# Preliminary Determination of Compliance

Oakley Generating Station

6000 Bridgehead Road Oakley, CA 94561



## Bay Area Air Quality Management District

Application 20798

October 2010

Kathleen Truesdell Air Quality Engineer IIii

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## Table of Contents

1. Introduction

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

2. The Power Plant Permitting Process and Opportunities for Public Participation

............................................................................................................. 3

3. Project Description

........................................................................................ 6

3.1 The Oakley Generating Station’s Combined

- Cycle “Fast

- Start” Design for

Intermediate- to -Baseload Operation: ......................................................................................... 6

3.2 Project Location ................................................................................................................ 7

3.3 How the Project Will Operate ....................................................................................... 12

3.4 Project Ownership .......................................................................................................... 17

3.5 Equipment Specifications ............................................................................................... 17



### 4. Fa cility Emissions

........................................................................................ 18

4.1 Cr iteria Pollutants .......................................................................................................... 18

4.1.1 Hourly Emissions from Gas Turbines........................................................................... 18

4.1.2 Emissions During Gas Turbine Startup, Shutdown, and Tuning Operations ............... 19

4.1.3 Hourly Emissions from Auxiliary Boiler ...................................................................... 20

4.1.4 Hourly Emissions from Fire Pump Diesel Engine ........................................................ 20

4.1.5 Da ily Facility Emissions ............................................................................................... 20

4.1.6 Annua l Facility Emissions ............................................................................................ 22

4.2 Toxic Air Contaminants ................................................................................................. 25



### 5. Bes t Available Control Technology (BACT)

............................................. 27

5.1 Introduction ..................................................................................................................... 27

5.2 Gas Turbines ................................................................................................................... 28

5.2.1 Best Available Control Technology for Oxides of Nitrogen (NO

x ) ......................... 28

5.2.2 B est Available Control Technology for Carbon Monoxide (CO) ........................... 37

5.2.3 B est Available Control Technology for Precursor Organic Compounds (POC)

.. 42

5.2.4 Best Available Control Technology for Particulate Matter (PM) .......................... 45

5.2.5 B est Available Control Technology for Sulfur Dioxide (SO 2 ) ................................ 48

5.2.6 B est Available Control Technology For Startups, Shutdowns, and Combustor Tuning

........................................................................................................................................ 49

5.2.7 B est Available Control Technology During Gas Turbine Commissioning

............ 57iii

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 5.3 Fire Pump Diesel Engine ................................................................................................ 62



### 6. R equirement to Offset Emissions Increases

.............................................. 65

6.1 POC Offsets ..................................................................................................................... 65

6.2 NO

x Offsets ...................................................................................................................... 65

6.3 PM 10 Offsets ..................................................................................................................... 66

6.4 SO 2 Offsets ....................................................................................................................... 66



### 7. Federal Permit Requirements

.................................................................... 67

7.1 Federal “Prevention of Significant Deterioration” Program ...................................... 67

7.2 Non-Attainment NSR for PM 2.5 ..................................................................................... 68



### 8. Health Risk Screening Analyses

................................................................ . 70

9. Other Applicable Requirements

................................................................ 71

9.1 Applicable District Rules and Regulations ................................................................... 71

9.2 State Requirements ......................................................................................................... 76

9.3 Federal Requirements .................................................................................................... 78

9.4 Greenhouse Gases ........................................................................................................... 82

9.5 Environmental Justi ce

................................ .................................................................... 86



### 10. Proposed Permit Conditions

....................................................................... 87

11. Preliminary Determination

....................................................................... 103

12. Glossary of Acronyms

............................................................................... 104

Appendix A

........................................................................................................... 106

Appendix B

........................................................................................................... 133iv

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## List of Tables

TABLE 1: GAS TURBINE STEADY-STATE EMISSIONS RATES (PER TURBINE) ... 18 TABLE 2: COMBINED-CYCLE TURBINE/HRSG EMISSIONS (PER TURBINE)

DURING STARTUP AND TUNING OPERATIONS............................................................. 19

T ABLE 3: MAXIMUM EMISSIONS PER SHUTDOWN (PER TURBINE) ..................... 19

TABLE 4: AUXILIARY BOILER EMISSION RATES ........................................................ 20

T ABLE 5: FIRE PUMP DIESEL ENGINE EMISSION RATES ......................................... 20

TABLE 6: MAXIMUM DAILY REGULATED CRITERIA AIR POLLUTANT

EMISSIONS FROM EACH SOURCE ..................................................................................... 22

TABLE 7: MAXIMUM ANNUAL CRITERIA AIR POLLUTANT EMISSIONS FO R

THE FACILITY.......................................................................................................................... 23

T ABLE 8: MAXIMUM FACILITY TOXIC AIR CONTAMINANT (TAC) EMISSIONS25

T ABLE 9: NO X EMISSION LIMITS FOR LARGE GAS TURBINES IN COMBINEDCYCLE POWER PLANTS ........................................................................................................ 33

TABLE 10: CO EMISSION LIMITS FOR LARGE GAS TURBINES IN COMBINEDCYCLE POWER PLANTS ........................................................................................................ 39

TABLE 11: POC EMISSION LIMITS FOR LARGE GAS TURBINES IN COMBINEDCY CLE POWER PLANTS ........................................................................................................ 42

TABLE 12: PROPOSED STARTUP AND SHUTDOWN EMISSION LIMITS FOR

OAK LEY GENERATING STATION ...................................................................................... 51

TABLE 13: STARTUP AND SHUTDOWN PERMIT LIMITS FOR SIMILAR

COMBINED-CYCLE POWER PLANT PROEJCTS USING FAST-START

TECHNOLOGY ......................................................................................................................... 55

T ABLE 14: COMMISSIONING PERIOD EMISSION LIMITS ......................................... 58

TABLE 15: COMMISSIONING SCHEDULE FOR OAKLEY GENERATING STATION

....................................................................................................................................................... 60

TABLE 16: HEALTH RISK ASSESSMENT RESULTS FOR THE PROJECT ............... 70

TABLE 17: HEALTH RISK ASSESSMENT RESULTS FROM EACH SOURCE ........... 70

TABLE 18: NEW SOURCE PERFORMANCE STANDARDS FOR COMBINED-CYCLE

GAS TURBINES ......................................................................................................................... 78

T ABLE 19: OAKLEY GENERATING STATION GHG EMISSIONS .............................. 84v Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## List of Figures

FIGURE 1: PROJECT LOCATION ......................................................................................... 8

FIGURE 2: ARCHITECTURAL RENDERING ...................................................................... 9

FIGURE 3: PLOT PLAN .......................................................................................................... 10

FIGURE 4: OAKLEY GENERATING STATION COMBINED-CYCLE DIAGRAM .... 161

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 1. Introduction

The Bay Area Air Quality Management District (District) is issuing a Preliminary Determination of Compliance (PDOC) pursuant to BAAQMD Regulation 2, Rule 3, Section 403, for the Oakley

Gene rating Station, a proposed 624-megawatt natural gas-fired electric power generation facility that would be built at 6000 Bridgehead Road in Oakley, CA. The Preliminary Determination of Compliance sets forth the District’s preliminary analysis as to how the facility will comply with applicable air quality regulatory requirements, as well as proposed permit conditions to ensure compliance. The District is publishing this document for public review and comment in accordance with District Regulations 2-3-404 and 2-2-405 and -406. The District will review

and consider all comments received from the public before deciding whether to issue a Final Determination of Compliance (FDOC) for the proposed project.

The proposed Oakley Generating Station project is a combined-cycle intermediate- to -baseload power plant that uses a state-of-the-art “Rapid Response” design for fast startups. This design means that the proposed facility will be able to operate efficiently both to meet contractual load and spot-sale demand for shaping or load-following generation, and on a full-time, base-loaded basis. As a combined-cycle facility, the proposed project will use Heat Recovery Steam Generators (HRSGs) to recover waste heat in the exhaust gases to make steam to generate additional power, increasing the plant’s overall efficiency. This highly efficient design will allow the facility to operate efficiently when needed full-time in a base-loaded mode. In addition, the proposed project’s “Rapid Response” design will allow fast startups, so that it can provide power to the grid quickly. The proposed facility will thus provide energy-efficient electric generation capacity using new conventional generation technology, with operational flexibility to efficiently address grid fluctuations due to the intermittent nature of renewable generation such as wind and solar.

The proposed project consists of two GE Frame 7FA gas turbines, two heat recovery steam generators (HRSGs), and one GE D-11 steam turbine in a combined-cycle configuration, with associated equipment including an air-cooled condenser, a natural gas-fired auxiliary boiler, a 3- cell evaporative fluid cooler, a diesel-engine driven fire pump, and an oil-water separator. More detail about the proposed facility is provided in Section 3 below (Project Description).

This PDOC sets forth the District’s reasons and analysis underlying the District’s preliminary determination that the project will comply with all applicable regulatory requirements relating to air quality. These requirements include applying Best Available Control Technology and providing emission offsets as described in District Regulation 2, Rule 2. This document also includes proposed permit conditions necessary to ensure compliance with applicable rules and regulations, air pollutant emission calculations, and a health risk assessment that estimates the impact of emissions from the project on public health.

This remainder of this document is organized as follows. Section 2 provides an overview of the legal framework for power plant permitting in California and describes how members of the public can learn about the project and provide input to the District and the California Energy Commission. Section 3 then proceeds to describe the proposed Oakley Generating Station project. Section 4 details the project’s air emissions. Sections 5 and 6 then describe the “Best2

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Available Control Technology” and emissions offset requirements for the project and how th e proposed facility will comply with them. Section 7 addresses two federal permittingrequirements, the “Prevention of Significant Deterioration” requirement and the “NonAttainment New Source Review” requirement for fine particulate matter, and explains how this facility is not subject to those requirements. Section 8 presents the results of the Health Risk Screening Analysis the District has conducted for the project, which found that the health risks from the project will be less than significant. Section 9 addresses other applicable legal requirements for the proposed project. Section 10 sets forth the proposed permit conditions for the project. Section 11 concludes with the District’s Preliminary Determination of Compliance for the project.3

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 2. The Power Plant Permitting Process and Opportunities for Public Participation

The California Energy Commission (Energy Commission or CEC) is the primary permitting authority for new power plants in California. The California Legislature has granted the Energy Commission exclusive licensing authority for all thermal power plants in California of 50 megawatts or more. ( See Warren-Alquist State Energy Resources Conservation and Development Act, Cal. Public Resources Code §§ 25000 et seq. ) This licensing authority supersedes all other local and state permitting authority. The intent behind this system is to streamline the licensing process for new power plants while at the same time providing for a comprehensive review of potential environmental and other impacts.

As the lead permitting agency, the CEC conducts an in-depth review of environmental and other issues posed by the proposed power plant. This comprehensive environmental review is the equivalent of the review required for major projects under the California Environmental Quality Act (CEQA), and the Energy Commission’s license satisfies the requirements of CEQA for these projects. This CEQA-equivalent review encompasses air quality issues within the purview of the District, and also includes all other types of environmental and other issues, including water quality issues, endangered species issues, and land use issues, among others.

The District collaborates with the Energy Commission regarding the air quality portion of its environmental analysis and prepares a “Determination of Compliance” that outlines whether and how the proposed project will comply with applicable air quality regulatory requirements. The Determination of Compliance is used by the Energy Commission to assess air quality issues of th e proposed power plant. This document presents the District’s Preliminary Determination of Compliance for the proposed Oakley Generating Station. The District will solicit and consider public input on the Preliminary Determination of Compliance, and then, if the project complies with applicable air quality requirements, the District will issue a Final Determination of Compliance for use by the Energy Commission in its CEQA-equivalent environmental review. The CEC will then conduct its environmental review, and at the end of that process, it will decide whether to issue a license for the project and under what conditions.

Both the Energy Commission licensing process and the District’s Determination of Compliance process relating to air quality issues provide opportunities for public participation. For the District’s Determination of Compliance, the District publishes its preliminary determination –

the PDOC – and invites interested members of the public to review and comment on it. This publi c process allows members of the public to review the District’s analysis of whether and how the facility will comply with applicable regulatory requirements and to bring to the District’s attention any area in which members of the public believe the District may have erred in its analysis. This process helps improve the District’s final determination by bringing to the District’s attention any areas where interested members of the public disagree with the District’s proposal at an early enough stage that the District can correct any deficiencies before making the final determination. The Energy Commission provides similar opportunities for public4

Preliminary Determination of Compliance, October 2010

Oakley Generating Station participation, and publishes its proposed actions for public review and comment before taking any final actions.

At this time, the District is at the beginning of this process for the Oakley Generating Station. The District is publishing its Preliminary Determination of Compliance (PDOC) for public review and comment, and will consider comments from the public in determining whether to issue a Final Determination of Compliance (FDOC) and on what basis. The District invites all interested parties to comment in writing on any aspect of the Preliminary Determination of Compliance pursuant to District Regulation 2-3-404. Comments should be made in writing and should be directed to Kathleen Truesdell, Air Quality Engineer II, Bay Area Air Quality Management District, 939 Ellis Street, San Francisco, CA 94109, (415) 749-4628, ktruesdell@baaqmd.gov . Comments must be received during the comment period that begins on the date of publication and ends December 7, 2010. All comments received during the comment

pe riod will be considered by the District and addressed as necessary in any Final Determination of Compliance.

The power plant approval process also provides opportunities for members of the public to participate in person in public hearings regarding this project. The District may hold a public meeting in accordance with Regulation 2, Rule 2, Section 405 to receive verbal comment from the public if there is sufficient reason to do so. Members of the public who would like to request that the District hold a public meeting should make such a request, in writing, to Ms. Truesdell at

th e address set forth in the preceding paragraph prior to the end of the comment period, and should explain the reasons why a public meeting is warranted for this particular project. Members of the public will also be afforded an opportunity to participate in public hearings regarding the project at the Energy Commission as part of the Commission’s environmental review process. The public hearings before the Energy Commission will encompass all aspects of the project, including air quality issues and all other environmental issues.

Interested members of the public are invited to learn more about the project as part of the public review and comment process. Detailed information about the project and how it will comply with applicable regulatory requirements are set forth in the subsequent sections of this document. All supporting documentation, including the permit application and data submitted by the applicant and all other information the District has relied on in its analysis, are available for public inspection at the District Headquarters, 939 Ellis Street, San Francisco, CA, 94109. This Engineering Evaluation and the principal supporting documentation are also available on the

District’s website at www.baaqmd.gov . The public may also contact Ms. Truesdell for further information (see contact information above). Para obtener información en español, comuníquese con Brenda Cabral en la sede del Distrito, (415) 749

- 4686, bcabral@baaqmd.gov

.

In addition to the District’s permitting process involving air quality issues, interested members of the public are also invited to participate in the Energy Commission’s licensing proceeding, which addresses other environmental concerns including those that are not related to air quality. For more information, go to the following CEC website: www.energy.ca.gov/sitingcases/oakley/

. The public may also contact the Energy Commission’s Public Adviser’s office at:5

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Oakley Generating Station Public Adviser California Energy Commission 1516 Ninth Street, MS-12

S acramento, CA 95814

Phone: 916-654 -4489

Toll-Free in California: 1-800-822 -6228

E-mail: PublicAdviser@energy.state.ca.us6

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 3. Project Description

The Oakley Generating Station project is a proposed 624-megawatt combined-cycle

intermediate- to -baseload power plant to be located at 6000 Bridgehead Road in Oakley, CA. This section describes the how the proposed project would function, describes where it would be located, and provides information about the specific equipment being proposed for the project.

3.1 The Oakley Generating Station’s Combined

- Cycle “Fast

- Start” Design for

Intermediate- to -Baseload Operation:

The proposed Oakley Generating Station project is a combined-cycle intermediate- to -baseload power plant, meaning that it will be able to operate efficiently to meet both contractual load and spot sale demand for electrical power, and on a full-time, base-loaded basis. 1

The facility would be a combined-cycle power plant. In a combined-cycle plant, gas turbines burn natural gas to generate electricity, and then the heat from the gas turbine exhaust is used to produce steam in a heat recovery steam generator (HRSG) to generate additional electricity via the steam turbine. The recovery of energy from the gas turbine exhaust, which otherwise would be wasted, increases the efficiency of electrical generation. Combined-cycle operation is the most efficient type of operation for a natural-gas-fired power plant, and it is typically used for base-loaded facilities that will operate full-time or near full-time. The drawback of conventional combined-cycle operation is that it takes longer for the facility to start up because the HRSG andsteam turbine have to be brought up slowly to a high temperature before the plant can come online. Combined-cycle facilities have therefore been traditionally used for base-loaded facilities, whereas simple-cycle facilities – which use just a gas turbine and not a HRSG and steam turbine

– have been used for “peaker” plants that operate only at times of peak electrical demand. Peaker plants need to come on-line quickly to be able to respond to fluctuations in demand, but they are not operated for long periods so their less-efficient design is not as great a concern.

The proposed project would overcome many of the drawbacks inherent in traditional combinedcycle operation by utilizing GE’s 207FA Expedited Rapid Response Engineered Equipment Package, which is designed to have improved operational flexibility over conventional combined-cycle power plants. The Rapid Response package allows the plant to start up significantly faster than conventional combined-cycle plants by uncoupling the steam turbine as the gas turbine ramps up and comes on-line. The steam turbine is brought on-line more slowly to allow the equipment to heat up. Using this Rapid Response package, the proposed plant will be able to complete hot startups in less than 30 minutes and cold startups in less than 90 minutes. By contrast, conventional combined-cycle power plants can take up to three hours for hot startups and six hours for cold startups. The shorter startup periods of the proposed plant mean that it can come on-line and provide electricity to the grid more quickly, and also translate to reduced startup emissions; while the combined-cycle configuration retains high thermal efficiency. This fast startup capability coupled with high efficiency will give the plant a high degree of operational flexibility, which will allow it to rapidly respond to grid fluctuations that

1 See PG&E All Source Long-Term Request for Offers , April 1, 20087

Preliminary Determination of Compliance, October 2010

Oakley Generating Station will result as more intermittent renewable resources are integrated into the grid while providing highly efficient generating capacity.

It should also be noted that the project would only be built if the California Public Utilities Commission (PUC) determines that there will be a need for it. The PUC recently declined to approve the project based on a determination that the facility would not be needed to meet current electrical demand projections (among other reasons). 2 In doing so, however, the PUC noted that the Oakley project “has numerous beneficial attributes” and would be an appropriate project if other projects currently under development are not actually completed for some reason. The PUC therefore expressly invited the applicant to resubmit the project for approval if another project or projects are not completed or other reasons arise showing that additional capacity is needed. Because of the possibility that the PUC may determine in the future that there is a need for the Oakley project, the CEC is going forward with its licensing proceeding for the facility and the District is developing a Determination of Compliance for use in that proceeding.

3.2 Project Location

The proposed Oakley Generating Station would be located at 6000 Bridgehead Road in Oakley, CA, on a 21.95-acre industrial site currently part of a 210-acre parcel owned by E. I. Du Pont de Nemours and Company (DuPont). To the west of the project site is the PG&E Antioch Terminal natural gas transmission hub, to the north is DuPont industrial and vacant industrial property, to the east is a DuPont’s landfill area, and to the south is the Atchison, Topeka and Santa Fe railroad. Currently, the proposed site is partly in viticultural use and partly undeveloped space. The proposed project location is identified on the Project Location Map below (Figure 1). (Note

that the map also identifies the locations of two other existing natural gas-fired power plants in the area, the Contra Costa Power Plant and the Gateway Generating Station, as well as the location of the recently-permitted Marsh Landing Generating Station, which is intended as a replacement for the Contra Costa Power Plant. The Contra Costa Power Plant is scheduled to shut down before the Marsh Landing Generating Station becomes operational, and before the proposed Oakley Generating Station would start operating.) An architectural rendering of the proposed project (Figure 2) and a plot plan (Figure 3) are also provided.

2 See California Public Utilities Commission Decision D1007045 on Pacific Gas & Electric Company’s 2008 Long-Term Request for Offer Results and Adopting Cost Recovery and Ratemaking July 29, 2010, available at: http://docs.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/121605-03.htm#P284_61392

.8

Preliminary Determination of Compliance, October 2010

Oakley Generating Station FIGURE 1: PROJECT LOCATION9

Preliminary Determination of Compliance, October 2010

Oakley Generating Station FIGURE 2: ARCHITECTURAL RENDERING10

Preliminary Determination of Compliance, October 2010

Oakley Generating Station FIGURE 3 : PLOT PLAN11

Preliminary Determination of Compliance, October 2010

Oakley Generating Station FIGURE 3 LEGEND12

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 3.3 How the Project Will Operate

The proposed facility would generate electric power for the grid using gas turbines and a steam turbine in a combined-cycle configuration. As noted above, “combined-cycle” means that the facility generates power from burning fuel in the gas turbines directly, and then also generates additional power using the heat in the turbine exhaust by making steam to turn a steam turbine. Generating additional power from the heat in the turbine exhaust, which would otherwise be wasted, increases the facility’s overall energy efficiency. This type of operation is represented schematically in Figure 4.

● Power Generating Equipment

The gas turbines generate power by burning natural gas, which expands as it burns and turns the turbine blades, which in turn rotate an electrical generator to generate electricity. The main components of the system consist of a compressor, combustor, and turbine. Each gas turbine would be equipped with an inlet air filter and an evaporative cooler to lower the temperature of the inlet air to the compressor and increase the mass of the inlet air during hot days, which increases power output. The compressor compresses combustion air to the combustor where the fuel is mixed with the combustion air and burned. Hot exhaust gases then enter the power turbine where the gases expand across the turbine blades, rotating a shaft to power the electric generator. The proposed two GE Frame 7FA gas turbines would be equipped with dry low NOx combustors to reduce NOx emissions and larger compressors than previous 7FA models. 3

After exiting the gas turbine, the hot exhaust gases are then sent to a heat recovery steam generator (HRSG), which makes steam from the hot exhaust gases. The proposed facility would use a triple-pressure, reheat, natural circulation HRSG 4 without duct burners. Triple-pressure reheat HRSGs maximize the amount of heat extracted from exhaust gases that would otherwise be wasted and produce high pressure (HP), intermediate pressure (IP), and low pressure (LP) steam. Under normal operating conditions, this steam is sent to a steam turbine to generate additional electricity, thereby increasing overall thermal efficiency. The reheat cycle 5 extracts more heat from the exhaust gases by reheating the cold reheat steam (steam exiting the HP section of the steam turbine) combined with superheated IP steam in the reheater sections of the HRSGs prior to being admitted to the IP section of the steam turbine. The reheat cycle makes the steam entering the IP section of the steam turbine hotter and drier, which reduces the potential for moisture erosion and increases steam turbine electrical output. Steam leaving the IP

section of the steam turbine is combined with LP steam from the HRSG and enters the LPsection of the steam turbine. Steam leaving the LP section of the steam turbine enters the aircooled condenser, transfers heat to the ambient air, condenses and returns to the HRSG feedwater system.

3 For more information, see GE Energy 7FA Heavy Duty Gas Turbine Product Evolution, at p. 4.

4 For a detailed description of the HRSG, see Radback Energy, Application for Certification Contra Costa Generating Station, June 2009, Vol. 1, Section 2.1, at p. 2-14.

5 For more information about the reheat cycle, see M. Boss, GE Power Systems, Steam Turbines for STAG TM Combined-Cycle Power Systems at p. 7-8. (available at: http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger3582e.pdf )13

Preliminary Determination of Compliance, October 2010

Oakley Generating Station After the exhaust gases exit the HRSGs, they will be routed to post-combustion emissionscontrol devices to treat the exhaust gases prior to exit from the stack. The proposed postco mbustion emissions controls consist of a Selective Catalytic Reduction (SCR) unit to reduce oxides of nitrogen (NOx) in the exhaust and an oxidation catalyst to reduce organic compounds and carbon monoxide in the exhaust. In the SCR system, NO

x in the exhaust reacts with ammonia and oxygen in the presence of a catalyst to form nitrogen and water. A small amount

of ammonia is not consumed in the reaction and is emitted in the exhaust stream as what is commonly called “ammonia slip”. The oxidation catalyst oxidizes the carbon monoxide and unburned hydrocarbons in the exhaust gases to form CO 2 and water. These emissions control

devices are described in more detail in Section 5.

Finally, the facility would use an air-cooled condenser to condense the steam from the steam turbine and recycle it back to the HRSGs. The air-cooled condenser would take the place of the traditional wet cooling tower at other combined-cycle facilities. It would use ambient air blown by large fans across finned tubes through which the steam flows. The condensed steam (condensate) is recycled back to the HRSGs. The use of an air-cooled condenser significantly reduces the amount of water consumed by the facility.

● “Rapid Response” Startup Technology

In addition to having the higher thermal efficiency of a combined-cycle plant, the proposed facility is designed to be able to start up and dispatch quickly with GE’s Rapid Response package. The Rapid Response package allows the plant to start up from warm or hot conditions in less than 30 minutes. The Rapid Response package achieves this fast performance by initiallybypassing the steam turbine when the gas turbines are started up. In a conventional combinedcycle system, the gas turbine needs to be held at low load for a period of time while the HRSG is warmed up and steam is gradually fed into the steam turbine and the steam turbine is brought up to operating temperature. The steam turbine needs to be brought up to operating temperature slowly in order to minimize thermal stresses on the equipment and to maintain the necessary clearances between the rotating and stationary components of the turbine. This delay necessitated by having to slowly warm up the HRSG and steam turbine means that the gas turbine cannot increase load as rapidly as a simple-cycle gas turbine to quickly provide power to the grid. It also causes increased startup NO

x and CO emissions, because the combustion turbine

needs to be held at low load – where it is not as efficient – while the HRSG and steam turbine are warmed up. The “Rapid Response” system initially bypasses the steam turbine when the combustion turbines are started, allowing them to ramp up quickly and begin providing power to

th e grid. The steam turbine can then be warmed up slowly without requiring the combustion turbines to be held at low load (except for a short time for cold startups), through the controlled admission of steam from the HRSGs into the steam turbine. The Rapid Response package therefore allows the facility to start up and begin providing power more quickly than a conventional system, which will enhance operational flexibility and reduce emissions associated with startups.

As part of the “Rapid Response” package, the proposed facility would also use a 50.6 MMBtu/hr natural gas-fired auxiliary boiler that would provide auxiliary steam when the plant is offline and14

Preliminary Determination of Compliance, October 2010

Oakley Generating Station during startups. When the plant is offline for relatively short periods, the auxiliary boiler would provide steam to be used for condensate sparging (to keep the oxygen level in the condensate low in order to prevent corrosion in the HRSG) and steam turbine seals (to maintain the seals and prevent loss of vacuum in the steam turbine and condenser) to maintain the steam turbine in a warm and ready state and expedite startups. At conventional combined-cycle plants (and at the proposed Oakley Generating Station during extended periods of shutdown), the steam turbine and condenser vacuum is released and vacuum needs to be re-established prior to startup. By eliminating these delays, the auxiliary boiler will allow the steam turbine to come on-line sooner and begin providing power to the grid.

● Additional Equipment

In addition to the two gas turbines, two HRSGs, steam turbine, air-cooled condenser, and auxiliary boiler, the Oakley Generating Station is proposed to include an evaporative fluid cooler to provide cooling water used by various equipment at the site, an oil-water separator, and a fire pump diesel engine.

The evaporative fluid cooler would be a relatively small, 3-cell heat exchanger, which extracts heat from a closed loop cooling system. 6 The closed loop cooling system provides cooling water to various plant equipment including gas turbine and steam turbine generator coolers, gas turbine and steam turbine lube oil coolers, and boiler feedwater pumps. During cool days, the evaporative fluid cooler would not be used. Instead, the closed-loop cooling water would be routed to an air-cooled heat exchanger that uses large fans to blow ambient air across the finned tubes carrying the closed-loop cooling water. During hot days when air-cooling would be insufficient to lower the temperature of the closed-loop cooling water, the evaporative fluid cooler would be used and circulating water would be sprayed over the tubes within the evaporative fluid cooler containing the closed-loop cooling water. The evaporation of the sprayed water would extract more heat from the closed-loop cooling water. Since this is a closed loop system, there is no contact between the closed-loop cooling water and the circulating water sprayed over the finned-tubes that evaporates. Water that is not evaporated would be captured in a sump at the bottom of the evaporative fluid cooler and circulated back to the top of the unit.

The proposed facility would have an oil-water separator to handle stormwater runoff from the powerblock area before discharge to the sanitary sewer system. 7 In the event that stormwater runoff picks up any liquid hydrocarbons ( e.g. , oil), the oil-water separator would remove them so that only water is discharged into the sanitary sewer system.

The proposed facility would also have a 400 hp diesel engine to power a fire pump onsite to be used in emergencies to provide water to fight fires in the event that electricity is not available for

6 See Radback Energy, Application for Certification Contra Costa Generating Station, June 2009, Vol. 1, Section 2.1.8.5, at p.2-26. (available at: http://www.energy.ca.gov/sitingcases/oakley/documents/applicant/afc/index.php )

7 See Radback Energy, Application for Certification Contra Costa Generating Station, June 2009, Vol. 1, Section 5.15, at p.5.15-14. (available at: http://www.energy.ca.gov/sitingcases/oakley/documents/applicant/afc/index.php )15

Preliminary Determination of Compliance, October 2010

Oakley Generating Station the electric-motor driven fire pumps. 8 The diesel engine driven fire pump would be used in case of emergency, and would also need to be operated periodically for short periods for testing and reliability purposes.

The schematic diagram in Figure 4 below illustrates how the proposed Oakley Generating

Station works.

8 See e-mail from J. McLucas Radback Energy to K. Truesdell BAAQMD dated 10/6/10.STEAMTURBINEGENERATORAIR‐COOLEDCONDENSERTOHRSG2HPIPLPLPCONDENSATERECEIVERCONDENSATEPUMPSGLANDSTEAM WATER&LEAKAGESFROMHRSG2TOFROM FROMHRSG2 HRSG2DEMINHRSG2HPIPLPLPCONDENSATEPUMPSSJAECAHPDRUMIPDRUMDLPDRUMEXHAUSTAMBIENTAIRMAKEUPWATERWARMHPIPLPLPINLETAIREVAPORATIVECOOLERHOTEXHAUSTGENERATORHPSUPERHEATERHPSUPERHEATERSTACKHPSUPERHEATERREHEATERHPECONOMIZERREHEATERHPSUPERHEATERHPEVAPORATORSUPERHEATERHPECONOMIZERIPSUPERHEATERLPHpECONOMIZERLPEVAPORATORFEEDWATERPREHEATERHPECONOMIZERIPECONOMIZERIPEVAPORATORHPIPLPLPGENERATORBLOWDOWNCOMBUSTIONTURBINE1(TYPICALOF2)HEATRECOVERYSTEAMGENERATOR(HRSG)1(TYPICALOF2)ADBNATURALHRSGBLOWDOWNHPIPLPLPBOILERFEEDPUMPSFUELGASHEATERCOakleyGeneratingStationCombined‐CycleProcessFlowDiagramGASHPIPLPLP17

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 3.4 Project Owne rship

The Oakley Generating Station is being developed by Contra Costa Generating Station, LLC (Applicant), wholly owned by Radback Energy, Inc. Contra Costa Generating Station, LLC and Radback Energy, Inc., intend to sell the project after it is built to PG&E, who would own and operate the facility thereafter.

3.5 Equipment Specifications

The proposed facility would use GE’s 207FA Expedited Rapid Response Engineered Equipment Package, including two GE Frame 7FA.05 natural gas-fired gas turbine-generators, each with a gross electrical output of 213 MW, and two unfired triple-steam-pressure heat recovery steam generators (HRSGs) that would feed one GE D-11 condensing steam turbine generator with a gross electrical output of 218 MW. Plant electrical auxiliary loads would be about 20 MW, so the net electrical output of the facility would be 624 MW. The proposed project also consists of

an air -cooled condenser, a natural gas-fired auxiliary boiler, a 3-cell evaporative fluid cooler, a diesel-engine driven fire pump, and an oil-water separator.

The equipment that the Applicant has identified for use at the Oakley Generating Station will be identified by the following identification numbers:

S-1 Gas Turbine Generator #1, GE Frame 7FA, Natural Gas-Fired, 213 MW, 2150 MMBtu/hr (HHV) maximum rated capacity with high-efficiency inlet air filter; abated by A-1 Selective Catalytic Reduction System (SCR) and A-2 Oxidation Catalyst

S-2 Gas Turbine Generator #2, GE Frame 7FA, Natural Gas-Fired, 213 MW, 2150 MMBtu/hr (HHV) maximum rated capacity with high-efficiency inlet air filter; abated by A-3 Selective Catalytic Reduction System (SCR) and A-4 Oxidation Catalyst

S-3 Auxiliary Boiler, Natural Gas-Fired, 50.6 MMBtu/hr maximum rated capacity (abated by A-5 Oxidation Catalyst if required)

S-4 Fire Pump Diesel Engine, Clarke JW6H-UFAD80 (or equivalent), 400 hp, 2.78 MMBtu/hr maximum rated heat input

S-5 Evaporative Fluid Cooler, 3-Cell, 5,880 gallons per minute (Exempt from District Permit requirements per Regulation 2, Rule 1, Section 128.4)

S-6 Oil-Water Separator, 120 gallons per hour (Exempt from District Permit requirements per Regulation 2, Rule 1, Section 103 and Regulation 8, Rule 8, Section 113)18

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 4. Facility Emissions

This section describes the air pollutant emissions that the Oakley Generating Station will have the potential to emit, as well as the principal regulatory requirements to which the emissions will be subject. Detailed emission calculations, including the derivations of emission factors, are presented in the appendices.

4.1 Criteria Pollutants

A “criteria” air pollutant is an air pollutant for which health-based standards have been established for the amount of the pollutant in the ambient air. This section discusses the criteria air pollutants that the facility will emit, along with the facility’s maximum hourly, daily, and

annual emissions rates.

4.1.1 Hourly Emissions from Gas Turbines

The Oakley Generating Station’s gas turbines will have the potential to emit up to the following amounts of criteria and precursor air pollutants per hour, as set forth in Table 1. These are the maximum emission rates for these air pollutants from each turbine during normal steady-state operations. Note that the emissions from the gas turbines will go to the HRSGs, where the heat in the exhaust will be used to make steam to generate additional power. The HRSGs will not fire any additional fuel, however, and so no additional emissions will be generated by them. The gas turbine emissions rates listed in this section therefore represent the emissions rates for the complete gas turbine/HRSG trains, although it is only the gas turbine equipment that actually generates the emissions. Emissions from this equipment will be measured at the stack at the end of the gas turbine/HRSG train, after abatement by the add-on control devices.

TABLE 1: GAS TURBINE STEADY-STATE EMISSIONS RATES (PER TURBINE)

Pollutant Turbine Emissions Rate (lb/hr)

NO

x (as NO 2 ) 15.52

CO 9.45 POC (as CH 4 ) 2.71

PM 10 /PM 2.5 7.74

SO

x (as SO 2 ) 6.0

Note that particulate matter from natural gas combustion sources normally has a diameter less

than one micron. 9 The particulate matter will therefore be both PM 10 (particulate matter with a diameter of less than 10 microns) and PM 2.5 (particulate matter with a diameter of less than 2.5 microns). 10

9 See AP -42, Table 1.4-2, July 1998, at footnote c. (available at www.epa.gov/ttnchie1/ap42/ch01/final/c01s04.pdf ).

10 PM 2.5 is a subset of particulate matter that has recently come under heightened regulatory scrutiny. EPA has established federal regulations for PM 2.5 , but they do not apply to this facility19

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 4.1.2 Emissions During Gas Turbine Startup, Shutdown, and Tuning Operations

Maximum emissions during turbine startups and combustor tuning operations, when the turbines are at low load where they are not as efficient and when emissions control equipment may not be fully operational, are summarized in Table 2. (These operating scenarios are discussed in more detail in Section 5.2.6 below.) Table 2 shows the startup emissions and tuning emissions for each turbine. (Note that only NOx, CO, and POC emissions are affected by reduced efficiency during startups. For PM and SO 2 , emission rates will not be any greater than normal operation during startup, shutdown, or tuning.)

