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. Head 
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Contents 

1.0 Introduction .......................................................................................................................... 1

1.1 Project Overview ..................................................................................................................... 1

1.2 Regulatory Overview .............................................................................................................. 2

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

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

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

2.2 Generating Facility Components ............................................................................................ 5

2.3 Process Description ................................................................................................................ 5

2.4 Energy Generation Facilities Description ............................................................................... 7

2.4.1 Combustion Turbine-Generators (CTGs) ............................................................... 7

2.4.2 Heat Recovery Steam Generators (HRSGs) and Steam Cycle ............................. 8

2.4.3 Auxiliary Boiler ......................................................................................................... 8

2.4.4 Steam Turbine-Generator (STG) ............................................................................ 9

2.4.5 Solar Thermal System ............................................................................................. 9

2.4.6 HTF Heater .............................................................................................................. 9

2.4.7 Emergency Generator ............................................................................................. 9

2.4.8 Emergency Fire Water Pump .................................................................................. 9

2.5 Operating Schedule .............................................................................................................. 10

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

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

3.1 Step1 - Identification of Available Control Technologies ..................................................... 12

3.1.1 Carbon Capture and Sequestration ...................................................................... 13

3.1.2 Lower Emitting Alternative Technology ................................................................. 14

3.1.3 Thermal Efficiency ................................................................................................. 16

3.2 Step 2 - Eliminate Technically Infeasible Options ............................................................... 17

3.2.1 Carbon Capture and Sequestration ...................................................................... 17

3.2.2 Lower Emitting Alternative Technology ................................................................. 19

3.2.3 Thermal Efficiency ................................................................................................. 19

3.3 Step 3 - Rank Remaining Control Technologies ................................................................. 19

3.3.1 Carbon Capture and Sequestration ...................................................................... 20

3.3.2 Thermal Efficiency ................................................................................................. 20

3.4 Step 4 - Evaluating the Most Effective Controls .................................................................. 20

3.4.1 Carbon Capture and Sequestration ...................................................................... 20

3.4.2 Thermal Efficiency ................................................................................................. 21
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3.5 Step 5 - Select BACT ............................................................................................................ 22

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

4.1 Step 1 - Identification of Available Control Technologies .................................................... 25

4.1.1 Carbon Capture and Sequestration ...................................................................... 25

4.1.2 Thermal Efficiency ................................................................................................. 25

4.2 Step 2 - Eliminating Technically Infeasible Options ............................................................. 25

4.2.1 Carbon Capture and Sequestration ...................................................................... 26

4.2.2 Thermal Efficiency ................................................................................................. 26

4.3 Step 3 - Rank Remaining Control Technologies ................................................................. 26

4.4 Step 4 - Evaluation of Most Effective Control ...................................................................... 26

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

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

Appendices 

A GHG Emissions Calculations 

List of Tables 

Table 1 Generation Configurations and Output .......................................................................................... 7

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

Table 3 Local Generation Heat Rates and 2008 Energy Outputs, Los 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 Diagram .................................................................................................................. 6

Figure 2 Potential CO2 Sequestration Locations by Type in Southern California .................................... 15 
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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 greenhouse gas (GHG) emissions from the project. A 

BACT analysis for criteria pollutants was submitted 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 Title V Permitting Guidance for Greenhouse Gases 

issued in March 2011. 

This Project is also subject to licensing by the California Energy Commission (CEC) as a thermal 

power plant with over 50 megawatts (MW) of electrical 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. Because 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 document, the PHPP will be a new 570 MW “state-of-the art,” “hybrid” 

natural gas-fired combined-cycle power plant integrated 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 minimize the use of fuel, which is achieved by using a thermally efficient process. 

