and ultimate sequestration of CO 2 emissions.

Capturing of CO 2 Emissions Carbon capture begins with th e separation and capture of CO 2 from the flue gas. Post-combustion capture systems being developed are expected to be capable of capturing more than 90 percent of flue gas CO 2 . Amine-based solvent systems are in commercial use for scrubbing CO 2 from industrial flue gases and process gases. However, solvents have yet to be applied and demonstrated in practice to remove the much larger volumes of CO 2 that are encountered in commercial scale power plants.

Solid sorbents can be used to capture CO 2 from flue gas through che mical adsorption, physical adsorption, or a combination of the two effects. Possible configurations for contacting the flue gas with solid sorbents include fixed, moving, and fluidized beds. Membrane-based capture uses permeable or semi-permeable materials that allo w for the selective transport/separation of CO 2 from flue gas. The process of separating CO 2 from the flue has high energy demand and is cost intensive.

Transportation of CO 2 Emissions

CO 2 captured by any of the above mentioned proce sses would have to be transported to a storage site. For geologic sequestration, a pipeline may be suitable. For other types of sequestration (e.g., ocean storage, mineral carbonation), transportation would depend on specific project requirements, and may involve pipelines, truck transport, ocean-going vessels, etc.

Sequestration of CO 2 emissions Geologic Sequestration Under geologic sequestration, a suitable geological formation is identified close to the proposed project and the captured CO 2 from the process is compressed and transported to the sequestration location. CO 2 is injected into that formation at a high pressure and to depths generally greater than 2,625 feet (800 meters). Below this depth, the pressurized CO 2 remains “supercritical” and behaves like a liquid. Supercritical CO 2 is denser and takes up less space than gaseous CO 2 . Once injected, the CO 2 occupies pore spaces in the surrounding rock, like water in a sponge. Saline water which already resides in the pore space would be displaced by the denser CO 2 . Over time, the CO 2 can dissolve in residual water and chemical reactions between the dissolved CO 2 and rock can create solid carbonate minerals, more permanently trapping the CO 2 . There are several geologic formations identified in California that might provide a suitable site for geologic sequestration. As shown in Figure 2, th e nearest potential sequestration basins to PHPP are north of the facility in the Lower San Joaquin Valley and southwest of the facility in Ventura County (NETL, 2010). While these sites may eventually prove to be suitable, the geotechnical analyses needed to confirm their suitability have not been conducted. For both the San Joaquin Valley and Ventura County basins, there are significant mounta in ranges that lie between the PHPP and potential sequestration sites that would produce very costly transportation options for a CCS project. In addition, NETL states in the 2010 Carbon Sequestration Atlas that the highly fractured shale in the Ventura Basin is not a good candidate for CO 2 sequestration (NETL, 2010, pg 111).14 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 Ocean Storage Ocean storage is accomplished by injecting CO 2 into the ocean water typically below 1,000 meters via pipe or ship. At these depths, CO 2 is expected to dissolve or form into a horizontal lens which would delay the dissolution of CO 2 into the surrounding environment. The depth of the overlying water and the lensing of the CO 2 will form a natural impediment to the vertical movement of the injected CO 2 .

Mineral Carbonation

Mineral carbonation is the reaction of CO 2 with the metal oxides forming metal carbonates which are very stable. These metal oxides are abundant in si licate minerals and in waste streams. The natural reaction of CO 2 with metal oxides is a very slow proce ss. However, the reaction time can be increased by enhancing the purity of these metal oxid es. Large scale production of metal oxides to meet the demand of electrical generation is very energy and cost intensive.



### 3.1.2 Lower Emitting Alternative Technology
There are power production technologies commercially available that are either low GHG-emitting or non-GHG emitting technologies, such as wind, solar, geothermal, hydroelectric, nuclear, and biomassfueled plants. The project already includes 50 MW of potential solar thermal power generation and so already incorporates a lower emitting alternative technology.

Alternatives analyses were prepared as part of the PHPP AFC (2008) and the CEC’s FSA (2010a), and included reviews of alternative technologies including wind, additional solar, geothermal, hydroelectric, nuclear and biomass, all of which were determined to be infeasible for this site.

The modification of the project to include alternativ e lower GHG-emitting technology, or an increase in the amount of solar thermal generation beyond 50 MW would fundamentally alter the business purpose of the Project. However, as stated by EPA (EPA 2010b, pg. 27), a BACT analysis is not generally used to redefine the applicant’s project.

While Step 1 [of a BACT Analysis] is intended to capture a broad array of potential options for pollution control, this step of the process is not without limits. EPA has recognized that a Step 1 list of options need not necessarily include inher ently lower polluting processes that would fundamentally redefine the nature of the source proposed by the permit applicant. BACT should generally not be applied to regulate the applicant’s purpose or objective for the proposed facility.

Consequently, no additional lower emitti ng alternative technologies are f easible to incorporate into the project without fundamentally changing th e business purpose of the Project.15 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 Figure 2. Potential CO 2 Sequestration Locations by Type in Southern California

Source: National Energy Technology Laboratory, Department of Energy. 2010 Carbon Sequestration Atlas of the United States and Canada, Third Edition.  PHPP16 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 

### 3.1.3 Thermal Efficiency

CO 2 is formed when fossil fuels are combusted and th e thermal efficiency of that combustion process is determined by the thermodynami cs of the system. The thermal efficiency is defined as the dimensionless ratio of the useful work performed by the process and the heat input to the process. It is not possible to alter the combustion process fr om the optimum stoichiometric conditions to reduce CO 2 emissions without also reducing the thermal effici ency at the same time. The only useful means to reduce CO 2 from a fossil fuel combustion process is to minimize the amount of fuel used, which is achieved by establishing a more thermally efficient pr ocess, or by substitution of a lower GHG emitting fuel.