TABLE 2: COMBINED-CYCLE TURBINE/HRSG EMISSIONS (PER TURBINE)

DU RING STARTUP AND TUNING OPERATIONS

Pollutant Cold

Startup (lb/event) a Cold

Startup (lb/hour) b Hot/Warm

Startup (lb/event) c Hot/Warm

Startup (lb/hour) d Tuning

(lb/event) e Tuning

(lb/hour)

NO

x (as NO 2 ) 96.3 99.9 22.3 33.9 576 .0 96

CO 360.2 362.4 85.2 92.2 2, 16 0.0 360 POC (as CH 4 ) 67.1 67.7 31.1 33.1 402 .0 67

a Cold Startups not to exceed 90 minutes; by definition, occurs after turbine has been inoperative for at least 48

hours

b Hourly emissions with a cold startup assumes one cold startup in 45 minutes and 15 minutes of steady-state operation

c Hot/Warm Startups not to exceed 30 minutes; by definition, occur between 0 and 48 hours after a shutdown

d Hourly emissions with a hot or warm startup assumes one hot startup in 14 minutes and 46 minutes of steady-state operation

e Combustor tuning not to exceed 6 hours per event and 2 tuning events per year per turbine. Note that emissions rates from combustor tuning may turn out to be lower than the rates listed here, and the District will evaluate turning emissions and potentially impose lower emissions limits once the facility commences operation. See Section 5.2.6.2. for further details. The rates listed here represent worst-case emissions.

Maximum emissions during gas turbine shutdowns (also discussed in detail in Section 5.2.6) are

summarized in Table 3.

TABLE 3 : MAXIMUM EMISSIONS PER SHUTDOWN (PER TURBINE)

Pollutant Shutdown Emissions Rate (lb/shutdown) a Shutdown Emis sions Rate (lb/hour)

NO

x (as NO 2 ) 39.3 46.8

CO 140.2 144.7 POC (as CH 4 ) 17.1 18.4

a Shutdowns not to exceed 30 minutes.

as discussed in Section 7. The District is also in the process of developing regulations specifically directed to control PM 2.5 , but those regulations are not in place yet. For this facility, however, the District’s existing PM 10 regu lations will be equally effective in controlling PM 2.5 because all of the PM emissions from this facility will be both PM 2.5 and PM 10

.20

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 4.1.3 Hourly Emissions from Auxiliary Boiler

The auxiliary boiler will have the potential to emit up to the following amounts of regulated air pollutants per hour, as set forth in Table 4.

TABLE 4: AUXILIARY BOILER EMISSION RATES

Pollutant Steady

- State

Emissions Rate (lb/hr) Startup/Shutdown a

Emissions Rate (lb/hr) Commissioning/Tuning (l b/hr)

NO

x (as NO 2 ) 0.42 1.27 2.55

CO 0.37 1.11 2.22 POC (as CH 4 ) 0.11 0.32 0.63

PM 10 /PM 2.5 0.35 0.35 0.35

SO

x (as SO 2 ) 0.14 0.14 0.14

a Startups make take up to one hour and shutdowns may take up to 15 minutes. Tuning required annually by District Regulation 9, Rule 7, section 313 in accordance with the procedures set forth in District Manual of Procedures, Volume I, Chapter 5.

4.1.4 Hourly Emissions from Fire Pump Diesel Engine

The fire pump diesel engine will have the potential to emit up to the following amounts of regulated air pollutants per hour, as set forth in Table 5. These are the emission rates for regulated air pollutants based on emission factors from CARB certification in Executive Order

U-R-004-0369 for one hour of operation.

TABLE 5 : FIRE PUMP DIESEL ENGINE EMISSION RATES

Pollutant Fire Pump Diesel Engine Emissions Rate (lb/hr)

NO

x (as NO 2 ) 2.311

CO 0.592 POC (as CH 4 ) 0.122

PM 10 /PM 2.5 0.105

SO

x (as SO 2 ) 0.004

4.1.5 Daily Facility Emissions

Maximum daily emissions of regulated air pollutants emissions for the Oakley Generating Station are set forth in Table 6 below. The table shows emissions from the gas turbines, the auxiliary boiler, and the diesel-engine driven fire pump. The table also shows emissions from the evaporative fluid cooler and oil water separator, which are both exempt from District permit requirements.21

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Note that for NOx, CO and POC, the daily maximum emission rates for the gas turbines are taken from the enforceable daily permit limits being proposed in condition Parts 19 and 20. The District is proposing these daily limits based on a reasonable assumption of the maximum operation likely for this equipment. The District has assumed such a reasonable maximum operating scenario to consist of one cold startup lasting 45 minutes and with the maximum permitted cold startup emissions of 96.3 lb NOx, 360.2 lb CO, and 67.1 lb POC; one shutdown lasting 30 minutes and with maximum permitted shutdown emissions of 39.3 lb NOx, 140.2 lb CO, and 17.1 lb POC; and the remaining 22.75 hours of the day in normal steady-state operation. For days on which combustor tuning occurs (limited to twice per year per turbine), 6 hours of the

22.75 steady-state operating hours were assumed to involve combustor tuning. The District has based the proposed daily emissions limits on these assumptions as a reasonable scenario of maximum foreseeable daily emissions, but it is important to note that emissions from this equipment will be limited to these emissions rates regardless of actual operating profile. This is because the emissions limitations in condition Parts 19 and 20 are enforceable permit limits, and the facility will be required to keep emissions below these levels regardless of operating profile. Thus, if for example the facility has more than one startup per day, leading to more startup emissions than the District used in its calculation of the reasonably foreseeable maximum operating scenario, the facility will be required to curtail operations to ensure that the daily

maximum is not exceeded. 11

The daily maximum emission rates for the auxiliary boiler are taken from the enforceable daily permit limits being proposed in condition Part 35. As with the turbine limits, these daily limits are based on reasonable assumptions of how the auxiliary boiler is likely to operate, but they are enforceable permit limits that the facility will be required to meet regardless of how it is operated on any particular day.

Maximum daily emissions for the diesel fire pump assume 24-hour operation in a prolonged

e mergency using the maximum hourly rates listed above. Maximum daily emissions from the evaporative fluid cooler are calculated from the total dissolved solids in the water, flow rate, and drift rate of the evaporative fluid cooler. Maximum daily emissions from the oil-water separator were calculated using EPA’s published emission factor for this equipment using the maximum hourly operating rate and assuming 24 hours per day operation. Full details are set forth in Appendix A.

11 As an intermediate- to -baseload facility, the Oakley Generating Station is not expected to have multiple startups per day under normal circumstances. It is possible that on a particular day the facility could be called on to start up and shut down more than once, however. The facility will still be subject to all permit conditions in such cases, including maximum limits on hourly emissions, startup and shutdown emissions, and daily emissions.22

Preliminary Determination of Compliance, October 2010

Oakley Generating Station TABLE 6 : MAXIMUM DAILY REGULATED CRITERIA AIR POLLUTANT

EMISSIONS FROM EACH SOURCE Pollutant (lb/day)

Source Nitrogen

Oxides (as NO 2 ) Carbon

Monoxide Precursor

Organic Compounds Particulate

Matter (PM 10 ) Sulfur

Dioxide

Gas Turbine (no tuning) 488 715 146 186 144 Gas Turbine (tuning) 971 2818 531 186 144

S

- 3 Auxiliary Boiler 9.8 9.8 2.8 8.5 3.4

S

- 4 Diesel Fire Pump Engine 55.5 14.2 2.9 2.5 0.1

S

- 5 Evaporative Fluid

Cooler a 0 0 0 3.2 0

S

- 6 Oil

- water separator b 0 0 0. 6 0 0

a S-5 Evaporative Fluid Cooler is exempt from District Regulations per BAAQMD Regulation 2-1-128.4.

b S-6 Oil-water separator is exempt from District Regulations per BAAQMD Regulations 2-1-103 and 8-8-113.

These daily emission rates are used to determine which sources at the facility are subject to the requirement to use “Best Available Control Technology” pursuant to District New Source Review regulation (NSR; Regulation 2, Rule 2). Pursuant to District Regulation 2-2-301.1, any

ne w source that has the potential to emit 10 pounds or more per highest day of POC, NO

x , SO 2 , PM 10 , or CO is subject to the BACT requirement for that pollutant. As Table 6 shows, the gas turbines will emit over 10 pounds per highest day of NO

x , CO, POC, PM 10 , and SO 2 , and are required to use Best Available Control Technology per Regulation 2-2-301 to limit emissions of these pollutants. The Diesel Fire Pump Engine will have the potential to emit over 10 pounds per day of NOx and CO and is required to use Best Available Control Technology to limit emissions of these pollutants. 12 The District’s analysis of the Best Available Control Technology for this equipment is described in Section 5 below.

The remaining equipment at the facility is not subject to the BACT requirement in District Regulation 2, Rule 2, as none of it will emit more than 10 pounds per day of any criteria pollutant. In addition, the evaporative fluid cooler is exempt from District permitting per Regulation 2, Rule 1, Section 128.4, and the oil/water separator is exempt from District permitting per Regulation 2, Rule 1, Section 103 and Regulation 8, Rule 8, Section 113.

4.1.6 Annual Facility Emissions

The maximum annual emissions of regulated air pollutants for the proposed Oakley Generating Station project are set forth in Table 7 below. Table 7 shows the annual emissions from the

12 Note that under normal circumstances, the diesel fire pump engine will only be operated for short periods for testing and reliability purposes. Under these circumstances, emissions of all criteria pollutants are likely to be well under 10 pounds per day. It is possible, however, that the engine would need to be operated for longer periods in the event of an emergency. The District is therefore providing worst-case emissions based on a full 24 hours per day of emergency operation.23

Preliminary Determination of Compliance, October 2010

Oakley Generating Station facility, totaled for the permitted sources and for the permitted sources plus the exempt sources. Annual facility emissions for permitted sources are used to determine whether the facility will need to offset its emissions with Emissions Reduction Credits under District Regulations 2-2-202

a nd 2-2-203. Offsets are required for permitted sources with NO

x and POC emissions over 10 tons per year and for PM 10 and SO 2 emissions over 100 tons per year. (Note that annual emissions are also used to determine whether additional federal permitting requirements apply. This project is not subject to any additional federal requirements because it will not emit more than 100 tons per year of any pollutant as discussed in more detail in Section 7.)

Annual emissions will be subject to enforceable permit limits to ensure that they remain below

the amounts listed in Table 7. These maximum annual rates are based on estimates derived from reasonable operating scenarios that the facility is likely to experience in operation as an

intermediate- to -baseload facility. Information about the operating scenarios the District used to develop these annual emissions rates is provided in the explanatory notes to Table 7, with additional details provided in Appendix A. While the District believes that these operating scenarios are realistic, it should be noted that compliance with the emissions rates listed in Table 7 does not require the facility to conform to any specific operating scenario. Because the emission rates listed in Table 7 are enforceable, not- to -exceed emissions limits in the permit, the facility will be required to monitor its emissions and ensure that they do not exceed the limits during any 12-month period. If it appears that the facility is nearing its annual limit, it will be

re quired by law to reduce or curtail operations to ensure that emissions do not exceed the permitting annual rates.

TABLE 7: MAXIMUM ANNUAL CRITERIA AIR POLLUTANT EMISSIONS FOR

T HE FACILITY

NO 2 a
(ton/yr) CO b

(ton/yr) POC c

(ton/yr) PM 10 a

(ton/yr) SO 2 a

(ton/yr)

Gas Turbines 98.626 98.000 29.274 63.715 12.524 Auxiliary Boiler 0.099 0.803 0.217 0.060 0.024 Diesel Fire Pump Engine 0.057 0 .015 0.003 0.003 0.0001 Total subject to District Permits 98.78 98.82 29.49 63.78 12.55 Total including equipment exempt from

District Permits 98.78 98.82 29.60 63.88 12.55

Notes: Exempt equipment includes Evaporative Fluid Cooler and Oil-water separator. See Appendices for Emission

Calculations.

a Annual NOx, PM, and SO 2 emissions are based on 8,463 hours per year of operation from the turbines (including 1 cold start, 51 hot starts, 52 shutdowns), 401 hours for the auxiliary boiler (including 52 startups and 52 shutdowns), 1,500 hours per year for the evaporative fluid cooler, and 49 hours per year of maintenance and testing for the fire pump diesel engine. Gas turbine annual NOx emissions are based on expected 1.5 ppmvd; annual SO 2 emissions are based on annual average grain loading (0.25 gr/100 scf) and 1.5 lb/hr emission rate.

b Annual CO emissions are based on 5,390 hours per year of operation from the turbines (including 25 cold starts, 275 warm/hot starts, 300 shutdowns), 3,978 hours for the auxiliary boiler (including 300 startups and 300 shutdowns), 1,500 hours per year for the evaporative fluid cooler, and 49 hours per year of maintenance and testing for the fire pump diesel engine. Gas turbine annual CO emissions are based on expected 1.0 ppmvd.

c Annual POC emissions are based on 5,662 hours per year of operation from the turbines (including 1 cold start, 311 hot/warm starts, 312 shutdowns) and 3,717 hours for the auxiliary boiler (including 312 startups and 312 shutdowns), 1,500 hours per year for the evaporative fluid cooler, and 49 hours per year of maintenance and testing for the fire pump diesel engine.24

Preliminary Determination of Compliance, October 2010

Oakley Generating Station These annual emissions rates show that the facility will be required to offset its emissions of NO

x and POC under District Regulation 2-2-302, because emissions will be over 10 tons per year (and for NO

x , will have to provide credits at a ratio of 1.15 tons of credits per 1 ton of emissions, because emissions will be over 35 tons per year). The facility will not be required to offset its

PM 10 and SO 2 emissions under District Regulation 2-2-303 because emissions of each of these poll utants will be less than 100 tons per year. Offset requirements are discussed in more detail in

Section 6.25

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 4.2 Toxic Air Contaminants

Toxic Air Contaminants (TACs) are a subset of air pollutants that can be harmful to health and the environment even in very small amounts. Table 8 provides a summary of the maximum annual facility toxic air contaminant (TAC) emissions from the project. 13

TABLE 8: MAXIMUM FACILITY TOXIC AIR CONTAMINANT (TAC) EMISSIONS

Toxic Air Contaminant Project

Emissions (lb/hour) Project

Emissions (lb/year) Acute

Risk Screening Trigger Level (lb/hr) Chronic

Risk Screening Trigger Level (lb/yr)
1,3

- Butadiene 0.001 4.40 None 0.63 Acetaldehyde 5.386 4952.12 1.0 38

Acrolein 0.290 663.67 0.0055 14

Ammonia 29.321 241336.38 7.1 7,700

Benzene 0.108 463.33 2.9 3.8 Benzo(a)anthracene a 0.00010 0.78 None None Benzo(a)pyrene a 0.00006 0.48 None 0.0069 Benzo(b)fluoranthene a 0.00005 0.39 None None Benzo(k)fluoranthene a 0.00005 0.38 None None Chrysene a 0.00011 0.87 None None Dibenz(a,h)anthracene a 0.00010 0.81 None None Ethylbenzene 0.137 622.64 None 43 Formaldehyde 19.487 16652.10 0.12 18

Hexane 1.090 8970.54 None 270, 000 Indeno(1,2,3

- cd)pyrene a 0.00010 0.81 None None Naphthalene 0.007 57.49 None 3.2 Propylene 3.244 26703.82 None 120,000 Propylene Oxide 0.201 1655.57 6.8 29

Toluene 0.413 2464.76 82 12,000 Xylene (Total) 0.110 903.98 49 27,000

Sulfuric Acid Mist ( H 2 SO 4 ) 6.194 12795.41 0.26 39

Benzo(a)pyrene equivalents 0.00019 1.58 None 0.0069

Specified PAHs b 0.00055 4.54 None None

Diesel Particulate Matter c 0.105 5.16 None 0.34

Arsenic d 0.000018 0.03 0.000440 0.0072 Copper d 0.000047 0.07 0.220000 None

Lead d 0.000013 0.02 None 3.2

Notes:

13 See “Project TACs Summary” spreadsheet in OGS Emissions Calcs workbook, prepared by K.

Truesdell.26

Preliminary Determination of Compliance, October 2010

Oakley Generating Station a Polycyclic Aromatic Hydrocarbons (PAHs) impacts are evaluated as Benzo(a)pyrene equivalents.

b Specified PAHs are the sum of the following PAHs.

PAHs Equivalency Factor Benzo(a)anthracene 0.1 Benzo(a)pyrene 1.0 Benzo(b)fluoranthrene 0.1 Benzo(k)fluoranthene 0.1 Chrysene 0.01 Dibenz(a,h)anthracene 1.05 Indeno(1,2,3-cd)pyrene 0.1

c Diesel Particulate Matter is a surrogate for all air toxics emitted by the diesel engine.

d Emitted by Evaporative Fluid Cooler

Total of Hazardous Pollutants listed in Section 112(b) of the Federal Clean Air Act = 18.7 tons/year. Section 112(b) list does not include ammonia, propylene, or sulfuric acid mist, which are included as Toxic Air Contaminants in BAAQMD Regulation 2, Rule 5. The project is not a major source of hazardous air pollutants under the Clean Air Act because emissions are less than 10 tons/year of any single hazardous air pollutant listed under Section 112(b) and less than 25 tons/year of all such hazardous air pollutants combined. Emissions from the exempt evaporative fluid cooler are included.

Table 8 is also a summary of the emissions used as input data for air pollutant dispersion models used to assess the increased health risk to the public resulting from the project. The ammonia emissions shown are based upon a worst-case ammonia emission concentration of 5 ppmvd @

15% O 2 from the gas turbine SCR systems. The chronic and acute screening trigger levels shown are per Table 2-5-1 of Regulation 2, Rule 5.

I f emissions are above certain established screening levels prescribed in Table 2-5-1 of

R egulation 2, Rule 5, a health risk assessment is required. Where no acute trigger level is listed for a TAC, none has been established for that TAC. Based on the information contained in Table 8, a health risk assessment is required by District Regulation 2, Rule 5. The health risk assessment is conducted to determine the potential impact on public health resulting from the worst-case TAC emissions from the projec t.

The results of the health risk assessment are discussed in full in Section 8 of this document. As explained in Section 8, the proposed facility will comply with all health risk requirements in District Regulation 2, Rule 5. Results from the health risk screening analysis indicate that the maximum cancer risk for the project as a whole is estimated at 1.56 in a million, and the maximum non-cancer risks for the project as a whole are estimated at a hazard index of 0.0832 for chronic health impacts and 0.2665 for acute health impacts. The risk from each source individually is below 1.0 in a million for the maximum individual cancer risk and below 0.02 for the maximum chronic hazard index. In accordance with the District’s Regulation 2, Rule 5, the proposed Oakley Generating Station will comply with all toxic risk requirements for each individual source and for the project as a whole.27

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 5. Best Available Control Technology (BACT)

The District’s New Source Review regulations require the proposed Oakley Generating Station to utilize the “Best Available Control Technology” (BACT) to minimize air emissions, as discussed in more detail below. This section describes how the BACT requirements will apply to the facility.

5.1 Introduction

District Regulation 2-2-301 requires that the Oakley Generating Station use the Best Available

C ontrol Technology to control NO

x , CO, POC, PM 10 , and SO

x emissions from sources that will have the potential to emit over 10 pounds per highest day of each of those pollutants. Pursuant to Regulation 2-2-206, BACT is defined as the more stringent of:

(a ) The most effective control device or technique which has been successfully utilized for the type of equipment comprising such a source; or

(b) The most stringent emission limitation achieved by an emission control device or technique for the type of equipment comprising such a source; or

(c) Any emission control device or technique determined to be technologically feasible and cost-effective by the APCO; or

(d) The most effective emission control limitation for the type of equipment comprising such a source which the EPA states, prior to or during the public comment period, is contained in an approved implementation plan of any state, unless the applicant demonstrates to the

satisfaction of the APCO that such limitations are not achievable. Under no circumstances shall the emission control required be less stringent than the emission control required by any applicable provision of federal, state or District laws, rules or regulations.

The type of BACT described in definitions (a) and (b) must have been demonstrated in practice and is referred to as “BACT 2”. This type of BACT is termed “achieved in practice”. TheBACT category described in definition (c) is referred to as “technologically feasible/costeffective” and it must be commercially available, demonstrated to be effective and reliable on a full-scale unit, and shown to be cost-effective on the basis of dollars per ton of pollutant abated. This is referred to as “BACT 1”. BACT specifications (for both the “achieved in practice” and “technologically feasible/cost-effective” categories) for various source categories have been compiled in the BAAQMD BACT Guideline.

The gas turbines are subject to BACT under the District’s New Source Review regulations (Regulation 2, Rule 2, Section 301) for NO

x , CO, POC, PM 10 , and SO

x because each unit will have the potential to emit more than 10 pounds per highest day of those pollutants. The diesel fire pump engine will have the potential to emit over 10 pounds per day of NOx and CO in28

Preliminary Determination of Compliance, October 2010

Oakley Generating Station emergency situations, 14 and it is subject to BACT for these pollutants. The following sections provide the basis for the District BACT analyses for this equipment.

5.2 Gas Turbines

The following section provides the District’s BACT analyses for the project’s gas turbines.

5.2.1 Best Available Control Technology for Oxides of Nitrogen (NO

x )

Oxides of Nitrogen (NO

x ) are a byproduct of the combustion of an air-and-fuel mixture in a hig h -temperature environment. NO

x is formed when the heat of combustion causes the nitrogen molecules in the combustion air to dissociate into individual nitrogen atoms, which then combine with oxygen atoms to form nitric oxide (NO) and nitrogen dioxide (NO 2 ). This reaction primarily forms NO (95% to 98%) and only a small amount of NO 2 (2% to 5%), but the NO eventually oxidizes and converts to NO 2 in the atmosphere. NO 2 is a reddish-brown gas with detectable odor at very low concentrations. NO and NO 2 are generally referred to collectively as

“NO

x ”. 15 NO

x is a precursor to the formation of ground-level ozone, the principal ingredient in

smog.

Control Technology Review:

The District has examined technologies that may be effective to control NO

x emissions in two general areas: combustion controls that will minimize the amount of NO

x created during combustion; and post-combustion controls that can remove NO

x from the exhaust stream after

combustion has occurred.

Combustion Controls

The formation of NO

x during combustion is highly dependent on the primary combustion zone temperature, as the formation of NO

x increases exponentially with temperature. There are therefore three basic strategies to reduce thermal NO

x in the combustion process:

 Reduce the peak combustion temperature

 Reduce the amount of time the air/fuel mixture spends exposed to the high combustion

temperature

 Reduce the oxygen level in the primary combustion zone

14 Routine, non-emergency use is limited to short periods of operation for testing and reliability purposes, with emissions well under 10 pounds per day of all pollutants.

15 NO

x can also be formed when a nitrogen-bound hydrocarbon fuel is combusted, resulting in the release of nitrogen atoms from the fuel (fuel NO

x ), and NO

x can be formed by organic free

ra dicals and nitrogen in the earliest stages of combustion (prompt NO

x ). Natural gas does not contain significant amounts of fuel-bound nitrogen. Therefore, thermal NO

x is the primary formation mechanism for natural gas fired gas turbines. References to NO

x formation during combustion in this analysis refer to “thermal NO

x ”, which is NO

x formed from nitrogen in the

combustion air.29

Preliminary Determination of Compliance, October 2010

Oakley Generating Station It should be noted, however, that techniques that control NO

x by reducing combustion temperatures involve a trade-off with the formation of other pollutants. Reducing combustion temperatures to limit NO

x formation can decrease combustion efficiency, resulting in increased byproducts of incomplete combustion such as carbon monoxide and unburned hydrocarbons. (Unburned hydrocarbons from natural gas combustion consist of methane, ethane and precursor organic compounds.) The District prioritizes NO

x reductions over carbon monoxide emissions, however, because the Bay Area is not in compliance with applicable ozone standards, but does comply with carbon monoxide standards. The District therefore requires applicants to minimize

NO

x emissions to the greatest extent feasible, and then optimize CO and POC emissions for that

level of NO

x control. This is a trade-off that must be kept in mind when selecting appropriate emissions control technologies for these pollutants.

The District has identified the following available combustion control technologies for reducing

NO

x emissions from the gas turbines.

Steam/Water Injection: Steam or water injection was one of the first NO

x control techniques utilized on gas turbines. Water or steam is injected into the combustion zone to act as a heat sink, lowering the peak flame temperature and thus lowering the quantity of thermal NO

x formed. The injected water or steam exits the turbine as part of the exhaust. The lower peak flame temperature can also reduce combustion efficiency and prevent complete combustion, so

carbon monoxide and POC emissions can increase as water/steam- to -fuel ratios increase. In addition, the injected steam or water may cause flame instability and can cause the flame to quench (go out). Water/steam injection in the gas turbines used in conjunction with Low- NO

x burners can achieve NO

x emissions as low as 25 ppm @ 15% O 2

. 16

Dry Low- NO

x Combustors: A technology that can control NO

x without water/steam injection is Dry Low- NO

x combustion technology. Dry Low- NO

x Combustors reduce the formation of

thermal NO

x through (1) “lean combustion” that uses excess air to reduce the primary combustion temperature; (2) reduced combustor residence time to limit exposure in a high temperature environment; (3) “lean premixed combustion” that reduces the peak flame temperature by mixing fuel and air in an initial stage to produce a lean and uniform fuel/air mixture that is delivered to a secondary stage where combustion takes place; and/or (4) two-stage rich/lean combustion using a primary fuel-rich combustion stage to limit the amount of oxygen available to combine with nitrogen and then a secondary lean burn-stage to complete combustion in a cooler environment. Dry Low- NO

x combustors can achieve NO

x emissions as low as 9 ppm

for frame-size turbines. 17

16 M. Schorr, J. Chalfin, GE Power Systems, Gas Turbine NOx Emissions Approaching Zero

– Is

it Worth the Price? GER4172 , September 1999, at p. 2 (available at: http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger4172.pdf )

17 J. Kovac, Siemens Energy Inc., Advanced SGT6-5000F Development

, Power-Gen International 2008-Orlando, Florida, at p. 8 (available at:http://www.energy.siemens.com/hq/pool/hq/energy-topics/pdfs/en/gas-turbines-powerplants/PowerGen2008_SGT65000F.pdf )30

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Catalytic Combustors: Catalytic combustors, marketed under trade names such as XONON 

,

u se a catalyst to allow the combustion reaction to take place with a lower peak flame temperature

in order to reduce thermal NO

x formation. XONON  uses a flameless catalytic combustion module followed by completion of combustion (at lower temperatures) downstream of the catalyst. Catalytic combustors such as XONON  have not been demonstrated on large-scale utility gas turbines such as the Siemens F Class or GE Frame 7FA so the technology is not available for use at the proposed Oakley Generating Station.

Post-Combustion Controls

The District has identified the following post-combustion controls that can remove NO

x from the

emissions stream after it has been formed.

Selective Catalytic Reduction (SCR): Selective catalytic reduction is a technology that reacts

the NO

x in the turbine exhaust with ammonia and oxygen in the presence of a catalyst to form nitrogen and water. NO

x conversion is sensitive to exhaust gas temperature, and performance can be limited by contaminants in the exhaust gas that may mask or poison the catalyst. A small

amount of ammonia is not consumed in the reaction and is emitted in the exhaust stream as what is commonly called “ammonia slip”. The SCR catalyst requires replacement periodically. SCR is a widely used post-combustion NO

x control technique on utility-scale gas turbines, usually in conjunction with combustion controls. SCR has been demonstrated to be able to achieve NOx emission limits of 2.0 ppm. 18

Selective non-catalytic reduction (SNCR): Selective non-catalytic reduction involves injection of ammonia or urea with proprietary conditioners into the exhaust gas stream without a catalyst. SNCR technology requires gas temperatures in the range of 1600°F to 2100°F 19 and is most commonly used in boilers because gas turbines do not have exhaust temperatures in that range. Selective non-catalytic reduction (SNCR) requires a temperature window that is higher than the exhaust temperatures from utility gas turbine installations. The exhaust temperature from the proposed turbines ranges from approximately 1030°F to 1135°F 20 , so SNCR is technically

infeasible.

EMx  : EMx  (formerly SCONOx  ) is a catalytic oxidation and absorption technology that uses a two-stage catalyst/absorber system for the control of NO

x emissions for gas turbine applications (as well as CO, VOC and optionally SOx emissions). A coated catalyst oxidizes

NO to NO 2 (as well as oxidizing CO to CO 2 and VOCs to CO 2 and water), and the NO 2 is then absorbed onto the catalyst surface where it is chemically converted to and stored as potassium nitrates and nitrites. A proprietary regenerative gas is periodically passed through the catalyst to

desorb the NO 2 from the catalyst and reduce it to elemental nitrogen (N 2 ). No ammonia is used

18 See, e.g. , facilities listed in Table 9 below using SCR to achieve 2.0 ppm permit limits.

19 See EPA Air Pollution Control Fact Sheet , EPA-452/F- 03 -031 (available at: http://www.epa.gov/ttn/catc/dir1/fsncr.pdf )

20 See Radback Energy Supplemental Filing Air Quality and Public Health Revised April 7, 2010, Application for Certification for Oakley Generating Station Project , Appendix 5.1F, at p.

5.1F-16.31

Preliminary Determination of Compliance, October 2010

Oakley Generating Station by the EMx  process. The EMx  catalyst requires washing and replacement periodically.

EMx  has been successfully demonstrated on several small gas turbine projects, including one on a 45 megawatt turbine. The District is not aware of any EMx  installations on a gas turbine of the size proposed for the Oakley Generating Station (Siemens F Class or GE Frame 7FA), although the manufacturer has claimed that it can be effectively scaled up and made available for utility-scale turbines. 21

EMx could potentially be an improvement over SCR as an add-on control device for achieving NOx reductions – assuming it can achieve the same level of NOx control – because it does not

use ammonia. Ammonia has the potential, under certain atmospheric conditions, to reach with nitric acid in the atmosphere to form ammonium nitrate, which can be a form of fine particulate matter (PM 2.5 ). The atmospheric chemistry regarding the extent to which this process actually happens under real-world conditions has historically not been well understood, and the District’ s scientific understanding has been until recently that there was insufficient nitric acid in the atmosphere to make secondary PM 2.5 formation a significant concern. As a result, the District has not historically regulated ammonia as a PM 2.5 precursor, and has not found that EMx’s lack of ammonia slip emissions would provide any significant benefit over SCR. The District has recently been reevaluating whether ammonia is in fact a significant contributor to secondary

PM 2.5 . The focus of the District’s further evaluation has been a computer modeling exercise designed to predict what PM 2.5 levels will be around the Bay Area, given certain assumptions

about emissions of PM 2.5 and its precursors, about regional atmospheric chemistry, and about prevailing meteorological conditions. 22 The results of this study, while still preliminary, confirm that the predominant limiting factor in the formation of secondary particulate matter is the availability of nitric acid, not ammonia. However, the study suggests that the amount of available nitric acid is not uniform, and varies in different locations around the Bay Area, and

that in some locations there is available nitric acid to react with ammonia. The District’s model thus predicts that a reduction of 20% in total ammonia emissions throughout the Bay Area would result in changes in ambient PM 2.5 levels of between 0% and 4%, depending on the availability of nitric acid. While this analysis is still preliminary, it suggests that that ammonia restrictions might play a role in a regional strategy to reduce PM 2.5

. 23 The District is therefore evaluating whether it should impose regulations on ammonia emissions as a PM 2.5 precursor, as well as taking a harder look at whether it should require EMx as a BACT control technology for NOx

reductions instead of SCR.

EMx has never been used on a large utility-scale turbine, however, and so there is no data on which to make a direct evaluation of how well the technology would work at this facility. EMx has been used on a smaller aeroderivitive turbine at the Redding Power Plant Unit No. 5, a 45-

21 See EmeraChem, High Performance EMxTM Technology For Fine Particles, NOx, CO, and VOCs From Gas Turbines and Stationary IC Engines (EMx White Paper), May 2008 at p. 15. (available at: http://www.emerachempower.com/index.php?section=downloads&id=10 )

22 See BAAQMD, Fine Particulate Matter Data Analysis and Modeling in the Bay Area (Preliminary Report, Oct. 1, 2009), at p. 8 (Preliminary PM2.5 Modeling Report). (available at: http://www.baaqmd.gov/~/media/Files/Planning%20and%20Research/Research%20and%20Mo deling/PM-data-analysis-and-modeling-report.ashx )

23 Preliminary PM 2 .5 Modeling Report at pp. E-3 – E-4.32

Preliminary Determination of Compliance, October 2010

Oakley Generating Station MW combined-cycle facility in Shasta County, CA. The data from that facility show that EMx cannot readily keep emissions as low as 2.0 ppm, which SCR can easily achieve. The Shasta County Air Quality Management District evaluated EMx TM at the Redding facility under a

demonstration NO

x limit of 2.0 ppm. After three years of operation, the Shasta County AQMD evaluated whether the facility was meeting this demonstration limit with EMx TM , and concluded that “Redding Power is not able to reliably and continuously operate while maintaining the NO

x demonstration limit of 2.0 ppmvd @ 15% O 2 .” 24 Although the manufacturer maintains that such problems have been overcome, concerns remain about how consistently the technology would be able to perform. Recent communications with the Shasta County Air District confirm that the earlier conclusions about the achievability of a lower limit remain valid. 25 In addition, monthly reports of Continuous Emissions Monitoring System (CEMS) data submitted by Redding Power Plant to Shasta County Air District during the past three calendar years indicate that emissions have often been substantially higher. 26 Furthermore, the data from Redding are from a smaller aeroderivitive turbine, and there is no guarantee that if it were scaled up for use on utility-size turbines that it would even be able to achieve the performance of the Redding Power facility. For all of these reasons, it is clear that EMx is not as developed as SCR at this time and cannot achieve the same level of emissions performance that SCR is capable of.

Proposed BACT Control Technology for NO

x for Gas Turbines:

The Applicant has proposed the use of Dry Low- NO

x combustors and SCR as BACT for the combined-cycle gas turbines. As explained above, these are the most effective combustion and pot-combustion control technologies available for this type of facility. These emissions control technologies therefore satisfy the District’s BACT requirement.

Proposed BACT Emissions Limit for NO

x for Gas Turbines:

The District is also proposing to establish a BACT emissions limit in the permit of 2.0 ppmvd @

15% O 2 (averaged over one hour), which is the most stringent limit that has been achieved in practice at any other similar facility and is the most stringent limit that would be technologically

feasible.

To determine the most stringent emissions limit that has been achieved in practice, the District evaluated other similar combined-cycle gas turbines. The District reviewed the NO

x emissions limits of power plants using large turbines in a combined-cycle mode abated by SCR systems. The District reviewed BACT determinations at the EPA RACT/BACT/LAER Clearinghouse, ARB BACT Clearinghouse and recent projects listed by the CEC as approved or under construction. The combined-cycle facilities with the most stringent permit limits, as listed in these databases, are shown in the table below.

24 Letter from R. Bell, Air Quality District Manager, Shasta County Air Quality Management District, to R. Bennett, Safety & Environmental Coordinator, Redding Electric Utility, June 23,

2005.

25 See Memorandum of Record of Telephone call to Shasta County dated 10/2 5 /2010, prepared by W

. Lee BAAQMD.