A power plant such as PHPP is considered to have met GHG BACT requirements because of its high 

thermal efficiency. The solar component of the 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 efficient) 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 Systems (GE) Rapid Start Process (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. 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 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 integrates a 50 MW solar thermal generation component into the natural-gas generation 

component which enhances PHPP’s overall thermal efficiency. The solar generation component 

utilizes arrays of parabolic collectors that use solar energy to heat a HTF). The HTF is used to boil 
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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 percent 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 sources, such as wind and solar generation. 

 PHPP would displace some less efficient local generation in the dispatch order of gas-fired 

facilities that are required to provide electricity. 

 PHPP would facilitate to some degree the replacement 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 replacement of generation provided by aging and 

once-through cooling power plants. 

 PHPP would utilize the General Electric Power 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 would displace, the addition PHPP would contribute to a 

reduction of the California and overall Western Electricity Coordinating Council system GHG1

emissions and GHG emission rate average. Thus, 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 emissions 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 Deterioration 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) major 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 (CO2e) will be 

 

1

 Fuel-use closely correlates to the efficiency of and carbon dioxide (CO2) emissions from natural gas-fired power 

plants. And since CO2 emissions from the fuel combustion dominate GHG emissions from power plants, the 

terms CO2 and GHG are used interchangeably in this document.
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considered a major source and is required to undergo 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 CO2e 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 CO2e, 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 relevant to GHG BACT analyses. In September 2006, 

Governor Schwarzenegger signed Assembly Bill (AB) 32, the California Global Warming Solutions Act 

of 2006. AB32 establishes regulatory, reporting, and market mechanisms to achieve quantifiable 

reductions in GHG emissions and a cap on statewide GHG emissions. Senate Bill (SB) 1368 is the 

companion bill of AB32 and required the California Public Utilities Commission (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 megawatt-hour (MWh). The legislation 

further requires that all electricity provided to California, including imported electricity, must be 

generated from plants that meet the standards set by the CPUC and the CEC. 

1.3 BACT Evaluation Overview 

BACT requirements are intended to ensure that a proposed project will incorporate control systems 

that reflect the latest demonstrated practical techniques 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 technology” 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 other costs, determines is achievable 

for such facility through application of production processes and available methods, 

systems, and techniques, including fuel cleaning, 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 reduction 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 respect 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 magnitude of the emissions reduction achievable. A BACT analysis is 

performed in a top-down manner in which all applicable 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 infeasibility due to energy, environmental, and 

economic impacts, and other costs. The first control technology in the ranked list that cannot be so 

eliminated is then defined as BACT for that pollutant and process. 
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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 demonstrated 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 Description 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. 
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2.0 Project Description and GHG Emissions 

2.1 Overview 

The City of Palmdale proposes to construct and operate the PHPP. The PHPP is expected to supply 

power to the rapidly growing Southern California market. The City has contracted with Inland Energy, 

Inc. to develop the Project. 

The PHPP consists of a hybrid of natural gas-fired 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 utilizes 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 electrical output of 570 MW and commercial operation is planned for 

two and a half to three years after permitting is complete. The solar thermal input will provide almost 

ten percent of the peak power generated by the Project during the daily periods of highest energy 

demand. 

2.2 Generating Facility 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 HRSGs equipped with duct burners, 

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

 One STG, 

 Approximately 251-acre solar thermal array field 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 control, 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 duct burners provide additional heat, which enable the 

HRSGs to produce more steam in order to obtain peak output from the STG.

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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 generate 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 (gross) (see Table 1). With the CTGs at full load and 

the duct burners in-service, the HRSGs produce sufficient steam for operation of the STG at its 

peaking output of 267 MW (gross) at average ambient 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 standard for combined-cycle plants in the United 

States. 

The “Rapid Start Process” (RSP) offered by General Electric Power Systems (GE), the planned 

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 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. 