The PHPP is already proposing to combust natural gas, the lowest emitting fossil fuel available. In addition, the PHPP is a state-of-the-art highly efficient thermal electric power plant. Finally, the PHPP is a “hybrid” natural gas-fired combined-cyc le power plant integrated with solar thermal generating equipment to enhance PHPP’s already high thermal efficiency. The PHPP utilizes two highly efficient state-of-the-art natural gas-fir ed combustion turbine generators (CTGs), two heat recovery steam generators (HRSGs), and one stea m turbine generator (STG), combined with an additional 50 MW of solar thermal generation capacity. The solar thermal input will provide almost ten percent of the peak power generated by the facili ty during the time of day when electrical demand is highest, enhancing the peak thermal efficiency of the PHPP.

The state-of-the-art design of the PHPP employs the General Electric Power Systems (GE) Rapid Start Process (RSP) to minimize emissions during st artup and increase the efficiency of the power plant. RSP allows for faster starting of the gas turbines by mitigating the restrictions of former HRSG designs. This design modification pr oduces a significant reduction in startup time that minimizes GHG emissions during startup. Traditionally, the CTGs are brought to full load slowly to limit thermal stresses in the high-pressure (HP) steam drum of the HRSG due to the high exhaust temperature of the CTGs. The new GE RSP design eliminates this restriction by modifying the steam drum design. Additional equipment to support the RSP includes an auxiliary boiler, which will supply sealing steam and allow startup of the steam turbine shortly after the gas turbines.

A natural gas-fired combined-cycle power plant su ch as PHPP uses a rela tively small amount of electricity to operate the facility compared to the energy in the fossil fuel combusted. Thus, there is negligible benefit in terms of energy efficiency and GHG emission reductions of the facility associated with lowering electricity usage at the facility compared to increasing the thermal efficiency of the process.

Addition of the high thermal efficiency of PHPP’s generation to the state’s electricity system will facilitate the integration of renewable resources in California’s generation supply and will displace other less efficient, higher GHG-emitting generati on. Because the project’s GHG emissions per megawatt-hour (MWh) will be lower than those of ot her power plants that the project would displace, the addition of PHPP to California’s energy supply w ill contribute to a reduction of the California and overall Western Electricity Coordinating Counc il system GHG emissions and GHG emission rate average. Thus, although PHPP would emit GHG em issions, the high thermal efficiency of PHPP and the system build-out of renewable resources in Califo rnia would result in a net cumulative reduction of GHG emissions from new and existi ng fossil resources (CEC 2010a).

California’s Renewable Portfolio Standard (RPS) was increased from 20% by 2010 to 33% by 2020 with the adoption of Senate Bill 2 on April 12, 2011 . To meet the new RPS requirements, the amount of dispatchable, high-efficiency, natural gas generat ion used as regulation resources, fast ramping17 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 resources, or load following or supplemental energy di spatches will have to be significantly increased. The construction of the PHPP will aid in the effort to meet Cali fornia’s RPS standard. Finally, the CEC has determined that the operation of PHPP will enhance the overall effi ciency of California’s electricity system operation and thereby reduce GHG emissions (CEC, 2010a).

In summary, state-of-the-art technologies including the RSP capability, highly efficient natural gas combustion, and the solar thermal component, are already integrated into PHPP and the project represents the apex of energy efficiency for similar plants.


### 3.2 Step 2 - Eliminate Tech nically Infeasible Options
The second step for the BACT analysis is to eliminate technically infeasible options from the control technologies identified in Step 1. For each option that was identified, a technology evaluation was conducted to determine the technical feasibility. Th e technology is feasible only when the technology is available and applicable. A technology that is no t commercially available for the scale of the project is also considered infeasible. An available technology is applicable if it can be reasonably be installed and operated on the proposed project.



### 3.2.1 Carbon Capture and Sequestration
The technical feasibility of each step of the CCS alternative is discussed separately below.

Carbon Capture
There are three basic processes consid ered for post-combustion capture of CO 2 from flue gas.

Solvent-based process There is limited experience available in the pos t-combustion solvent-based capture technology for a commercial scale power plant. Existing demonstratio n solvent-based capturing facilities for the power industries are only utilizing a fraction of the flue gas . Significant cost and operating issues would have to be addressed before such technology can be scaled up for a commercial scale power generation system. Consequently, a solvent-based carbon c apture process is currently judged to be technologically infeasible for a commercial power plant application.

Sorbent-based process Solid particle sorbents can be used for post-combustion capture of CO 2 . Most of the U.S. Department of Energy (DOE) funded projects employing solid ads orption are in demonstration phase for coal-fired plants, but there currently are nei ther demonstration scale nor commercial scale installations for a combined-cycle gas turbine application. Consequent ly, a sorbent-based carbon capture process is currently judged to be technologically infeasible for a natural gas-fired commercial power plant application.

Membrane-based process Membranes are commercially availabl e in the chemical industry for CO 2 removal but have not been demonstrated in practice for power generatio n applications. Consequently, a membrane-based carbon capture process is currently judged to be technologically infeasible for a commercial power plant application.18 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 CO 2 Transportation The basic technologies required for CO 2 transportation (i.e., pipeline, tanker truck, ship) are in commercial use today for a number of applications and can be considered commercially available for liquid CO 2 .
Sequestration Geologic Sequestration Geologic sequestration has been demonstrated on the pilot scale. These pilot scale projects indicate that geologic sequestration has potential to be a viable long-term storage solution for CO 2 . However, a number of significant technical issues remain to be resolved before the technology can be applied to a successful commercial scale application at a spec ific site. These technical issues include:

 A suitable geologic repository must exist for injection of the recovered CO 2 . The repository must have one or more injection zones that can accept and store large quantities of CO 2 and is overlain by suitable caprocks.