26 See Redding Unit 5 NOx CEM summary (SCONOx) 2007-2008.33

Preliminary Determination of Compliance, October 2010

Oakley Generating Station TABLE 9: NO

x EMISSION LIMITS FOR LARGE GAS TURBINES I N COMBINEDCYCLE POWER PLANTS

Facility Name RBLC ID or

CEC Docket # NOx ppmvd @ 15% O2 (averaging period)

Lawrence Energy OH

- 0248 3.0 Longview Energy Development WA

- 0288 3.0 (24

- hr); 2.5 (12

- month)

Middleton Facility ID

- 0010 3.0 (24

- hr) without duct fi ring; 3.5 (24

- hr) with duct firing; 2.5 (12

- month) all modes Wansley Combined Cycle Energy Facility GA

- 0102 3.0 Augusta Energy Center GA

- 0093 3.0

Delta

- Calpine 1998

- AFC

- 03 2.5 (1

- hr) Moss Landing

- L.S. Power 1999

- AFC

- 04 2.5 (1

- hr)

La Paloma

- Compl ete Energy Holdings 1998

- AFC

- 02 2.5 (1

- hr)

Los Medanos

- Calpine 1998

- AFC

- 01 2.5 (1

- hr)

Pastoria

- Calpine 1999

- AFC

- 07 2.5 (1

- hr) Gateway

- PG&E 2000

- AFC

- 01 2.5 (1

- hr) High Desert

- Constellation 1997

- AFC

- 01 2.5 (1

- hr)

Sutter

- Calpine 1997

- AFC

- 02 2.5 (1

- hr) Blythe I

- NextEra Energy (FPL) 1999

- AFC

- 08 2.5 (1

- hr)

Elk Hills

- Sempra & Oxy 1999

- AFC

- 01 2.5 (1

- hr)

Metcalf

- Calpine 1999

- AFC

- 03 2.5 (1

- hr) COB Energy Facility, LLC OR

- 0039 2.5 (4

- hr)

Wallula Power Plant WA

- 0291 2.5 (3

- hr)

McIntosh Comb ined Cycle Facility GA

- 0105 2.5 Cogen Technologies Linden Venture, L.P. NJ

- 0059 2.5

Empire Power Plant NY

- 0100 2.0 (3

- hr) without duct firing; 3 (3

- hr) with duct firing FPL Turkey Point Power Plant FL

- 0263 2.0 (24

- hr)

Otay Mesa

- Calpine 1999

- AFC

- 05 2. 0 (1

- hr), allows 15 1

- hr excursions for

transient load etc.

Mountainview 2000

- AFC

- 02 2.0 (1

- hr), allows 15 one

- hour excursions for

transient load etc.

Cosumnes

- SMUD 2001

- AFC

- 19 2.0 (1

- hr); 30 (1

- hr) transient load

Palomar Escondido

- SDG&E 2001

- AFC

- 24 2.0 (1

- hr); 2.0 (3

- hr) with duct firing or

transient hour of +25 MW Sacramento Municipal Utility District CA

- 0997 2.0 PSEG Fossil LLC Linden Generating

Station NJ

- 0058 2.0

Warren County Facility VA

- 0308 2.0 Warren County Facility VA

- 0308 2.0

Warre n County Facility VA

- 0308 2.0 Tracy Substation Expansion Project NV

- 0035 2.0 (3

- hr) Copper Mountain Power NV

- 0037 2.0 (3

- hr) Sumas Energy 2 Generation Facility WA

- 0315 2.0 (3

- hr) Magnolia

- So. Ca. Power Producers 2001

- AFC

- 06 2.0 (3

- hr)

Goldendale Ene rgy, Inc. WA

- 0302 2.0 (3

- hr) La Paz Generating Facility, Siemens option AZ

- 0049 2.0 (3

- hr) changes to (1

- hr) after 18 months La Paz Generating Facility, GE option AZ

- 0049 2.0 (3

- hr) changes to (1

- hr) after 18 months Wellton Mohawk Generating Station,

Si emens

- Westinghouse 501F option AZ

- 0047 2.0 (3

- hr) changes to (1

- hr) after 18 months

Wellton Mohawk Generating Station, GE

7FA option AZ

- 0047 2.0 (3

- hr) changes to (1

- hr) after 18 months34

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Facility Name RBLC ID or

CEC Docket # NOx ppmvd @ 15% O2 (averaging period)

Ivanpah Energy Center, L.P. NV

- 0038 2.0 (1

- hr) without duct firing; 13.96 lb/hr with duct firing Gila Bend Power Generating Station AZ

- 0038 2.0 (1

- hr) El Segundo Repower

- NRG 2000

- AFC

- 14 2.0 (1

- hr) Victorville Hybrid Gas

- Solar

- City of

Victorville 2007

- AFC

- 1 2.0 (1

- hr)

Duke Energy Arlington Valley AZ

- 0043 2.0 (1

- hr)

Colusa II Generation Station

- PG&E

Final Decision 2006

- AFC

- 9 2.0 (1

- hr)

Lodi Energy Center

- NCPA 2008

- AFC

- 10 2.0 (1

- hr) Avenal Energy

- Avenal Power Center, LLC 2008

- AFC

- 1 2.0 (1

- hr) Russell City

- Calpine & GE 2001

- AFC

- 07 2.0 (1

- hr)

CPV Warren VA

- 0291 2.0 (1

- hr) Kleen Energy Systems, Inc. CT

- 0151 2.0 (1

- hr) IDC Bellingham a CA

- 1050 2.0/1.5 (1

- hr)

a The IDC Bellingham facility in Massachusetts, was permitted with a two-tiered NOx emissions limit that imposed an absolute not- to -exceed limit of 2.0 ppm but also required the facility to maintain emissions below 1.5 ppm during normal operations. (Note also that the facility was never built.) This two-tiered limit recognized that emissions can be highly variable depending on operating circumstances, and will have relatively lower emissions at some times and relatively higher emissions at other times. The proposed Oakley Generating Station is expected to exhibit the same type of variation in emissions under the various operating scenarios it will face, and it is expected to have emissions below 2.0 ppm at times but will have emissions as high as 2.0 ppm under some circumstances. The District is therefore proposing a 2.0 ppm limit to ensure that the limit will be achievable under all operating conditions.

As Table 9 shows, emissions of 2.0 ppm NO

x averaged over 1-hour is the most stringent emission limitation that has been determined to be achievable at any similar facility using SCR

for NO

x control.

The District also considered whether it would be feasible to implement a NO

x permit limit below

2 .0 ppm. Consistent compliance with a limit below 2.0 ppm has never been demonstrated in practice, and the equipment vendors that the District contacted regarding this issue stated that they would not be able to guarantee that a lower limit could be achieved. 27 The District nevertheless considered whether it would be technologically feasible to do so. The District has concluded that imposing a NOx emissions limit below 2.0 ppm cannot be justified as BACT at

this time.

Additional NOx reductions could potentially be achieved by increasing the amount of catalyst or size of the catalyst bed in the SCR system. It would be difficult to achieve any substantial additional reductions, however, because at the very low NOx levels that are currently being achieved by SCR additional efforts produce diminishing returns. SCR performance for NO

x control is highly dependent on the NO

x to ammonia reaction stoichiometry. At stoichiometric

27 See, e.g., Letter from T. Pintcke, Vice President, Black & Veatch, to K. Truesdell, Air Quality Engineer, Bay Area Air Quality Management District, Oct. 11, 2010, stating that Black & Veatch “sees no basis for and will not guarantee an hourly limit for NO

x emissions below 2 ppm for any averaging period.”35

Preliminary Determination of Compliance, October 2010

Oakley Generating Station conditions, there would be just enough ammonia to react with the NO

x with no additional ammonia slip exhausted out the stack. It becomes highly challenging to ensure a uniform

distribution of ammonia to NO

x over the entire gas turbine operating range when NOx concentrations are very low. Alternatively, some vendors have considered staging two separate ammonia injection grids and catalyst beds in series in order to achieve an optimal distribution of

ammonia to NO

x that might maintain emissions at less than 2.0 ppm NO

x over the entire gas turbine operating range. But this approach has its own drawbacks, such as increasing the backpressure on the turbine exhaust and decreasing the efficiency of the turbine resulting in higher emissions per megawatt of power generated. Moreover, no installation using a staged series of ammonia injection grids has been demonstrated in practice. Additionally, temperature variations across the catalyst bed also impact SCR performance. At progressively lower NOx concentrations, these variations have an increasingly significant impact on maintaining stoichiometric conditions. For all of these reasons, it becomes increasingly difficult to gain additional NOx reductions as concentrations are driven to extremely low levels simply by increasing the amount of catalyst or the size of the catalyst bed. Increasing the amount of catalyst or size of catalyst bed theoretically can provide for more NOx reduction, but for a number of reasons simply adding more catalyst reaches a point of diminishing returns as NOx levels approach zero. 28

In addition, achieving lower NOx emissions levels would have other potential offsetting impacts. Ensuring emissions consistently remain below 2.0 ppm could potentially cause a significant increase in ammonia slip and require a higher ammonia slip permit limit. Implementing a NO

xlimit below 2.0 ppm would also likely require an increase in the frequency of catalyst changeouts to maintain compliance. This would have both cost impacts and ancillary environmental impacts, because the old catalyst must be disposed of as hazardous waste, because the larger amount of catalyst needed would generate more spent catalyst to be disposed of, and because additional energy and natural resources would need to be used to produce the new catalyst. A

NO

x permit limit below 2.0 ppm limit would also result in additional maintenance, which adds to

ope rating costs and requires maintenance outages during which the plant is unavailable to meet demand. For example, achieving very low NOx limits would require the seals in the SCR system

to be maintained to very tight tolerances to minimize the amount of NOx that may slip by them.

With a NO

x permit limit below 2.0 ppm, it is likely that more frequent outages will be required to inspect and maintain these seals, which adds to the cost and could significantly impact the plant’s

a vailability to support the grid.

Finally, assuming that an SCR system could be designed to achieve emissions below 2.0 by increasing the amount of catalyst or the size of the catalyst bed, the system would have to be able

to operate to maintain compliance at all times, including during periods transient load. Compliance is much more difficult during such periods because the SCR system’s ammonia injection control system is limited in how quickly it can respond to rapidly changing conditions. The amount of ammonia being inject ed is determined based on turbine operating conditions and

the NO

x concentration at the stack exhaust. There is an optimal amount of ammonia based on the incoming NO

x and the ammonia injection system provides a slight excess to ensure the NO

x

28 See generally M. Schorr & J. Chalfin, Gas Turbine NOx Emissions Approaching Zero

– Is it

Worth the Price? , GE Power Generation, Publication No. GER 4172,36

Preliminary Determination of Compliance, October 2010

Oakley Generating Station emissions are minimized while ammonia slip levels are also minimized. When gas turbine load is ramped quickly, its NOx emissions can change much more rapidly than the ammonia injection system can respond due to the lag time in the ammonia injection control system and the NO

x continuous emission monitor. This control system lag and continuous emission monitor (CEM) lag time make meeting a permit limit below 2.0 ppm NO

x averaged over one hour much more difficult during rapid load changes.

Designing an SCR system to consistently maintain compliance with a limit below 2.0 ppm would also be more difficult because transient load conditions and fast ramp rates are expected to

beco me more common in the coming years as California moves to more renewable power generation. Renewable sources of electrical power such as wind and solar are much more intermittent and uncertain that traditional power plants. Fossil fuel fired plants will be needed to fill in the gaps when the sun is not shining or the wind is not blowing, and they will be required to ramp up quickly when needed and then ramp back down when renewable sources come back

on -line. 29 For this reason, facilities such as the Oakley Generating Station are expected to experience a significantly increased amount of transient load conditions, although it is difficult to predict with certainty exactly how these facilities will need to operate. An SCR system would need to be designed to operate at a very high degree of efficiency in order to ensure that it would be able to maintain compliance with a short-term NOx limit below 2.0 during all potential transient load conditions. Moreover, given the uncertainty as to how exactly the facility will need to operate in support of additional renewable generation, it would be difficult to predict the maximum design parameters that would be needed to ensure compliance.

Based on all of this analysis, the District has concluded that there is insufficient evidence on which to make a determination that a NOx emissions limit can be justified as BACT for this facility. Although it may be possible in theory to design an enhanced SCR system that could potentially be more effective in reducing NOx, there is substantial uncertainty as to how effective such an enhanced system would actually be in consistently achieving a lower permit limit. Moreover, even if a lower limit could theoretically be achieved, there is substantial uncertainty over how the SCR system would need to be designed to do so given the changes in power plant operating scenarios that are expected as California moves to more renewable power sources, and in particular the greater incidence of transient load conditions. The District is also concerned that if the facility is subjected to a lower limit and finds that it cannot achieve it during transient loads, the facility would not be able to be operated to support renewable resources as readily, which would hinder California’s efforts to develop those resources. And finally, the

Dist rict is also mindful of the additional costs and ancillary adverse environmental impacts that would be associated with an enhanced SCR system. Although additional costs and ancillary impacts can be acceptable where justified by the increased effectiveness of a better add-on control system under a BACT analysis, there is little clear indication that additional NOx reductions beyond the very stringent 2.0 ppm levels that are currently being achieved would be worth it here (to the extent that any additional reductions could even be obtained in practice). Given the high degree of uncertainty regarding what level of additional NOx reductions could actually be achieved, what would be required from a technical standpoint to achieve any such

29 Integration of Renewable Resources, Operational Requirements and Generation Fleet

Ca pability at 20% RPS, August 31, 2010, California ISO, pg. iii.37

Preliminary Determination of Compliance, October 2010

Oakley Generating Station additional reductions, and what the adverse ancillary impacts would be, the technical information available at this point does not provide a sufficiently certain basis to support a BACT determination that a NOx emissions limit below 2.0 should be required. The District has considered all of this evidence and has concluded that it does not support imposing a NOx emissions limit below 2.0 ppm as BACT for this project.

The District has therefore determined that 2.0 ppmvd at 15% O 2 , averaged over 1-hour, is the

BACT emission limit for NO

x for the combined-cycle gas turbines. The District is also proposing corresponding hourly mass emissions limits. Compliance with the NO

x permit limits will be demonstrated on a continuous basis using a continuous emissions monitor.

5.2.2 Best Available Control Technology for Carbon Monoxide (CO)

Carbon monoxide is a colorless odorless gas that is a product of incomplete combustion.

Control Technology Review:

As with NO

x , the District has examined both combustion controls to reduce the amount of carbon monoxide generated and post-combustion controls to remove carbon monoxide from the exhaust

stream.

Combustion Controls

Carbon monoxide is formed by incomplete combustion. Incomplete combustion occurs when there is not enough air to fully combust the fuel, and when the air and fuel are not properly mixed due to poor combustor tuning. Maximizing complete combustion by ensuring an adequate air/fuel mixture with good mixing will reduce carbon monoxide emissions by preventing its formation in the first place.

Increasing combustion temperatures can also promote complete combustion, but doing so will

increase NO

x emissions due to thermal NO

x formation as described in the previous section. The District prioritizes NO

x control over carbon monoxide control because the Bay Area is not in compliance with state and federal standards for ozone, which is formed by NO

x emissions reacting with other pollutants in the atmosphere. The District therefore does not favor increasing combustion temperatures to control carbon monoxide. Instead, the District favors approaches

that reduce NO

x to the lowest achievable rate and then optimize carbon monoxide emissions for

that level of NO

x emissions.

Good Combustion Practi ce: The District has identified good combustion practice as an available combustion control technology for minimizing carbon monoxide formation during combustion. Good combustion practice utilizes “lean combustion” – large amount of excess air – to produce a cooler flame temperature to minimize NO

x formation, while still ensuring good air/fuel mixing with excess air to achieve complete combustion, thus minimizing CO emissions. Good combustion practice can be used with the low- NO

x combustion technology selected for minimizing NO

x emissions (Dry Low- NO

x Combustors).38

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Post-Combustion Controls

The District has also identified two post-combustion technologies to remove carbon monoxide

from the exhaust stream.

Oxidation Catalysts: An oxidation catalyst oxidizes the carbon monoxide in the exhaust gases

to form CO 2 . Oxidation catalysts are a proven post-combustion control technology widely in use on large gas turbines to abate CO and POC emissions.

EMx  : EMx  , described above in the NO

x discussion, is a multimedia control technology that

abates CO and POC emissions as well as NO

x . EMx  technology uses a catalyst to oxidize

carbon monoxide emissions to form CO 2 , and is therefore also an oxidation catalyst. However, it is not a stand-alone oxidation catalyst since the EMx  is also a NO

x reduction device. Hence, it is identified as a device separate from the oxidation catalyst. EMx  is not as effective as SCR in achieving NOx reductions, however, and so the District rejected it as a BACT control technology.

Proposed BACT Control Technology for CO for Gas Turbines:

Based on the foregoing discussion, the District has determined that the proposed combination of good combustion practice to reduce the formation of carbon monoxide during combustion and an

o xidation catalyst to remove carbon monoxide from the gas turbines exhaust satisfies the BACT requirement.

Proposed BACT Emissions Limit for Carbon Monoxide (CO) for Gas Turbines:

The District is also proposing a CO BACT limit of 2.0 ppmvd @ 15% O 2 (1 -hou r average), which is the most stringent that has been achieved in practice at other similar combined-cycle facilities and is the most stringent limit that is technologically feasible and cost-effective.

To establish what level of emissions performance has been achieved in practice for this type of facility, the District reviewed the CO emissions limits of other large combined-cycle power plants using oxidation catalyst systems. As with the NO

x comparison set forth above, the District reviewed BACT determinations for CO at the EPA RACT/BACT/LAER Clearinghouse, ARB BACT Clearinghouse and recent projects listed by the CEC as approved or under construction. The combined-cycle facilities with the most stringent permit limits, as listed in these databases, are shown in the table below.39

Preliminary Determination of Compliance, October 2010

Oakley Generating StationTABLE 10: CO EMISSION LIMITS FOR LARGE GAS TURBINES IN COMBINEDCY CLE POWER PLANTS

Facility Name RBLC ID or

CEC Docket # CO ppmvd @ 15% O2 (averaging period)

FPL Turkey Point Power Plant FL

- 0263 14.1 (24

- hr) with duct firing and power aug; 6.0 (all modes) annual average

Delta

– Calpine 1998

- AFC

- 03 10 (3

- hr)

La Paloma

- Complete Energy Holdings 1998

- AFC

- 02 10 (3

- hr) if < 221 MW, or 6.0 (3

- hr) if > 221

MW Moss Landing

- L.S. Power 1999

- AFC

- 04 9.0 (3

- hr)

Pastoria

– Calpine 1999

- AFC

- 07 6.0 (3

- hr) Gateway

- PG&E 2000

- AFC

- 01 6.0 (3

- hr)

Los Medanos

– Calpine 1998

- AFC

- 01 6.0 (3

- hr) Otay Mesa

– Calpine 1999

- AFC

- 05 6.0 (3

- hr)

Mountainview 2000

- AFC

- 02 6.0 (1

- hr) Longview Energy Development WA

- 0288 6.0 (1

- h r); 2.0 (12

- month) Middleton Facility ID

- 0010 5.0 (1

- hr), 2.0 (12

- month) Sacramento Municipal Utility District CA

- 0997 4.0 High Desert

– Constellation 1997

- AFC

- 01 4.0 (24

- hr) Blythe I

- NextEra Energy (FPL) 1999

- AFC

- 08 4.0 (3

- hr)

Sutter

– Calpine 1997

- AFC

- 02 4.0 (3

- hr)

Cosumnes

– SMUD 2001

- AFC

- 19 4.0 (3

- hr)

Elk Hills

- Sempra & Oxy 1999

- AFC

- 01 4.0 (3

- hr)

Metcalf

– Calpine 1999

- AFC

- 03 4.0 (3

- hr)

Palomar Escondido

- SDG&E 2001

- AFC

- 24 4.0 (3

- hr) Gila Bend Power Generating Station AZ

- 0038 4.0 (3

- hr)

Ivanpah Energy Center, L.P. NV

- 0038 4.0 (1

- hr) without duct firing; 17 lb/hr with duct firing El Segundo Repower

– NRG 2000

- AFC

- 14 4.0 (1

- hr) Tracy Substation Expansion Project NV

- 0035 3.5 (3

- hr) La Paz Generating Facility, Siemens option AZ

- 0049 3.0 ( 3

- hr) La Paz Generating Facility, GE option AZ

- 0049 3.0 (3

- hr) Wellton Mohawk Generating Station,

Siemens

- Westinghouse 501F option AZ

- 0047 3.0 (3

- hr)

Wellton Mohawk Generating Station, GE 7FA

option AZ

- 0047 3.0 (3

- hr)

Copper Mountain Power NV

- 0037 3.0 (3

- hr) Duke Energy Arlington Valley AZ

- 0043 3.0 (3

- hr)

Colusa II Generation Station

- PG&E

Final Decision 2006

- AFC

- 9 3.0 (3

- hr)

Lawrence Energy OH

- 0248 2.0 without duct firing; 10.0 with duct firing Victorville Hybrid Gas

- Solar

- City of

Vic torville 2007

- AFC

- 1 2.0 (1

- hr) without duct firing; 3.0 (1

- hr) with duct firing Wansley Combined Cycle Energy Facility GA

- 0102 2.0 Augusta Energy Center GA

- 0093 2.0 McIntosh Combined Cycle Facility GA

- 0105 2.0 Cogen Technologies Linden Venture, L.P. NJ

- 0059 2.0 PSEG Fossil LLC Linden Generating Station NJ

- 0058 2.0 COB Energy Facility, LLC OR

- 0039 2.0 (4

- hr) Avenal Energy

- Avenal Power Center, LLC 2008

- AFC

- 1 2.0 (3

- hr)

Wallula Power Plant WA

- 0291 2.0 (3

- hr) Lodi Energy Center

- NCPA 2008

- AFC

- 10 2.0 (3

- hr) Magnolia

- So. Ca. Power Producers 2001

- AFC

- 06 2.0 (1

- hr)40

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Facility Name RBLC ID or

CEC Docket # CO ppmvd @ 15% O2 (averaging period)

Sumas Energy 2 Generation Facility WA

- 0315 2.0 (1

- hr) Goldendale Energy, Inc. WA

- 0302 2.0 (1

- hr) IDC Bellingham CA

- 1050 2.0 (1

- hr) Russell City

- Calpine & GE 2001

- AFC

- 07 2.0 (1

- hr)

W arren County Facility a VA

- 0308 1.8 without duct firing; 2.5 with duct firing

CPV Warren a VA

- 0291 1.3 without duct firing; 1.8 with duct firing and power aug Warren County Facility a VA

- 0308 1.3 without power aug. Warren County Facility a VA

- 0308 1.3 w ithout duct firing; 1.2 with duct firing Kleen Energy Systems, Inc. b CT

- 0151 0.9 (1

- hr) without duct firing

Notes:

a Warren County Facility and CPV Warren are the same facility (Permit Number 81391) and have not been built; a new application amended April 27, 2010, by Virginia Electric Power and Power Company (Dominion) is under review and will replace the listed determinations.

b Kleen Energy Systems has not yet been operated.

Based on the facilities that the District has reviewed, the most stringent permit limit that has been achieved in practice by any other similar facility is 2.0 ppmvd @ 15% oxygen averaged over one hour. Permits issued for two facilities – the Warren County facility and the Kleen Energy

S ystems facility – included some limits of less than 2.0, but neither of these facilities has actually

c ome online yet and so there is no operating data available on which to assess whether they will actually be able to meet these lower limits. The fact that permits have been issued with limits below 2.0 ppm does not establish that such lower limits have actually been “achieved” as that term is used in the BACT definition where there is no evidence from actual operations demonstrating that the facilities have in fact been operating in compliance with these permit limits. As the District’s BACT guidelines explain, an “achieved in practice” emissions limit is “the most stringent emission limit achieved in the field for the type and capacity of equipment comprising the source under review and operating under similar conditions, e.g. process throughput and material usage, hours of operation, site-specific limitations and opportunities, etc. For example, the control device performance or emission limit has already been verified by source tests or other appropriate documentation approved by this District or another California

air district.” 30 Where a limit has simply been included in a permit, but the facility had not been built and emissions have not been verified as being in compliance with the limits, the limits are not “achieved in practice” for purposes of the District BACT requirement. The lowest permit limit that has actually been achieved in practice is 2.0 ppm averaged over one hour.

The District also considered whether it would be technically feasible and cost-effective to require the proposed facility to meet an emission limit below the 2.0 ppm level that has been achieved for similar combined-cycle facilities. The District found that although it may be technically feasible to do so, it would not be cost-effective to do so given the magnitude of the costs involved. Additionally, a larger catalyst capable of meeting a CO permit limit below 2 ppm may have other implementation problems such as a high back pressure, which could adversely impact turbine operating performance and efficiency.

30 BAAQMD BACT/TBACT Workbook, “Guidelines For Best Available Control Technology”, Section 3 (“Policy and Implementation Procedure”), subsection 1 (“Interpretation of BACT”),

available at http://hank.baaqmd.gov/pmt/bactworkbook/default.htm

.41

Preliminary Determination of Compliance, October 2010

Oakley Generating Station The District evaluated the costs and emissions reduction benefits of installing a larger oxidation catalyst capable of consistently maintaining emissions below 1.0 ppm. Based on these analyses, the cost of achieving a 1.0 ppm permit limit would be an additional $77,882 per year (above what it would cost to achieve a 2.0 ppm limit), and the additional reduction in CO emissions would be approximately 20.11 tons per year, making an incremental cost-effectiveness value of over $3,874 per ton of additional CO reduction. 31 Moreover, the total cost of achieving a 1.0 ppm CO limit (as opposed to the incremental costs of going from 2.0 ppm to 1.0 ppm) would be over $524,959 per year, and the total emission reductions from 9.0 ppm from the turbine to a 1.0 ppm limit would be 121.01 tons per year, resulting in a total (or “average”) cost effectiveness value of $4,338. Based on these costs (on a per-ton basis) and the relatively little additional CO emissions benefit to be achieved (on a per-dollar basis), requiring a 1.0 ppm CO permit limit cannot reasonably be justified as a BACT limit. Requiring controls to meet a 1.0 ppm limit would be more expensive, on a per-ton basis, than what other similar facilities are required t o achieve. The District has not adopted its own cost-effectiveness guidelines for CO, 32 but a review of guidelines adopted by other districts in California and of BACT determinations made by agencies around the country found that additional CO controls are not normally required where the cost per ton exceeds a few hundred to a few thousand dollars per ton. 33 Additional CO reductions here would not be justified as BACT given these costs.

The District has therefore determined that BACT for CO for this facility is the use of good combustion practice with abatement by an oxidation catalyst, and a permit limit of 2.0 ppmvd @

15% O 2 , averaged over 1-hour. The District is also proposing corresponding hourly mass

31 See OGS Cost effectiveness spreadsheet , prepared by K. Truesdell BAAQMD, and Responses to BAAQMD 092310 E-mail Attachment 2 , prepared by Gregory Darvin Atmospheric Dynamics.

32 Bay Area Air Quality Management District Best Available Control Technology (BACT) Guideline, § 1, Policy and Implementation Procedure, available at: http://hank.baaqmd.gov/pmt/bactworkbook/default.htm

. 33 See South Coast Air Quality Management District, Best Available Control Technology Guidelines, August 17, 2000, revised July 14, 2006, at 29; available at: www.aqmd.gov/bact/BACTGuidelines2006-7-14.pdf ; Memorandum, David Warner, Director of Permit Services, to Permit Services Staff, Subject: “Revised BACT Cost Effectiveness Thresholds”, May 14, 2008; available at: www.valleyair.org/busind/pto/bact/May%202008%20updates%20to%20BACT%20cost%20effe ctiveness%20thresholds.pdf ; U.S. EPA RACT/BACT/LAER Clearinghouse Identification No.

GA -0127, for permit issued to Southern Company/Georgia Power, Plant McDonough Combined Cycle, Permit No. 4911-067-0003 -V-02-2, issued January 7, 2008; U.S. EPA RACT/BACT/LAER Clearinghouse Identification No. NV-0035, for permit issued to Sierra Pacific Power Company Tracey Substation Expansion Project, Permit No. AP4911-1504, issued August 16, 2005; U.S. EPA RACT/BACT/LAER Clearinghouse Identification No. OR-0041, Wanapa Energy Center, Permit No. R10PSD- OR -05 -01, August 8, 2005; BAAQMD Application No. 15487, Russell City Energy Center, Responses to Public Comments (Feb. 3, 2010), pp. 69-74; EPA Region 4, “National Combustion Turbine List,” available at: www.epa.gov/region4/air/permits/national_ct_list.xls

.42

Preliminary Determination of Compliance, October 2010

Oakley Generating Station emissions limits of 9.45 pounds per turbine. Compliance with the CO permit limits will be demonstrated on a continuous basis using a continuous emissions monitor.

5.2.3 Best Available Control Technology for Precursor Organic Compounds (POC)

Emissions of POC from combustion sources are products of incomplete combustion, as is the

case with CO emissions.

Control Technology Review:

Emissions control techniques for CO are also applicable to POC emissions from combustion sources and are discussed above. The appropriate BACT control device or technique for CO i s therefore also the BACT control device or technique for POC.

Proposed BACT Control Technology for POC for Combined-Cycle Gas Turbines:

The District has reviewed the available control technologies in the BACT analysis for CO (equally applicable to POC) and determined that good combustion practice and abatement using an oxidation catalyst are the BACT technologies for controlling POC from the proposed combined-cycle gas turbines at Oakley Generating Station.

Proposed BACT Emissions Limit for POC for Combined-Cycle Gas Turbines:

To establish what level of emissions performance has been achieved in practice for this type of facility, the District reviewed the POC emissions limits of other large combined-cycle power plants using oxidation catalyst systems. The District reviewed BACT determinations for POC at the EPA RACT/BACT/LAER Clearinghouse, ARB BACT Clearinghouse and recent projects listed by the CEC as approved or under. The combined-cycle facilities with most stringent permit limits, as listed in these databases, are shown in the table below.

TABLE 11: POC EMISSION LIMITS FOR LARGE GAS TURBINES IN COMBINEDCY CLE POWER PLANTS

Facility Name RBLC ID or

CEC Docket # VOC ppmvd @ 15% O2 (averaging period)

Wallula Power Plant WA

- 0 291 5.0 (1

- hr) Kleen Energy Systems, Inc. CT

- 0151 5.0 (1

- hr) La Paz Generating Facility, GE option AZ

- 0049 4.5 (3

- hr) Tracy Substatioin Expansion Project NV

- 0035 4.0 (3

- hr) Duke Energy Arlington Valley AZ

- 0043 4.0 (3

- hr)

Copper Mountain Power NV

- 0037 4.0 (3

- hr) without duct firing; 1.9 (3

- hr) with duct firing; Wellton Mohawk Generating Station AZ

- 0047 3.0 (3

- hr) Wellton Mohawk Generating Station AZ

- 0047 3.0 (3

- hr)

Ivanpah Energy Center, L.P. NV

- 0038 2.3 (1

- hr) without duct firing; 5.6 lb/hr with du ct firing

La Paloma 1998

- AFC

- 02 2.80 lb/hr and 0.7 (3

- hr) (as propane) Wansley Combined Cycle Energy

Facility GA

- 0102 2.043

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Facility Name RBLC ID or

CEC Docket # VOC ppmvd @ 15% O2 (averaging period)

Augusta Energy Center GA

- 0093 2.0 McIntosh Combined Cycle Facility GA

- 0105 2.0 Otay Mesa

- Calpine 1999

- AFC

- 05 2.0

Pastoria

- C alpine 1999

- AFC

- 07 2.0 (3

- hr)

Elk Hills

- Sempra & Oxy 1999

- AFC

- 01 2.0 (3

- hr)

Palomar Escondido

- SDG&E 2001

- AFC

- 24 2.0 (3

- hr) Magnolia

- So. Ca. Power Producers 2001

- AFC

- 06 2.0 (1

- hr) Avenal Energy

- Avenal Power Center, LLC 2008

- AFC

- 1 1.4 without du ct firing; 2.0 with duct firing (3

- hr)

Victorville Hybrid Gas

- Solar

- City of

Victorville 2007

- AFC

- 1 1.4 without duct firing; 2.0 with duct firing

Gila Bend Power Generating Station AZ

- 0038 1.4 Sacramento Municipal Utility District CA

- 0997 1.4

Cosumnes

- SMUD 2001

- AFC

- 19 1.4 (3

- hr) Lodi Energy Center

- NCPA 2008

- AFC

- 10 1.4 (3

- hr)

Colusa II Generation Station

- PG&E 2006

- AFC

- 9 1.38 without; 2.0 with duct firing (1

- hr) FPL Turkey Point Power Plant FL

- 0263 1.3 without duct firing; 1.9 with duct firing Cogen Technologies Linden Venture,

L.P. NJ

- 0059 1.2

Empire Power Plant NY

- 0100 1.0 without duct firing; 7.0 with duct firing

Sutter

- Calpine 1997

- AFC

- 02 1.0 (3

- hr) IDC Bellingham CA

- 1050 1.0 (1

- hr) Blythe I

- NextEra Energy (FPL) 1999

- AFC

- 08 2.9 lb /hr (based on 1.0 ppm) Russell City

- Calpine & GE 2001

- AFC

- 07 2.86 lb/hr (based on 1.0 ppm) High Desert

- Constellation 1997

- AFC

- 01 2.51 lb/hr (based on 1.0 ppm)

CPV Warren a VA

- 0291 0.7 without duct firing; 1.0 with duct firing; 1.4 with duct firing a nd power aug.

Warren County Facility, Scenario 1 a VA

- 0308 0.7 without duct firing; 1.0 with duct firing; 1.4 with duct firing and power aug. Warren County Facility, Scenario 2 a VA

- 0308 0.7 without duct firing; 1.0 with duct firing Warren County Facili ty, Scenario 3 a VA

- 0308 0.7 without duct firing; 1.0 with duct firing

Notes: Only facilities with known concentration limits were included for comparison.

a Warren County Facility and CPV Warren are the same facility (Permit Number 81391) and have not been built; a new application amended April 27, 2010, by Virginia Electric Power and Power Company (Dominion) will replace the listed determinations.

As this review of POC permit emissions limits for similar facilities shows, 1.0 ppmvd @ 15% O 2 is the most stringent emissions limit achieved by an emissions control device or technique on utility-sized gas turbines. As with CO, the CPV Warren plant has had a permit issued with certain limits lower than 1.0 ppm, but this plant has not been built (and will not be built, according to the permitting agency) 34 and so there is no operational data indicating this limit is achievable. Such a permit limit is not achieved- in -practice for purposes of the District’s BACT requirement. The La Paloma facility has a 0.7 ppm limit, but it is measured at propane and it is based on a three-hour averaging period, both of which indicate that it is not a more stringent limit. The District’s proposed limit here is 1.0 ppm measured as methane, which is approximately three times lighter than propane. As a result, the mass of POC emissions corresponding to a 0.7 ppm limit measured as propane will actually be over twice the mass of

34 See e-mail from J. Pandey VADEQ to K. Truesdell BAAQMD dated July 7, 2010.44

Preliminary Determination of Compliance, October 2010

Oakley Generating Station POC emissions corresponding to a 1.0 ppm limit measured as methane. This is reflected in the fact that the facility emits up to 2.8 pounds per hour of POC, whereas the proposed Oakley facility will only emit only 2.71 pounds per hour using larger turbines. (La Paloma uses ASEA Brown Boveri GT024 turbines with a capacity of 171.1 MW each, which are smaller than the Oakley facility’s 213 MW GE Frame 7FA turbines.) In addition, the longer averaging time will allow for significant excursions above the 0.7 ppm permit limit compared with the District’s proposed more stringent 1-hour averaging time. For all of these reasons, La Paloma does not establish that a limit has been achieved in practice that is more stringent than 1.0 ppm measured as methane and averaged over one hour.

To determine whether a lower limit could be justified as BACT 1 (technologically feasible and cost-effective), the District evaluated the costs and emissions reduction benefits of installing a larger oxidation catalyst that could be capable of consistently maintaining emissions below 0.7 ppm. Based on these analyses, the cost of achieving a 0.7 ppm permit limit would be an additional $77,882 per year (above what it would cost to achieve a 1.0 ppm limit), and the additional reduction in POC emissions would be approximately 3.29 tons per year, making an incremental cost-effectiveness value of $23,706 per ton of additional POC reduction. The total cost of achieving a 0.7 ppm POC limit (as opposed to the incremental costs of going from 1.0 ppm to 0.7 ppm) would be over $524,959 per year, and the total emission reductions from 1.4 ppm from the turbine to a 0.7 ppm limit would be 6.16 tons per year, resulting in a total (or “average”) cost effectiveness value of $85,238. The District has adopted guidelines that limit the maximum cost per ton of POC controlled that would be considered cost-effective to $17,500. 35
Based on the high costs (on a per-ton basis) and the relatively little additional POC emissions benefit to be achieved (on a per-dollar basis), requiring a 0.7 ppm POC permit limit cannot reasonably be justified as a BACT limit. Requiring controls to meet a 0.7 ppm limit would be significantly more expensive, on a per-ton basis, than what the District would require any other similar facilities are required to achieve under the District’s cost-effectiveness guidelines for

POC.