2.4 Energy Generation Facilities Description 

This section describes the major energy generation 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 CTGs 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 proposed 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. 
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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 (HP) 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 and 

reintroduced into the HRSG through the reheat loop. The hot reheat steam flows to the intermediatepressure section of the STG, and then to the low-pressure (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-aerating 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 emission 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 RSP 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 start 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 volume 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 startup. The PHPP will use one 110 MMBtu/hr, 

natural gas-fired auxiliary boiler to facilitate rapid startup 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. 
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2.4.4 Steam Turbine-Generator (STG) 

Steam from the HRSGs is sent to the STG. The 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 large 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 horizontal axis. Each solar collector has a linear 

parabolic-shaped reflector (referred to as the Heat Collection 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 ensure 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 vehicle travel over the unpaved portions of the solar field to perform 

routine maintenance including mirror washing, maintenance inspections and repairs of the piping 

network, herbicide application and dust 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 whenever 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 the plant. The plant critical services will include 

battery chargers, turning gear, lubricating oil systems, Distributed Control System and Programmable 

Logic Controller controls and critical lighting. The 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 integrity. The emergency generator system will be 

synchronized with the normal auxiliary power system from 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 emergency 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. 
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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 CO2. This report primarily presents the GHG BACT 

analysis for CO2 emissions, as CH4, N2O and SF6 emissions are insignificant, at less than 0.3 percent 

of facility GHG CO2e 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 combustion in the emergency fire water pump and emergency generator engines, 

and SF6 emissions from electrical component equipment. 

Appendix A presents the GHG emission calculations for the PHPP taken from the PHPP Application 

for Certification (AFC) as submitted to the California Energy Commission in July 2008. All emissions 

are converted to metric tons of CO2-equivalents (CO2e) and totaled. Electricity generation GHG 

emissions are dominated by CO2 emissions from natural gas combustion. The remaining PHPP GHG 

emissions of CH4, N2O, and SF6 contribute only 0.3 percent of the total CO2e emissions due to facility 

operation, notwithstanding the relatively high global 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 CO2e per year if operated at its maximum permitted level. This annual emission estimate is 

based on 8,760 hours of operation of the combustion turbines 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 boiler, and HTF heater is responsible for 99.7 percent 

of facility GHG CO2e emissions. Based on these emission estimates, 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, SF6 leakage, or vehicle emissions. 
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Table 2 Estimated Potential Greenhouse Gas (GHG) Emissions 

Emissions Source Operational GHG Emissions a

(MTCO2e/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 Performance (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 significant figures. Note that the emissions 

contribution from the emergency equipment, SF6 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. 
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3.0 BACT Determination for Combustion Turbines and Duct 

Burners 

This section presents the top-down GHG BACT determination 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. Since the combustion turbine and HRSG are coupled 

together in a combined-cycle configuration, and exhaust 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 control technologies for Combined Cycle Combustion 

Turbines was reviewed for step one of this analysis. Databases reviewed included South Coast Air 

Quality Management District (SCAQMD) 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 Clearinghouse (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 natural gas-fired combined-cycle facilities, Portland 

General Electric Company’s Carty Power Plant (SLR International, 2010). 

In addition, GHG BACT analyses were found for two Integrated Gasification Combined-Cycle (ICGG) 

facilities: 

 Hyperion Energy Center, BACT Review for Greenhouse Gas Emissions, RTP Environmental 

Consultants, October 2010. 

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

The U.S. Department of Energy (DOE) website also contained applicable information regarding 

available CO2 control technologies which are discussed below. 

For review of the CO2 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. 
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3.1.1 Carbon Capture and Sequestration 

CCS is a multiple step process which involves capturing of CO2 emissions, transportation of CO2

emissions to the sequestration site, and ultimate sequestration of CO2 emissions. 

Capturing of CO2 Emissions 

Carbon capture begins with the separation and capture of CO2 from the flue gas. Post-combustion 

capture systems being developed are expected to be capable of capturing more than 90 percent of 

flue gas CO2. Amine-based solvent systems are in commercial use for scrubbing CO2 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 CO2 that are encountered in commercial scale power 

plants. 