 The geologic repository must capable of sequestering the CO 2 for the length of time necessary to accomplish the goal of sequestrat ion. The seismicity of Southern California works against long-term sequestration and there are very limited locations in Southern California that meet these requirements.

 The geologic repository is located close enough to the power plant such that efficient transport of the recovered CO 2 is possible.

 Standards for site security, and for measur ing, monitoring, and ve rification (MMV) of containment must be established to allow confi dence that long-term seques tration will occur.

Without existing detailed hydrogeologic studies of nearby potentially suitable repositories, the solution of long-term containment issues associated with the seismicity of Southern California, and standards for long-term security and MMV, the technical feas ibility for geological sequestration for the PHPP cannot be determined. Therefore CCS using geolog ical sequestration cannot be demonstrated to be technically feasible in practice for the PHPP.

Ocean Storage Ocean storage and its ecological impacts are still in the research phase. Given the potential for acidification of the oceans and the resultant biol ogical consequences such as the weakening of the carbonate shells of marine invertrabrates, the use of ocean storage may never be realized. Using the oceans as a storage location for CO 2 is essentially moving the issue fr om climatic impacts to biological and marine impacts. Long term studies are st ill required to understand the potential unintended consequences of such disposal of CO 2 in ocean basins before ocean storage can be considered to be technically feasible.

Mineral Carbonation The formation of metal carbonates is technically f easible, as reaction chemistry is well understood. However, the sequestration of CO 2 through mineral carbonation has not been demonstrated on a commercial scale.19 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 Summary of CCS Feasibility
In summary, the post-combustion carbon capture te chnologies are still in the development stage or pilot scale projects. These technologies would not be considered commercially availability for the project size of a full-scale commercial power plant . In addition, there are no comprehensive standards in place defining requirements for security and MMV to verify long term seques tration. Therefore, CCS is not yet demonstrated in practice for a commercial scale natural gas power plant such as PHPP.

In consideration of the uncertainty in the technical feasibility of CCS and its emergence as a promising technology, CCS is carried forward in this BACT an alysis as a potential GHG control technology. However, substantial evidence demonstrates that CCS is not yet demonstrated as technically feasible for PHPP.



### 3.2.2 Lower Emitting Alternative Technology
As discussed previously, any of the commercially av ailable low GHG-emitting technologies that could be implemented, including additional solar therma l generating capacity, were determined to be infeasible for this site (CEC 2010a) and would fundamentally alter the business purpose of the emission source. As such, lower emitting alternative technology was not considered as part of the BACT analysis (EPA 2010b, pg. 27).



### 3.2.3 Thermal Efficiency

The State of California has established a GH G performance standard of 1,100 pounds of CO 2 per MWh. Senate Bill (SB) 1368 required the CPUC to establish a GHG emission performance standard for base load generation from investor owned utilities by February 1, 2007. The CEC was required to establish a similar standard for local publicly owned utilities by June 30, 2007. These standards cannot exceed the GHG emission rate from a base load combined-cycle natural gas-fired plant of 1,100 pounds per MW-hour. The California Legislature in Assembly Bill (AB) 1613 (2007), as amended by AB 2791 (2008), established a CO 2 Emission Performance Standard (EPS) for combined heat and power facilities of 1,100 lbs CO 2 /MWh. In 2010, the CEC promulgated its regulation to implement AB 1613 in its Guidelines for Certificat ion of Combined Heat and Power Systems Pursuant to the Waste Heat and Carbon Emi ssions Reduction Act (CEC 2010b).

The PHPP meets the California GHG emission performance standard (EPS) of 1,100 pounds of CO 2 per MWh with its state-of-the-art natural gas com bustion turbines with RS P technology. As presented below in Table 3, the PHPP will emit CO 2 at a rate of 0.370 MT CO 2 /MWh (815 lb/MWh), well below the required EPS. In addition, PHPP has added a low-e mitting component to the project in the form of its 50 MW of dispatchable solar thermal generat ion capability, which further improves the power plant’s efficiency.

The thermal efficiency for the PHPP achieved by the state-of-the-art technologies described above is a technically feasible alternative for reducing GHG em issions from a fossil-fuel fired power plant. The conclusion is that the combustion process inherent in the PHPP is achieved in practice and is eligible for consideration under Step 3 of the BACT analysis.


### 3.3 Step 3 - Rank Remain ing Control Technologies
While CCS was determined to be technically infeasible for this Project, the Applicant understands that the technical feasibility of CCS is a topic of considerable uncertainty and technical debate and,20 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 therefore, this option is carried forward in the BACT analysis to Step 3. The rank order of control, starting from the most effective control (1) to the least effective control (2), is as follows:

1. CCS

2. Thermal efficiency

The control effectiveness is explained below.



### 3.3.1 Carbon Capture and Sequestration
Post-combustion capture systems bei ng developed are expected to be capable of capturing more than 90 percent of flue gas CO 2 . At an assumed control efficiency of 90%, this would be equivalent to an emission rate of 10 percent of the California EPS, or approximately 110 lb CO 2 /MWh. This makes CCS the top-ranked technology on a theoretical basis . However, as discussed in Step 2, CCS was found to be technically infeasible for PHPP.