The District has therefore determined that BACT for POC for this facility is the use of good combustion practice with abatement by an oxidation catalyst for each gas turbine with permit limits of 2.71 lb per hour, which corresponds to 1.0 ppmvd @ 15% O 2 . Compliance with the POC permit limits will be demonstrated by annual source tests.

35 See Bay Area Air Quality Management District Best Available Control Technology (BACT) Guideline, § 1, Policy and Implementation Procedure, available at: http://hank.baaqmd.gov/pmt/bactworkbook/default.htm

.45

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 5.2.4 Best Available Control Technology for Particulate Matter (PM) 36

Particulate matter emissions from gas turbines result from several processes. Particulate matter may be entrained in the combustion air that passes through the combustor inlet filter, which will pass through the combustion chamber and out into the exhaust stream. Trace amounts of particulate matter may also be entrained in the natural gas and will also end up in the exhaust stream. Sulfur in the natural gas can form PM during combustion, and can also combine with other compounds in the atmosphere after it is emitted to form secondary PM such as sulfates. Unburned hydrocarbons from the natural gas that are not fully combusted may condense to form

PM.

Control Technology Review:

The District evaluated control technologies for PM in three areas: (1) pre-combustion controls (2) combustion controls, and (3) post-combustion controls.

Pre-Combustion Controls

• Inlet Air Filter: An inlet air filter is commonly used to protect the turbine from contaminants in the air, which can damage the turbine. There are two main types of filters, static filters and self-cleaning filters. Self-cleaning filters are cleaned periodically by a pulse of backflow air that dislodges the layer of dust collected on the outside surface of the filter. Self-cleaning filters require less maintenance than static filters and can be used in harsher environments. Both filter types can utilize high-efficiency filters capable of filtering particles less than 10 μm in diameter.

Combustion Controls

• Good Combustion Practice: Good combustion will ensure proper air/fuel mixing to achieve complete combustion, thus minimizing emissions of unburned hydrocarbons that

can lead to formation of PM at the stack.

36 This facility is subject to BACT requirements for PM 10 only. PM 2.5 , a subset of PM 10 , is regulated under federal requirements in 40 C.F.R. Section 52.21 (PSD) and 40 C.F.R. Part 51, Appendix S (Non-Attainment NSR). The facility is not subject to PSD or PM 2.5 Non-Attainment NSR permit requirements under Section 52.21 or Appendix S because the facility is not a “major facility” for the purposes of these regulations. The District is therefore not conducting a PSD permitting analysis or an Appendix S permitting analysis for PM 2.5 . For a detailed discussion of the applicability of these federal requirements for PM 2 .5 , see Section 7 below. The District notes, however, that for combustion turbines essentially all of the PM emissions are less than one micron in diameter, so it is both PM 10 and PM 2.5 . ( See AP -42, Table 1.4-2, footnote c, 7/98 (available at www.epa.gov/ttnchie1/ap42/ch01/final/c01s04.pdf ). Moreover, the same emissions control technologies that will be effective for PM 10 for this facility will also be similarly

effective for PM 2.5 . The District’s BACT analysis and emissions limit for PM 10 will also therefore effectively be a BACT limit on PM 2.5 emissions as well, even though the facility is not subject to the federal PM 2.5 BACT requirements as discussed in Section 7.46

Preliminary Determination of Compliance, October 2010

Oakley Generating Station • Clean-burning fuels: The use of clean-burning fuels, such as natural gas that has only trace amounts of sulfur that can form particulates, will result in minimal formation of PM during combustion. The use of low-sulfur natural gas is commercially available and

de monstrated for gas turbines.

• Dry Low- NO

x Combustor: The use of a Dry Low- NO

x Combustor provides efficient combustion to ensure complete combustion thereby minimizing the emissions of

unburned fuel that can form condensable PM. Dry Low- NO

x Combustors are in wide use on utility scale gas turbines.

Post-Combustion Controls

• Electrostatic precipitators: Electrostatic precipitators are used on solid fuel boilers andincinerators to remove PM from the exhaust. Electrostatic precipitators use a highvoltage direct-current corona to electrically charge particles in the gas stream. The suspended particles are attracted to collecting electrodes and deposited on collection plates. Particles are collected and disposed of by mechanically rapping the electrodes and plates and dislodging the particles into collection hoppers.

• Baghouses: Baghouses are used to collect PM by drawing the exhaust gases through a fabric filter. Particulates collect on the outside of filter bags that are periodically shaken to release the particulates into hoppers.

Inlet air filters, good combustion practice, clean-burning fuels, and Dry Low- NO

x Combustors are common control devices/techniques that are technically feasible for combined-cycle gas turbines and are often used to control emissions from sources of this type. These technologies are “achieved in practice” for this type of facility, and the District is proposing to require them here as the BACT control technologies.

With respect to the add-on controls – electrostatic precipitators and baghouses – these control

de vices are not achieved- in -practice for natural gas-fired gas turbines. These devices are normally used on solid-fuel fired sources or others with high PM emissions, and are not used in natural gas-fired applications, which have inherently low PM emissions. The District is not aware of any gas turbine that has ever been required to use add-on controls such as these. The District also reviewed the EPA BACT/LAER Clearinghouse and confirmed that EPA has no record of any post-combustion particulate controls that have been required for natural gas-fired gas turbines. The District has therefore determined that these control devices are not achieved in practice for purposes of the BACT analysis.

Furthermore, these devices would not be technologically feasible to implement here. If add-on control equipment were installed, it would create significant backpressure that would significantly reduce the efficiency of the plant and would cause more emissions per unit power produced. Moreover, these devices are designed to be applied to emissions streams with far higher particulate emissions, and they would have very little effect on the low-PM emissions47

Preliminary Determination of Compliance, October 2010

Oakley Generating Station streams from this facility in further reducing PM emissions. 37 It takes an emissions stream with a much higher grain loading for these types of abatement devices to operate efficiently. This low level of abatement efficiency (if any) also means that these types of control devices would not be cost-effective, even if they could feasibly be applied to this type of source. For all of these reasons, post-combustion particulate control equipment is not technologically feasible/cost effective for the proposed turbines.

Proposed BACT Control Technology for PM for Combined-Cycle Gas Turbines:

The District has determined that use of a high efficiency inlet air filter, low-sulfur natural gas and Dry Low- NO

x combustors with good combustion practice are the BACT control

tech nologies for the proposed Oakley Generating Station. For low-sulfur fuel, the highest quality commercially available natural gas is natural gas that meets the PG&E Gas Rule 21, Section C standard of less than 1.0 grains of sulfur per 100 scf. This PG&E standard is the maximum sulfur content at any point in time. 38 The District is therefore proposing a BACT limit for fuel sulfur content of 1.0 grains of sulfur per 100 scf. Good combustion practice for the proposed gas turbines at Oakley Generating Station 39 would include the use of GE’s DNL-2.6 combustion system, which controls turbine emissions of CO to 9 ppm (prior to abatement by the oxidation catalyst), Continuous Dynamics Monitoring (CDM) enhancements, including onsite visual tools for monitoring combustion dynamics and performing diagnostics, and other advanced controls software. The high level of control of CO indicates unburned hydrocarbons are also well controlled, thereby minimizing PM emissions. Compliance with the stringent CO emission limits will ensure that good combustion practice is being maintained.

The District is not proposing to impose a numerical emissions limit in addition to the BACT requirement to use low-sulfur natural gas and good combustion practices. The District’s BACT regulations require the District to implement BACT either as a control device or technique (Regulation 2-2-206.1 and 2-2-206.3) or as an emission limitation (Regulation 2-2-206.2 and 2-

2 -206.4), and do not require both types of BACT limits. The District is therefore proposing the control techniques described above to fulfill the BACT requirement for PM in accordance with Regulations 2-2-206.1 and 2-2-206.3. The District considered whether to require a numerical

37 For example, if a baghouse were installed on the turbines, the turbine exhaust at the inlet to the baghouse would contain less PM than is normally seen in baghouse output , after abatement. PM emissions from a baghouse are normally in the range 0.0013 to 0.01 grains per standard cubic foot ( see BAAQMD BACT/TBACT Workbook , Section 11: Miscellaneous Sources), whereas PM emissions from the proposed Oakley Generating Station turbines would be 0.00095 gr/dscf (@

15% O 2 ).

38 PG&E’s Gas Rule 21, Section C requires the quality of gas received into the pipeline system to have a maximum sulfur content of 1.0 grain per 100 scf. The actual average content is expected to be less than 0.25 grains per 100 scf. The District has based its calculations of annual emissions on this 0.25 grain per 100 scf average sulfur content. Note that a portion of the sulfur contained in natural gas is intentionally added as an odorant to allow for the detection of leaks which would be a safety concern. PG&E Gas Rule 21, Section C can be found at: http://www.pge.com/pipeline/operations/sulfur/sulfur_info.shtml

. 39 See e-mail from J. McLucas, Radback Energy, to K. Truesdell dated 8/31/2010.48

Preliminary Determination of Compliance, October 2010

Oakley Generating Station emissions limit as well, but has concluded that doing so would not be warranted here, given that there are no add-on control devices that the facility can use to control PM emissions. Assuming the facility is using good combustion practices, PM emissions will be determined by the amount of sulfur in the fuel and the way that the combustion equipment functions, which are factors that are not within the control of the operator. PM therefore presents a different situation than other pollutants such as NOx or CO where the project owner can design its add-on control systems to

a chieve the required level of emissions and ensure that it will comply with its emission limits by operating the add-on control systems properly.

This proposed BACT determination is consistent with guidance from the California Air Resources Board in setting BACT for natural gas-fired gas turbines. 40 This proposed BACT determination is also consistent with District BACT Guideline 89.1.6, which specifies BACT for

PM 10 for combined-cycle gas turbines with rated output of > 40 MW as the exclusive use of

clean -burning natural gas with a maximum sulfur content of < 1.0 grains per 100 scf. 41 These guidance documents do not suggest that a numerical emissions limit should be required as a BACT permit condition.

5.2.5 Best Available Control Technology for Sulfur Dioxide (SO 2 )

Emissions of SO 2 are formed from the oxidation of trace amounts of sulfur in the fuel.

Control Technology Review:

There are two primary mechanisms used to reduce SO 2 emissions from combustion sources: (i) reduce the amount of sulfur in the fuel, and (ii) remove the sulfur from the combustion exhaust

gases.

Limiting the amount of sulfur in the fuel is a common practice for natural gas-fired power plants. Such plants in California are typically required to combust only natural gas with a sulfur content of less than 1 grain per 100 standard cubic feet (scf). In the Bay Area, PG&E supplies gas that complies with its Gas Rule 21, Section C, which requires a sulfur content of less than 1.0 grains of sulfur per 100 scf. This PG&E standard is the maximum sulfur content at any point in time. The requirement for low-sulfur natural gas is a control technique has been achieved in practice at other facilities, and it is technologically feasible and cost-effective. The District is therefore proposing to require the use of natural gas with a sulfur content of less than 1 grain/100 scf as a BACT control technique for SO 2

.

Add-on controls that remove sulfur from the combustion exhaust, such as flue gas desulfurization, are not feasible for natural gas-fired power plants and have not been used at such

40 Guidance for Power Plant Siting and Best Available Control Technology, California Air Resources Board, Stationary Source Division, September 1999, pg. 34.

41 See Bay Area Air Quality Management District Best Available Control Technology (BACT) Guideline, § 1, Policy and Implementation Procedure, available at: http://hank.baaqmd.gov/pmt/bactworkbook/default.htm49

Preliminary Determination of Compliance, October 2010

Oakley Generating Station facilities. These types of control devices are typically installed on coal fired power plants that burn fuels with much higher sulfur contents. There are two main types of SO 2 post-combustion control technologies: wet scrubbing and dry scrubbing. Wet scrubbers use an alkaline solution to

remove the SO 2 from the exhaust gases and may remove up to 90% of the SO 2 from the exhaust stream. Dry scrubbers use an SO 2 sorbent injected as a powder or slurry to remove the SO 2 and

the SO 2 and sorbent are removed by a particulate control device. The abatement efficiencies vary with different types of dry scrubbing technologies, but are generally lower than efficiencies for wet scrubbing technologies. These technologies are not feasible for combustion sources burning low sulfur content natural gas. The SO

x concentrations in the natural gas combustion exhaust gases are too low (less than 1 ppm) for the scrubbing technologies to work effectively or be technologically feasible and cost effective. These control technologies require much higher sulfur concentrations in the combustion exhaust gases to become feasible as a control technology. For this reason, they have not been used at natural gas-fired power plants such as the proposed Oakley Generating Station. As these control technologies have not been achieved in practice at other similar facilities and are not technologically feasible here, the District is not proposing to require them as BACT for this facility.

Proposed BACT Control Technology for SO 2 for Gas Turbines:

Fuel sulfur limits are the only feasible SO 2 control technology for natural gas combustion sources, and the District is proposing to require this technology as BACT. The District i s proposing BACT permit limits requiring the use of natural gas containing a maximum of 1 grain of sulfur per 100 scf of natural gas. Compliance will be demonstrated with monthly sulfur content data. As with the PM BACT requirement, the District is proposing to implement BACT as a control technology only and not as a condition establishing a numerical limit on SO 2 emitted from the stack. The same reasons why the District has concluded that a numerical emissions limit would not be warranted for PM apply to as SO 2 well.

5.2.6 Best Available Control Technology For Startups, Shutdowns, and Combustor Tuning

Startup and shutdown periods are a normal part of the operation of natural gas-fired power plants. They involve emissions rates that are greater than emissions during steady-state operation and that are highly variable. Emissions are greater during startup and shutdown for several reasons. One reason is that during startup and shutdown, the turbines are not operating at full load where they are most efficient. Another reason is that the exhaust temperatures are lower than during steady-state operations. Post-combustion emissions control systems such as the SCR catalyst and oxidation catalyst do not function optimally outside a certain temperature range, and so there may be partial or no abatement for NO

x , carbon monoxide and precursor organic compounds for a portion of the startup period. Thus, emissions can be minimized by reducing the duration of the startup sequence and by controlling the startup sequence to reduce

emissions.

In addition, the gas turbines will need to perform combustor tuning. This is a regular plant equipment maintenance procedure in which testing, adjustment, tuning, and calibration operations50

Preliminary Determination of Compliance, October 2010

Oakley Generating Stationare performed, as recommended by the equipment manufacturer, to ensure safe and reliable steadystate operation, and to minimize NO

x and CO emissions. Emissions will be greater during tuning because the turbines need to be operated at low load where they are less efficient, and because the SCR and oxidation catalyst may not be fully operational. The applicant will need to be able to conduct up to two 6-hour tuning operations per year per turbine.

Because emissions are greater during startups, shutdowns, and combustor tuning periods, the

B ACT limits established in the previous sections for steady-state operations are not technically feasible during these periods. The District is therefore establishing separate BACT limits representing the most stringent emissions limits that are achieved- in -practice or technologically feasible/cost-effective for this type of facility. To do so, the District has conducted an additional BACT analysis specifically for startups, shutdowns, and combustor tuning periods.

5.2.6.1 Turbine Startups and Shutdowns

Control Technology Review:

Best Work Practice: Emissions from startups and shutdowns can be minimized using best work practice. By following the plant equipment manufacturers’ recommendations, power plant operators can minimize emissions during these operating modes and can limit the duration of each startup and shutdown to the minimum duration achievable. Plant operators also use their own operational experience with their particular turbines and ancillary equipment to optimize startup and shutdown.

Fast-Start Technology: Turbine manufacturers have recently developed design improvements that allow combined-cycle facilities such as this one to start up more quickly and efficiently. These improvements allow combined-cycle facilities to bypass the steam turbine during the early stages of startup, eliminating some of the delay. With a conventional combined-cycle design, the combustion turbine must be held at low load while the steam turbine is being heated up, which needs to be done slowly to minimize thermal stresses and maintain the necessary clearances between the rotating and stationary components of the steam turbine. These new designs allow steam generated by the HRSGs to bypass the steam turbine during startups, allowing the turbines to come up to full load quickly. As the proper steam conditions are achieved, a portion of the steam will be sent to the steam turbine, which will ramp up slowly until the point is reached where steam is no longer bypassing the steam turbine. GE is marketing this new technology under the name “Rapid Response”, and Siemens is marketing a similar technology under the name “Flex-Plant”. The applicant is proposing to use the GE “Rapid Response” design for the Oakley Generating Station.

Proposed BACT Control Technology for Startups and Shutdowns

The District is proposing the use of best work practices with fast-start technology as BACT for startups and shutdowns of combined-cycle plants. Both control technologies are technically feasible and are the most effective technology available for decreasing startup and shutdown emissions. The applicant has proposed the use of best work practices and GE’s Rapid Response Technology, which satisfies the BACT requirement. The facility will be equipped with a51

Preliminary Determination of Compliance, October 2010

Oakley Generating Station specially-designed HRSG that can heat up quickly without generating excessive thermal stresses. The facility will also be equipped with an auxiliary boiler that would provide auxiliary steam when the plant is offline and during startups. This auxiliary steam will be used for condensate sparging and to maintain the seals and prevent loss of vacuum in the steam turbine and condenser, so that the steam turbine is maintained in ready state and can start up as quickly as possible when called upon. ( See Section 3.3 above for further detail regarding the use of the auxiliary boiler to improve startup performance.)

Proposed BACT Emissions Limits for Startups and Shutdowns

The District is also proposing numerical emissions limits for startups and shutdowns that represent the best emissions performance that can consistently be achieved by the BACT technology discussed above. The proposed emissions limits for Oakley Generating Station are

shown in Table 12 below.

TABLE 12: PROPOSED STARTUP AND SHUTDOWN EMISSIO N L IMITS FOR

OAKLEY GENERATING STATION

Pollutant Cold

Startup (lb/event) Hot/Warm

Startup (lb/event) Shutdown

Emission Limits (lb/event)

NO

x (as NO 2 ) 96.3 22.3 39.3

CO 360.2 85.2 140.2 POC (as CH 4 ) 67.1 31.1 17.1

The District is also proposing to add time limits for startups and shutdowns, in addition to numerical emissions limits. BACT limits are normally expressed as numerical emissions limits, as it is the actual emissions of air pollutants from a facility that have an impact on air quality. The numerical emissions limits are therefore the primary permit limits – and the permit conditions required by BACT – but the District is also proposing limits on startup and shutdown

dura tion for this facility as an additional backstop to help ensure that startup and shutdown emissions are kept to a minimum. The District is proposing time limits of 30 minutes for hot/warm startups, 90 minutes for cold startups, and 30 minutes for shutdowns.

These proposed startup and shutdown limits are based on an analysis of what is involved in startup and shutdown operations using best work practices and GE’s Rapid Response system. 42
The facility will typically start from a “ready- to -start” condition, with the electrical systems energized, steam process vessels filled to prestart level, manual valves in run position, and controls in auto. The plant will also typically have “Purge Credit” established, meaning the gas turbine and HRSG were purged with air to clear any remaining combustible gases and the gas turbine fuel train was prepared to assure that no fuel entered the gas turbine and HRSG while the unit was offline. The steps of purging the gases from the gas turbine and HRSG are also referred to as a “purge cycle” and, at conventional combined-cycle plants, are performed in the startup sequence and can take approximately 15 minutes. A purge cycle is required prior to firing the

42 See Gordon R. Smith and Andrew Baxter, GE Energy Rapid Response Combined Cycle

, PowerPoint presentation (Sept. 24, 2007).52

Preliminary Determination of Compliance, October 2010

Oakley Generating Station gas turbine to prevent explosion of any residual gases. GE has worked with the National Fire Protection Agency to establish safe conditions without the delay in startup time that the purge cycle normally takes by moving the purge cycle to the end of the shutdown sequence. GE calls this feature Purge Credit.

The gas turbine starting process is initiated to roll the gas turbine, and the gas turbine is fired

withi n a couple of minutes after roll. After fire, the gas turbine accelerates to full speed no load (FSNL) with the driving power provided by the load commutated inverter (LCI), a variable speed drive motoring the generator. At about 95% speed, the LCI disengages and the gas turbine settles at FSNL. Accelerating the gas turbines to 95% speed occurs as fuel is burned in certain

burners within the combustors to ensure a stable flame and takes about 5 to 6 minutes to complete. 43 The combustors are not operating at their optimum efficiency at this point so emissions are higher than during steady-state operation.

On hot and warm starts, 44 the gas turbine synchronizes and loads directly to the desired load. This immediate loading is the benefit of the fast-start design compared to conventional combined-cycle designs, in which the combustion turbine cannot be brought up to minimum emissions compliance load until the steam turbine is brought up to operating temperature. Startup emissions in the Rapid Response plant are therefore lower than in a conventional combined-cycle plant, although they are still greater than steady-state emissions because the combustors must be loaded in a particular sequence to maintain a controlled and stable flame as load is increased. The combustors go through six modes of firing different burner combinations to reach steady-state emissions compliance, which takes another 5 or 6 minutes to complete. For cold starts, the gas turbine needs somewhat longer to come up to minimum emissions compliance load because the HRSG needs to be brought up to temperature gradually to reduce thermal stresses. Cold startups therefore require an additional hold at low load, which causes cold starts to be longer than hot and warm starts (although cold starts with the Rapid Response system are still shorter than cold starts with a conventional combined-cycle system).

Based on discussions with GE, the District estimates that with this Rapid-Response system, a typical hot/warm startup will take approximately 15 minutes until emissions reach compliance

43 See Dry Low NOx Combustion Systems for GE Heavy-Duty Gas Turbines GER3568g L.B. Davis and S.H Black, GE Power Systems, October 2000, at pp. 12-14. (available at: http://www.gepower.com/prod_serv/products/tech_docs/en/downloads/ger3568g.pdf ) See also GE Rapid Response 207FA Plant Operation G.R. Smith, GE June 4, 2010. See also Email from J. McLucas Radback Energy to K. Truesdell BAAQMD subject: OGS-Additional Information on Startups, dated 10/21/2010.

44 Note that there will be no difference in performance between hot and warm startups. The District has often differentiated between hot startups and warm startups for other combined-cycle facilities with conventional designs (with hot startups being defined as startups when the turbine has been down for less than 8 hours and warm startups being defined as startups when the turbine has been down for 8-48 hours). To avoid confusion, the District is maintaining the hot/warm terminology here, even though there is no difference in startup performance between hot and warm startups. A hot/warm startups for this facility are defined as any startup that

occurs within 48 hours of a shutdown.53

Preliminary Determination of Compliance, October 2010

Oakley Generating Station with the proposed steady-state emission limits, and a typical cold startup will take approximately

4 6 minutes. 45 The District estimates that hot/warm startups will generate up to 22.3 pounds of NOx, 85.2 pounds of CO, and 31.1 pounds of POC; and that cold startups will generate up to

96 .3 pounds of NOx, 360.2 pounds of CO, and 67.1 pounds of POC. 46 The District has found that the duration of turbine startups can vary significantly from startup to startup depending on a large number of variables, and that not- to -exceed startup limits need to reflect this variability so that the facility can comply with them consistently over the life of the facility under all reasonably foreseeable operating scenarios. 47 The District is therefore proposing limits on startup duration of 30 minutes for hot/warm startups and 90 minutes for cold startups, which is twice the duration of a typical startup as estimated by the equipment manufacturer, to ensure that the facility will be able to achieve these limits consistently. 48

For shutdowns, the process is as follows. Over approximately 10 minutes, the gas turbines unload to the point where gas turbine exhaust temperature is slightly above rated steam temperature. This is the lowest load at which the gas turbine can operate without causing the steam temperature to drop below the rated steam temperature. The purpose of this hold is to avoid unintentionally cooling the steam turbine to a point that could cause the next plant startup to be longer than necessary. The gas turbine hold is expected to be around 20 percent load. While the gas turbines are holding, the steam turbine is unloaded by closing all steam turbine control valves. As the steam turbine control valves close, the steam turbine bypass valves begin to divert steam from the steam turbine to the condenser, essentially maintaining constant steam pressure. After approximately 5 minutes, the steam turbine will be completely unloaded, desynchronized, and the steam turbine will begin to decelerate. After the steam turbine has unloaded and the gas turbine resumes unloading, a second low load hold will occur when the gas

45 See Memorandum of Record of Telephone call dated 10/21/2010, prepared by K. Truesdell BAAQMD. GE provided estimates of what would be required to reach steady-state emissions compliance, but did not include any emissions at the steady-state emissions rate. The District’s startup definitions provide that a startup ends with two consecutive compliant emissions readings, however. The District has therefore added one minute to GE’s estimated startup duration and one minute’s worth of steady-state emissions. Including one minute of steady-state emissions in addition to the manufacturer’s emissions limits is appropriate to ensure compliance based on the CEMs’ reading.

46 See id

. 47 The District has evaluated startup data in prior permit proceedings for power plants such as this one and has documented the high degree of variability in individual startups. See

, e.g. , Statement of Basis, Russell City Energy Center, Application No. 15487 (Dec. 8, 2008), available

at www.baaqmd.gov/~/media/Files/Engineering/Public%20Notices/2009/15487/B3161_nsr_15487 _sb-corrected_121208.ashx , , at Section V.A.4.

48 Since no fast-start facilities have yet been built, there is no startup data available from actual operating facilities on which to base a compliance margin specifically for the GE Rapid Response system. Variability in individual startups of twice the typical startup is not unusual for other combined-cycle facilities using conventional designs, however, and in the District’s professional engineering judgment it is an appropriate basis for establishing a startup duration permit limit for a Rapid Response design.54

Preliminary Determination of Compliance, October 2010

Oakley Generating Station turbine reaches approximately 10 percent load. This hold is designed to further reduce steam temperature and allow the cooler steam to reduce the temperature of the HRSG superheater lower header. Ten minutes are allotted for this hold per HRSG manufacturer direction. This hold is necessary to reduce the potential for HRSG damage during the purge operation shortly following shutdown, as described above, where relatively cool air will be blown through the gas turbine and HRSG as part of establishing Purge Credit. At the end of this hold, the gas turbines will resume ramping to zero load over a period of about 3 to 4 minutes whereupon they will desynchronize and begin fired shutdown. Flame is maintained in the gas turbines during deceleration to reduce the thermal shock on the hot gas path parts (gas turbine and HRSG). At about 20 percent gas turbine speed, fuel is cut off, the gas turbine flames out, and decelerates freely from this point to turning gear. Based on discussions with GE , the District estimates that shutdowns will take up to 30 minutes and involve 39.3 pounds of NOx emissions, 140.2 pounds

of CO emissions, and 17.1 pounds of POC emissions. 49 The District is proposing these limits as

not- to -exceed permit limits on shutdowns. The District does not believe any additional time allowance is required for shutdown.

The District has also compared these proposed startup and shutdown limits with other proposed facilities using fast-start combined cycle designs. The District compared the startup and shutdown limits for the Lodi Energy Center, which was licensed by the CEC in April of 2010, 50
and the Blythe II project, which is currently in the CEC licensing process. 51 Both of these projects incorporate the Siemens Flex-Plant 30 fast-start system. In addition, the District also evaluated the Victorville 2 Hybrid Power Project and the Palmdale Hybrid Power Project, which are designed with an earlier application of the fast-start concept. This application, which GE called “Rapid Start”, provides for the steam turbine to be bypassed during startups to achieve faster starts and is therefore somewhat comparable, although it does not include all of the additional elements of the more recent Rapid Response design. In comparing these facilities, the District looked at the permit limits applicable to startups and shutdowns combined, for several reasons. One reason is that every startup is necessarily coupled with a shutdown, as by definition

a startup has to follow a shutdown. Another reason is that the proposed Oakley project will incorporate “Purge Credit” into its shutdown sequence, which removes a required step from the startup process as described above so that the facility can be started up more quickly. It would not make sense to penalize this project for moving this step from the startup sequence to the shutdown sequence, and so to avoid such an outcome the District evaluated overall facility performance for startups and shutdowns combined. The comparison of the applicable permit conditions for these facilities and the proposed Oakley Generating Station permit conditions is

summarized in Table 13 below.

49 See Memorandum of Record of Telephone call dated 10/21/2010, prepared by K. Truesdell BAAQMD. As with the startup emissions, the manufacturer’s shutdown emissions do notaccount for any time at steady-state. The District therefore add one minute’s worth of steadystate emissions to the manufacturer’s estimates to establish permit limits on turbine shutdowns.

50 See Final Commission Decision, available at: www.energy.ca.gov/2010publications/CEC-800-

2010 -003/CEC-800-2010 -003-CMF.PDF

. 51 The Energy Commission’s web page for this proceeding can be found at www.energy.ca.gov/sitingcases/blythe2/compliance/

.55

Preliminary Determination of Compliance, October 2010

Oakley Generating Station TABLE 13 : STARTUP AND SHUTDOWN PERMIT LIMITS FOR SIMILAR

COMBINED-CYCLE POWER PLANT PROEJCTS USING FAST-START

TECHNOLOGY

Facility Name Victorville 2

Hybrid

Power Project Palmdale

Hybrid

Power Project Lodi

Energy

Cent er Blythe

Energy Project II (proposed) Oakley

Generating

Station (proposed)

Technology GE Rapid

Start Process GE Rapid

Start Process Siemens

Flex

- Plant

30 Siemens

Flex

- Plant

30 GE Rapid

Response

Maximum Heat Input (MMBtu/hr/gas turbine) 1736.4 1736.4 214 2 2019.6 2150

Hot/Warm Startup + Shutdown

Total Duration (min) 110 110 360 120 60

Total Emissions Limit (lb)

NOx 97 97 960 111.6 61

CO 666 666 5400 83.8 225

POC no limit no limit 96 no limit 48 Cold Startup + Shutdown

Total Duration (min) 140 140 360 240 120

Total Emissions Limit (lb)

NOx 153 153 960 150.6 135

CO 747 747 5400 165.7 500

POC no limit no limit 96 no limit 84

As Table 13 shows, the proposed permit conditions for the Oakley Generating Station are very stringent compared with other similar facilities, and meet or exceed all of the other facilities’ permit limits with one exception. The one exception is the CO emissions limits that are currently being proposed for the Blythe II project, which, if adopted in their current form, will limit combined CO emissions to 83.8 pounds of CO for a hot/warm startup and shutdown (compared with the proposed 225 pounds for Oakley) and 165.7 pounds of CO for a cold startup and shutdown (compared with the proposed 500 pounds for Oakley). The District has evaluated these proposed CO limits for Blythe II and has concluded that they do not suggest that the District’s proposed limits for the Oakley Generating Station are inappropriate, for several reasons. First, the Blythe II project is still under review, and the limits that are currently being considered have not yet been finalized and could potentially change when the project is approved. Second, even if the Blythe II project is ultimately permitted with these limits, the facility is not yet built and operational and so there is no actual operating data that demonstrate that these limits will in fact be achievable by the facility. And third, even assuming that the56

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Blythe II facility will be able to be operated in compliance these proposed permit conditions, the limits being proposed for the facility reflect a balance between NOx and CO reductions that has

been made in a manner different from how the District would make it . There is an inherent tradeoff between achieving additional NOx reductions and achieving additional CO reductions because NOx is reduced by lowering the combustion temperature to reduce the formation of thermal NOx whereas CO is reduced by increasing the combustion temperature to avoid incomplete combustion. ( See discussion in Section 5.2.1 above for more details.) The District prioritizes NOx reductions over CO reductions because the Bay Area is not in attainment of the state and federal ambient air quality standards for ozone (NOx is a precursor to ozone formation), whereas it is in attainment of the CO standards. The District therefore prefers lower NOx limits even if that means somewhat higher CO limits. In this case, the Oakley Generating Station will be able to achieve NOx emissions for startups that are significantly below the proposed limits for Blythe II (61 pounds vs. 111.6 pounds for hot/warm startups/shutdowns, and 135 pounds vs. 150.6 pounds for cold startups/shutdowns). The District considers these additional NOx reductions to be more important than the additional CO reductions reflected in the proposed Blythe II conditions. For all of these reasons, the District has concluded that the Blythe II project does not suggest that the proposed conditions for the Oakley Generating Station are inappropriate.

Based on all of this analysis, the District is proposing the startup and shutdown conditions described above as BACT for the Oakley Generating Station. The District finds that these are the most stringent emission limits that can be achieved by this facility based on all of the information available at this time regarding the performance of this newly developed technology.

5.2.6.2 Combustor Tuning

Combustor tuning is required to maintain the gas turbines in optimal operating condition. Tuning is done in response to turbine wear and variations in fuel, temperature, and humidity. The gas turbines will be subject to extremely stringent limits for startups and shutdowns in addition to stringent steady-state limits, so providing an allowance for tuning is necessary to assure compliance during the rest of the year.

The burners in the turbines that would be used at the Oakley Generating Station have 6 modes of operation, depending on where and how much fuel and air are routed to different parts of the burner (combustion fuel staging). Details on the modes of operation can be seen in the GE Publication #GER 3568G “Dry Low NOx Combustion Systems for GE Heavy-Duty Gas Turbines.” Tuning involves testing and adjusting the 6 modes and the transition from one mode to another. These operations are time-intensive and are expected to take up to 6 hours to complete. The reason that up to 6 hours are required to complete the tuning is that during tuning,

the turbine operating rate is brought up 5 MW at a time and tuning is performed at each MW level. The turbines are held at each load level while settings are varied to establish the optimal operating conditions. Tuning would need to be performed up to two times per year per turbine. Each turbine would be able to be tuned separately to keep tuning emissions to a minimum.

Tuning has traditionally been performed during cold startups. Cold startups involve bringing the turbine load up slowly, and so they provide an appropriate opportunity to conduct tuning.57

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Recently, regulatory agencies have started imposing shorter time limits on cold startups, and so it has become increasingly difficult for operators to complete tuning within their cold startup time limits. Recent permits have therefore had to include specific provisions allowing for tuning operations outside of cold startups. Since tuning operations were originally conducted under cold startup limits, these provisions have typically provided for tuning operations to be subject to the same emissions limits applicable during cold startups. These limits are also generally appropriate for tuning because tuning involves low-load operation where emissions controls are not as effective, as is the case with cold startups. (Tuning takes longer than cold startups, however, because the turbines must be kept at each load level for a period of time while tuning takes place, and cannot be ramped up as soon as equipment conditions allow.)

The District is therefore proposing that tuning operations should be subject to emissions limits at least as stringent as the hourly emissions limits that apply during cold startups – 96 lb/hour of

NO x, 260 lb/hour of CO, and 67 lb/hour of POC. The District believes that it may be possible to maintain tuning emissions at even lower levels, although the facility has not yet been built and so there is not yet sufficient operating data on which to base lower permit limits. The District is therefore proposing that further emissions limits for tuning operations would be established after the facility is built based on test data obtained during actual tuning operations. These further emissions limits would be at least as stringent as the cold startup limits, and would be even lower if lower limits prove to be feasible.

The District is therefore proposing a provision that would allow the Oakley Generating Station to conduct up to two tuning events per year per turbine, with a duration not to exceed 6 hours per tuning event. In addition, the facility would be allowed to conduct tuning on only one turbine at a time. Emissions would be subject to the lowest limits that can be achieved by the facility, which the District would establish based on testing after the facility is built and which would in no event be greater than the hourly emissions rates applicable for cold startups.

5.2.7 Best Available Control Technology During Gas Turbine Commissioning

The combined-cycle gas turbines and associated equipment are highly complex and have to be carefully tested, adjusted, tuned and calibrated after the facility is constructed. These activities are generally referred to as “commissioning” of the facility. During the commissioning period, each of the gas turbine generators needs to be fine-tuned at zero load, partial load, and full load to optimize its performance. The dry-low NO

x combustors also need to be tuned to ensure that the turbines run efficiently while meeting both the performance guarantees and emission guarantees. In addition, the selective catalytic reduction (SCR) systems and oxidation catalysts

need to be installed and tuned.