Solid sorbents can be used to capture CO2 from flue gas through chemical 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 allow for the selective transport/separation of CO2 from 

flue gas. The process of separating CO2 from the flue has high energy demand and is cost intensive. 

Transportation of CO2 Emissions 

CO2 captured by any of the above mentioned processes 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 CO2 emissions 

Geologic Sequestration

Under geologic sequestration, a suitable geological formation is identified close to the proposed 

project and the captured CO2 from the process is compressed and transported to the sequestration 

location. CO2 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 CO2 remains “supercritical” and behaves 

like a liquid. Supercritical CO2 is denser and takes up less space than gaseous CO2. Once injected, 

the CO2 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 CO2. Over time, the CO2 can 

dissolve in residual water and chemical reactions between the dissolved CO2 and rock can create 

solid carbonate minerals, more permanently trapping the CO2. 

There are several geologic formations identified in California that might provide a suitable site for 

geologic sequestration. As shown in Figure 2, the 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 mountain 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 CO2 sequestration (NETL, 2010, pg 111). 
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Ocean Storage

Ocean storage is accomplished by injecting CO2 into the ocean water typically below 1,000 meters via 

pipe or ship. At these depths, CO2 is expected to dissolve or form into a horizontal lens which would 

delay the dissolution of CO2 into the surrounding environment. The depth of the overlying water and 

the lensing of the CO2 will form a natural impediment to the vertical movement of the injected CO2. 

Mineral Carbonation

Mineral carbonation is the reaction of CO2 with the metal oxides forming metal carbonates which are 

very stable. These metal oxides are abundant in silicate minerals and in waste streams. The natural 

reaction of CO2 with metal oxides is a very slow process. However, the reaction time can be 

increased by enhancing the purity of these metal oxides. 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 alternative 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 inherently 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 emitting alternative technologies are feasible to incorporate into the 

project without fundamentally changing the business purpose of the Project. 
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Figure 2. Potential CO2 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. 

 PHPP 
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3.1.3 Thermal Efficiency 

CO2 is formed when fossil fuels are combusted and the thermal efficiency of that combustion process 

is determined by the thermodynamics 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 from the optimum stoichiometric conditions to reduce 

CO2 emissions without also reducing the thermal efficiency at the same time. The only useful means 

to reduce CO2 from a fossil fuel combustion process is to minimize the amount of fuel used, which is 

achieved by establishing a more thermally efficient process, 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-cycle 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-fired combustion turbine generators (CTGs), two heat 

recovery steam generators (HRSGs), and one steam 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 facility 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 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. This design modification produces 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 such as PHPP uses a relatively 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 generation. Because the project’s GHG emissions per 

megawatt-hour (MWh) will be lower than those of other power plants that the project would displace, 

the addition of PHPP to California’s energy supply will contribute to a reduction of the California and 

overall Western Electricity Coordinating Council system GHG emissions and GHG emission rate 

average. Thus, 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 emissions from new and existing 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 generation used as regulation resources, fast ramping 
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resources, or load following or supplemental energy dispatches will have to be significantly increased. 

The construction of the PHPP will aid in the effort to meet California’s RPS standard. Finally, the CEC 

has determined that the operation of PHPP will enhance the overall efficiency 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 Technically 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. The technology is feasible only when the technology 

is available and applicable. A technology that is not 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 considered for post-combustion capture of CO2 from flue gas. 

Solvent-based process

There is limited experience available in the post-combustion solvent-based capture technology for a 

commercial scale power plant. Existing demonstration 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 capture 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 CO2. Most of the U.S. Department 

of Energy (DOE) funded projects employing solid adsorption are in demonstration phase for coal-fired 

plants, but there currently are neither demonstration scale nor commercial scale installations for a 

combined-cycle gas turbine application. Consequently, 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 available in the chemical industry for CO2 removal but have not been 

demonstrated in practice for power generation applications. Consequently, a membrane-based 

carbon capture process is currently judged to be technologically infeasible for a commercial power 

plant application. 
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CO2 Transportation 

The basic technologies required for CO2 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 CO2. 