### 3.3.2 Thermal Efficiency
Thermal efficiency is capable of lowering GHG emi ssions, but the potential is much less than CCS on a theoretic basis. As discussed in Section 2, PHPP already incorporates increased thermal efficiency in its design by incorporation of state-of-the-art co mbined-cycle combustion turbines with the addition of RPS startup capability. Since the parasitic load is already relatively low at this facility, further increases to thermal efficiency are not achievabl e without changing basic objectives of the power project, if at all, and hence are not required by EPA guidelines for GHG BACT (EPA 2010b).


### 3.4 Step 4 - Evaluating the Most Effective Controls
Step 4 of the BACT analysis is to evaluate the mo st effective control. This step involves the consideration of energy, environmental, and ec onomic impacts associated with each control technology. The top-down approach requires that th e evaluation begin with the most effective technology.



### 3.4.1 Carbon Capture and Sequestration
As noted earlier, at this time, the Applicant does not believe that CCS is technically feasible for application at PHPP; however, it was carried forward to Step 4 of this analysis. At this point, CCS is evaluated for economic, energy, or environmental impacts. Regarding economic impacts, in its PSD BACT guidance, EPA states:

EPA recognizes that at present CCS is an ex pensive technology, largely because of the costs associated with CO 2 capture and compression, and these costs will generally make the price of electricity from power plants wi th CCS uncompetitive compared to electricity from plants with other GHG controls. Even if not eliminated in Step 2 of the BACT analysis, on the basis of the current costs of CCS, we expect that CCS will oft en be eliminated from consideration in Step 4 of the BACT analysis, even in some cases where underground storage of the captured CO 2 near the power plant is feasible. However, there ma y be cases at present where the economics of CCS are more favorable (for example, where the captured CO 2 could be readily sold for enhanced oil recovery), making CCS a more viable option under Step 4. (EPA 2010b).21 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 In addition to the cost of CO 2 capture, CCS involves geologic or terrestrial sequestration or conversion of the CO 2 into long-term storage. The costs associated with sequestration are very site-specific and can involve substantial costs for items such geotechni cal studies to define identify and define feasible potential repositories, pipeline construction, pumping , drilling and well construction, and monitoring. Due to these limitations, quantit ative cost analyses were determi ned to be both impractical and unreliable for this analysis and were not performed. In addition, as CCS has been determined to be not feasible for PHPP, the expenditure of funds for these studies is not warranted.

In order to determine a capture/control efficiency for CCS, there must be sufficient technical data including drilling studies, pilot studies, and geotechnica l studies. Currently those data are unavailable to even estimate a control efficiency. Therefore CCS can only be looked at qual itatively as whether it is feasible or not. Since a control efficiency cannot be established, even with cost information available, there is insufficient information for the denominator of the BACT formula to calculate a dollar per ton of CO 2 controlled. Therefore the cost feas ibility of CCS cannot be provided.

As noted in Section 3.1, the database review found information about two IGCC facilities, including the Hyperion Energy Center. Because the IGCC tec hnology is fundamentally different than the power generation units being proposed by PHPP, the GHG BACT findings are not considered relevant to PHPP; however, there is interesting information rela ted to CCS. In February 2011, the South Dakota Department of Environment and Natural Resources ( SD-DENR) issued a draft PSD permit for this 400,000 barrel per day greenfield petroleum refinery proposed by Hyperion Energy. The permit covers the refinery and an associated IGCC plant that will power the refinery’s operations. As discussed in its statement of basis for the permit, SD-DENR conducted an extensive anal ysis of BACT for GHG emissions, including consideration of CCS. Accordi ng to SD-DENR’s analysis, the implementation of CCS at the Hyperion refinery would require an add itional 400 MW of power generation capacity for gas drying and boosting, and the additional power generation capacity required to run CCS would significantly increase emissions of conventional pol lutants, increase energy demands, and emit 23 percent of the GHG emissions that the CCS was designed to capture. SD-DENR rejected CCS as BACT for GHG emissions based on these factors and its high costs. Through a comparison of GHG emissions at other refineries, SD-DENR conc luded that Hyperion’s proposed measures of good combustion practices and energy efficiency measur es incorporated into the plant design were BACT (Vinson & Elkins 2011).

As described in Step 2, CCS is not technically feasib le for the PHPP. Even to the extent there is any uncertainty regarding the fe asibility determination in Step 2, this Step 4 analysis demonstrates that CCS is not cost effective for CO 2 control from the proposed Project, and has been eliminated from further consideration.



### 3.4.2 Thermal Efficiency

The database review of BACT determinations described in Section 3.1 identified two facilities with natural gas-fired combined-cycle combustion turbi nes for which a GHG BACT analysis was done:

 The Bay Area Air Quality Management District (BAAQMD) issued a GHG BACT determination for the Calpine Russell City Ener gy Center in Hayward, Alameda County, California. According to a presentation by Ca lpine (Calpine 2010), thermal efficiency was the only feasible combustion control technology c onsidered as CCS was determined to be not commercially available. Thermal efficiency was f ound to be the top level of control feasible for a combined-cycle power plant, and hence was the technology selected at GHG BACT for Russell City.22 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011  A voluntary GHG BACT review was performed for the proposed addition of a 415 MW combined-cycle power plant at the existing Ca rty Power Plant operated by Portland General Electric Company near Boardman, Oregon (SLR International 2010). This review concluded that using natural gas fuel, with good opera tion and maintenance to maintain the thermal efficiency, was BACT for the GHG emissions.