The combined-cycle gas turbines will not be able to meet the stringent BACT limits for normal operations during the commissioning period for a number of reasons. First, the SCR systems and oxidation catalysts cannot be installed immediately when the turbines are initially started up. There may be oils or lubricants in the equipment from the manufacture and installation of the equipment, which would damage the catalysts if they were installed immediately. Instead, the turbines need to be operated without the SCR systems and oxidation catalysts for a period of time to burn off any impurities that may be left in the equipment. In addition, once all of the58

Preliminary Determination of Compliance, October 2010

Oakley Generating Station pollution control equipment is installed, it needs to be tuned in order to achieve optimum emissions performance. Until the equipment is tuned, it will not be able to achieve the very high levels of emissions reductions reflected in the stringent BACT limits for normal operations.

Because the BACT limits established for normal operations are not technically feasible during the commissioning period, these limits are not BACT for this phase of the facility’s operation. Alternate BACT limits must therefore be specified for this mode of operation. To do so, the District has conducted an additional BACT analysis specifically for the required commissioning

activities.

The only control technology available for limiting emissions during commissioning is to use best work practices to minimize emissions as much as possible during commissioning, and to expedite the commissioning process so that compliance with the stringent BACT limits for normal operations can be achieved as quickly as possible. There are no add-on control devices or other technologies that can be installed for commissioning activities.

To implement best work practices as an enforceable BACT requirement, the District is proposing conditions that will require the turbines to minimize emissions to the maximum extent possible during commissioning. The District is also proposing numerical emissions limits based upon the equipment manufacturer’s best estimates of uncontrolled emissions at the operating loads that the turbines will experience during commissioning (see table below). 52 The proposed permit conditions will limit emissions to below the following levels:

TABLE 14: COMMISSIONING PERIOD EMISSION LIMITS

Air Pollutant Proposed Commissioning Period Emission Limits (Uncontrolled or Partially controlled) (lb/calendar day) (lb/hr)

NO 2 2,380.8 148.7

Carbon Monoxide 13,303 700

Note: Please see “OGS Supplemental Air Quality Filing April 7 2010” Table 5.1A-5b for GE’s detailed commissioning schedule.

Commissioning emissions will also be subject to the annual emissions limits applicable to normal operations. All emissions from commissioning activities will be counted towards the facility’s annual limits. Because commissioning is a relatively short-term period, the facility should be able to stay within those limits over the course of the entire year. Counting commissioning emissions towards the annual limits will also provide an additional incentive for the facility operator to minimize emissions as much as possible.

The District is also proposing permit conditions to minimize the duration of commissioning activities. The proposed conditions require the facility to tune the gas turbines to minimize emissions at the earliest feasible opportunity; and to install, adjust and operate the SCR systems and oxidation catalysts at the earliest feasible opportunity. The District is also proposing to cap

52 See e-mail attachment from Greg Darvin, Atmospheric Dynamics, to K. Truesdell, BAAQMD,

dated 7/19/201059

Preliminary Determination of Compliance, October 2010

Oakley Generating Station the total amount of time that the turbines can operate partially abated and/or without the SCR systems and oxidation catalysts at 831 total hours. This limit represents the shortest amount of time in which the facility can reasonably complete the required commissioning activities without jeopardizing safety and equipment warranties. The proposed limit is based on the following estimates from GE of the time it will take for each specific commissioning activity in Table 15.60

Preliminary Determination of Compliance, October 2010

Oakley Generating Station TABLE 15: COMMISSIONING SCHEDULE FOR OAKLEY GENERATING STATION

Test Description Duration (hours) Average

GT Load (%) Total Emissions (tons)

NO X CO VOC PM 10

GT Initial Start

- up
GT first firing

GT FSNL on p rimary fuel & generator filtration

GT intertriping matrix checks

GT generator short circuit, overspeed and open

circuit tests 50 0 1.5 11.4 1.0 0.2

GT Sync & Load

GT first synchro 10 7.5 0.7 3.5 0.2 0.0

HRSG Steam blows

HRSG MS steam blows

HRSG CRH & HRH steam blows

HRSG LP steam blows

Air cooled condenser flushing

Steam to gland seal, condenser vacuum tests 240 7.5 5.7 13.8 4.3 1.1

HRSG Operation on Steam Bypass

HRSG startup, steam bypass checks

HRSG steam safety valve tests

HRSG & BOP control loop tuni ng 323 25 16 9.7 0.6 1.5

GT Loading up to Base on PPM

Part load tests

Full load tests

HRSG operation on bypass for steam purity 50 46 2.5 1.5 0.1 0.2

ST Initial Start

- up ST generator filtration

ST intertriping checks

ST generator short circuit, overspeed and open

circuit tests 23 19 1.1 0.7 0.0 0.1

ST Sync & Load

ST first synchro

ST tests on load with one GT 38 68 0.3 0.1 0.0 0.2

GT Tuning up to Base on PSS Mode with Primary Fuel

Part load tests

Full load tests 97 64 0.7 0.2 0.1 0.4

Total a 831

- 28.6 4 0.8 6.4 3.7

See “OGS Supplemental Air Quality Filing April 7 2010” Table 5.1A-5b for GE’s detailed commissioning schedule. Totals are slightly different than adding the emissions for each activity due to rounding. Emissions will be limited by annual permit limits.61

Preliminary Determination of Compliance, October 2010

Oakley Generating Station The District also looked to other similar facilities to determine whether any other facility hasachieved better commissioning performance. Commissioning limits for conventional combinedcycle plants would not be feasible for this facility due to the complex design of Rapid Response that allows faster startups, and there are currently no operating GE Rapid Response or Siemens Flex Plant 30 plants with which to compare the proposed commissioning period. The proposed Siemens Flex Plant 30 in Lodi, CA is for one gas turbine and one steam turbine and does not have a permit limit for commissioning hours. 53 The Victorville 2 Hybrid Power Project and City of Palmdale Hybrid Power Plant Project will both use GE’s Rapid Start Process, which utilizes a modified HRSG and an auxiliary boiler to reduce startup times, and they are limited to 624 hours of commissioning per turbine. 54 The proposed Siemens Flex Plant 30 for Blythe Energy Project Phase II Amendment, which is proposed as two gas turbines and one steam turbine, is proposed for up to 734 hours of commissioning per gas turbine/HRSG train. 55 The BACT limit for the commissioning period of conventional combined-cycle plants is not technologically feasible for the combined-cycle plant proposed for Oakley Generating Station due to the complex design of Rapid Response that allows faster startups. The proposed limit for the commissioning period for Oakley Generating Station is less than the limits proposed at other fast start/rapid start plants proposed in California. The District is proposing 831 total hours for the BACT limit on commissioning at Oakley Generating Station.

Emissions during commissioning will accrue towards the facility’s annual emission limits. Compliance with these proposed conditions for the commissioning period will be monitored by continuous emissions monitors that the applicant will be required to install before any commissioning work begins, and through a written commissioning plan laying out all commissioning activities in advance, which the applicant will be required to submit to the District for review and approval.

53 See Lodi Energy Center Final Commission Decision (08-AFC-10), California Energy Commission, April 2010. (available at: http://www.energy.ca.gov/sitingcases/lodi/documents/index.html)

54 See Victorville 2 Hybrid Power Project Final Commission Decision, California Energ y Commission, July 2008, AQT-23 at p. 131. (available at: http://www.energy.ca.gov/sitingcases/victorville2/documents/index.html ). See also VOLUME 2: Preliminary Staff Assessment for the Palmdale Hybrid Power Plant Project (Docket # 08- AFC-9), February 2010, AQT-23 at p. 4.1-65 (available at: http://www.energy.ca.gov/sitingcases/palmdale/documents/index.html)

55 See Final Determination of Compliance Blythe Energy Project II, Mojave Desert Air Quality Management District, August 10, 2010, at p. 25.62

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 5.3 Fire Pump Diesel Engine

The proposed Oakley Generating Station will require an emergency fire pump diesel engine to be used in case of emergency to provide water to fight fires. The fire pump diesel engine would be used solely to pressurize a fire suppression system. It would be operated only in case of emergency, as well as for short periods for inspection, maintenance, and testing, as required by the standards of the National Fire Protection Agency (NFPA) to ensure reliability in case of fire.

The following section provides the District’s BACT analysis for the project’s fire pump diesel engine. The diesel fire pump engine will have the potential to emit over 10 pounds per day of NOx and CO since emergency use is not limited, and it is subject to BACT for these pollutants.

Control Technology Review:

The District has identified three primary types of control technologies that could potentially be used to reduce air pollutant emissions from the diesel fire pump engine: the use of clean dieselfuel; combustion technologies to limit pollutant formation during combustion; and postcombustion technologies that remove pollutants that are formed before they can enter the atmosphere.

Clean Fuel Technologies

The use of diesel fuel that meets the CARB ultra-low sulfur diesel fuel standard (< 0.0015% by weight sulfur) can reduce the amount of NO

x formed during combustion. Using ultra-low sulfur

fuel reduces NO

x emissions because the hydro-treating technique used to remove the sulfur from the diesel fuel also removes nitrogen, leaving only trace amounts. Reducing the amount of nitrogen in the fuel reduces the amount of nitrogen available to form NO

x during combustion. Ultra-low sulfur diesel fuel is available and demonstrated for stationary compression ignition engines. It is technically feasible for the fire pump engine. 56

Combustion Technologies

There are also a number of design features that can be used for diesel engines that can reduce the amount of air pollutants generated during combustion of the fuel, including NO

x and Carbon Monoxide. These features include turbocharging, which uses an exhaust gas-driven air compressor to increase the mass of air entering the engine to create more power and thereby increase efficiency; intercooling, or charge air cooling, which uses an air- to -air or air- to -liquid heat exchange device to increase the intake air charge density through cooling, another method to increase efficiency; retarded injection timing, which slightly delays the injection of fuel into the engine to reduce the peak flame temperature, thereby improving NO

x emissions (but typically resulting in higher PM emissions); exhaust gas recirculation, which allows a controlled portion of spent combustion gases to circulate back into the intake system where they mix with pre-

56 Under Title 17, California Code of Regulations, section 93115 “Airborne Toxic Control Measure for Stationary Compression Ignition (CI) Engines,” the emergency fire pump engine will use only California ultra-low sulfur Diesel fuel when operating.63

Preliminary Determination of Compliance, October 2010

Oakley Generating Stationcombustion air, similarly reducing peak combustion temperature; and the use of a precombustion chamber, which involves a prechamber in the engine that improves air/fuel mixing and lowers combustion temperature.

The design of a diesel engine – including the choice of combustion technologies to reduce the

for mation of air pollutants during combustion – is determined by the manufacturer of the engine,

not by the end-user. Emissions from such engines are regulated by EPA under a system of “Tiers”, or progressively more stringent emissions standards that engine manufacturers must meet. Engine manufacturers design their equipment using appropriate control technology to meet these EPA-designated Tiers. Diesel engine users, such as the Oakley Generating Station here, are limited to the engines that are commercially available from manufacturers. The determination of what combustion control technologies are technically feasible must therefore focus on what types of engines are commercially available to be purchased for this project, and what “Tier” standards such equipment can meet. The technologies that are commercially available are those that manufacturers are using to achieve the EPA “Tier 3” requirements for engines of the class needed for emergency fire service at the Oakley Generating Station.

Post-Combustion Controls

Finally, there are several post-combustion technologies that could potentially be used to remove emissions from the fire pump diesel engine’s exhaust before they are emitted to the atmosphere. One such system discussed above in connection with the gas turbines and auxiliary boiler is

s elective catalytic reduction (SCR), which uses a reagent, typically ammonia or urea, to convert NOx to nitrogen and oxygen over a catalyst. Another after-treatment based NO

x control technology is referred to as the lean- NO

x catalyst. Similar in principle to an SCR system, a LeanNO

x Catalyst system relies on injection of a reagent upstream of the catalyst to reduce NO

x emissions. Finally, NO

x adsorbers, also called NO

x traps, are one of the newest emission control strategies under development. They employ catalysts that adsorb NO

x in the exhaust stream when the engine runs lean. After the adsorber has been fully saturated with NO

x , the system is regenerated with released NO

x being catalytically reduced when the engine runs rich.

Post-combustion controls are not feasible for direct-drive fire pump engines of the type needed to serve the emergency fire suppression needs of the Oakley Generating Station, however. Addition of a catalytic device to the exhaust system would be technically infeasible, due to the variable load of the engine and the nature of the control system. Injection of a reagent into the engine exhaust to control pollutants (mainly NO

x ) is dependent on a constant steady state engine load. But the fire pump engine will need to operate effectively under highly variable loads, thus ruling out this type of control technology. Installation of other after-treatment devices will also compromise reliability, performance, and safe operation of the fire pump. 57

In addition, the use of post-combustion control technologies would be incompatible with the fire pump’s role as a safety device for use in emergencies. Direct-drive fire pump engines of the type proposed for the Oakley Generating Station are designed differently than other stationary or offroad diesel-fueled engines. Direct-drive fire pump engines must meet the stringent National Fire Protection Association (NFPA) standards that establish minimum requirements for reserve

57 Clarke, letter dated December 11, 2006 to the South Coast Air Quality Management District.64

Preliminary Determination of Compliance, October 2010

Oakley Generating Station horsepower capacity, engine cranking systems, engine cooling systems, fuel types used, instrumentation and control, and exhaust systems, among others. The direct-drive fire pump engine, and anything connected to the engine that may affect its performance abilities, must be tested and certified by an independent agency ( e.g. Underwriters’ Laboratories) to be conforming to the requirements of NFPA Standards 20 (Installation of Stationary Pumps for Fire Protection) and/or 25 (Inspection, Testing and Maintenance of Water-Based Fire Protection Systems). 58
Adding exhaust system controls to these engines would void the existing certification s. 59

Proposed BACT Control Technology Emergency Fire Pump Diesel Engines

The District has determined the use of ultra-low sulfur diesel and Tier 3 engine technology are

the only feasible control technologies and therefore meet BACT. Tier 3 engines incorporate control technologies that meet the emission standards for fire pump diesel engines required by EPA in 40 CFR Part 60, Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion Engines. 60 EPA does not require future stationary fire pump engines to meet Tier 4 emission standards, which would likely involve the use of after-treatment devices. The proposed Tier 3 engine also meets the emission standards set forth in the California Air Resources Board (CARB) Airborne Toxic Control Measure for Stationary Compression Ignition Engines (sections 93115 through 93115.15, title 17, California Code of Regulations).

58 In addition, even if add-on post-combustion technologies were technologically feasible for an emergency fire pump engine, the would not be cost-effective for an engine that is operated only a small number of hours per year. With a small number of operating hours, the cost per hour of operation of adding a post-combustion control system would be prohibitive.

59 March 30, 2005, letter from the California Air Resources Board (CARB) to Clarke Fire Protection Products (recognizing the limited number of options that direct-drive fire pump manufacturers have in replacing or modifying engines); Clarke December 11, 2006, letter to the South Coast Air Quality Management District.

60 40 CFR Part 60, Subpart IIII

, Table 4

- Emission Standards for Stationary Fire Pump Engines65

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 6. Requirement to Offset Emissions Increases

District regulations require that new facilities must provide Emission Reduction Credits (ERCs) to offset the increases in air emissions that they will cause. ERCs are generated when old facilities sources are shut down, or when sources are controlled below regulatory limits. The emissions reductions granted by the District are used to offset the increases from new facilities, so that there will be no overall increase in emissions from facilities subject to this offset

program.

Pursuant to Regulation 2-2-302, federally enforceable emission offsets are required for POC and

NO

x emission increases from permitted sources at facilities that will emit 10 tons per year or more of those pollutants. For facilities that will emit more than 35 tons per year of NO

x offsets must be provided by the applicant at a ratio of 1.15 to 1.0. Pursuant to Regulation 2-2-302.2, POC offsets may be used to offset emission increases of NO

x . For PM 10 and SO 2 , offsets are required for facilities that will emit 100 tons per year or more of those pollutants under District Regulation 2-2-303.

P ursuant to District Regulation 2-2-302, ERCs must be surrendered by the time the District

iss ues the Authority to Construct for the facility, although many applicants identify the ERCs they hold during the permitting process in order to demonstrate that they will be able to satisfy the emission offset requirements. At the time of issuance of this Preliminary Determination of Compliance, the applicant has not identified which emission reduction credits will be used to offset emissions from this project. The applicant has committed to identify a list of offsets holders who have indicated in writing their willingness to sell sufficient ERCs to offset the levels

of POC and NO

x emissions specified below prior to issuance of the Final Determination of Compliance. Pursuant to District Regulation 2-2-302, the applicant will be required to surrender

sufficient ERCs to offset the levels of POC and NO

x emissions specified below prior to issuance of the Authority to Construct.

The District’s analysis of the applicable offset requirements for the four pollutants for which offsets requirements have been established is outlined below.

6.1 POC Offsets

Because the proposed Oakley Generating Station will emit less than 35 tons of POC per year from permitted sources, the POC emissions must be offset at a ratio of 1.0 to 1.0 pursuant to District Regulation 2-2-302. The facility will be required to provide offsets for 29.49 tons per year of POC emissions.

6.2 NO

x Offsets

Because the proposed Oakley Generating Station will emit greater than 35 tons per year of NO

x from permitted sources, the NO

x emissions must be offset at a ratio of 1.15 to 1.0 pursuant to District Regulation 2-2-302. The facility will emit up to 98.78 tons/yr of NO

x , and will therefore be required to provide offsets for 113.60 tons per year of NO

x emissions.66

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 6.3 PM 10 Offsets

Because the total PM 10 emissions from permitted sources will not exceed 100 tons per year, the proposed Oakley Generating Station is not required to offset its PM 10 emissions under District Regulation 2-2 -303.

6.4 SO 2 Offsets

Pursuant to Regulation 2-2-303, emission reduction credits are not required for the SO 2 emission increases associated with this project since the facility’s SO 2 emissions will not exceed 100 tons

per year.67

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 7. Federal Permit Requirements

In addition to the Bay Area Air Quality Management District permit requirements in District Regulation 2, Rule 2 and Regulation 2, Rule 3, there are two federal permitting programs that apply to major facilities: (i) the federal “Prevention of Significant Deterioration” (PSD) requirements under 40 C.F.R. section 52.21; and (ii) the “Non-Attainment New Source Review” (Non -Attainment NSR) requirements for PM 2.5 sources set forth in Appendix S of 40 C.F.R. Part 51. The District has analyzed these requirements for the proposed Oakley Generating Station and has determined that neither of these permit requirements applies to this facility because it will not be a major source under either of those programs. The District is therefore not proposing to issue a PSD permit for this facility or to include Appendix S PM 2.5 Non-Attainment NSR requirements in the permit.

7.1 Federal “Prevention of Significant Deterioration” Program

The federal PSD program applies to “major” stationary sources. For 28 categories, including fossil fuel-fired steam electric plants of more than 250 MMBtu/hr heat input such as the proposed Oakley Generating Station, major stationary source means a new source that emits more than 100 tons per year of any PSD pollutant. 61 PSD pollutants are regulated pollutants for which the Bay Area is not in violation of the National Ambient Air Quality Standard (NAAQS) for that pollutant. For the Bay Area, PSD pollutants include carbon monoxide, PM 10 , PM 2.5 , and

SO 2 , among others. Facilities that exceed the federal PSD “major source” threshold for any of these pollutants must apply for and obtain PSD permits before they can commence construction. Although PSD permits are federal permits issued under the authority of EPA Region 9, the District conducts the PSD analysis and issues PSD permits on behalf of EPA Region 9 pursuant to a Delegation Agreement between the District and EPA Region 9. 62

The Oakley Generating Station will not be subject to PSD permitting requirements because it is not a “major source” because annual emissions are less than 100 tons of all PSD pollutants. ( See Annual Emissions, listed in Table 7 in Section 4.1.6 above.) Annual emissions will be subject to enforceable permit limits to ensure that they remain below the amounts listed in Table 7. As explained in Section 4.1.6, although these annual emissions rates are based on certain assumptions about how the facility will operate, they will subject to enforceable permit conditions that will ensure that emissions do not exceed the 100 ton PSD threshold. The facility will be required to monitor its emissions and ensure that they do not exceed the limits during any

61 Note that starting in 2011, EPA will regulate greenhouse gas emissions under the PSD program, with a “major source” applicability threshold of 100,000 tons per year and a PSD “significance” threshold 75,000 tons per year. See 40 C.F.R. § 52.21(b)(1)(i)(a) and § 52.21(b)(49)(iv)-(v). For new sources such as this one that are not otherwise subject to PSD permitting requirements, these requirements would not be effective until July 1, 2011.

62 The District also has incorporated PSD requirements from the federal PSD regulations into its NSR Rule in Regulation 2, Rule 2. The substance of these requirements in Regulation 2, Rule 2 track the federal requirements.68

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 12 -month period. If it appears that the facility is nearing its annual limit, it will be required by law to reduce or curtail operations to ensure that emissions do not exceed the permitting annual rates. These permit limits will ensure that the facility does not operate in a manner that would require a PSD permit. EPA’s PSD program specifically allows the use of enforceable emissions limitations in the permit as a basis for concluding that a facility’s emissions will not trigger PSD requirements and that the facility is therefore not subject to PSD permitting. 63 The District is therefore not proposing to issue a federal PSD permit for this facility.

7.2 Non-Attainment NSR for PM 2.5

The Bay Area has recently been designated as “non-attainment” of the National Ambient Air Quality Standard for PM 2.5 (24-hour average). 64 Areas classified as non-attainment are subject to the “Non-Attainment New Source Review” (Non-Attainment NSR) requirements of the federal

C lean Air Act. The Clean Air Act requires states to develop Non-Attainment NSR regulations to implement this requirement within 3 years of a non-attainment designation, and the District will be doing so for PM 2.5 in the months and years to come. In the interim, while the District is working on its own PM 2.5 Non-Attainment NSR regulations, Non-Attainment NSR for PM 2.5 is governed by the federal Non-Attainment NSR rule in EPA’s Emissions Offset Interpretive Ruling, which is set forth in Appendix S of 40 C.F.R. Part 51 (“Appendix S”).

Non-Attainment NSR under Appendix S is a federal permit program and is implemented under the federal regulations set forth in Appendix S. It is not a state law permitting program and it is not implemented under the requirements of District regulations established pursuant to the California Health & Safety Code. The Environmental Protection Agency has determined that the District can impose conditions in its District permits (Authority to Construct and Permit to Operate) that will allow a facility to establish compliance with the federal Non-Attainment NSR requirements for PM 2.5

. 65

, 66 If the District includes requirements in its District permits pursuant to District Regulation 2-1-403 (Permit Conditions) that satisfy the applicable PM 2 .5 Non-

63 See 40 C.F.R. § 52.21(b)(6); se e also National Mining Ass’n v. EPA , 50 F.3d 1351, 1365 (D.C. Cir. 1995).

64 EPA promulgated National Ambient Air Quality Standards (NAAQS) for PM 2.5 in 1997 (with an update in 2006), and began designating certain regions of the country as non-attainment with those Standards starting in 2005. EPA made a determination as to the region’s attainment status with respect to PM 2.5 , which it published on November 13, 2009. EPA determined that the Bay

Area is in attainment of the PM 2.5 NAAQS for the annual standard, and is non-attainment for the

24 -hour standard. The EPA’s non-attainment determination for the PM 2.5 24-hour standard

be came effective on December 14, 2009 (See Federal Register Friday November 13, 2009, Air Quality Designations for the 2006 24-Hour Fine Particle (PM 2.5 ) National Ambient Air Quality Standards).

65 Letter dated 10/28/09 from Jack Broadbent of BAAQMD to Deborah Jordan U.S. EPA Region IX, Re: Guidance on “Appendix S” Non-Attainment NSR Permitting for PM 2.5 Source During

PM 2.5 Transition Period.

66 Letter dated 12/9/09 from Deborah Jordan U.S. EPA Region IX to Jack Broadbent of BAAQMD, Re: Guidance on “Appendix S” Non-Attainment NSR Permitting for PM 2.5 Source During PM 2.5 Transition Period.69

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Attainment NSR requirements of Appendix S for a source, EPA has determined that it will treat those conditions as satisfying the federal Appendix S requirements for that source.

Under Appendix S, Non-Attainment NSR requirements for PM 2.5 apply to facilities with PM 2.5 emissions of more than 100 tons per year. ( See 40 CFR 51, Appendix S, II.A.4(i)(a) establishing 100 tpy threshold for regulation of Major Stationary Sources. 67 ) The proposed Oakley Generating Station would emit only 63.88 tons per year of PM 2.5 , so the Appendix S NonAttainment NSR requirements do not apply for this facility. The District is therefore not proposing to include conditions in the permit for compliance with Appendix S for PM 2.5 . Note, however, that the proposed permit includes permit limits on PM 10 , which will be effective to

control PM 2.5 emissions as well.

67 The facility will emit less than 100 tons per year of direct PM 2.5 emissions and less than 100 tons per year of any PM 2.5 precursors, as defined in Appendix S II.A.31(iii). ( See Preliminary Determination of Compliance, Table 7.)70

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 8. Health Risk Screening Analyses

Pursuant to the District’s Toxic Risk Management regulation (Regulation 2, Rule 5), a health risk screening must be conducted to determine the potential impact on public health resulting from the worst-case emissions of toxic air contaminants (TACs) from the proposed Oakley Generation Station. In accordance with the requirements of District Regulation 2, Rule 5 and California Office of Health Hazard Assessment (OEHHA) guidelines, the impact on public health due to the emission of these compounds was assessed utilizing EPA-approved air pollutant dispersion

models.

Tables 16 and 17 present the Health Risk Assessment results for the Oakley Generating Station. Table 16 summarizes the maximum cancer and non-cancer health risks from the project as a

whole , and Table 17 summarizes the maximum cancer risk from each source individually.

TABLE 16 : HEALTH RISK ASSESSMENT RESULTS FOR THE PROJECT

Receptor Cancer Risk Chronic Non

- Cancer

Hazard Index Acute Non

- Cancer

Hazard Index

Maximum Values 1.56 in a million 0.0832 0.2665

TABLE 17: HEALTH RISK ASSESSMENT RESULTS FROM EACH SOURCE

Source Maximum Residential/Worker Cancer Risk from Source

North Gas Turbine 0.70 in a million

South Gas Turbine 0.65 in a million Auxiliary Boiler 0.03 in a million Evaporative Fluid Cooler 0.39 in a million Fire Pump Diesel Engine 0.73 in a million

The District performed a health risk assessment in accordance with guidelines adopted by Cal/EPA’s Office of Environmental Health Hazard Assessment (OEHHA), the California Air Resources Board (CARB), and the California Air Pollution Control Officers Association (CAPCOA). Based on this assessment, the proposed sources for Oakley Generating Station will comply with the project risk requirements in accordance with the District’s Regulation 2, Rule 5. Regulation 2, Rule 5 requires that the maximum health risk from the project as a whole must be

less than 10 in one million excess cancer risk and less than a hazard index of 1.0 chronic and acute non-cancer risk; and that the maximum health risk from each individual source at the project must be less than 1.0 in one million excess cancer risk and less than a hazard index of 0.2 chronic non-cancer risk. As shown in Table 16, the maximum increased carcinogenic risk

a ttributed to this project is 1.56 in one million, and the chronic hazard index and the acute hazard index attributed to the emission of non-carcinogenic air contaminants are 0.0832 and 0.2665, respectively. As shown in Table 17, the risk from each source individually is below 1.0 in a

mi llion maximum individual cancer risk; and since the maximum chronic non-cancer hazard index for the project as a whole is less than 0.2, the chronic hazard index for each source is less than 0.20. Please see Appendix B (Memo dated August 12, 2010, prepared by Glen Long, Air Toxics Section) for further discussion.71

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 9. Other Applicable Requirements

The following section summarizes the applicable District, state and federal rules and regulations and describes how the Oakley Generating Station will comply with those requirements.

9.1 Applicable District Rules and Regulations

Regulation 1, Section 301: Public Nuisance

None of the project's sources of air contaminants are expected to cause injury, detriment, nuisance, or annoyance to any considerable number of persons or the public with respect to any impacts resulting from the emission of air contaminants regulated by the District.

Regulation 2, Rule 1, Sections 301 and 302: Authority to Construct and Permit to Operate

Pursuant to Sections 2-1-301 and 2-1-302, the applicant has submitted an application to the

Dist rict to obtain an Authority to Construct and Permit to Operate for all regulated sources at the proposed Oakley Generating Station. Those permits will be issued after the CEC completes its licensing process.

Regulation 2, Rule 2: New Source Review

The primary requirements of New Source Review that apply to the proposed Oakley Generating Station are Section 2-2-301; “Best Available Control Technology Requirement”, Section 2-2- 302; “Offset Requirements, Precursor Organic Compounds and Nitrogen Oxides, NSR”, Section

2 -2 -303, “Offset Requirement, PM 10 and Sulfur Dioxide, NSR”.

Regulation 2, Rule 2, Section 301: BACT

The District has performed a BACT analysis for the gas turbines, auxiliary boiler, and fire pump diesel engine as shown in Section 5. The proposed Oakley Generating Station meets the BACT requirements under Section 2-2-301.

Regulation 2, Rule 2: Sections 302 and 303

The District has presented the offsets required for the project for NO

x and POC as shown in Section 6 of this document. The proposed Oakley Generating Station will meet the offset requirements under Sections 2-2-302 and 2 -2-303.72

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Regulation 2, Rule 2: Sections 304, 305, 306 and 414

The Prevention of Significant Deterioration (PSD) requirements in District Regulation 2, Rule 2 (Sections 304, 305, 306, and 308) are intended to implement the federal PSD requirements in 40 C.F.R. Section 52.21 and track those federal requirements. The proposed Oakley Generating Station will not be subject to PSD requirements. Those requirements are discussed in detail in

Section 7 above.

Regulation 2, Rule 3: Power Plants

Pursuant to Section 2-3-304, this Preliminary Determination of Compliance is subject to the public notice, public comment, and public inspection requirements contained in Sections 2-2-406

a nd 2-2-407. This document presents the Preliminary Determination of Compliance for the

pr oject. The District will consider all comments received during the comment period prior to

is suing any Final Determination of Compliance for the project. The Final Determination of Compliance will be relied upon by the CEC in their licensing amendment proceeding. If the CEC grants a license to the project, then the District will issue an Authority to Construct.

Regulation 2, Rule 5: New Source Review of Toxic Air Contaminants

A risk screening analysis was performed to estimate the health risk resulting from the toxic air contaminant (TAC) emissions from the proposed Oakley Generating Station. The proposed sources for Oakley Generating Station comply with the project risk requirements in accordance with the District’s Regulation 2, Rule 5. The increased carcinogenic risk attributed to this project is less than 10.0 in one million, and the chronic hazard index and the acute hazard index attributed to the emission of non-carcinogenic air contaminants are less than 1.0. The risk from each source individually is below 1.0 in a million maximum individual cancer risk, and the chronic hazard index is less than 0.20. In addition, the gas turbines and fire pump diesel engine will apply Best Available Control Technology for Toxics (TBACT). TBACT for the gas turbines is the use of an oxidation catalyst. TBACT for the fire pump diesel engine is a diesel PM emission rate of less than 0.15 gram per brake horsepower-hour (g/bhp-hr); the engine proposed for Oakley Generating Station has a diesel PM emission rate of 0.119 g/bhp-hr.

Regulation 2, Rule 6: Major Facility Review After construction, the facility will be subject to Regulation 2, Rule 6, which implements the Title V program of the Federal Clean Air Act and 40 CFR 70, State Operating Permit Programs.

Pursuant to Section 404.1, the owner/operator of the Oakley Generating Station shall submit an application to the District for a major facility review permit within 12 months after the facility becomes subject to Regulation 2, Rule 6. Pursuant to Section 2-6-217 (Phase II Acid Rain Facility), the Oakley Generating Station will become subject to Regulation 2, Rule 6, upon completion of construction as demonstrated by first firing of the gas turbines.73

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Regulation 2, Rule 7: Acid Rain

The Oakley Generating Station gas turbine units will be subject to the requirements of Title IV of the federal Clean Air Act. The requirements of the Acid Rain Program are outlined in 40 CFR Part 72. The specifications for the type and operation of continuous emission monitors (CEMs) for pollutants that contribute to the formation of acid rain are given in 40 CFR Part 75. District Regulation 2, Rule 7 incorporates by reference the provisions of 40 CFR Part 72.

40 CFR Part 72, Subpart A - Acid Rain Program

Part 72, Subpart A, establishes general provisions and operating permit program requirements for sources and affected units under the Acid Rain program, pursuant to Title IV of the Clean Air Act. The gas turbines are affected units subject to the program in accordance with 40 CFR Part 72, Subpart A, Section 72.6(a)(3)(i).

40 CFR Part 72, Subpart C – Acid Rain Permit Applications

Subpart C, section 72.30(b)(2)(ii) requires that the applicant submit a complete Acid Rain Permit application 24 months before the gas turbines commence operation. Pursuant to 40 CFR Part 72.2, “commence operation” includes the start-up of the unit’s combustion chamber.

40 CFR Part 73 - Sulfur Dioxide Allowance System

Part 73 establishes the sulfur dioxide allowance system for tracking, holding, and transferring allowances. The applicant will be required to obtain sufficient SO 2 allowances for each operating year on March 1st (or February 29th in a leap year) of the following year.

40 CFR Part 75 – Continuous Emission Monitoring

Part 75 contains the continuous emission monitoring requirements for units subject to the Acid Rain program. The applicant will be required to meet the Part 75 requirements for monitoring, recordkeeping and reporting of SO 2 , NO

x , and CO 2 emissions. The applicant will also need to meet Part 75 requirement for monitoring, recordkeeping, and reporting volumetric flowrate and opacity.

Regulation 6, Rule 1: Particulate Matter

– General Requirements

Opacity Requirements The gas turbines and auxiliary boiler are expected to comply with the visible emissions limitation in Section 6-1-301 (Ringelmann No. 1 Limitation) through the use of dry low- NO

x burner technology, good combustion practice, and natural gas. The evaporative fluid cooler is expected to comply with the visible emissions limitation in Section 6-1-301 (Ringelmann No. 1

L imitation) through the use of water with a maximum total dissolved solids content of 1,500 mg/l, which is not expected to result in visible emissions. The fire pump diesel engine is expected to comply with the visible emissions limitation in Section 6-1-303 (Ringelmann No. 2

L imitation) through the use of an EPA/CARB-certified Tier 3 engine and ultra-low sulfur diesel.74

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Visible Particles The facility's sources are expected to comply with Section 6-1-305 (Visible Particles) with

e missions of particles not causing annoyance to others or large enough to be visible as individual particles at the emission point or of such size and nature as to be visible individually as incandescent particles.

Particulate Weight Limitation The gas turbines and auxiliary boiler are subject to 6-1-310 (Particulate Weight Limitation) with

pa rticulate matter emissions of less than 0.15 grains per dry standard cubic foot of exhaust gas volume, in actual conditions and calculated in accordance with Section 6-1-310.3 since the HRSG and auxiliary boiler involve heat transfer operations. The grain loading resulting from the operation of each gas turbine is 0.0008 gr/dscf @ 15% O 2 and from the boiler is 0.0048 gr/dscf @ 3% O 2 . The grain loading resulting from the operation of each gas turbine is 0.0021 gr/dscf @

6% O 2 and from the boiler is 0.0040 gr/dscf @ 6% O 2

.

The fire pump diesel engine is subject to Section 6-1-310 (Particulate Weight Limitation) with

pa rticulate matter emissions of less than 0.15 grains per dry standard cubic foot of exhaust gas volume. The grain loading resulting from the operation of the fire pump diesel engine is 0.029 gr/dscf @ 0% O 2. See Appendix A for calculations.