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 CO2. 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 specific site. These technical issues include: 

 A suitable geologic repository must exist for injection of the recovered CO2. The repository 

must have one or more injection zones that can accept and store large quantities of CO2 and 

is overlain by suitable caprocks. 

 The geologic repository must capable of sequestering the CO2 for the length of time 

necessary to accomplish the goal of sequestration. 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 CO2 is possible. 

 Standards for site security, and for measuring, monitoring, and verification (MMV) of 

containment must be established to allow confidence that long-term sequestration 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 feasibility for geological sequestration for the PHPP 

cannot be determined. Therefore CCS using geological 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 biological 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 CO2 is essentially moving the issue from climatic impacts to biological 

and marine impacts. Long term studies are still required to understand the potential unintended 

consequences of such disposal of CO2 in ocean basins before ocean storage can be considered to be 

technically feasible. 

Mineral Carbonation

The formation of metal carbonates is technically feasible, as reaction chemistry is well understood. 

However, the sequestration of CO2 through mineral carbonation has not been demonstrated on a 

commercial scale. 
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Summary of CCS Feasibility 

In summary, the post-combustion carbon capture technologies 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 sequestration. 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 analysis 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 available low GHG-emitting technologies that could 

be implemented, including additional solar thermal 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 GHG performance standard of 1,100 pounds of CO2 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 CO2 Emission Performance Standard (EPS) for combined 

heat and power facilities of 1,100 lbs CO2/MWh. In 2010, the CEC promulgated its regulation to 

implement AB 1613 in its Guidelines for Certification of Combined Heat and Power Systems Pursuant 

to the Waste Heat and Carbon Emissions Reduction Act (CEC 2010b). 

The PHPP meets the California GHG emission performance standard (EPS) of 1,100 pounds of CO2

per MWh with its state-of-the-art natural gas combustion turbines with RSP technology. As presented 

below in Table 3, the PHPP will emit CO2 at a rate of 0.370 MT CO2/MWh (815 lb/MWh), well below 

the required EPS. In addition, PHPP has added a low-emitting component to the project in the form of 

its 50 MW of dispatchable solar thermal generation 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 emissions 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 Remaining 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, 
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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 being developed are expected to be capable of capturing more 

than 90 percent of flue gas CO2. 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 CO2/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 emissions, 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 combined-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 achievable 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 most effective control. This step involves the 

consideration of energy, environmental, and economic impacts associated with each control 

technology. The top-down approach requires that the 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 expensive technology, largely because of the costs 

associated with CO2 capture and compression, and these costs will generally make the price of 

electricity from power plants with 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 often be eliminated from consideration in Step 4 of 

the BACT analysis, even in some cases where underground storage of the captured CO2 near 

the power plant is feasible. However, there may be cases at present where the economics of 

CCS are more favorable (for example, where the captured CO2 could be readily sold for 

enhanced oil recovery), making CCS a more viable option under Step 4. (EPA 2010b). 
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In addition to the cost of CO2 capture, CCS involves geologic or terrestrial sequestration or conversion 

of the CO2 into long-term storage. The costs associated with sequestration are very site-specific and 

can involve substantial costs for items such geotechnical studies to define identify and define feasible 

potential repositories, pipeline construction, pumping, drilling and well construction, and monitoring. 

Due to these limitations, quantitative cost analyses were determined 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 geotechnical studies. Currently those data are unavailable 

to even estimate a control efficiency. Therefore CCS can only be looked at qualitatively 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 CO2 controlled. Therefore the cost feasibility 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 technology 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 related 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 analysis of BACT 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 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 pollutants, 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 concluded that Hyperion’s proposed measures of good 

combustion practices and energy efficiency measures incorporated into the plant design were BACT 

(Vinson & Elkins 2011). 