Because the Russell City Energy Facility is similar to the PHPP, its thermal efficiency is compared to PHPP. The PHPP compares fa vorably with the Russell Ci ty facility in terms of energy efficiency of the CTGs proposed for each facility. In order to compar e the thermal efficiency of the two facilities, the Power Plant Efficiency section of the CEC FSA was re viewed for each facility. According to the CEC, the Russell City Energy Center ( 01-AFC-7C) will employ two Siemens Westinghouse 501FD Phase 2 combustion turbine generators with inlet air fogging systems and steam injection producing approximately 200 MW each, two multi-pressure HRSGs with duct burners, and one single 3- pressure, reheat, condensing STG producing a ma ximum of 235 MW, arranged in a two-on-one combined-cycle train, totaling approximately 600 MW (CEC 2002). The Russell City FSA states that the F-class turbines proposed by the Russell City Energy Center are nominally rated 550 MW of output and have a 55.8 percent efficiency Lower Heating Value (LHV) at International Standards Organization (ISO) conditions. By comparison, t he CEC PHPP FSA (CEC 2010a) indicates PHPP will have a higher maximum full load efficiency of 56.5 percent at ISO conditions for the two GE Frame 7FA CTGs in a two-on-one combined-cycle power train nominally rated at 530 MW.

The PHPP CTG trains each will have slightly higher energy efficiency (56.5 v. 55.8) than does the Russell City facility by 0.7% percent based solely on the prime movers. The energy efficiency difference is even larger for two reasons. First, t he PHPP will be located in the City of Palmdale at approximately 3,240 feet above sea level while the Russell City Energy Center is located approximately 16 feet above sea level. Combustion tu rbine efficiency is sensitive to air density with higher efficiency at the higher air density of a lo wer altitude. Thus there is an energy efficiency associated with the PHPP due to it base elevation. Second, the stated energy efficiency for the PHPP is without the solar generating component contributing to the efficiency. When the solar generation is added into the analysis, the PHPP thermal efficien cy will increase. Consequently, the use of GE Frame7FA natural gas-fired CTGs produces an energy efficiency greater than that of the Russell City Energy Center, the one power gener ation facility in California fo r which a GHG BACT level has been established.

The thermal efficiency of operating power generation fa cilities in Southern California, in terms of GHG performance, has been compared by the CEC in t he FSA for the PHPP project (CEC 2010a). The thermal efficiency of the PHPP is the lowest (i.e ., best) of any of the 37 pow er generation facilities listed in Greenhouse Gas Tables 4 and 5 in the FSA (Tables 3 and 4, below) examined by the CEC. In fact, the PHPP exceeds the next best facility (La Paloma Generating Station) by 5.6 percent. Once it is in operation, the PHPP will be one of the mo st thermally efficient power plants in Southern California. Consequently, the PHPP meets any reas onable thermal efficiency standard for definition as BACT.


### 3.5 Step 5 - Select BACT
Based on the above analysis, thermal efficiency is the only technically and economically feasible alternative for CO 2 / GHG emissions control at PHPP and the current design of the facility meets the BACT requirement for GHG emission reductions. Fo r the PHPP, the BACT emission limit for each combustion turbine generating unit shoul d be 930,000 metric tons of CO 2 per year, rounded up to two23 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 significant figures. Compliance can be based on a 12-month rolling average, as determined using a CO 2 Continuous Emissions Monitoring S ystem (CEMS) for each CTG unit.



### Table 3 Local Generation Heat Rates and 2008 Energy Outputs, Los Angeles Basin

Plant Name Heat Rate (Btu/kWh) a 2008 Energy Output (GWh) GHG Performance (MTCO 2 /MWh) c
Palmdale Hybrid Power Project 6,970 4,993 b 0.370 Watson Cgeneration Co 8,512 3,017 0.452 Corona Cogen 9,430 274 0.500

Civic Center 9,447 467 0.501

San Gabriel 9,859 155 0.523

THUMS 10,123 379 0.537

ARCO Products Co 10,140 477 0.538 Harbor Cogeneration Co 10,649 44 0.565

Alamitos 10,782 2,533 0.572 Huntington Beach (AES) 10,927 1,536 0.580 El Segundo Power 11,044 508 0.586 Carson Cogeneration Co 11,513 540 0.611 Redondo Beach LLC (AES) 11,726 317 0.622 Total Energy Facilities 12,281 137 0.652 Torrance Refinery 12,370 161 0.656 Long Beach Generation LLC 15,323 27 0.813 UCLA Energy Systems Facility 15,418 206 0.818 BP West Coast Wilmington Calciner 16,953 201 0.900
Source: CEC PHPP FSA (2010a), Greenhouse Table 4. Energy Commission staff based on Quarterly Fuel and Energy Report (QFER) ; with independent Energy Commission staff analysis for PHPP based on maximum utilization.

Notes: a. Based on the Higher Heating Value or HHV of the fuel. b. Includes solar generation component c. Based on continuous operation at peak capacity.24 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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### Table 4 Local Generation Heat Rates and 2008 Energy Outputs, Big Creek/Ventura LSA

Plant Name Heat Rate (Btu/kWh) a 2008 Energy Output (GWh) b GHG Performance (MTCO 2 /MWh) c
Palmdale Hybrid Power Project 6,970 4,993 c 0.370 La Paloma Generating 7,172 6,185 0.392 Pastoria Energy Facility LLC 7,025 4,905 0.384

Sunrise Power 7,266 3,605 0.397
Elk Hills Power, LLC 7,048 3,552 0.374 Sycamore Cogeneration Co 12,398 2,096 0.677 Midway-Sunset Cogeneration 11,805 1,941 0.645 Kern River Cogeneration Co 13,934 1,258 0.761 Ormond Beach Generating Station 10,656 783 0.582 Mandalay Generating Station 10,082 597 0.551 McKittrick Cogeneration Plant 7,732 592 0.422 Mt Poso Cogeneration (coal/pet. coke) 9,934 410 0.930

South Belridge Cogen Facility 11,452 409 0.625 McKittrick Cogeneration 9,037 378 0.494 KRCD Malaga Peaking Plant d 9,957 151 0.528

Henrietta Peaker d 10,351 48 0.549

CalPeak Power – Panoche 10,376 7 0.550
Wellhead Power Gates, LLC d 12,305 5 0.652
Wellhead Power Panoche, LLC d 13,716 3 0.727
MMC Mid-Sun, LLC d 12,738 1.4 0.675 Fresno Cogen Partners, LP PKR d 16,898 0.8 0.896
Source: CEC PHPP FSA (2010a), Greenhouse Table 5. Energy Commission staff based on Quarterly Fuel and Energy Report (QFER) ; with independent Energy Commission staff analysis for PHPP based on maximum utilization.