General Operations The evaporative fluid cooler is subject to Regulation 6-1-311 (General Operations), which limits

pa rticulate matter emissions based on process weight. Based on 352,800 gallons of water per hour, the emission limit in Section 6-1-311 would be 40 lb PM/hour; emissions of PM based on a

0.003% drift rate and 1,500 total dissolved solids content would be 0.132 lb PM/hour, so the evaporative fluid cooler would comply with Section 6-1-311. See Appendix A for calculations.

P articulate matter emissions associated with the construction of the facility are exempt from District permit requirements, but are subject to Regulation 6, Rule 1. However, the California Energy Commission will impose requirements for construction activities such as the use of water and/or chemical dust suppressants to minimize PM 10 emissions and prevent visible particulate

emissions.

Regulation 7: Odorous Substances

Section 7-302 prohibits the discharge of odorous substances, which remain odorous beyond the facility property line after dilution with four parts odor-free air. Section 7-303 limits ammonia emissions to 5000 ppm. Because the ammonia slip emissions from the combined-cycle units will be limited by permit condition to 5 ppmvd @ 15% O 2 , the facility is expected to comply with the requirements of Regulation 7.

Regulation 8: Organic Compounds

The gas turbines and auxiliary boiler are exempt from Regulation 8, Rule 2, “Miscellaneous Operations” per Section 8-2-110 since natural gas will be fired exclusively at those sources. The75

Preliminary Determination of Compliance, October 2010

Oakley Generating Station fire pump diesel engine will comply with Section 8-2-301 since its emissions will contain a total carbon concentration of less than 300 ppmv, dry, and it will emit less than 15 lb VOC/day.

The evaporative fluid cooler is exempt from Regulation 8, Rule 2, “Miscellaneous Operations” per 8-2-114 since it is a closed loop cooling tower. The evaporated water, which is sprayed over

the e nclosed tubes containing the cooling fluid, does not contact the cooling fluid.

The use of solvents for cleaning and maintenance at the Oakley Generating Station is expected to be at a level that is exempt from permitting in accordance with Regulation 2, Rule 1, Section 118. The facility may utilize less than 20 gallons per year of solvent for wipe cleaning per Section 2-1-118.9 and remain exempt from permitting requirements. The facility may also

uti lize a cold cleaner for maintenance cleaning as long as the unit meets the exemption set forth in Section 2-1-118.4. The facility may also perform solvent cleaning and preparation using

a erosol cans meeting the exemption set forth in Section 2-1-118.10. Any solvent usage

e xceeding the amounts in Section 2-1-118 would require a permit. In addition, any solvent usage

in excess of a toxic air contaminant trigger level contained in Regulation 2, Rule 5 would require a permit.

The oil-water separator is exempt from Regulation 8, Rule 8, “Wastewater Collection and Separation Systems” per Section 8-8 -113, since it is a stormwater sewer system for collection of stormwater that is segregated from a process wastewater collection system.

Regulation 9: Inorganic Gaseous Pollutants

Regulation 9, Rule 1, Sulfur Dioxide

This regulation establishes emission limits for sulfur dioxide from all sources and applies to the combustion sources at this facility. Section 9-1-301 (Limitations on Ground Level

C oncentrations) prohibits emissions, which would result in ground level SO 2 concentrations in excess of 0.5 ppm continuously for 3 consecutive minutes, 0.25 ppm averaged over 60 consecutive minutes, or 0.05 ppm averaged over 24 hours. Section 9-1-302 (General Emission

L imitation) prohibits SO 2 emissions in excess of 300 ppmv (dry). With maximum projected SO 2 emissions of < 1 ppmv, the gas turbines and natural gas-fired auxiliary boiler are not expected to cause ground level SO 2 concentrations in excess of the limits specified in Section 301 and should easily comply with Section 302.

Section 9-1-304 (Fuel Burning (Liquid and Solid Fuels) prohibits burning of liquid fuel having a

sulfur content in excess of 0.5% by weight. The fire pump diesel engine will be required to burn CARB diesel as defined in title 13, CCR, sections 2281 and 2282, which has a maximum sulfur

content of 0.0015%.

Regulation 9, Rule 3, Nitrogen Oxides from Heat Transfer Operations

The gas turbines shall comply with the Section 9-3-303 NO

x limit of 125 ppm by complying with a permit condition NO

x emission limit of 2.0 ppmvd @ 15% O 2 . The auxiliary boiler shall comply with the Section 9-3-303 NO

x limit of 125 ppm by complying with a permit condition76

Preliminary Determination of Compliance, October 2010

Oakley Generating Station NO

x emissions limit of 7 ppmvd @ 3% O 2 . The proposed fire pump diesel engine is not subject to this regulation since it is not a heat transfer operation.

Regulation 9, Rule 7, Nitrogen Oxides and Carbon Monoxide from Industrial, Institutional, and Commercial Boilers, Steam Generators, and Process Heaters

The gas turbines are not subject to Regulation 9, Rule 7 requirements per Section 9-7-110.5 (w aste heat recovery boilers that are used to recover sensible heat from the exhaust of gas turbines).

The natural gas-fired boiler is subject to Regulation 9, Rule 7 requirements. The boiler shall comply with the NO

x emission limit of 30 ppm contained in Section 9-7-301.1, the future NO

x

e mission limit of 9 ppm contained in Section 9-7-307.5, and the CO emission limit of 400 ppmvd @ 3% O2 by using a boiler with manufacturer guaranteed emission rates of 7 ppmvd @ 3% O2 for NOx and 10 ppmvd @ 3% O 2 for CO or lower. The boiler is also subject to and expected to comply with 9-7-311 (Insulation Requirements), 312 (Stack Gas Temperature Limits), 313 (T une-Up Requirements), 403 (Initial Demonstration of Compliance), and 503 (Records).

Regulation 9, Rule 9, Nitrogen Oxides from Stationary Gas Turbines

Because each of the gas turbines will be limited by permit condition to NO

x emissions of 2.0 ppmvd @ 15% O 2 , respectively, they will comply with the Regulation

9 -9 -301.2 NO

x limitation of 5 ppmvd @ 15% O 2 . The gas turbines exhaust emissions will be monitored by CEMs and will comply with 9-9-501, which requires each unit to have a CEM to

moni tor NO

x .

Regulation 10: Standards of Performance for New Stationary Sources

Regulation 10 incorporates Title 40 of the Code of Federal Regulations Part 60 into the Rules and Regulations of the Bay Area Air Quality Management District. The specific requirements applicable to the proposed Oakley Generating Station are discussed in Section 9.4, Federal Requirements, of this document.

9.2 State Requirements

California Health and Safety Code Sections 25531 to 25541

T itle 19, Division 2, Chapter 4.5 California Accidental Release Prevention Program (CalARP)

The proposed facility will utilize aqueous ammonia in a 29.4% (by weight) solution for SCR ammonia injection, which will be transported to the facility and stored on-site in tanks. The transportation and storage of ammonia presents a risk of an ammonia release in the event of a major accident. These risks will be addressed in a number of ways under safety regulations and sound industry safety codes and standards. These safety measures include the Risk Management77

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Plan requirements pursuant to the California Accidental Release Prevention Program. 68 The Risk Management Plan must include an off-site consequences analysis and appropriate mitigation measures; a requirement to implement a Safety Management Plan (SMP) for delivery of ammonia and other liquid hazardous materials; a requirement to instruct vendors delivering hazardous chemicals, including aqueous ammonia, to travel certain routes; a requirement to install ammonia sensors to detect the occurrence of any potential migration of ammonia vapors offsite; a requirement to use an ammonia tank that meets specific standards to reduce the potential for a release event; and a requirement to conduct a “Vulnerability Assessment” to address the potential security risk associated with storage and use of aqueous ammonia onsite.

Th e Energy Commission will also be evaluating these risks further through its CEQA-equivalent environmental review process and will impose mitigating conditions as necessary to ensure that the risks are less than significant.

California Health and Safety Code Section 44300 et seq

The proposed Oakley Generating Station will be subject to the Air Toxic “Hot Spots” Program contained in the California Health and Safety Code Section 44300 et seq. The facility will be required to prepare inventory plans and reports as required.

Title 17, California Code of Regulations Section 93115

Section 93115 Airborne Toxic Control Measure for Stationary Compression Ignition (CI) Engines applies to the fire pump diesel engine. Section 93115.5 requires the use of CARB dieselfuel, which the engine will use. Section 93115.6(a)(4) requires the engine to meet Tier 3 OffRoad Compression Ignition Engine Standards and allows the engine to be tested as required by the National Fire Protection Maintenance Association (NFPA) 25 standards. The proposed engine is certified to Tier 3 Off-Road Compression Ignition Engine Standards and will be limited to 49 hours per year for maintenance and testing. Section 93115.10 Recordkeeping, Reporting, and Monitoring requirements requires reporting and emissions submittal to the District, installation of a non-resettable hour meter, and recordkeeping requirements regarding hours of operation and fuel usage. The on-going applicable requirements will be included in the permit

conditions.

Title 17, California Code of Regulations Sections 95100 to 95133, Article 2, Subchapter 10

The proposed Oakley Generating Station will be subject to the Mandatory Greenhouse Gas Emissions Reporting regulation. Potential GHG emissions were calculated in accordance with this regulation in Section 9.4 of this document. The proposed Oakley Generating Station would have to submit a greenhouse gas emissions data report and verification opinion to the California Air Resources Board each year.

68 See Contra Costa Generating Station Application for Certification , Vol. 1, section 5.5.4.2.2 at p. 5.5 -21. (available at: http://www.energy.ca.gov/sitingcases/oakley/documents/applicant/afc/index.php )78

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 9.3 Federal Requirements

40 CFR Part 60 Subpart Dc

Subpart Dc “Standards of Performance for Small Industrial-Commercial-Institutional Steam Generating Units” applies to this facility. The boiler will comply with all applicable standards and limits in this regulation. Since the boiler will exclusively use natural gas, there are no applicable NO

x , SO 2 , or opacity standards in this regulation.

Section 60.48c(a) requires notification of date of construction and actual startup along with design heat capacity and anticipated annual capacity factor. Section 60.48c(g)(2) requires the facility to record and maintain records of the amount of fuel combusted during each calendar month, which will also be included as a permit condition. Section 60.48c(g)(2) requires submittal of reports every six months.

40 CFR Part 60 Subpart IIII

Subpart IIII “Standards of Performance for Stationary Compression Ignition Internal Combustion Engines” applies to this facility. The fire pump diesel engine will comply with all applicable standards and limits by meeting the emission standards in section 60.4205(c), operating and maintaining the engine according to manufacturer’s instructions per section 60.4206, using ultra low sulfur diesel fuel per section 60.4207, installing a non-resettable hour meter, and limiting maintenance and testing hours to 49 hours per year, which complies with the 100 hours per year limit in section 60.4211(e). The engine is exempt from notification requirements per 60.4214(b).

40 CFR Part 60 Subpart KKKK

Generally Regulation 10 incorporates by reference the provisions of Title 40 CFR Part 60. However, the District has not sought delegation of the New Source Performance Standard (NSPS) contained in Subpart KKKK. Subpart KKKK “Standards of Performance for Stationary Gas Turbines” applies to this facility. The gas turbines will comply with all applicable standards and limits required by these regulations. The applicable emission limitations are summarized

below:

TABLE 18: NEW SOURCE PERFORMANCE STANDARDS FOR COMBINED-CYCLE

G AS TURBINES

Source Requirement Emission Limitation Compliance Demonstration

Gas

Turbines Subpart KKKK

§60.4320 (NO

x ) §60.4330(SO 2 ) 0.43 lb NO

x /MW

- hr, or 15 ppm NO

x as NO 2 @ 15%O 2; 0.9 lb SO 2 /MW

- hr, or

0.06 lb SO 2 /MMBtu maximum

No CO li mit in Subpart KKKK No PM limit in Subpart KKKK 2.0 ppm NO

x as NO 2 @ 15%O 2 Permit Limit;

0.00281 lb SO 2 /MMBtu Permit

Limit

Section 60.4340(b)(1) requires continuous emissions monitors for NO

x , and NO

x initial and annual performance tests are to be satisfied by complying with Section 60.4405 RATA testing.79

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Section 60.4365(a) exempts the facility from SO 2 monitoring by requiring a contract for naturalgas with 20 grains of sulfur or less per 100 standard cubic feet. The facility will use PUCregulated natural gas and be conditioned to use natural gas with 1 grain of sulfur or less per 100

standard cubic feet.

Section 60.4375 requires submittal of reports of excess emissions and monitoring of downtime for all periods of unit operation, including startup, shutdown, and malfunction. The applicant is expected to maintain adequate records for Subpart KKKK reporting requirements. The gas turbines will be equipped with continuous emissions monitors for NO

x and CO and annual emission test will not be required for Subpart KKKK.

40 CFR 63 Subpart Q

Subpart Q “National Emission Standards for Hazardous Air Pollutants for Industrial Process Cooling Towers” does not apply to this facility per section 63.400(a) since this regulation applies specifically to Industrial Process Cooling Towers that use chromium-based water treatment chemicals and are located at major sources of HAP emissions. Oakley Generating Station will not use chromium-based water treatment chemicals and is not a major source of HAP emissions, so Subpart Q does not apply.

40 CFR Part 63 Subpart YYYY

Subpart YYYY contains the National Emission Standards for Hazardous Air Pollutants (NESHAPs) for Stationary Combustion Turbines. This regulation has been stayed (Federal Register; April 7, 2004, Volume 69, Number 67) for a combustion turbine that is a lean premix gas fired unit or a diffusion flame gas fired unit.

The emissions standards contained in Subpart YYYY have been stayed for natural gas-fired combustion turbines per Section 63.6095. If a gas fired combustion turbine were subject to Subpart YYYY, then it would still need to comply with the Initial Notification requirements in

Section 63.6145.

Subpart YYYY does not apply to the Oakley Generating Station gas turbines since the facility is not a major source of Hazardous Air Pollutants (HAPs). The Oakley Generating Station emits less than the major HAP thresholds of 10 tons/year of any single HAP, or 25 tons/year of aggregate HAP. Please note that ammonia, propylene, and sulfuric acid are not HAPs pursuant to section 112(b) of the Clean Air Act.

40 CFR Part 63 Subpart ZZZZ

Subpart ZZZZ “National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines” applies to this facility. Per Section 63.6590(c), the fire pump diesel engine will meet the requirements of this subpart by meeting the requirements of 40 CFR Part 60 Subpart IIII.80

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 40 CFR Part 63 Subpart JJJJJJ

Subpart JJJJJJ “National Emission Standards for Area Sources: Industrial/Commercial/

In stitutional Boilers” is proposed and the public comment period has been extended to August 3, 2010. If the regulation is adopted, the proposed auxiliary boiler at the Oakley Generating Station would not be subject to this subpart per section 63.11195(e) since it would be a gas-fired boiler.

40 CFR Part 64

–

Compliance Assurance Monitoring (CAM)

Requirements for enhanced monitoring may apply to facilities that are required to obtain Part 70 (Title V or Major Facility Review) permits. If so, they would apply at the time of issuance of the Major Facility Review permit. Although, these requirements would not apply at the completion of construction, it is prudent to determine at this time if they will apply so that it can be determined whether the monitoring strategy would comply with CAM.

In general, the requirement applies if an emission unit, as defined in Section 64.1, is subject to a federally-enforceable emission limit for a pollutant, has emissions of the pollutant that are greater than the major source thresholds (100 tpy of any regulated air pollutant or 10 tpy of a HAP) and the emissions of that pollutant are abated by a control device. There are several exemptions.

In this case, NOx and CO from the gas turbines are controlled by SCR and a CO catalyst and CO from the auxiliary boiler may be controlled by a CO catalyst.

Monitoring for the NOx limits for the gas turbines is exempt in accordance with 40 CFR 64.2(b)(iii) because the monitoring is subject to the Acid Rain monitoring requirements in 40

CF R 75.

Monitoring for the CO limits for the gas turbines is required since the pre-abatement potential to emit of CO for each turbine is greater than 100 tons per year. Each gas turbine will have a

continuous emission monitor for CO.

Monitoring for the CO limits for the auxiliary boiler is not required since the pre-abatement potential to emit of CO is less than 100 tons per year.

The estimated potential to emit from each gas turbine is calculated using the following

parameters: Fuel input: 2150 MMbtu/hr CO Concentration: 9.0 ppmv (Normal Operation)

lb -mol CO = 28 lb CO 8743 scf flue gas/MMbtu @ 0% O2

386.8 dscf/lbmol

At 9.0 ppm (9.0 ppmv)(20.95 - 0)/(20.95 - 15) = 31.69 ppmv, dry @ 0% O281

Preliminary Determination of Compliance, October 2010

Oakley Generating Station (31.69/106)(lbmol/386.8 dscf)(28 lb CO/lbmol)(8743 dscf/MM Btu) = 0.0201 lb CO/MMBtu

(2150 MMbtu/hr)(0.0201 lb CO/MMBtu) = 43.12 lb CO/hr

At 5390 hours/year of normal operation + 25 cold starts + 275 hot starts + 300 shutdowns = (5390 hours)(43.12 lb CO/hr) + (25 cold start)(360 lb/cold start) + (275 hot start)(85 lb/hot start) + (300 shutdowns)(140 lb/shutdown)

= 153 TPY CO/turbine

The auxiliary boiler may be required to be abated by an oxidation catalyst if the CO limit cannot be met without abatement. If the oxidation catalyst is needed, pre-abatement CO potential to

emit is estimated below.

Fuel input: 50.6 MMbtu/hr CO Concentration: 50.0 ppmv

lb -mol CO = 28 lb CO 8743 scf flue gas/MMbtu @ 0% O2

386.8 dscf/lbmol

At 50.0 ppm (50.0 ppmv)(20.95 - 0)/(20.95 - 15) = 176.1 ppmv, dry @ 0% O2

(176. 1/106)(lbmol/386.8 dscf)(28 lb CO/lbmol)(8743 dscf/MM Btu) = 0.1114 lb CO/MMBtu

(50.6 MMbtu/hr)(0.1114 lb CO/MMBtu) = 5.64 lb CO/hr

At 4324 hours/year = (4324 hour/year)(5.64 lb CO/hr)

= 12.2 TPY

Since pre-abatement potential to emit for CO is less than 100 tons per year, the auxiliary boiler is not subject to CAM.

40 CFR Part 70, State Operating Permit Programs These requirements are discussed in Section 8.2 under Regulation 2, Rule 6, Major Facility

R eview, which implements Part 70.

40 CFR Part 72, Subpart A

– Acid R ain Program

Part 72, Subpart A, establishes general provisions and operating permit program requirements for sources and affected units under the Acid Rain program, pursuant to Title IV of the Clean Air Act. The gas turbines are affected units subject to the program in accordance with 40 CFR Part 72, Subpart A, Section 72.6(a)(3)(i).

40 CFR Part 72, Subpart C

– Acid Rain Permit Applications8 2

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Subpart C, section 72.30(b)(2)(ii) requires that the applicant submit a complete Acid Rain Permit application 24 months before the gas turbines commence operation. Pursuant to 40 CFR Part 72.2, “commence operation” includes the start-up of the unit’s combustion chamber.

40 CFR Part 73

– Sulfur Dioxide Allowance System

Part 73 establishes the sulfur dioxide allowance system for tracking, holding, and transferring allowances. The applicant will be required to obtain sufficient SO 2 allowances for each operating year on March 1st (or February 29th in a leap year) of the following year.

40 CFR Part 75

–

Continuous Emission Monitoring

Part 75 contains the continuous emission monitoring requirements for units subject to the Acid Rain program. The applicant will be required to meet the Part 75 requirements for monitoring, recordkeeping and reporting of SO 2 , NO

x , and CO 2 emissions. The applicant will also need to meet Part 75 requirement for monitoring, recordkeeping, and reporting volumetric flowrate and opacity.

40 CFR Part 98

Part 98 Mandatory Greenhouse Gas Reporting, requires certain facilities, including electrical generation facilities such as Oakley Generating Station, to monitor, keep records of, and report GHG emissions every March 31 for the previous calendar year.

9.4 Greenhouse Gases

Climate change poses a significant risk to the Bay Area with such impacts such as rising sea levels, reduced runoff from snow pack in the Sierra Nevada, increased air pollution, impacts to agriculture, increased energy consumption, and adverse changes to sensitive ecosystems. The generation of electricity from burning natural gas produces air emissions known as greenhouse gases (GHGs) in addition to the criteria air pollutants. GHGs are known to contribute to the warming of the earth’s atmosphere. These include primarily carbon dioxide, nitrous oxide (N 2 O,

not NO or NO 2 , which are commonly known as NO

x or oxides of nitrogen), and methane (unburned natural gas). Also included are sulfur hexafluoride (SF 6 ) from transformers, and hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs) from refrigeration/chillers. The proposed Oakley Generating Station would use evaporative inlet air cooling, which uses water,

and not HFCs or PFCs.

The California Global Warming Solutions Act of 2006 (AB32) requires the California Air Resources Board (ARB) to adopt a statewide GHG emissions limit equivalent to the statewide GHG emissions levels in 1990 to be achieved by 2020. To achieve this, ARB has a mandate to adopt rules and regulations to achieve the maximum technologically feasible and cost-effective

GHG emission reductions.83

Preliminary Determination of Compliance, October 2010

Oakley Generating Station The ARB is expected to adopt early action GHG reduction measures in the near future to reduce greenhouse gas emissions by 2020. ARB has adopted regulations requiring mandatory GHG emissions reporting. The facility is expected to report all GHG emissions to meet ARB requirements.

The facility will also be required to report GHG emissions to CARB, the District, and US EPA. In 2008, the District placed a fee on GHG emissions from large stationary sources of GHGs.

The GHG emissions estimates for Oakley Generating Station are shown below.84

Preliminary Determination of Compliance, October 2010

Oakley Generating Station TABLE 19: OAKLEY GENERATING STATION GHG EMISSIONS

Fuel Usage Emission

Factor Emission

Factor Emission

Factor GHG

Emissions Global

Warming CO2

equivalents

(MMBtu/year) (kg

CO2/MMBtu) (g

CH4/MMBtu) (g

N2O/MMBtu) (metr ic

tons/year) Potential (metric tons/year)

Gas

Turbines 35397277

CO2 52.87 1.871E+06 1 1871454.035

CH4 0.9 3.186E+01 21 669.009

N2O 0.1 3.540E+00 310 1097.316 Auxiliary

Boiler 218606

CO2 52.87 1.156E+04 1 11557.699

CH4 0.9 1.967E

- 01 21 4.132

N2O 0.1 2.186E

- 02 310 6.777 Fire Pump Engine 136

CO2 73.10 9.942E+00 1 9.942

CH4 3.0 4.080E

- 04 21 0.009

N2O 0.6 8.160E

- 05 310 0.025

Circuit

Breakers Total Capacity

of SF6 leak rate GHG

Emissio ns GHG

Emissions Global

Warming CO2

equivalents

(lbs) (%) (kg/year) (metric tons/year) Potential (metric tons/year)

SF6 200 0.50% 0.454 4.536E

- 04 23900 10.841

TOTAL GHG Emissions (CO2 equivalent, metric tons/year) 1,884,809.885

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Oakley Generating Station has the potential to emit 1,884,809.8 metric tons of CO 2 equivalents per year using the ARB Mandatory Reporting Rule calculation methodology.

The Oakley Generating Station combined-cycle gas turbines will have a gross electrical efficiency of 56% at 59oF and a relative humidity of 60%. 69 The Oakley Generating Station will have a net facility heat rate of 6,752 (HHV) Btu/KW-hr at 59oF and a relative humidity of 60%. 70

On September 29, 2006, Governor Arnold Schwarzenegger signed into law Senate Bill 1368 (Perata, Chapter 598, Statutes of 2006). The law limits long-term investments in baseload generation by the state's utilities to power plants that meet an emissions performance standard (EPS) jointly established by the California Energy Commission and the California Public

Utilities Commission.

The Energy Commission has designed regulations that, among other things, establish a standard for baseload generation owned by, or under long-term contract to publicly owned utilities, of 1,100 lbs CO 2 per megawatt-hour (MWh). A utility must submit a compliance filing with the CEC upon committing to an investment that is required to meet the Emission Performance Standard (Compliance Filing).

The applicant has estimated that the proposed Oakley Generating Station will meet the Emission Performance Standard of 1,100 lbs CO 2 per megawatt-hour (MWh):

At ISO conditions:

624 MW (net) 2102 MMBtu/hr/turbine (HHV) x 2 turbines x 52.87 kg CO 2 /MMBtu /1000

= 222.27 metric tons CO 2 /hr

222.27 metric tons CO 2 /hr / 624 MW = 0.356 metric tons CO 2 /MWh

0.356 metric tons CO 2 /MWh x 2204.6 lb/metric ton = 784.8 lb CO 2 /MWh

As published in the Federal Register on June 3, 2010, beginning January 2, 2011, only stationary sources that are major for a regulated new source review pollutant that is not a GHG and will emit or have the potential to emit 75,000 TPY CO 2 equivalent or more are subject to Prevention of Significant Deterioration for GHGs. 71 Beginning July 1, 2011, new stationary sources that will emit or have the potential to emit 100,000 TPY CO 2 equivalent or more are subject to Prevention

69 See Radback Energy Supplemental Filing Air Quality and Public Health Revised April 7, 2010, Application for Certification for Oakley Generating Station Project , at p. Appendix 5.1F33.

70 See Radback Energy Supplemental Filing Air Quality and Public Health Revised April 7, 2010, Application for Certification for Oakley Generating Station Project , Table 5.1-1 at p. 5.1-

3.

71 See 40 CFR Part 52.21(b)(49)(iv)-(v).86

Preliminary Determination of Compliance, October 2010

Oakley Generating Station of Significant Deterioration for GHG. Therefore, Oakley Generating Station is not required to

address GHG emissions under the Clean Air Act at this time.

As the lead agency under the CEQA-equivalent process, the CEC will be required to quantify and assess GHG emissions from the Oakley Generating Station to evaluate the facility's compliance with applicable laws, ordinances, regulations and standards, and the potential impacts and benefits associated with adding Oakley Generating Station to the electricity system.

9.5 Environmental Justice

The District is committed to implementing its permit programs in a manner that is fair and equitable to all Bay Area residents regardless of age, culture, ethnicity, gender, race, socioeconomic status, or geographic location in order to protect against the health effects of air pollution. The District has worked to fulfill this commitment in the current permitting action, although there is no legal requirement that the District undertake an environmental justice analysis for this permitting action. 72 Nevertheless, regardless of any applicable legal requirements, the District considers environmental justice concerns to be sufficiently important

to warrant a discussion in this document.

The emissions from the proposed project will not cause or contribute to any significant public health impacts in the community. As described in detail above, the District has undertaken a detailed review of the potential public health impacts of the emissions authorized under the proposed permitting action, and has found that they will involve no significant public health risks. The District has found that the maximum lifetime cancer risk associated with the facility is 1.56 in one million, and that the maximum chronic Hazard Index would be 0.0832 and the

maximum acute Hazard Index would be 0.2665. These risk levels are below what the District considers to be significant. In particular, these risk levels are less than the thresholds of significance that the District’s Board of Directors recently adopted as indicating whether health risk impacts would be significant in the context of a CEQA review. 73 The District anticipates that there will be no significant impacts due to air emissions related to the Oakley Generating Station after all of the mitigations required by District Rules and the California Energy Commission are implemented. The District does not anticipate a significant adverse impact on any community due to air emissions from the Oakley Generating Station; therefore, there will be no significant disparate adverse impact on any Environmental Justice community located near the facility.

72 The environmental justice analysis requirements of the federal Executive Order 12898 do not apply here because the District is not issuing a federal permit, and state requirements for evaluating environmental justice impacts as part of the overall CEQA environmental review are handled through the CEC’s CEQA- eq uivalent. (Note that Title VI civil rights requirements applicable to agencies that receive federal funds impose anti-discriminatory requirements on the agency’s programs as a whole, and do not impose any specific requirements for an environmental justice analysis for individual permitting actions.)

73 See BAAQMD Air Quality CEQA Threshold of Significance (June 2, 2010), available at: www.baaqmd.gov/~/media/Files/Planning%20and%20Research/CEQA/Adopted%20Thresholds %20Table_6_2_10.ashx

.87

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 10. Proposed Permit Conditions

The District is proposing the following permit conditions to ensure that the project complies with all applicable District, state, and federal Regulations. The proposed conditions would limit operational parameters such as fuel use, stack gas emission concentrations, and mass emission rates. The permit conditions also specify abatement device operation and performance levels. To aid enforcement efforts, conditions specifying emission monitoring, source testing, and record keeping requirements are included. Furthermore, pollutant mass emission limits (in units of lb/hr) will ensure that daily and annual emission rate limitations are not exceeded.

For the gas turbines and auxiliary boiler, compliance with CO and NO X limitations would be verified by continuous emission monitors (CEMs) that will be in operation during all turbine operating modes, including start-up, shutdown, and combustor tuning. Compliance with POC,

SO 2 , and PM 10 mass emission limits would be verified by source testing.

In addition to permit conditions that apply to steady-state operation of each gas turbine power train, the District is proposing conditions that govern equipment operation during the initial commissioning period when the gas turbine power trains will operate without their SCR systems and/or oxidation catalysts in place. Commissioning activities include, but are not limited to, the testing of the gas turbines and adjustment of control systems. Parts 1 through 10 of the proposed permit conditions for the combined-cycle gas turbines apply to this commissioning period and are intended to minimize emissions during the commissioning period.88

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

### Proposed Oakley Generating Station Permit Conditions

Definitions:

Hour: Any continuous 60

- minute period

Clock Hour: Any continuous 60

- minute period beginning on the hour

Cale ndar Day: Any continuous 24

- hour period beginning at 12:00 midnight or

0000 hours

Year: Any consecutive twelve

- month period of time

Rolling 3

- hour period: Any consecutive three

- clock hour period, not including start

- up or shutdown periods

Heat Input: Al l heat inputs refer to the heat input at the higher heating value (HHV) of the fuel, in BTU/scf

Firing Hours: Period of time during which fuel is flowing to a unit, measured

in hours

MMBtu: million British thermal units

Gas Turbine Cold Start

- up A gas t urbine startup that occurs more than 48 hours after a gas turbine shutdown, and is limited in time to the lesser of (i) the

first 90 minutes of continuous fuel flow to the Gas Turbine after fuel flow is initiated or (ii) the period of time from Gas Turbine

fuel flow initiation until the Gas Turbine achieves the first of two consecutive CEM data points in compliance with the emission concentration limits of Parts 16(b) and 16(d)

Gas Turbine Hot/Warm Start

up A gas turbine startup that occurs within 48 hours of a gas turbine shutdown, and is limited in time to the lesser of (i) the

first 30 minutes of continuous fuel flow to the Gas Turbine after fuel flow is initiated or (ii) the period of time from Gas Turbine

fuel flow initiation until the Gas Turbine achi eves the first of two consecutive CEM data points in compliance with the emission concentration limits of Parts 16(b) and 16(d)

Gas Turbine Shutdown: The lesser of the 30

- minute period immediately prior to the

termination of fuel flow to the Gas Turbine o r the period of

time from non

- compliance with any requirement listed in Parts 16(b) and 16(d) until termination of fuel flow to the Gas

Turbine

Gas Turbine Combustor Tuning: The period of time, not to exceed 6 operating hours per tuning event, in which te sting, adjustment, tuning, and calibration operations are performed, as recommended by the gas turbine manufacturer, to ensure safe and reliable steady

- state operation,

and to minimize NO X and CO emissions.89

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Specified PAHs: The polycyclic aromatic hydroca rbons listed below shall be considered to be Specified PAHs for these permit conditions. Any emission limits for Specified PAHs refer to the sum of the emissions for all six of the following compounds:

Benzo[a]anthracene Benzo[b]fluoranthene Benzo[k]fluora nthene Benzo[a]pyrene Dibenzo[a,h]anthracene Indeno[1,2,3

- cd]pyrene

Corrected Concentration: The concentration of any pollutant (generally NO X , CO, or

NH 3 ) corrected to a standard stack gas oxygen concentration. For emission points P

- 1, the exhaust of Gas Turbine (S

- 1), and

P

- 2, the exhaust of Gas Turbine (S

- 2), the standard stack gas oxygen concentration is 15% O 2 by volume on a dry basis. For emission point P

- 3, the exhaust of Auxiliary Boiler (S

- 3), the standard stack gas oxygen concentration is 3% O 2 b y volume on a dry basis.

Commissioning Activities: All testing, adjustment, tuning, and calibration activities recommended by the equipment manufacturers and the OGS construction contractor to ensure safe and reliable steady

- state operation of the gas tur bines, heat recovery steam generators, steam turbine, and associated electrical delivery systems during the commissioning period

Commissioning Period: The Commissioning Period shall commence when all mechanical, electrical, and control systems are install ed and individual system start

- up has been completed, or when a gas turbine is first fired, whichever occurs first. The Commissioning Period shall terminate when the plant has completed performance and emissions testing.

Precursor Organic Compounds (POCs) : Any compound of carbon, excluding methane, ethane, carbon monoxide, carbon dioxide, carbonic acid, metallic carbides or carbonates, and ammonium carbonate

CEC CPM: California Energy Commission Compliance Program Manager

OGS: Oakley Generating Station

Owner/operator: The owner/operator of Oakley Generating Station

Total Particulate Matter: The sum of all filterable and all condensable particulate matter.90

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

### GE 7FA Combined-Cycle Gas Turbines

Applicability:

Parts 1 through 10 of this condition shall only apply during the commissioning period as defined above. Unless otherwise indicated, Parts 11 through 30 of this condition shall apply after the commissioning period has ended.