As described in Step 2, CCS is not technically feasible for the PHPP. Even to the extent there is any 

uncertainty regarding the feasibility determination in Step 2, this Step 4 analysis demonstrates that 

CCS is not cost effective for CO2 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 turbines 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 Energy Center in Hayward, Alameda County, 

California. According to a presentation by Calpine (Calpine 2010), thermal efficiency was the 

only feasible combustion control technology considered as CCS was determined to be not 

commercially available. Thermal efficiency was found 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. 
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 A voluntary GHG BACT review was performed for the proposed addition of a 415 MW 

combined-cycle power plant at the existing Carty Power Plant operated by Portland General 

Electric Company near Boardman, Oregon (SLR International 2010). This review concluded 

that using natural gas fuel, with good operation 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 favorably with the Russell City facility in terms of energy efficiency of the 

CTGs proposed for each facility. In order to compare the thermal efficiency of the two facilities, the 

Power Plant Efficiency section of the CEC FSA was reviewed 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 maximum 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, the 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, the 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 turbine efficiency is sensitive to air density with 

higher efficiency at the higher air density of a lower 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 efficiency 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 generation facility in California for which a GHG BACT level has been 

established. 

The thermal efficiency of operating power generation facilities in Southern California, in terms of GHG 

performance, has been compared by the CEC in the FSA for the PHPP project (CEC 2010a). The 

thermal efficiency of the PHPP is the lowest (i.e., best) of any of the 37 power 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 most thermally efficient power plants in Southern 

California. Consequently, the PHPP meets any reasonable 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 CO2 / GHG emissions control at PHPP and the current design of the facility meets the 

BACT requirement for GHG emission reductions. For the PHPP, the BACT emission limit for each 

combustion turbine generating unit should be 930,000 metric tons of CO2 per year, rounded up to two 
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significant figures. Compliance can be based on a 12-month rolling average, as determined using a 

CO2 Continuous Emissions Monitoring System (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 

(MTCO2/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. 
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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 

(MTCO2/MWh)c

Palmdale Hybrid Power Project 6,970 4,993c 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 facility 
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4.0 Auxiliary Boiler and HTF Heater GHG BACT Analysis 

The auxiliary boiler is part of the RSP system. The 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 HRSG 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 boiler, which will supply sealing steam and allow 

startup of the steam turbine shortly 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 periods, 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 infrequently to prevent the HTF from freezing on cold 

nights. Because boilers and heaters operate similarly, 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 analysis is to identify available control technology options. For review of 

the CO2 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 operation of the auxiliary boiler and HTF heater, postcombustion carbon capture is the only possible means of capturing CO2 emissions. CO2 emissions 

from the flue gas can be separated by the solvent, sorbent or membrane based technologies. 

Separated CO2 would be compressed, transported and stored in geological, oceanic or mineral 

formations. 

4.1.2 Thermal Efficiency 

Thermal efficiency is a control technology for CO2 because fuel use is directly related to CO2

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 Technically Infeasible Options 

The second step of the BACT analysis is to eliminate technically infeasible options from the control 

technologies identified in Step 1. 
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4.2.1 Carbon Capture and Sequestration 

As discussed in Section 3.1.1, CCS control technologies 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 CO2 emissions from a small auxiliary boiler or HTF heater. 

4.2.2 Thermal Efficiency 

Thermal efficiency is a technically feasible alternative. It is achieved by combusting natural gas and 

use of best operating practice and operating procedures. 

4.3 Step 3 - Rank Remaining 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 emissions, 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. Combustion of natural gas and implementation of best 

operating practice including periodic tune-up and automated adjustment of air intake will maintains the 

thermal efficiencies of the auxiliary boiler and HTF heater at or near their design values. 
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5.0 References 

California Energy Commission (CEC), 2009. Framework for Evaluating Greenhouse Gas Implications 

of Natural Gas-Fired Power Plants in California, 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 Carbon Emissions Reduction Act, Public Utilities 

Code, Section 2840 Et Seq. - Publication # 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 Study, 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 Standards, PSD and Title V Permitting Guidance For 

Greenhouse Gases, November. 