Notes: a. Based on the Higher Heating Value or HHV of the fuel. b. Includes solar generation component c. Based on continuous operation at peak capacity. d. Peaker facility25 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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## 4.0 Auxiliary Boiler and HT F Heater GHG BACT Analysis

The auxiliary boiler is part of the RSP system. Th e RSP offered by GE, the expected supplier of the Project’s combustion equipment, allows for faster starting of the gas turbines by mitigating the restrictions of former HRSG designs. Traditionally, the CTGs are brought to full load slowly to limit thermal stresses in the HP steam drum of the HRS G due to the exhaust temperature of the CTGs. The GE RSP design eliminates this restriction by modifying the steam drum design. Equipment required to support the RSP includes an auxiliary boi ler, which will supply sealing steam and allow startup of the steam turbine s hortly after the gas turbines.

As part of the RSP design, the auxiliary boiler is an essential part of the emission control system for the conventional criteria pollutants during start-up per iods, specifically, NOx, CO and VOC. As such, removing or eliminating the boiler would be detrimental to the overall plant emissions.

PHPP will also have an HTF heater. The HTF heater will be needed for the solar thermal component of the Project design. The HTF heater is used infr equently to prevent the HTF from freezing on cold nights. Because boilers and heaters operate sim ilarly, the GHG BACT for both these equipment are discussed together.


### 4.1 Step 1 - Identification of Available Control Technologies
The first step in this top-down analys is is to identify available contro l technology options. For review of the CO 2 control technologies for the auxiliary boiler and HTF heater, the following list of potentially applicable technologies available is evaluated:

 Carbon Capture and Sequestration; and

 Thermal Efficiency



### 4.1.1 Carbon Capture and Sequestration
Considering the design size, purpose, and operati on of the auxiliary boiler and HTF heater, postcombustion carbon capture is the only possible means of capturing CO 2 emissions. CO 2 emissions from the flue gas can be separated by the solv ent, sorbent or membrane based technologies. Separated CO 2 would be compressed, transported and st ored in geological, oceanic or mineral formations.



### 4.1.2 Thermal Efficiency
Thermal efficiency is a control technology for CO 2 because fuel use is directly related to CO 2 emissions from the auxiliary boiler and HTF heater. Periodic tune-up and automated adjustment of air intake improves the thermal efficiency of the boiler and heater.


### 4.2 Step 2 - Eliminating Tec hnically Infeasible Options
The second step of the BACT analysis is to eliminate technically infeasible options from the control technologies identified in Step 1.26 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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### 4.2.1 Carbon Capture and Sequestration
As discussed in Section 3.1.1, CCS control technologi es are either at pilot, demonstration or bench scale levels. Based on EPA and DOE assessments, CCS is not a technically feasible control technology for the control of CO 2 emissions from a small auxi liary boiler or HTF heater.



### 4.2.2 Thermal Efficiency
Thermal efficiency is a technically f easible alternative. It is achi eved by combusting natural gas and use of best operating practice and operating procedures.


### 4.3 Step 3 - Rank Remain ing Control Technologies
The third step of the BACT analysis is to rank the feasible control technologies; the following are the list of control technologies to be considered:

 Thermal Efficiency.

Thermal efficiency is capable of lowering GHG emissi ons, but is not quantified for the auxiliary boiler or small HTF heater, and is less than 100 percent.


### 4.4 Step 4 - Evaluation of Most Effective Control
Thermal efficiency is the only remaining technology.


### 4.5 Step 5 - Select BACT
Thermal efficiency is selected as BACT. Com bustion of natural gas and implementation of best operating practice including periodic tune-up and automa ted adjustment of air intake will maintains the thermal efficiencies of the auxiliary boiler and HTF heater at or near their design values.27 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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## 5.0 References

California Energy Commission (CEC), 2009. Fram ework for Evaluating Greenhouse Gas Implications of Natural Gas-Fired Power Plants in Cali fornia, CEC-700- 2009-009, MRW and Associates, May 27, page 92.

CEC, 2010a. Palmdale Hybrid Power Project ( 08-AFC-9), Final Staff Assessment, December.

CEC, 2010b. Commission Modified Final Guidelines for Certification of Combined Heat and Power Systems Pursuant to the Waste Heat And Car bon Emissions Reduction Act, Public Utilities Code, Section 2840 Et Seq. - Public ation # CEC-200-2009-016-CMF-REV2. May.

CEC, 2002. Russell City Energy Project ( 01-AFC-7), Final Staff Assessment. June.

Calpine, 2010. GHG BACT Analysis Case St udy, Russell City Energy Center. May.

City of Palmdale, 2008. Palmdale Hybrid Power Project Application for Certification. July.

Clean Air Act, section 169(3), 42 U.S.C. § 7479(3).

(U.S.) Environmental Protection Agency (EPA), 2010a. Available and Emerging Technologies for Reducing Greenhouse Gas Emissions from Coal-Fired Electrical Generating Units, October, page 23.