Conditions for the Commissioning Period for GE 7FA Gas Turbines (S-1 and S-2)

1. The owner/operator shall minimize emissions of carbon monoxide and nitrogen oxides from S-1 and S-2 Gas Turbines to the maximum extent possible during the commissioning period. (Basis: BACT, Regulation 2, Rule 2, Section 409)

2. At the earliest feasible opportunity in accordance with the recommendations of the equipment manufacturers and the construction contractor, the owner/operator shall tune the

S-1 and S-2 Gas Turbines combustors to minimize the emissions of carbon monoxide and nitrogen oxides. (Basis: BACT, Regulation 2, Rule 2, Section 409)

3. At the earliest feasible opportunity in accordance with the recommendations of the equipment manufacturers and the construction contractor, the owner/operator shall install, adjust, and operate the A-2 and A-4 Oxidation Catalysts and A-1 and A-3 SCR Systems to

mi nimize the emissions of carbon monoxide and nitrogen oxides from S-1 and S-2 Gas Turbines. (Basis: BACT, Regulation 2, Rule 2, Section 409)

4. The owner/operator shall submit a plan to the District Engineering Division and the CEC CPM at least four weeks prior to first firing of S-1 and S-2 Gas Turbines describing the procedures to be followed during the commissioning of the gas turbines. The plan shall include a description of each commissioning activity, the anticipated duration of each activity in hours, and the purpose of the activity. The activities described shall include, but not be limited to, the tuning of the Dry-Low- NO X combustors, the installation and operation of the required emission control systems, the installation, calibration, and testing of the CO and

NO X continuous emission monitors, and any activities requiring the firing of the Gas Turbines (S-1 and S-2) without abatement by their respective oxidation catalysts and/or SCR Systems. The owner/operator shall not fire any of the Gas Turbines (S-1 or S-2) sooner than 28 days after the District receives the commissioning plan. (Basis: Regulation 2, Rule 2, Section 419)

5. During the commissioning period, the owner/operator shall demonstrate compliance with Parts 7, 8, and 9 through the use of properly operated and maintained continuous emission monitors and data recorders for the following parameters and emission concentrations:

firing hours

fuel flow rates stack gas nitrogen oxide emission concentrations stack gas carbon monoxide emission concentrations stack gas oxygen concentrations

The monitored parameters shall be recorded at least once every 15 minutes (excluding normal calibration periods or when the monitored source is not in operation) for the Gas91

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Turbines (S-1 and S-2). The owner/operator shall use District-approved methods to calculate heat input rates, nitrogen dioxide mass emission rates, carbon monoxide mass emission rates,

and NO X and CO emission concentrations, summarized for each clock hour and each calendar day. The owner/operator shall retain records on site for at least 5 years from the date of entry and make such records available to District personnel upon request. (Basis: Regulation 2, Rule 2, Section 419)

6. The owner/operator shall install, calibrate, and operate the District-approved continuous monitors specified in Part 5 prior to first firing of the Gas Turbines (S-1 and S-2). After first firing of the turbines, the owner/operator shall adjust the detection range of these continuous emission monitors as necessary to accurately measure the resulting range of CO and NO Xemission concentrations. The instruments shall operate at all times of operation of S-1 and S2 including start-up, shutdown, upset, and malfunction, except as allowed by BAAQMD Regulation 1-522, BAAQMD Manual of Procedures, Volume V. If necessary to comply with this requirement, the owner/operator shall install dual-span monitors. The type, specifications, and location of these monitors shall be subject to District review and approval. (Basis: Regulation 2, Rule 2, Section 419)

7. The owner/operator shall not fire S-1 and S-2 Gas Turbine without abatement of nitrogen oxide emissions by the corresponding SCR System A-1 and A-3 and/or abatement of carbon monoxide emissions by the corresponding Oxidation Catalyst A-2 and A-4 for more than a combined total of 831 hours during the commissioning period. Such operation of any Gas Turbine (S-1, S-2) without abatement shall be limited to discrete commissioning activities that can only be properly executed without the SCR system and/or oxidation catalyst in place. Upon completion of these activities, the owner/operator shall provide written notice to the District Engineering and Enforcement Divisions and the unused balance of the 831 firing hours without abatement shall expire. (Basis: BACT, Regulation 2, Rule 2, Section 409)

8. The total mass emissions of nitrogen oxides, carbon monoxide, precursor organic compounds, PM 10 , and sulfur dioxide that are emitted by the Gas Turbines (S-1, and S-2) during the commissioning period shall accrue towards the consecutive twelve-month emission limitations specified in Part 43. (Basis: Regulation 2, Rule 2, Section 409)

9. The owner/ operator shall not operate the Gas Turbines (S-1 and S-2) in a manner such that the pollutant emissions from each gas turbine will exceed the following limits during thecommissioning period. These emission limits shall include emissions resulting from the startup and shutdown of the Gas Turbines (S-1, S-2). (Basis: BACT, Regulation 2, Rule 2, Section 409)

NO X (as NO 2 ) 2,380.8 pounds per calendar day 148.7 pounds per hour

CO 13,303 pounds per calendar day 700 pounds per hour

10. Within 90 operating days after first fire of each Gas Turbine, the owner/operator shall conduct District- and CEC-approved source tests for that Gas Turbine to determine compliance with the emission limitations specified in Part 17. The source tests shall

determine NO X , CO, and POC emissions during start-up and shutdown of the gas turbines. The POC emissions shall be analyzed for methane and ethane to account for the presence of unburned natural gas. The source test shall include a minimum of three start-up and three shutdown periods. Thirty working days before the execution of the source tests, the92

Preliminary Determination of Compliance, October 2010

Oakley Generating Station owner/operator shall submit to the District and the CEC Compliance Program Manager (CPM) a detailed source test plan designed to satisfy the requirements of this Part. The District and the CEC CPM will notify the owner/operator of any necessary modifications to the plan within 20 working days of receipt of the plan; otherwise, the plan shall be deemed approved. The owner/operator shall incorporate the District and CEC CPM comments into the test plan. The owner/operator shall notify the District and the CEC CPM within seven (7) working days prior to the planned source testing date. The owner/operator shall submit the source test results to the District and the CEC CPM within 60 days of the source testing date. (Basis: Regulation 2, Rule 2, Section 419)

Cond itions for the GE 7FA Combined-Cycle Gas Turbines (S-1 and S-2)

11. The owner/operator shall fire the Gas Turbines (S-1 and S-2) exclusively on PUC regulated natural gas with a maximum sulfur content of 1 grain per 100 standard cubic feet. To demonstrate compliance with this limit, the operator of S-1 and S-2 shall sample and analyze the gas from each supply source at least monthly to determine the sulfur content of the gas. PG&E monthly sulfur data may be used provided that such data can be demonstrated to be representative of the gas delivered to the OGS. (Basis: BACT for SO 2 and PM 10 )

12. The owner/operator shall not operate the units such that the heat input rate to each Gas Turbine (S-1 and S-2) exceeds 2,150 MMBtu (HHV) per hour. (Basis: BACT for NO X )

13. The owner/operator shall not operate the units such that the heat input rate to each Gas Turbine (S-1 and S-2) exceeds 51,600 MMBtu (HHV) per day. (Basis: Cumulative Increase

for PM 10 )

14. The owner/operator shall not operate the units such that the combined cumulative heat input rate for the Gas Turbines (S-1 and S-2) exceeds 35,397,277 MMBtu (HHV) per year. (Basis: Offsets)

15. The owner/operator shall ensure that each Gas Turbine (S-1, S-2) is abated by the properly operated and properly maintained Selective Catalytic Reduction (SCR) System A-1 or A- 3 and Oxidation Catalyst System A-2 or A-4 whenever fuel is combusted at those sources and the corresponding SCR catalyst bed (A-1 or A-3) has reached minimum operating temperature. (Basis: BACT for NO X , POC and CO)

16. The owner/operator shall ensure that the Gas Turbines (S-1, S-2) comply with the following limits. The limits in this part do not apply during a gas turbine start-up, combustor tuning operation or shutdown. (Basis: BACT and Regulation 2, Rule 5)

a) Nitrogen oxide mass emissions (calculated as NO 2 ) at each exhaust point P-1 and P-2 (exhaust point for S-1 and S-2 Gas Turbine after abatement by A- 1 and A-3 SCR System) shall not exceed 15.52 pounds per hour, averaged over any 1-hour period. (Basis: Cumulative Increase for NO X )

b) The nitrogen oxide emission concentration at each exhaust point P-1 and P- 2 shall not exceed 2.0 ppmv, on a dry basis, corrected to 15% O 2 , averaged over any 1-hour period. (Basis: BACT for NO X )93

Preliminary Determination of Compliance, October 2010

Oakley Generating Station c) Carbon monoxide mass emissions at each exhaust point P-1 and P-2 shall not exceed 9.45 pounds per hour, averaged over any 1-hour period. (Basis: Cumulative Increase for CO)

d) The carbon monoxide emission concentration at each exhaust point P-1 and P2 shall not exceed 2.0 ppmv, on a dry basis, corrected to 15% O 2 averaged over any 1-hour period. (Basis: BACT for CO)

e) Ammonia (NH 3 ) emission concentrations at each exhaust point P-1 and P- 2 shall not exceed 5 ppmv, on a dry basis, corrected to 15% O 2 , averaged over any rolling 3-hour period. This ammonia emission concentration shall be verified by the continuous recording of the ammonia injection rate to each SCR System A-1 and A-3. The correlation between the gas turbine heat input

ra tes, A-1 and A-3 SCR System ammonia injection rates, and corresponding

a mmonia emission concentration at emission points P-1 and P-2 shall be determined in accordance with Part 25 or a District approved alternative method. (Basis: Regulation 2, Rule 5)

f) Precursor organic compound (POC) mass emissions (as CH 4 ) at each exhaust point P-1 and P-2 shall not exceed 2.71 pounds per hour. (Basis: Cumulative Increase for POC)

17. The owner/operator shall ensure that the regulated air pollutant mass emission rates from each of the Gas Turbines (S-1, and S-2) during a start-up or shutdown does not exceed the

lim its established below. (Basis: BACT Limit for Non-Steady-State Operation)

Pollutant Hot/Warm

Startup (lb/startup) Maximum

Emissions During an

Hour Containing

a Hot/Warm Startup (lb/hr) Maximum

Emissions

Per

Cold Startup (lb/startup) Maximum

Emissions

Duri ng an Hour Containing

a Cold Startup (lb/hr) Maximum

Emissions

Per

Shutdown (lb/shutdown) Maximum

Emissions During an

Hour Containing

a Shutdown (lb/hr)

NO X (as

NO 2 ) 22.3 33.9 96.3 99.9 39.3 46.8

CO 85.2 92.2 360.2 362.4 140.2 144.7

POC (as

CH 4 ) 31.1 33 .1 67.1 67.7 17.1 18.4

18. The owner/operator shall not perform combustor tuning on each Gas Turbine (S-1 or S-2) more than twice in any consecutive 12 month period. Each tuning event shall not exceed

6 hours. Combustor tuning shall only be performed on one gas turbine per day. The owner/operator shall notify the District no later than 7 days prior to combustor tuning activity. The emissions during combustor tuning from each gas turbine shall not exceed the hourly limits established below, and shall not exceed hourly limits established by the District based on emissions data obtained during the first tuning event for each turbine. The94

Preliminary Determination of Compliance, October 2010

Oakley Generating Station owner/operator shall measure and record mass emissions of NOx and CO using the continuous emission monitors during tuning. Th e owner/operator shall measure POC emissions during the first tuning after the first turbine has been commissioned using a District-approved source test method. The owner/operator shall submit the record of the

NOx

, CO , and POC emissions during the first tuning event after the first turbine has been commissioned to the District within 60 days after the first tuning event. The District shall establish mass emissions limits for the future tuning events based on this test data and shall notify the owner/operator of these limits. (Basis: BACT, Offsets, Cumulative Increase)

Pollutant Emissions Limit ( lb/hr )

NO X (as NO 2 ) 96

CO 360

POC (as CH 4 ) 67

19. The owner/operator shall not allow total emissions from each Gas Turbine (S-1 or S-2), including emissions generated during gas turbine start-ups, and shutdowns to exceed the following limits during any calendar day (except for days during which combustor tuning events occur, which are subject to Part 20 below):

a) 488 pounds of NO X (as NO 2 ) per day (Basis: Cumulative Increase)

b) 715 pounds of CO per day (Basis: Cumulative Increase)

c) 146 pounds of POC (as CH 4 ) per day (Basis: Cumulative Increase)

20. The owner/operator shall not allow total emissions from each Gas Turbine (S-1 or S-2), including emissions generated during gas turbine start-ups, shutdowns, and combustor tuning events to exceed the following limits during any calendar day on which a tuning event

occurs:

a) 97 1 pounds of NO X (as NO 2 ) per day (Basis: Cumulative Increase)

b) 2818 pounds of CO per day (Basis: Cumulative Increase)

c) 53 1 pounds of POC (as CH 4 ) per day (Basis: Cumulative Increase)

21. The owner/operator shall not allow the maximum projected annual toxic air contaminant emissions (per Part 24) from the Gas Turbines (S-1, S-2) combined to exceed the following

limits:

Formaldehyde 16,636.1 pounds per year Benzene 462.9 pounds per year Specified polycyclic aromatic hydrocarbons (PAHs) 4.54 pounds per year

unless the following requirement is satisfied:

The owner/operator shall perform a health risk assessment to determine the total facility risk using the emission rates determined by source testing and the most current Bay Area Air Quality Management District approved procedures and unit risk factors in effect at the time of the analysis. The owner/operator shall submit the risk analysis to the District and the CEC95

Preliminary Determination of Compliance, October 2010

Oakley Generating Station CPM within 60 days of the source test date. The owner/operator may request that the District and the CEC CPM revise the carcinogenic compound emission limits specified above. If the owner/operator demonstrates to the satisfaction of the APCO that these revised emission limits will not result in a significant cancer risk, the District and the CEC CPM may, at their discretion, adjust the carcinogenic compound emission limits listed above. (Basis : Regulation 2, Rule 5)

22. The owner/operator shall demonstrate compliance with Parts 12 through 14, 16(a) through 16(d), 17 (NO X , and CO limits), 18 (NO X and CO limits), 19(a), 19(b), 20(a), 20(b), 43(a)

a nd 43(b) by using properly operated and maintained continuous monitors (during all hours

of operation including gas turbine start-up, combustor tuning, and shutdown periods). If necessary to comply with this requirement, the owner/operator shall install dual-span monitors. The owner/operator shall monitor for all of the following parameters and record each parameter at least every 15 minutes (excluding normal calibration periods):

a) Firing Hours and Fuel Flow Rates for each of the following sources: S-1 and S-2

b) Ox ygen (O 2 ) concentration, Nitrogen Oxides (NO X ) concentration, and carbon monoxide (CO) concentration at exhaust points P-1 and P-2

c) Ammoni a injection rate at A-1 and A-2 SCR Systems

The owner/operator shall use the parameters measured above and District approvedcalculation methods to calculate and record the following parameters for each gas turbine (S1 and S-2):

d) Corrected NO X concentration and corrected CO concentration, averaged for each

clock hour

e) Corrected NO X concentration and corrected CO concentration, averaged for each calendar day

The owner/operator shall use the parameters measured above and District-approvedcalculation methods to calculate and record the following parameters for each gas turbine (S1 and S-2) and totaled for S-1 and S-2:

f) For each rolling three hour period, the heat input rate in MMBtu (HHV) per hour

g) For each calendar day, the average hourly heat input rate in MMBtu (HHV) per hour and total daily heat input rate in MMBtu (HHV) per day

h) For each consecutive twelve month period, the total heat input rate in MMBtu (HHV)

per year

i) For each clock hour, the NO X mass emission rate (as NO 2 ) and CO mass emissions rate in pounds per hour

j) For each calendar day, the NO X mass emission rate (as NO 2 ) and CO mass emissions rate in pounds per day

k) For each consecutive 12-month period, the monthly NO X (as NO 2 ) and CO mass emissions rates in pounds per month and annual NO X and CO mass emissions rates in pounds per year and tons per year

(Basis: 1-520.1, 9-9-501, BACT, Offsets, NSPS, Cumulative Increase)96

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 23. To demonstrate compliance with Parts 16(f), 19(c), 20(c), and 43(c) the owner/operator shall

c alculate and record on a daily basis, the precursor organic compound (POC) mass emissions from each power train. The owner/operator shall use the actual heat input rates measured pursuant to Part 22, actual Gas Turbine start-up times, actual Gas Turbine shutdown times, and CEC and District-approved emission factors developed pursuant to source testing under Part 26 to calculate these emissions. The owner/operator shall present the calculated emissions in the following format:

a) For each calendar day, POC mass emissions, summarized for each gas turbine and S1 and S-2 combined

b) For each consecutive 12-month period, the cumulative total POC mass emissions for each gas turbine and S-1 and S-2 combined.

(Basis: Offsets, Cumulative Increase)

24. To demonstrate compliance with Part 21, the owner/operator shall calculate and record on an annual basis the maximum projected annual emissions of: Formaldehyde, Benzene, and Specified PAHs. The owner/operator shall calculate the maximum projected annual emissions using the combined maximum annual heat input rate of 35,397,277 MMBtu/year for S-1 and S-2 combined and the highest emission factor (pounds of pollutant per MMBtu of heat input) determined by the most recent of any source test of the S-1 or S-2 Gas Turbines. If the highest emission factor for a given pollutant occurs during minimum-load turbine operation, a reduced annual heat input rate may be utilized to calculate the maximum projected annual emissions to reflect the reduced heat input rates during gas turbine start-up and minimum-load operation. The reduced annual heat input rate shall be subject to District review and approval. (Basis: Regulation 2, Rule 5)

25. Within 90 operating days of first fire of each of the OGS GE 7FA units, the owner/operator shall conduct a District-approved source test on each corresponding exhaust point P-1 or P- 2 to determine the corrected ammonia (NH 3 ) emission concentration to determine compliance with Part 16(e). The source test shall determine the correlation between the heat input rates of the gas turbine, A-1 or A-3 SCR System ammonia injection rate, and the corresponding NH 3 emission concentration at emission point P-1 or P-2. The source test shall be conducted over the expected operating range of the turbine (including, but not limited to, minimum and full load modes) to establish the range of ammonia injection rates necessary to achieve NO X emission reductions while maintaining ammonia slip levels. The owner/operator shall repeat the source testing on an annual basis thereafter. Ongoing compliance with Part 16(e) shall be demonstrated through calculations of corrected ammonia concentrations based upon the source test correlation and continuous records of ammonia injection rate. The owner/operator shall submit the source test results to the District and the CEC CPM within 60 days of conducting the tests. (Basis: Regulation 2, Rule 5)

26. Within 90 operating days of first fire of each of the OGS GE 7FA units and, at a minimum, on an annual basis thereafter, the owner/operator shall conduct a District-approved source test on exhaust points P-1 and P-2 while each Gas Turbine is operating at maximum load to determine compliance with Parts 16(a), 16(b), 16(c), 16(d), 16(f), and to establish the emissions factors to be used to demonstrate compliance with Parts 43(d) and 43(e); and while

e ach Gas Turbine is operating at minimum load to determine compliance with Parts 16(c) and 16(d); and to verify the accuracy of the continuous emission monitors required in Part97

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 22. The owner/operator shall test for (as a minimum each year): water content, stack gas flow rate, oxygen concentration, precursor organic compound concentration and mass emissions, nitrogen oxide concentration and mass emissions (as NO 2 ), carbon monoxide concentration and mass emissions, sulfur dioxide concentration and mass emissions, methane, ethane, and

PM 10 emissions including condensable particulate matter. The owner/operator may conduct source tests of individual compounds listed in this part separately. The owner/operator shall submit the source test results to the District and the CEC CPM within 60 days of conducting the tests. The owner/operator may perform up to four tests per year for PM 10 emissions including condensable particulate matter. (Basis: BACT, Offsets, Cumulative Increase)

27. The owner/operator shall obtain approval for all source test procedures from the District’s Source Test Section and the CEC CPM prior to conducting any tests. The owner/operator shall comply with all applicable testing requirements for continuous emission monitors as specified in Volume V of the District’s Manual of Procedures. The owner/operator shall notify the District’s Source Test Section and the CEC CPM in writing of the source test protocols and projected test dates at least 7 days prior to the testing date(s). As indicated above, the Owner/Operator shall measure the contribution of condensable PM (back half) to any measurement of the total particulate matter or PM 10 emissions. However, the Owner/Operator may propose alternative measuring techniques to measure condensable PM such as the use of a dilution tunnel or other appropriate method used to capture semi-volatile organic compounds. The owner/operator shall submit the source test results to the District and the CEC CPM within 60 days of conducting the tests. (Basis: BACT, Regulation 2, Rule 2, Section 419)

28. Within 90 operating days of first fire of the second of the OGS GE 7FA gas turbines and on abiennial basis (once every two years) thereafter, the owner/operator shall conduct a Districtapproved source test on one of the following exhaust points P-1 or P-2 while the Gas Turbine is operating at maximum allowable operating rates to demonstrate compliance with Part 21. The owner/operator shall also test the gas turbine while it is operating at minimum load. If

three consecutive biennial source tests demonstrate that the annual emission rates calculated pursuant to Part 24 for any of the compounds are less than 50% of the levels listed in Part 21, then the owner/operator may discontinue future testing for that pollutant. (Basis: Regulation 2, Rule 5)

29. Within 90 days of start-up of each of the OGS GE 7FA gas turbines and on an annual basis thereafter, the owner/operator shall conduct a District-approved source test on one of the two exhaust points P-1 or P-2 while the gas turbine is operating at maximum heat input rate to demonstrate compliance with the total sulfuric acid mist emission rate for S-1 and S-2 of 6.3 tons per year. The owner/operator shall test for (as a minimum) SO 2 , SO 3 , and H 2 SO 4 , and the sulfur content of the fuel. The owner/operator shall submit the source test results to the District and the CEC CPM within 60 days of conducting the tests. (Basis: Regulation 2, Rule 5)

30. The owner/operator shall ensure that the stack height of emission points P-1 and P-2 is each at least 155.5 feet above grade level at the stack base. (Basis: Regulation 2, Rule 5)98

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

### Auxiliary Boiler (S- 3)

31. The owner/operator shall submit manufacturer’s specifications and emissions guarantees for

NO

x and CO for the Auxiliary Boiler (S-3) to the District Engineering Division and the CEC CPM at least four weeks prior to first firing of Auxiliary Boiler (S-3). (Basis: Regulation 2, Rule 2, Section 419)

32. If Oxidation Catalyst (A-5) is required, the owner/operator shall install, adjust, and operate the A-5 Oxidation Catalyst at the earliest feasible opportunity, in accordance with the recommendations of the equipment manufacturers and the construction contractor, to minimize the emissions of carbon monoxide from S-3 Auxiliary Boiler. (Basis: Regulation 2, Rule 2, Section 419)

33. The heat input rate to the Auxiliary Boiler (S-3) shall not exceed 50.6 MMBtu per hour, averaged over any rolling 3-hour period. (Basis: Cumulative Increase)

34. The heat input rate to the Auxiliary Boiler (S-3) shall not exceed 218,606 MMBtu per year. (Basis: Cumulative Increase)

35. The owner/operator of the Auxiliary Boiler (S-3) shall meet all of the requirements listed in

below.

a) Nitrogen oxide emissions at P-3 (the exhaust point for the Auxiliary Boiler)

shall not exceed 9.8 pounds per day, calculated as NO 2 . (Basis: Regulation 2-

1 -403)

b) Carbon monoxide emissions at P-3 shall not exceed 9.8 pounds per day. (Basis: Regulation 2-1-403)

c) P OC emissions at P-3 shall not exceed 2.8 pounds per day. (Basis: Regulation

2 -1 -403)

36. The owner/operator shall demonstrate compliance with Parts 35(a), 35(b) and 43(a) and 43(b) by using properly operated and maintained continuous monitors (during all hours of operation including auxiliary boiler start-up, tuning, and shutdown periods). The owner/operator shall monitor for all of the following parameters and record each parameter at least every 15 minutes (excluding normal calibration periods):

a) Firing Hours and Fuel Flow Rates

b) Oxygen (O 2 ) concentration, Nitrogen Oxides (NO X ) concentration, and carbon monoxide (CO) concentration at exhaust point P-3

The owner/operator shall use the parameters measured above and District approved calculation methods to calculate and record the following parameters for the Auxiliary Boiler (S -3):

c) Corrected NO X concentration and corrected CO concentration, averaged for each

clock hour

d) Corrected NO X concentration and corrected CO concentration, averaged for each calendar day99

Preliminary Determination of Compliance, October 2010

Oakley Generating Station The owner/operator shall use the parameters measured above and District-approved calculation methods to calculate and record the following parameters for Auxiliary Boiler (S -3):

e) For each rolling three hour period, the heat input rate in MMBtu (HHV) per hour

f) For each calendar day, the average hourly heat input rate in MMBtu (HHV) per hour and total daily heat input rate in MMBtu (HHV) per day

g) For each consecutive twelve month period, the total heat input rate in MMBtu (HHV)

per year

h) For each clock hour, the NO X mass emission rate (as NO 2 ) and CO mass emissions rate in pounds per hour

i) For each calendar day, the NO X mass emission rate (as NO 2 ) and CO mass emissions rate in pounds per day

j) For each consecutive 12-month period, the monthly NO X (as NO 2 ) and CO mass emissions rates in pounds per month and annual NO X (as NO 2 ) and CO mass emissions rates in pounds per year and tons per year

(Basis: 1-520.1, 9-7-307, BACT, Offsets, Cumulative Increase)

37. To demonstrate compliance with Part 35(c) the owner/operator shall calculate and record on a daily basis, the precursor organic compound (POC) mass emissions from the auxiliary boiler. The owner/operator shall use the actual heat input rates measured pursuant to Part 36, and CEC and District-approved emission factors developed pursuant to source testing under Part 38 to calculate these emissions. The owner/operator shall present the calculated

e missions in the following format:

a) For each calendar day, POC mass emissions, summarized for S-3

b) For each consecutive 12-month period, the cumulative total POC mass emissions for

S-3.

(Basis: Offsets, Cumulative Increase)

38. Within 90 operating days after first fire of Auxiliary Boiler (S-3), the owner/operator shall conduct a District-approved source test on exhaust point P-3 while the auxiliary boiler is operating at maximum load to determine emission factors for POC, PM 10 and SO

x . The owner/operator shall test for (as a minimum): water content, stack gas flow rate, oxygen concentration, precursor organic compound concentration and mass emissions, nitrogen oxide concentration and mass emissions (as NO 2 ), carbon monoxide concentration and mass emissions, sulfur dioxide concentration and mass emissions, methane, ethane, and PM 10 emissions including condensable particulate matter. Thirty working days before the execution of the source tests, the owner/operator shall submit to the District and the CEC Compliance Program Manager (CPM) a detailed source test plan designed to satisfy the requirements of this Part. The District and the CEC CPM will notify the owner/operator o f any necessary modifications to the plan within 20 working days of receipt of the plan; otherwise, the plan shall be deemed approved. The owner/operator shall incorporate the District and CEC CPM comments into the test plan. The owner/operator shall notify the District and the CEC CPM within seven (7) working days prior to the planned source testing100

Preliminary Determination of Compliance, October 2010

Oakley Generating Station date. The owner/operator shall submit the source test results to the District and the CEC CPM within 60 days of the source testing date. (Basis: Regulation 2, Rule 2, Section 419)

Conditions for the Fire Pump Diesel Engine (S-4)

39. The owner/operator shall fire the Fire Pump Diesel Engine (S-4) exclusively on diesel fuel having a sulfur content no greater than 0.0015% by weight. (Regulation 2, Rule 5, Cumulative Increase, "Stationary Diesel Engine ATCM", CA Code of Regulations, Title 17, Section 93115.5(a))

40. The owner/operator shall operate the Fire Pump Diesel Engine (S-4) for no more than 49 hours per year for the purpose of reliability testing and non-emergency operation. (Regulation 2, Rule 5, Cumulative Increase, "Stationary Diesel Engine ATCM", CA Code of Regulations, Title 17, Section 93115.6(a)(4)(A))

41. The owner/operator shall operate the Fire Pump Diesel Engine (S-4) only when a nonresettable totalizing hour meter (with a minimum display capability of 9,999 hours) is installed, operated and properly maintained. (Basis: BAAQMD Regulation 9-8-530,

" Stationary Diesel Engine ATCM", CA Code of Regulations, Title 17, Section 93115.10(e)(1))

42. The owner/operator shall maintain the following monthly records for Fire Pump Engine (S-4) in a District-approved log for at least 5 years.

a. Hours of operation for reliability-related activities (maintenance and testing).

b. Hours of operation for emission testing to show compliance with emission limits.

c. Hour s of operation for emergency use.

d. For each emergency, the nature of the emergency condition.

e. Fuel usage.

Log entries shall be retained on-site, either at a central location or at the engine's location, and made immediately available to the District staff upon request. (Basis: BAAQMD Regulation 9-8-530, "Stationary Diesel Engine ATCM", CA Code of Regulations, Title 17, Section 93115.10(g))

Conditions for the Combined-Cycle Gas Turbines (S-1 and S-2), Auxiliary Boiler (S-3), and Fire Pump Engine (S-4)

43. The owner/operator shall not allow total combined emissions from the Gas Turbines (S-1 and S-2), including emissions generated during gas turbine start-ups, combustor tuning, shutdowns, and malfunctions, the auxiliary boiler (S-3), including emissions generated during auxiliary boiler start-ups, tune-ups, shutdowns, and malfunctions, and the fire pump diesel engine (S-4), including non-emergency and emergency operation, to exceed the following limits during any consecutive twelve-month period:

a) 98.78 tons of NO

x (as NO 2 ) (Basis: Offsets)

b) 98.82 tons of CO (Basis: Cumulative Increase)

c) 29.49 tons of POC (as CH 4 ) (Basis: Offsets)101

Preliminary Determination of Compliance, October 2010

Oakley Generating Station d) 63.78 tons of PM 10 (Basis: Cumulative Increase)

e) 12.55 tons of SO 2 (Basis: Cumulative Increase)

Compliance with the limits in this part shall be determined using the following procedures:

Emissions of PM 10 and SO 2 from each gas turbine shall be calculated by multiplying turbine fuel usage times an emission factor determined by source testing of the turbine conducted in accordance with Part 26. The emission factor for each turbine shall be based on the average of the emissions rates observed during the 4 most recent source tests on that turbine (or, prior to the completion of 4 source tests on a turbine, on the average of the emission rates observed during all source tests on the turbine).

Emissions of PM 10 , SO 2 , and POC from the auxiliary boiler shall be calculated by multiplying auxiliary boiler fuel usage times an emission factor determined by source testing of the auxiliary boiler conducted in accordance with Part 38.

The owner/operator shall calculate emissions from the fire pump diesel engine from the hours of operation recorded in Part 42 and the following emission factors:

NO

x : 2.62 g/hp-hr

CO : 0.67 g/hp-hr

POC: 0.14 g/hp-hr

PM: 0.119 g/hp-hr

SO

x : 0.004 g/hp-hr

44. To demonstrate compliance with Part 43, the owner/operator shall record the total emissions for each consecutive 12-month period. The owner/operator shall calculate emissions of each pollutant listed in Part 43(a) through (e) from the gas turbines, auxiliary boiler, and fire pump diesel engine for each calendar month using the calculation procedures established in Part 43, and shall calculate annual emissions to determine compliance with the limits listed in Part 43(a) through (e) by summing the monthly totals for the previous 12 months. (Basis: Regulation 2, Rule 2, Section 419)

45. The owner/operator shall submit all reports (including, but not limited to monthly CEM reports, monitor breakdown reports, emission excess reports, equipment breakdown reports, etc.) as required by District Rules or Regulations and in accordance with all procedures and time limits specified in the Rule, Regulation, Manual of Procedures, or Enforcement Division Policies & Procedures Manual. (Basis: Regulation 2, Rule 1, Section 403)

46. The owner/operator shall maintain all records and reports on site for a minimum of 5 years. These records shall include but are not limited to: continuous monitoring records (firing hours, fuel flows, emission rates, monitor excesses, breakdowns, etc.), source test and analytical records, natural gas sulfur content analysis results, emission calculation records, records of plant upsets and related incidents. The owner/operator shall make all records and reports available to District and the CEC CPM staff upon request. (Basis: Regulation 2, Rule 1, Section 403, Regulation 2, Rule 6, Section 501)

47. The owner/operator shall notify the District and the CEC CPM of any violations of these permit conditions. Notification shall be submitted in a timely manner, in accordance with all102

Preliminary Determination of Compliance, October 2010

Oakley Generating Station applicable District Rules, Regulations, and the Manual of Procedures. Notwithstanding the notification and reporting requirements given in any District Rule, Regulation, or the Manual of Procedures, the owner/operator shall submit written notification (facsimile is acceptable) to the Enforcement Division within 96 hours of the violation of any permit condition. (Basis: Regulation 2, Rule 1, Section 403)

48. The owner/operator shall provide adequate stack sampling ports and platforms to enable the performance of source testing. The location and configuration of the stack sampling ports shall comply with the District Manual of Procedures, Volume IV, Source Test Policy and Procedures, and shall be subject to BAAQMD review and approval, except that the facility shall provide four sampling ports that are at least 6 inches in diameter in the same plane of each gas turbine stack (P-1, P-2). (Basis: Regulation 1, Section 501)

49. Within 180 days of the issuance of the Authority to Construct for the OGS, the owner/operator shall contact the BAAQMD Technical Services Division regarding requirements for the continuous emission monitors, sampling ports, platforms, and source tests required by Parts 10, 25, 26, 28, 29, 38, and 39. The owner/operator shall conduct all source testing and monitoring in accordance with the District approved procedures. (Basis: Regulation 1, Section 501)

50. The owner/operator shall ensure that the OGS complies with the continuous emission monitoring requirements of 40 CFR Part 75. (Basis: Regulation 2, Rule 7)103

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 11. Preliminary Determination

The APCO has made a preliminary determination that the proposed Oakley Generating Station power plant, which is composed of the permitted sources listed below, complies with all applicable District, state and federal air quality rules and regulations. The following sources will be subject to the permit conditions and BACT and offset requirements discussed previously.

S-1 Gas Turbine Generator #1, GE Frame 7FA, Natural Gas-Fired, 213 MW, 2150 MMBtu/hr (HHV) maximum rated capacity with high-efficiency inlet air filter; abated by A-1 Selective Catalytic Reduction System (SCR) and A-2 Oxidation Catalyst

S-2 Gas Turbine Generator #2, GE Frame 7FA, Natural Gas-Fired, 213 MW, 2150 MMBtu/hr (HHV) maximum rated capacity with high-efficiency inlet air filter; abated by A-3 Selective Catalytic Reduction System (SCR) and A-4 Oxidation Catalyst

S-3 Auxiliary Boiler, Natural Gas-Fired, 50.6 MMBtu/hr (HHV) maximum rated capacity (abated by A-5 Oxidation Catalyst if required)

S-4 Fire Pump Diesel Engine, Clarke JW6H-UFAD80, 400 hp, 2.78 MMBtu/hr maximum rated heat input

S-5 Evaporative Fluid Cooler, 3-Cell, 5,880 gallons per minute (Exempt from District Permit requirements per Regulation 2, Rule 1, Section 128.4)

S-6 Oil-Water Separator, 120 gallons per hour (Exempt from District Permit requirements per Regulation 2, Rule 1, Section 103 and Regulation 8, Rule 8, Section 113)

This document is subject to the public notice, public comment, and public inspection requirements of District Regulations 2-2-405 and 2-2-406. Accordingly, a notice inviting written publi c comment will be published in a newspaper of general circulation in the area of the proposed Oakley Generating Station and mailed to certain entities. The public inspection and comment period will be at least 30 days in duration and will start the date of such publication.

Written comments on this document should be directed to:

Kathleen Truesdell Air Q uality Engineer II Bay Area Air Quality Management District

939 Ellis Street

San Francisco CA 94109 ktruesdell@baaqmd.gov104

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## 12. Glossary of Acronyms

AAQS Ambient Air Quality Standard

ARB Air Resource Board

BTU British Thermal Unit BAAQMD Bay Area Air Quality Management District

BACT Best Available Control Technology

Cal ISO California Independent System Operator

CAISO California Independent System Operator

CARB California Air Resources Board

CEC California Energy Commission

CEM Continuous Emission Monitor CEQA California Environmental Quality Act

CO Carbon Monoxide

CO 2 Carbon Dioxide

CPUC California Public Utilities Commission

CTG Combustion Turbine Generator

EO/APCO Executive Officer/Air Pollution Control Officer

EPA Environmental Protection Agency

ERC Emission Reduction Credit

FDOC Final Determination of Compliance

FSNL Full Speed No Load

GE General Electric Company

GHG Greenhouse Gases

GT Gas Turbine

MW Megawatt

NH 3 Ammonia

N 2 Nitrogen

NO Nitric Oxide

NO 2 Nitrogen Dioxide

NO

x Nitrogen Oxides

NSR New Source Review

O 2 Oxygen

OGS Oakley Generating Station

LAER Lowest Achievable Emissions Rate

LLC Limited Liability Company

MMBtu Million Btu NAAQS National Ambient Air Quality Standard

PAH Polycyclic Aromatic Hydrocarbon

PDOC Preliminary Determination of Compliance

PG&E Pacific Gas & Electric Company

PM 10 Particulate Matter less than 10 Microns in Diameter

PM 2.5 Particulate Matter less than 2.5 Microns in Diameter

POC Precursor Organic Compounds ppmvd Parts Per Million by Volume, Dry105

Preliminary Determination of Compliance, October 2010

Oakley Generating Station PSD Prevention of Significant Deterioration

PUC Public Utilities Commission

RACT Reasonably Available Control Technology

RATA Relative Accuracy Test Audit SCAQMD South Coast Air Quality Management District

SNCR Selective Non -catalytic Reduction

SCR Selective Catalytic Reduction

SJVAPCD San Joaquin Valley Air Pollution Control District

SO 2 Sulfur Dioxide

SO

x Sulfur Oxides

TAC Toxic Air Contaminant

TBACT Toxics Best Available Control Technology

U.S. EPA United States Environmental Protection Agency

VOC Volatile Organic Compounds106

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## Appendix A

Emission Calculations107

Preliminary Determination of Compliance, October 2010

Oakley Generating StationThe following physical constants and standard conditions were utilized to derive the criteriapollutant emission factors used to estimate and verify criteria pollutant and toxic air contaminant emissions submitted in the permit application. The criteria emission calculations were prepared by the applicant’s consultant and are based on a combustion model. The District has verified these values using the calculations shown below. For the toxic air contaminants the District revised the calculation submitted by the applicant.

standard temperature a : 70 o F standard pressure a : 14.7 psia

molar volume: 386.8 dscf/lbmol ambient oxygen concentration: 20.95%

dry flue gas factor b : 8743 dscf/MM Btu natural gas higher heating value: 1020 Btu/dscf

a BAAQMD standard conditions per Regulation 1, Section 228.

b F-factor is based upon the assumption of complete stoichiometric combustion of natural gas. In effect, it is assumed that all excess air present before combustion is emitted in the exhaust gas stream. Value shown reflects the typical composition and heat content of utility-grade natural gas in San Francisco bay area.