Gorte, Ross W., 2009. U.S. Tree Planting for Carbon 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 Sequestration: A Revealed-Preference Approach. The 

American Economic Review, September. 

SLR International, 2010. Portland General Electric Company, Addendum to the Carty Power Plant 

PSD Application – Voluntary GHG BACT Analysis. November. 
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Vinson & Elkins, 2011. First Greenhouse Gas PSD Permits Issued by State Regulatory Agencies.

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

http://www.velaw.com/resources/FirstGreenhouseGasPSDPermitsIssuedStateRegulatoryAgencies.aspx
AECOM Palmdale Hybrid Power Project 

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Appendix A 

GHG Emissions Calculations 
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PHPP Greenhouse Gas Emissions 

This appendix contains a description of the greenhouse gas (GHG) emissions calculated for the 

Palmdale Hybrid Power Project (PHPP). 

The combustion sources and circuit breakers proposed for PHPP may emit greenhouse gases (GHG), 

including carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), and sulfur hexafluoride (SF6). 

The methodology used to calculate GHG emissions from these sources is explained below. 

Combustion Turbine and Duct Burner GHG Emissions 

GHG emissions from operation of each of the two 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. 

EGHG = Fuel x Operation x HV x EFGHG x conversion factor (Eq. A-1) 

Where: EGHG = EmissionsGHG (metric tons/yr) 

 Fuel = natural gas usage rate (MMscf/hr) 

 Operation = Operating schedule (hrs/yr) 

 HV = heating value of natural gas (MMBtu/MMscf) 

 EFGHG = emission factor for each GHG from Tables C.6 and C.7 of GRP 

(kg/MMBtu) 

 conversion factor = conversion factor for kilograms to metric tons 

Auxiliary Boiler and HTF 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 using Equation A-1. Emission calculations 

are shown in Table A-1. 

Emergency Internal Combustion Engine GHG Emissions 

GHG emissions from operation of the emergency diesel-fueled engines are based upon the estimated 

usage by the Project (50 hours per year, per engine), the estimated fuel 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 operations, and do not reflect emergency use. 

 

1

 GRP, 2008. California Climate Action Registry General Reporting Protocol, Version 3.0, April. 
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EGHG = fuel use x EFGHG x conversion factor (Eq. A-2) 

Where: EGHG = EmissionsGHG, (metric tons/yr) 

 EFGHG = emission factor for each GHG from Tables C.6 and C.7 of GRP 

 conversion factor = conversion factor for kg to metric tons 

Circuit Breakers 

There are 160 pounds of SF6 in use in circuit breakers in the Project equipment. Emissions are 

calculated according to Equation A-3. 

ESF6 = Q x LR / 2,200 lbs/ton (Eq. A-3) 

Where: ESF6 = Emissions of SF6 (metric tons/yr) 

 Q = Quantity of SF6 in the Project circuit breakers 

 LR = Leak Rate (dimensionless) 

The SF6 leakage rate from operating equipment is guaranteed at 0.5 percent per year and can be kept 

below 0.2 percent per year with current best technology. 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 CO2

equivalent (CO2e) emissions. The more probable, technically feasible leak rate is 0.2 percent, which 

corresponds to approximately 3.5 metric tons CO2e emissions per year, or 105 metric tons CO2e 

emissions over the 30-year plant lifetime. Emission summaries are shown in Table A-1. Emission 

calculations are shown in Attachment 1 to this appendix. 