EPA 2010b. Office of Air Quality Planning and Sta ndards, PSD and Title V Permitting Guidance For Greenhouse Gases, November.

Gorte, Ross W., 2009. U.S. Tree Planting for Car bon Sequestration, Congressional Research Service 7-5700, R40562, May 4.

National Laboratory Directors for U.S. Department of Energy, 1997. Technology Opportunities to Reduce Greenhouse Gas Emissions, October.

National Energy Technology Laboratory (NETL), Department of Energy. 2010 Carbon Sequestration Atlas of the United States and Canada, Third Edition.

RTP Environmental Consultants, 2010. Hyperion Energy Center, BACT Review for Greenhouse Gas Emissions. October.

Stavins, R.N., 1999. The Costs of Carbon Seques tration: A Revealed-Pr eference Approach. The American Economic Review, September.

SLR International, 2010. Portland General Electric Company, Addendum to the Carty Power Plant PSD Application – Voluntary GH G BACT Analysis. November.28 AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 Vinson & Elkins, 2011. First Greenhouse Gas PSD Pe rmits Issued by State Regulatory Agencies. U.S. Environmental Law Update E-communication, March 21. http://www.velaw.com/resources/FirstGreenhouseGasP SDPermitsIssuedStateRegulatoryAgencies.aspxAECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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## Appendix A

GHG Emissions CalculationsAECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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## PHPP Greenhouse Gas Emissions

This appendix contains a description of the greenhous e gas (GHG) emissions calculated for the Palmdale Hybrid Power Project (PHPP).

The combustion sources and circuit breakers propos ed for PHPP may emit greenhouse gases (GHG), including carbon dioxide (CO 2 ), methane (CH 4 ), nitrous oxide (N 2 O), and sulfur hexafluoride (SF 6 ). The methodology used to calculate GHG emissi ons from these sources is explained below.



### Combustion Turbine and Duct Burner GHG Emissions
GHG emissions from operation of each of the tw o combustion turbines and duct burners are based upon the estimated usage of each at 8,760 hours/year , the estimated natural gas usage rate of 1.93 million standard cubic feet per hour (MMscf/hr), the estimated heat content of natural gas of 1,024 Btu/scf and the emission factors listed in Tables C. 6 and C.7 of the California Climate Action Registry General Reporting Protocol (GRP), Version 3.0. 1 Annual emissions of GHG are calculated using Equation A-1. Emission calculations are shown in Table A-1.

E GHG = Fuel x Operation x HV x EF GHG x conversion factor (Eq. A-1)
Where: E GHG = Emissions GHG (metric tons/yr) Fuel = natural gas usage rate (MMscf/hr) Operation = Operating schedule (hrs/yr) HV = heating value of natural gas (MMBtu/MMscf)
EF GHG = emission factor for each GHG fr om Tables C.6 and C.7 of GRP (kg/MMBtu) conversion factor = conversion factor for kilograms to metric tons 

### Auxiliary Boiler and HT F Heater GHG Emissions
GHG emissions from operation of the 100 MMBtu per hour auxiliary boiler and 40 MMBtu per hour HTF heater are based upon the estimated usage of the units by the Project (500 hours per year for the boiler and 1,000 hours per year for the heater) and the emission factors listed in Tables C.6 and C.7 of the GRP. 1 Annual emissions of GHG are calculated us ing Equation A-1. Emission calculations are shown in Table A-1.


### Emergency Internal Combus tion Engine GHG Emissions
GHG emissions from operation of the emergency diesel-fueled engi nes are based upon the estimated usage by the Project (50 hours per year, per engine), the estimated f uel consumption and the emission factors listed in Tables C.6 and C.7 of the GRP. 1 The emissions are calculated according to Equation A-2. Emission calculations are shown in Table A-1. Note that the GHG emissions are estimated for maintenance and testing operat ions, and do not reflect emergency use.

1 GRP, 2008. California Climate Action Registry General Reporting Protocol, Version 3.0, April.AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

60138827 May 2011 E GHG = fuel use x EF GHG x conversion factor (Eq. A-2)

Where: E GHG = Emissions GHG , (metric tons/yr)
EF GHG = emission factor for each GHG fr om Tables C.6 and C.7 of GRP conversion factor = conversion factor for kg to metric tons


### Circuit Breakers
There are 160 pounds of SF 6 in use in circuit breakers in th e Project equipment. Emissions are calculated according to Equation A-3.

E SF6 = Q x LR / 2,200 lbs/ton (Eq. A-3)
Where: E SF6 = Emissions of SF6 (metric tons/yr) Q = Quantity of SF6 in the Project circuit breakers LR = Leak Rate (dimensionless)

The SF 6 leakage rate from operating equipment is guarant eed at 0.5 percent per year and can be kept below 0.2 percent per year with current best technol ogy. At the maximum guaranteed leak rate of 0.5 percent, this corresponds to 0.8 pounds per year of emissions, or 8.7 metric tons /year of CO 2 equivalent (CO 2 e) emissions. The more probable, technically feasible leak rate is 0.2 percent, which corresponds to approximately 3.5 metric tons CO 2 e emissions per year, or 105 metric tons CO 2 e emissions over the 30-year plant lifetime. Emission summaries are shown in Table A-1. Emission calculations are shown in A ttachment 1 to this appendix.