On-site Vehicular Traffic 

GHG emissions from on-site light-duty vehicles (LDV), heavy-duty trucks (HDT) and the mirror wash 

vehicle are based upon the predicted annual miles traveled for the Project, average fuel economy 

values from the EMFAC2007 BURDEN model2

 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: 

CO2, metric tons/yr = (AR/ M) x EF x conversion factor of kg to metric tons (Eq. A-4) 

Where: AR = vehicle-miles-traveled (miles/year) 

 M = distance traveled per gallon of fuel consumed (miles/gallon) 

 EF = CO2 emission factor (kg/gal) 

Methane (CH4) and nitrous oxide (N2O) emissions are calculated according to Equation A-5. 

CH4 or N2O, metric tons/yr = AR x EF x conversion factor of kg to metric tons (Eq. A-5) 

Where: AR = vehicle-miles-traveled (miles/year) 

 EF = CH4 or N2O 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. 
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Summary of GHG Emissions 

CO2 equivalent emissions are calculated using the global warming potential (GWP) provided in 

Appendix A.3, Table 2 of California Air Resources Board Mandatory Reporting of Greenhouse Gas 

Emissions Regulation3

. The GWP values used are 1 for CO2, 21 for methane, 310 for nitrous oxide, 

and 23,900 for sulfur hexafluoride. Total CO2e emissions are shown in Table A-1. Due to the 

inherent uncertainties in these calculations, emission 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 Project 

Environment Greenhouse Gas BACT Analysis60138827 Table 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 O Emission 2

Factor, kg 

N O/MMBTU (b) 2

CH

4 Emission 

Factor, kg 

CH

4/gallon (b) 

N O Emission 2

Factor, kg 

N O/gallon (b) 2

CO

2 Emissions, 

metric tons/year 

CH

4 Emissions, 

metric tons/year N O Emissions

2

Turbine 1 17,356,845 -- 53.06 0.0059 0.0001 -- -- 920,954 102 1.74 Turbine 2 17,356,845 -- 53.06 0.0059 0.0001 -- -- 920,954 102 1.74 Auxiliary Boiler 

50,000 -- 53.06 0.0059 0.0001 -- -- 2,653 0.30 5.00

HTF Heater 40,000 -- 53.06 0.0059 0.0001 -- -- 2,122 0.24 4.00Emergency Generator 

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

Fire Pump 50 390 73.15 -- -- 0.0003 0.0001 4 3.90E-05 3.90SF6 in circuit 

breakers 

 

Vehicles 10 1.00E-03 1.19TOTAL 1,846,722 205 3.48 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 Diesel fuel heat content, BTUs/gallon - 129,500 Global warming potential of CH4, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008 - 21 Global warming potential of N2O, Table C.1, California Climate Action Registry General Reporting Protocol, Version 3.0, April 2008 - 310 

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

Environment Greenhouse Gas BACT Analysis60138827 Table A-2 GHG Emissions from On-Site Vehicular Traffic – Operation 

Activity Amount Units 

Heavy-duty truck trips 136 mi/yr Light-duty vehicle trips 19,200 mi/yr Water rinse truck 600 mi/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 

Amount 

Units 

Amount 

Units 

Emission 

Factor 

Category 

CO

2 EF, kg/gal 

CH

4 EF, g/mi 

N O EF, g/mi 2

CO

2

Emissions, 

metric 

tons/year 

CH4 

Heavy-duty truck trips 136 miles/yr 25 gal/yr HDT diesel 1996+ 

model year 

9.96 0.06 0.05 0.25 0

Light-duty vehicle trips 19,200 miles/yr 1,003 gal/yr LDT gasoline 2000+ 

model year 

8.55 0.05 0.06 8.6 0

Water rinse truck 600 miles/yr 112 gal/yr HDT diesel 1996+ 

model year 

9.96 0.06 0.05 1.11 0

Total 19,936 miles/yr 1,141 gal/yr 9.95 0Notes: CO2e = CO2 emisions + 21 x CH4 emissions + 310 x N2O emissions