### On-site Vehicular Traffic
GHG emissions from on-site light-duty vehicles (L DV), heavy-duty trucks (HDT) and the mirror wash vehicle are based upon the predicted annual miles tr aveled for the Project, average fuel economy values from the EMFAC2007 BURDEN model 2 results for 2009, and the emission factors listed in Tables C.4 and C.5 of the GRP. 1 Annual emissions of GHG are calculated using the following equations:

CO 2 , metric tons/yr = (AR/ M) x EF x conversion factor of kg to metric tons (Eq. A-4)
Where: AR = vehicle-mi les-traveled (miles/year) M = distance traveled per gallon of fuel consumed (miles/gallon)
EF = CO 2 emission factor (kg/gal)

Methane (CH 4 ) and nitrous oxide (N 2 O) emissions are calculated according to Equation A-5.

CH 4 or N 2 O, metric tons/yr = AR x EF x conversion fa ctor of kg to metric tons (Eq. A-5) Where: AR = vehicle-miles-traveled (miles/year)
EF = CH 4 or N 2 O emission factor (kg/mile)

Emission calculations are shown in Table A-2.

2 ARB, 2007. California Air Resources Board EMFAC2007 (version 2.3) Burden Model available online at:

http://www.arb.ca.gov/msei/onroad/latest_version.htm.AECOM Palmdale Hybrid Power Project Environment Greenhouse Gas BACT Analysis

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### Summary of GHG Emissions

CO 2 equivalent emissions are calculated using the global warming potential (GWP) provided in Appendix A.3, Table 2 of California Air Resour ces Board Mandatory Reporting of Greenhouse Gas Emissions Regulation 3 . The GWP values used are 1 for CO 2 , 21 for methane, 310 for nitrous oxide, and 23,900 for sulfur hexafluoride. Total CO 2 e emissions are shown in Table A-1. Due to the inherent uncertainties in these calculations, emissi on should be rounded up to two significant digits.

3 California Code of Regulations, Title 17, Subchapter 10, Article 2, Sections 95100 to 95133.AECOM Palmdale Hybrid Power ProjectEnvironment Greenhouse Gas BACT Analysis60138827May 2011Table A-1 Estimated Potential Greenhouse Gas (GHG) Emissions

Source Annual Usage, MMBTU/year Annual Usage, gallons/year CO 2 Emission Factor, kg CO 2 /MMBTU (a) CH 4 Emission Factor, kg CH 4 /MMBTU (b)

N 2 O Emission Factor, kg N 2 O/MMBTU (b) CH 4 Emission Factor, kg CH 4 /gallon (b) N 2 O Emission Factor, kg N 2 O/gallon (b) CO 2 Emissions, metric tons/year CH 4 Emissions, metric tons/year N 2 O Emissions, metric tons/year SF 6 Emissions, metric tons/year CO 2 Equivalents, metric tons/yearTurbine 1 17,356,845 -- 53.06 0.0059 0.0001 -- -- 920,954 102 1.74 923,643Turbine 2 17,356,845 -- 53.06 0.0059 0.0001 -- -- 920,954 102 1.74 923,643AuxiliaryBoiler50,000 -- 53.06 0.0059 0.0001 -- -- 2,653 0.30 5.00E-03 2,661HTF Heater 40,000 -- 53.06 0.0059 0.0001 -- -- 2,122 0.24 4.00E-03 2,129EmergencyGenerator341 2,633 73.15 -- -- 0.0003 0.0001 25 2.63E-04 2.63E-04 25Fire Pump 50 390 73.15 -- -- 0.0003 0.0001 4 3.90E-05 3.90E-05 4SF6in circuitbreakers3.63E-04 8.67Vehicles 10 1.00E-03 1.19E-03 10.33TOTAL 1,846,722 205 3.48 3.63E-04 1,852,123Notes:(a) Table C.6, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008(b) Table C.7, Industrial Sector, California Climate ActionRegistry General Reporting Protocol, Version 3.0, April 2008Diesel fuel heat content, BTUs/gallon - 129,500Global warming potential of CH4, Table C.1, California ClimateAction Registry General Reporting Protocol, Version 3.0, April 2008 - 21Global warming potential of N2O, Table C.1, California ClimateAction Registry General Reporting Protocol, Version 3.0, April 2008 - 310Global warming potential of SF6, Table C.1, California ClimateAction Registry General Reporting Protocol, Version 3.0, April 2008 - 23900AECOM Palmdale Hybrid Power ProjectEnvironment Greenhouse Gas BACT Analysis60138827May 2011Table A-2 GHG Emissions from On-Site Vehicular Traffic – OperationActivity Amount UnitsHeavy-duty truck trips 136 mi/yrLight-duty vehicle trips 19,200 mi/yrWater rinse truck 600 mi/yrHeavy heavy -duty truck gas mileage 5.37 mpgLight-duty vehicle gas mileage 19.1 mpgReference:EMFAC2007 V2.3 November 1, 2006, KCAPCD Burden 2009

Activity Amount Units Amount Units Emission Factor Category CO 2 EF, kg/gal CH 4 EF, g/mi

N 2 O EF, g/mi CO 2 Emissions, metric tons/year CH 4 Emissions, metric tons/year N 2 O Emissions, metric tons/year CO 2 e emissions, metric tons/yearHeavy-duty truck trips 136 miles/yr 25 gal/yr HDT diesel 1996+model year9.96 0.06 0.05 0.25 0.0000 0.0000 0.25Light-duty vehicle trips 19,200 miles/yr 1,003 gal/yr LDT gasoline 2000+model year8.55 0.05 0.06 8.6 0.0010 0.0012 9.0Water rinse truck 600 miles/yr 112 gal/yr HDT diesel 1996+model year9.96 0.06 0.05 1.11 0.0000 0.0000 1.12Total 19,936 miles/yr 1,141 gal/yr 9.95 0.00 0.00 10.33Notes:CO2e = CO2 emisions + 21 x CH4 emissions + 310 x N2O emissions