Table A-1 summarizes the regulated air pollutant emission factors that were used to calculate mass emission rates for the gas turbines. All units are pounds per million Btu of natural gas-fired based upon the high heating value (HHV). All emission factors are after abatement by applicable control equipment.

TABLE A-1

CONTROL LED REGULATED AIR POLLUTANT EMISSION FACTORS FOR

G AS TURBINES AND HRS GS

Pollutant Source

Combined

- Cycle

Gas Turbine

lb/MM Btu c lb/hr c

Nitrogen Oxides (as NO 2 ) a 0.00722 15.52

Carbon Monoxide b 0.004395 9.45 Precursor Organic Compounds 0.00126 2.71 Particulate Matter (PM 10 ) 0.0036 7.74

Sulfur Dioxide 0.00281 6.0 Sulfur Dioxide (Annual Average) 0.00070 1.5

a based upon stack concentration of 2.0 ppmvd NO

x @ 15% O 2 that reflects the use of dry low- NO

x combustors at the CTG and abatement by the Selective Catalytic Reduction Systems with ammonia injection.

b based upon the permit condition emission limit of 2.0 ppmvd CO @ 15% O 2 that reflects abatement by oxidation catalysts.

c based upon firing rate of 2150 MMBtu/hour (100% Load, 34oF)108

Preliminary Determination of Compliance, October 2010

Oakley Generating Station REGULATED AIR POLLUTANTS

NITROGEN OXIDE EMISSION FACTORS

The NO

x emissions from the combined-cycle gas turbines during normal operation will be 2.0 ppmv, dry @ 15% O 2 . This concentration is converted to a mass emission factor as follows:

(2.0 p pmvd)(20.95 - 0)/(20.95 - 15) = 7.04 ppmv NO

x , dr y @ 0% O 2

(7.04/10 6 )(1 lbmol/386.8 dscf)(46 lb NO 2 /lbmol)(8743 dscf/MM Btu)

= 0.00732 lb NO 2 /MM Btu

Calculations shown below are based on emission factors submitted by the applicant.

The NO

x (as NO 2 ) mass emission rate based upon the maximum firing rate of the combined-cycle gas turbine is calculated as follows:

(0.00722 lb/MM Btu)(2150 MM Btu/hr) = 15.52 lb NO

x (as NO 2 )/ hr

CARBON MONOXIDE EMISSION FACTORS

The CO emissions from the combined-cycle gas turbines during normal operation will be 2.0 ppmv, dry @ 15% O 2 . This concentration is converted to a mass emission factor as follows:

(2.0 ppmv)(20.95 - 0)/(20.95 - 15) = 7.04 ppmv, dry @ 0% O 2

(7.04 /10 6 )(lbmol/386.8 dscf)(28 lb CO/lbmol)(8743 dscf/MM Btu)

= 0.00446 lb CO/MM Btu

Calculations shown below are based on emission factors submitted by the applicant.

The CO maximum mass emission rate based upon the maximum firing rate of the combinedcycle gas turbine is calculated as follows:

(0.004395 lb/MM Btu)(2150 MM Btu/hr) = 9.45 lb CO/hr109

Preliminary Determination of Compliance, October 2010

Oakley Generating Station PRECURSOR ORGANIC COMPOUND (POC) EMISSION FACTORS

The POC emissions from the combined-cycle gas turbines during normal operation will be 1.0 ppmv, dry @ 15% O 2 . This concentration is converted to a mass emission factor as follows:

(1.0 ppmv)(20.95 - 0)/(20.95 - 15) = 3.52 ppmv, dry @ 0% O 2

(3.52 /10 6 )(lbmol/386.8 dscf)(16 lb CH 4 /lbmol)(8743 dscf/MM Btu)

= 0.00127 lb POC/MMBtu

Calculations shown below are based on emission factors submitted by the applicant.

The POC mass emission rate based upon the maximum firing rate of the combined-cycle gas

turbine is calculated as follows:

(0.00126 lb/MMBtu)(2150 MMBtu/hr) = 2.71 lb POC/hr

PARTICULATE MATTER (PM 10 ) EMISSION FACTORS

The District has determined the BACT technology for the combined-cycle gas turbines corresponds to a PM 10 emission rate of 0.0036 lb per MMBtu.

The PM mass emission rate based upon the maximum firing rate of the combined-cycle gas

turbine is calculated as follows:

(0.0036 lb/MMBtu)(2150 MMBtu/hr) = 7.74 lb PM/hr (0.0036 lb/MMBtu)(35,397,277 MMBtu/year)/(2,000 lb/ton) = 63.715 TPY PM/year

SULFUR DIOXIDE EMISSION FACTORS

The SO 2 emission factor is based upon annual average natural gas sulfur content of 0.25 grains per 100 scf and a higher heating value of 1020 Btu/scf.

The sulfur emission factor is calculated as follows:

SO 2 lb/hr

Natural Gas 1 grains of S/100 scf for Maximum Hourly

SO 2 = (1 gr S/100 scf)(lb S/7000 gr)(1/1020 BTU/scf)(1 x 10E6 Btu/MMBtu)(64 lb SO 2 /32 lb S)

= 0.00280 lb/MMBtu

Natural Gas 0.25 grains of S/100 scf for Annual Average

SO 2 = (0.25 gr/100 scf)(lb/7000 gr)(1/1020 BTU/scf)(1 x 10E6 Btu/MMBtu)(64 lb SO 2 /32 lb S)

= 0.00070 lb/MMBtu110

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Calculations shown below are based on emission factors submitted by the applicant.

Max Hourly SO 2

The corresponding SO 2 emission rate for the combined-cycle gas turbine firing:

(0.00281 lb SO 2 /MM Btu)(2150 MM Btu/hr) = 6.0 lb/hr

Annual Average SO 2

The corresponding SO 2 emission rate for the combined-cycle gas turbine firing:

(0.00070 lb SO 2 /MM Btu)(2150 MM Btu/hr) = 1.5 lb/hr111

Preliminary Determination of Compliance, October 2010

Oakley Generating Station GE estimates for startups and shutdowns are summarized below by Radback Energy.112

Preliminary Determination of Compliance, October 2010

Oakley Generating Station113

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Maximum Annual Emissions were calculated using three operating scenarios. The maximum emissions for each pollutant was used to establish the annual facility-wide emissions limits..114

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Maximum Annual Regulated Air Pollutant emission calculations submitted by the Applicant were verified below. Proposed permit limits are calculated by the Applicant and differences can be attributed to rounding.

Scenario

1 2 turbines Boiler Boiler Fire Pump Engine Evaporative

Fluid Oil/Water Scenario

1

Normal Operation Hot/Warm

Starts Cold

Starts Shutdown Normal

Operation Startup &

Shutdown Cooler Separator Emissions

Pollutant TPY TPY TPY TPY TPY TPY TPY TPY TPY TPY

NO2 58.20 6.05 2.40 11.70 0.76 0.24 0.06 79.4

CO 23.62 23.38 9.00 42.00 0.66 0.21 0.01 98.9

POC 13.53 8.53 1.68 5.10 0.19 0.06 0.00 0.11 29.2

PM10 38.7 1 0.50 0.15 1.16 0.64 0.07 0.00 0.10 41.3

SO2 7.74 0.06 0.01 0.15 0.25 0.03 0.00 8.2

2 turbines Boiler Boiler Fire Pump Engine Evaporative

Fluid Oil/Water Scenario

2

Scenario

2 Normal

Operation Hot/Warm

Starts Cold

Starts Shu tdown Normal

Operation Startup &

Shutdown Cooler Separator Emissions

Pollutant TPY TPY TPY TPY TPY TPY TPY TPY TPY TPY

NO2 61.34 6.84 0.10 12.17 0.70 0.25 0.06 81.5

CO 24.90 26.44 0.36 43.68 0.61 0.22 0.01 96.2

POC 14.26 9.64 0.07 5.30 0.18 0 .06 0.00 0.11 29.6

PM10 40.79 0.56 0.01 1.21 0.59 0.07 0.00 0.10 43.3

SO2 8.15 0.07 0.00 0.16 0.23 0.03 0.00 8.6

2 turbines Boiler Boiler Fire Pump Engine Evaporative

Fluid Oil/Water Scenario

3

Scenario

3 Normal

Operation H ot/Warm

Starts Cold

Starts Shutdown Normal

Operation Startup &

Shutdown Cooler Separator Emissions

Pollutant TPY TPY TPY TPY TPY TPY TPY TPY TPY TPY

NO2 95.38 1.12 0.10 2.03 0.07 0.04 0.06 98.8

CO 38.71 4.34 0.36 7.28 0.06 0.04 0.01 50.8

POC 22.17 1.58 0.07 0.88 0.02 0.01 0.00 0.11 24.8

PM10 63.43 0.09 0.01 0.20 0.06 0.01 0.00 0.10 63.9

SO2 12.64 0.01 0.00 0.03 0.02 0.00 0.00 12.7115

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Preliminary Determination of Compliance, October 2010

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Preliminary Determination of Compliance, October 2010

Oakley Generating Station Annual Toxic Air Contaminants Scenario 3 Worst Case

2 turbines Scenario 3 Fu ll Load Max.

Annual

Normal Operation Hot

Starts Warm

Starts Cold

Starts Shutdowns Tuning Emissions

from 2

turbines Emissions

from 2

turbines Emissions

per turbine

Toxic Air

Contaminant lb/year lb/year lb/year lb/year lb/year lb/year lb/year lb/year lb/y ear 1,3

- Butadiene 4.38E+00 4.45E

- 03 0.00E+00 2.81E

- 04 9.73E

- 03 8.55E

- 03 4.3987E+00 4.3987E+00 2.1993E+00 Acetaldehyde 4.72E+03 4.49E+01 0.00E+00 2.83E+00 9.80E+01 8.62E+01 4.9521E+03 4.7450E+03 2.4761E+03

Acrolein 6.51E+02 2.42E+00 0.00E+00 1.52E

- 01 5.2 8E+00 4.64E+00 6.6367E+02 6.5461E+02 3.3183E+02

Ammonia 2.40E+05 2.44E+02 0.00E+00 1.54E+01 5.34E+02 4.69E+02 2.4134E+05 2.4134E+05 1.2067E+05

Benzene 4.58E+02 8.97E

- 01 0.00E+00 5.66E

- 02 1.96E+00 1.72E+00 4.6288E+02 4.6065E+02 2.3144E+02
Benzo(a)anthrac ene 7.79E

- 01 7.92E

- 04 0.00E+00 4.99E

- 05 1.73E

- 03 1.52E

- 03 7.8276E

- 01 7.8276E

- 01 3.9138E

- 01 Benzo(a)pyrene 4.79E

- 01 4.87E

- 04 0.00E+00 3.07E

- 05 1.06E

- 03 9.36E

- 04 4.8143E

- 01 4.8143E

- 01 2.4072E

- 01
Benzo(b)fluoranthene 3.89E

- 01 3.96E

- 04 0.00E+00 2.50E

- 05 8.65 E

- 04 7.61E

- 04 3.9138E

- 01 3.9138E

- 01 1.9569E

- 01 Benzo(k)fluoranthene 3.79E

- 01 3.86E

- 04 0.00E+00 2.43E

- 05 8.42E

- 04 7.41E

- 04 3.8099E

- 01 3.8099E

- 01 1.9049E

- 01 Chrysene 8.68E

- 01 8.83E

- 04 0.00E+00 5.57E

- 05 1.93E

- 03 1.70E

- 03 8.7281E

- 01 8.7281E

- 01 4.3640E

- 01

Di benz(a,h)anthracene 8.10E

- 01 8.24E

- 04 0.00E+00 5.19E

- 05 1.80E

- 03 1.58E

- 03 8.1393E

- 01 8.1393E

- 01 4.0696E

- 01 Ethylbenzene 6.17E+02 1.14E+00 0.00E+00 7.20E

- 02 2.50E+00 2.19E+00 6.2264E+02 6.1997E+02 3.1132E+02 Formaldehyde 1.58E+04 1.62E+02 0.00E+00 1.02E+0 1 3.55E+02 3.12E+02 1.6636E+04 1.5880E+04 8.3180E+03

Hexane 8.92E+03 9.08E+00 0.00E+00 5.72E

- 01 1.98E+01 1.74E+01 8.9705E+03 8.9705E+03 4.4853E+03 Indeno(1,2,3

- cd)pyrene 8.10E

- 01 8.24E

- 04 0.00E+00 5.19E

- 05 1.80E

- 03 1.58E

- 03 8.1393E

- 01 8.1393E

- 01 4.0696E

- 01 Naphthalene 5.72E+01 5.82E

- 02 0.00E+00 3.67E

- 03 1.27E

- 01 1.12E

- 01 5.7495E+01 5.7495E+01 2.8747E+01 Propylene 2.66E+04 2.70E+01 0.00E+00 1.70E+00 5.90E+01 5.19E+01 2.6704E+04 2.6704E+04 1.3352E+04 Propylene Oxide 1.65E+03 1.68E+00 0.00E+00 1.06E

- 01 3. 66E+00 3.22E+00 1.6556E+03 1.6556E+03 8.2778E+02

Toluene 2.45E+03 3.44E+00 0.00E+00 2.17E

- 01 7.52E+00 6.61E+00 2.4640E+03 2.4591E+03 1.2320E+03 Xylene (Total) 8.99E+02 9.15E

- 01 0.00E+00 5.77E

- 02 2.00E+00 1.76E+00 9.0398E+02 9.0398E+02 4.5199E+02

Sulfuri c Acid Mist (H2SO4) 1.25E+04 5.10E+01 0.00E+00 3.21E+00 1.11E+02 9.80E+01 1.2795E+04 1.2598E+04 6.3976E+03 Benzo(a)pyrene equivalents 1.57E+00 1.60E

- 03 0.00E+00 1.01E

- 04 3.50E

- 03 3.07E

- 03 1.5817E+00 1.5817E+00 7.9085E

- 01 Specified PAHs 4.5372E+00 4 .5372E+00 2.2686E+00119

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Oakley Generating Station123

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Table A-2 summarizes the regulated air pollutant emission factors submitted by the applicant that were used to calculate mass emission rates for the auxiliary boiler. All units are pounds per million Btu of natural gas-fired based upon the high heating value (HHV). All emission factors are after abatement by applicable control equipment.

TABLE A-2

CONTROL LED REGULATED AIR POLLUTANT EMISSION FACTORS FOR

AU XILIARY BOILER

Pollutant Source
Auxiliary Boiler

lb/MM Btu c lb/hr c

Nitrogen Oxides (as NO 2 ) a 0.0083 0.42

Carbon Monoxide b 0.0073 0.37 Precursor Organic Compounds 0.0022 0.11 Particulate Matter (PM 10 ) 0.0069 0.35

Sulfur Dioxide 0.0028 0.14

a Based upon stack concentration of 7.0 ppmvd NO

x @ 3% O 2 that reflects the use of ultra-low- NO

x burners and flue gas recirculation. NO

x concentration will be monitored by continuous emission monitors.

b Based upon stack concentration of 10.0 ppmvd CO @ 3% O 2 . Applicant may use vendor guarantee of 10.0 ppm CO or may use an oxidation catalyst. CO concentration will be monitored by continuous emission monitors.

c Based upon firing rate of 50.6 MMBtu/hour

REGULATED AIR POLLUTANTS

NITROGEN OXIDE EMISSION FACTORS

The NO

x emissions from the auxiliary boiler during normal operation will be 7.0 ppmv, dry @

3% O 2 . This concentration is converted to a mass emission factor as follows:

(7.0 ppmvd)(20.95 - 0)/(20.95 - 3) = 8.17 ppmv NO

x , dr y @ 0% O 2

(8.17/10 6 )(1 lbmol/386.8 dscf)(46 lb NO 2 /lbmol)(8743 dscf/MM Btu) = 0.0085 lb NO 2 /MM Btu

Calculations shown below are based on emission factors submitted by the applicant.

The NO

x (as NO 2 ) mass emission rate based upon the maximum firing rate of the auxiliary boiler

is calculated as follows:

(0.0083 lb/MM Btu)(50.6 MM Btu/hr) = 0.42 lb NO

x (as N O 2 )/ hr

CARBON MONOXIDE EMISSION FACTORS

The CO emissions from the auxiliary boiler during normal operation will be 10.0 ppmv, dry @

3% O 2 . This concentration is converted to a mass emission factor as follows:124

Preliminary Determination of Compliance, October 2010

Oakley Generating Station (10.0 ppmv)(20.95 - 0)/(20.95 - 3) = 11.67 ppmv, dry @ 0% O 2

(11.67/10 6 )(lbmol/386.8 dscf)(28 lb CO/lbmol)(8743 dscf/MM Btu) = 0.00739 lb CO/MM Btu

Calculations shown below are based on emission factors submitted by the applicant.

The CO maximum mass emission rate based upon the maximum firing rate of the auxiliary

boil er is calculated as follows:

(0.0073 lb/MM Btu)(50.6 MM Btu/hr) = 0.37 lb CO/hr

PRECURSOR ORGANIC COMPOUND (POC) EMISSION FACTORS

The POC emissions from the auxiliary boiler during normal operation will be 5.0 ppmv, dry @

3% O 2 . This concentration is converted to a mass emission factor as follows:

(5.0 ppmv)(20.95 - 0)/(20.95 - 3) = 5.36 ppmv, dry @ 0% O 2

(5.36 /10 6 )(lbmol/386.8 dscf)(16 lb CH 4 /lbmol)(8743 dscf/MM Btu) = 0.0019 lb POC/MMBtu

Calculations shown below are based on emission factors submitted by the applicant.

The POC mass emission rate based upon the maximum firing rate of the combined-cycle gas

turbine is calculated as follows:

(0.0022 lb/MM Btu)(50.6 MM Btu/hr) = 0.11 lb POC/hr

PARTICULATE MATTER (PM 10 ) EMISSION FACTORS

The applicant has estimated PM emissions to be 0.007 lb/MMBtu.

(0.007 lb/MMBtu)(50.6 MMBtu/hr) = 0.35 lb PM 10 /hr125

Preliminary Determination of Compliance, October 2010

Oakley Generating Station SULFUR DIOXIDE EMISSION FACTORS

The sulfur emission factor is calculated as follows:

Natural Gas 1 grains of S/100 scf for Maximum Hourly

SO 2 = (1 gr S/100 scf)(lb S/7000 gr)(1/1020 BTU/scf)(1 x 10E6 Btu/MMBtu)(64 lb SO 2 /32 lb S) = 0.00280 lb/MMBtu

Calculations shown below are based on emission factors submitted by the applicant.

Max Hourly SO 2

The corresponding SO 2 emission rate for the combined-cycle gas turbine firing:

(0.0028 lb SO 2 /MM Btu)(50.6 MM Btu/hr) = 0.14 lb/hr

Toxic Air Contaminants from the auxiliary boiler were adjusted by the District in accordance with the memo from dated September 7, 2005 from Brian Bateman to the Engineering Division Staff regarding Emission Factors for Toxic Air Contaminants from Miscellaneous Natural Gas Combustion Sources (included at the end of this Appendix).

TABLE A-3

TOXIC AIR CONTAMINANT EMISSIONS FROM

AUXILIARY BOILER

Toxic Air Contaminant Factor Factor Emissions Trigger Levels

lb/MMBTU lb/mmscf lb/hr lb/yr lb/hr lb/yr

Benzene 2.06E

- 06 2.10E

- 03 1.04E

- 04 0.45 2.9E+00 3.8E+00
Formaldehyde 7.35E

- 05 7.50E

- 02 3.71E

- 03 16.04 1.2E

- 01 1.8E+01

Sulfuric Acid 1.42E

- 03 1 .45E+00 7.20E

- 02 0.16 2.6E

- 01 3.9E+01

Toluene 3.33E

- 06 3.40E

- 03 1.65E

- 07 0.73 8.2E+01 1.2E+04126

Preliminary Determination of Compliance, October 2010

Oakley Generating Station127

Preliminary Determination of Compliance, October 2010

Oakley Generating Station Hazardous Air Pollutants from Fire Pump Diesel Engine HAPs were reviewed for Federal Major Source of Hazardous Air Pollutants applicability. Impacts to health were analyzed using diesel particulate matter as a surrogate. Emission factors are from California Air Toxics Emission Factors (CATEF) database.

SOURCEID MATERIAL SCC TYPE DESCRITION CAS SUBSTANCE MEAN UNIT Annual HAP

Emissions

3246 Diesel 20200 102 None O2>13% 106

- 99

- 0 1,3

- Butadiene 5.41E

- 03 lbs/Mgal 5.30E

- 03 lb/year

3251 Diesel 20200102 None O2>13% 75

- 07

- 0 Acetaldehyde 1.07E

- 01 lbs/Mgal 1.05E

- 01 lb/year

3252 Diesel 20200102 None O2>13% 107

- 02

- 8 Acrolein 1.30E

- 02 lbs/Mgal 1.27E

- 02 lb/year

3256 Diesel 20200102 None O2>13% 71

- 43

- 2 Benzene 1.22E

- 01 lbs/Mgal 1.20E

- 01 lb/year

3220 Diesel 20100102 None O2>13% 50

- 32

- 8 Benzo(a)pyrene 3.35E

- 03 lbs/Mgal 3.28E

- 03 lb/year

3222 Diesel 20100102 None O2>13% 205

- 99

- 2 Benzo(b)fluoranthene 6.70E

- 03 lbs/Mgal 6. 57E

- 03 lb/year

3226 Diesel 20100102 None O2>13% 207

- 08

- 9 Benzo(k)fluoranthene 6.70E

- 03 lbs/Mgal 6.57E

- 03 lb/year

3227 Diesel 20100102 None O2>13% 218

- 01

- 9 Chrysene 3.58E

- 03 lbs/Mgal 3.51E

- 03 lb/year

3229 Diesel 20100102 None O2>13% 53

- 70

- 3 Dibenz(a,h)an thracene 3.49E

- 03 lbs/Mgal 3.42E

- 03 lb/year

3235 Diesel 20100102 None O2>13% 50

- 00

- 0 Formaldehyde 1.11E+00 lbs/Mgal 1.09E+00 lb/year

3238 Diesel 20100102 None O2>13% 193

- 39

- 5 Indeno(1,2,3

-

cd)pyrene 3.46E

- 03 lbs/Mgal 3.39E

- 03 lb/year

3240 Diesel 20100102 None O2>13% 91

- 20

- 3 Naphthalene 5.64E

- 02 lbs/Mgal 5.53E

- 02 lb/year

3286 Diesel 20200102 None O2>13% 108

- 88

- 3 Toluene 5.50E

- 02 lbs/Mgal 5.39E

- 02 lb/year

3289 Diesel 20200102 None O2>13% 1330

- 20

- 7 Xylene (Total) 3.59E

- 02 lbs/Mgal 3.52E

- 02 lb/year

Total 1.50E+00 lb/year128

Preliminary Determination of Compliance, October 2010

Oakley Generating Station129

Preliminary Determination of Compliance, October 2010

Oakley Generating Station130

Preliminary Determination of Compliance, October 2010

Oakley Generating Station131

Preliminary Determination of Compliance, October 2010

Oakley Generating Station132

Preliminary Determination of Compliance, October 2010

Oakley Generating Station133

Preliminary Determination of Compliance, October 2010

Oakley Generating Station 

## Appendix B

Health Risk Assessment ResultsINTEROFFICE MEMORANDUM AUGUST 12, 2010

TO: Kathleen Truesdell Via: Scott B. Lutz Daphne Y. Chong FROM: Glen Long

SUBJECT: Results of Health Risk Screening Analysis for Contra Costa Generating Station LLC [also known as Oakley Generating Station] (Oakley, CA), Combined Cycle Power Plant, Plant #19771, Application #20798

Per your request, we have completed a health risk screening analysis for the above referenced permit application. The analysis estimates the incremental health risk resulting from toxic air contaminant (TAC) emissions from the operation of two gas powered turbines, an auxiliary boiler, a three-cell evaporative condenser, and a fire pump. Results from the health risk screening analysis indicate that the project maximum cancer risk is estimated at 1.56 in a million, a chronic non-cancer hazard index of 0.0832, and an acute hazard index of 0.2665. The risk from each source individually is below 1.0 in

a million maximum individual cancer risk and the chronic hazard index is less than 0.20. In accordance with the District’s Regulation 2, Rule 5, this source is in compliance with all project risk requirements.

EMISSIONS: TAC emission were obtained from your August 10, 2010 emissions spreadsheet for the facility. Table I summarizes these emissions.

MODELING: The AERMOD air dispersion computer model was used to estimate maximum one-hour and annual average ambient air concentrations. AERMET was used to create two sets of five years of data with the Contra Costa Power meteorological data (2001-2002 and 2004-2006; 2003 did not meet the EPA required data recovery rates). The first set, Contra Costa Power (CCP), was processed using the land use characteristics around the meteorological tower. The second set was also created with the Contra Costa Power meteorological data, but the site characteristics around the proposed project site were used. All maximum impacts occurred using the CCGS data. Stack and building parameters for the analysis were based on information provided by the applicant.

HEALTH RISK: AERMOD results were imported into HARP using the HARP on-ramp module and the latest version of HARP (version 1.4a) was used to predict all health impacts. Estimates of residential risk assume potential exposure to annual average TAC concentrations occur 24 hours per day, 350 days per year, for a 70-year lifetime. The HARP option “Derived (Adjusted) Method” was used for calculating residential cancer risks. Risk estimates for offsite workers assume potential exposure occurs 8 hours per day, 245 day per ye ar, for 40 years. The HARP default exposure assumptions were used for calculating worker cancer risks. Cancer risk adjustment factors (CRAFs) were used to calculate all cancer risk estimates. The CRAFs are age-specific weighting factors used in calculating cancer risks from exposures of infants, children and adolescents, to reflect their anticipated special sensitivity to carcinogens. There are no schools located within 1000 feet of the facility. Shown in Figures 1-4 are the cancer risk and the chronic hazard index for both residents and workers. Shown in Figure 5 is the acute hazard index. The estimated health risks for this permit application at the Point of Maximum Impact (PMI) are presented in Table II. Shown in Table III is the

maximum cancer risk from each source. Because the cancer risk for each source is less than 1.0 in one million and the chronic hazard index for each source is less than 0.20, and because the total project risk is less than 10 in one million and the project chronic hazard index and acute hazard index are less than 1.0, the project complies with all of the toxic risk requirements of District Regulation 2,

Rule 5.Table I: Maximum Oakley Generating Station TAC emissions.TurbinesBoilerEvaporative CoolerFirepumpMax 1- hour Emissions per turbine Max Annual Max 1- hour Emissions Max Annual Max 1- hour Emissions Max Annual Max 1- hour EmissionsMax AnnualToxic Air Contaminantincluding tuning (lb/hr) lb/yrlb/hrlb/yr per cell (lb/hour) per cell (lb/yr) lb/hourlb/yr1,3-Butadiene2.672080E-04 2.199342E+00Acetaldehyde2.693120E+00 2.476060E+03Ammonia1.466053E+01 1.206682E+05 0.000000E+00 0.000000E+00Benzene5.386240E-02 2.314390E+021.039500E-04 4.491900E-01Benzo(a)anthracene4.755040E-05 3.913789E-01Benzo(a)pyrene2.924560E-05 2.407153E-01Benzo(b)fluoranthene2.377520E-05 1.956894E-01Benzo(k)fluoranthene2.314400E-05 1.904942E-01Chrysene5.302080E-05 4.364048E-01Dibenz(a,h)anthracene4.944400E-05 4.069648E-01Ethylbenzene6.859040E-02 3.113176E+02Formaldehyde9.741520E+00 8.318029E+033.712500E-03 1.604250E+01Hexane5.449360E-01 4.485271E+03Indeno(1,2,3-cd)pyrene4.944400E-05 4.069648E-01Naphthalene3.492640E-03 2.874730E+01Propylene1.622184E+00 1.335191E+04Propylene Oxide1.005712E-01 8.277837E+02Toluene2.066128E-01 1.232017E+031.648350E-07 7.272600E-01Xylene (Total)5.491440E-02 4.519907E+02Sulfuric Acid Mist (H2SO4)3.061071E+00 6.397629E+037.203230E-02 1.557338E-01Arsenic6.085800E-06 9.128700E-03Copper1.561140E-05 2.341710E-02Lead4.383540E-06 6.575310E-03Diesel PM1.052157E-01 5.155457E+00Table II. Maximum project health effects. Receptor Cancer Risk Chronic Non-cancer Hazard Index Acute Hazard Index

Resident 1.56 chances in a million 0.0832

Worker 0.14 chances in a million 0.0790 0.2665

Table III. Maximum cancer risk from each source.

Source Maximum Residential/Worker Cancer Risk from source

North Turbine 0.70 in a million
South Turbine 0.65 in a million Auxiliary Boiler 0.03 in a million Evaporative Cooler 0.39 in a million Fire Pump 0.73 in a million1 E -0

07

1 E

- 0 0 7

1 E -0 0 7

1E - 00 7

1 E - 0 0 7 1 E- 0 07 1 E - 0 0 7 1 E - 0 0 7 1 E - 0 0 7 1

E - 0 0 7

2 E - 0 0 7

2 E - 0 0 7

2 E - 0 0 7

2 E - 0 0 7

2 E - 0 0 7 2 E - 0 0 7 2

E - 0 0 7 2 E - 0 0 7 2 E - 0 0 7

3 E - 0 0 7

3 E -0 0 7

3 E - 0 0 7

3 E - 0 0 7

3E

- 0 07 3E - 0 07 3 E - 0 0 7 3

E - 0 0 7 3 E - 0 0 7

4 E - 0 0 7

4 E - 0 0 7

4 E- 0 0 7

4 E - 0 0 7

4 E - 007 4 E - 0 0 7 4 E - 0 0 7 4

E - 0 0 7 4 E - 0 0 7 4 E - 0 0 7

5 E - 0 0 7

5 E -0 0 7

5 E - 0 0 7

5 E - 0 0 7

5 E - 0 0 7 5 E - 0 0 7 5 E -0 0 7 5 E - 0 0 7 5 E - 0 0 7

6 E - 0 0 7

6 E - 0 0 7

6 E- 0 0 7

6E - 0 0 7

6 E - 007 6 E - 0 0 7 6 E - 0 0 7 6E - 0 07

7 E - 0 0 7

7 E - 0 0 7

7 E-

0 0 7

7 E - 0 0 7 7 E - 0 0 7 7 E - 0 0 7

8 E- 0 0 7

8 E - 0 0 7

8 E - 0 0 7 8 E - 0 0 7

8 E - 0 0 7 9 E - 0 0 7

9 E - 0 0 7 9 E- 0 0 7 9 E- 0 0 7

1 E - 0 0 6

1 E - 0 0 6 1 E- 0 0 6 1 . 1 E - 0 0 6

1 .1 E - 006 1 . 2 E -0 0 6

1 . 2 E - 0 0 6 1 . 4 E - 0 0 66082006084006086006088006090006092006094006096006098006100006102006104006106006108006110006112006114006116006118006120004206400420660042068004207000420720042074004207600420780042080004208200420840042086004208800420900042092004209400TURNTURSBLRWC1WC2WC3FPMet data:CCGSAugust 12, 2010Figure 1: Oakley Generating Station Residential Cancer Risk1 E - 00 7

1 E - 0 0 76082006084006086006088006090006092006094006096006098006100006102006104006106006108006110006112006114006116006118006120004206400420660042068004207000420720042074004207600420780042080004208200420840042086004208800420900042092004209400TURNTURSBLRWC1WC2WC3FPMet data:CCGSAugust 12, 2010Figure 2: Oakley GeneratingStation Worker Cancer Risk0 . 0 1

0

. 0 1

0

.

0 1

0 . 0 1

0 .0 1 0

. 0 1 0 . 0 1 0 . 0 1 0 . 0 1 0 . 0 1 0 . 0 1

0 . 0 1 5

0

. 0 1 5

0

. 0 1 5

0

. 0 1 5 0 . 0 1 5 0 . 0 1 5 0

. 0 1 5 0 . 0 1 5 0 . 0 1 5

0. 0 2

0

. 0 2

0

. 0 2

0

. 0 2

0 . 0 2 0 . 0 2 0 . 0 2 0

.0 2 0 . 0 2 0. 0 2

0 . 0 2 5

0

. 0 2 5

0

. 0 2 5

0

. 0 2 5

0 .0 25 0 . 0 2 5 0 . 0 2 5 0 . 0 2 5 0 . 0 2 5 0. 02

5

0 . 0 3

0

. 0 3

0

. 0 3

0

.

0 3

0 . 0 3 0 . 0 3 0 . 0 3 0 . 0 3 0

. 03

0 . 0 3 5

0

. 0 3 5

0

. 0 3 5

0

. 0 3 5 0 . 0 3 5 0 . 0 3 5 0 . 0 3 5

0 . 0 4

0

. 0 4

0

. 0 4 0 . 0 4 0 . 0 4 0

. 0 4

0 . 0 4 0 . 0 4 5

0

. 0 4 5

0 . 0 4 5 0 . 0 4 5 0 . 0 5

0

. 0 5

0 . 0 5 0 . 0 5

0. 055

0

. 0 5 5 0 . 0 5 5 0 . 06

0

. 0 6 0

. 0 6

0 . 0 6 5

0 .0 6 5 0 . 0 7

0 . 0 7 0 . 0 7 5

0

. 0 86082006084006086006088006090006092006094006096006098006100006102006104006106006108006110006112006114006116006118006120004206400420660042068004207000420720042074004207600420780042080004208200420840042086004208800420900042092004209400TURNTURSBLRWC1WC2WC3FPMet data:CCGSAugust 12, 2010Figure 3: Oakley GeneratingStation Residential Chronic HI0 . 0 1

0

. 0 1

0

.

01

0

. 0 1

0 .0 1 0 . 0 1 0 . 0 1 0

. 0 1 0 . 01

0. 01 5

0

. 0 1 5

0

. 0 1 5

0

. 0 1 5 0. 0 15 0 . 0 1 5 0 . 0 1 5 0 . 0 1 5

0 . 0 2

0

. 0 2

0

. 0 2

0

. 0 2

0 . 0 2 0 . 0 2 0 . 0 2 0 . 0 2 0 . 0 2

0 . 0 2 5

0

. 0 2 5

0 .0 2 5

0

. 0 2 5 0 . 0 2 5 0 . 0 2 5 0 . 0 2 5 0
. 0 2 5

0 .0 3

0 . 0 3

0

. 0 3

0 . 0 3 0 . 0 3 0 . 0 3 0
. 0 3

0 . 0 3 5

0

. 0 3 5

0

. 0 3 5 0 . 0 3 5 0 . 0 3 5 0
. 0 3 5

0 . 0 4

0

. 0 4

0 . 0 4 0 . 0 4 0 . 0 4

0 . 0 4 5

0

. 0 4 5

0 . 0 4 5 0 . 0 4 5

0 . 0 5

0

. 0 5 0 . 0 5 0 . 0 5

0. 0 55

0

. 0 5 5 0

. 0 5 5 0. 06

0 . 0 6 0 . 0 6 5

0 . 0 6 5 0 . 0 7

0

. 0 7 56082006084006086006088006090006092006094006096006098006100006102006104006106006108006110006112006114006116006118006120004206400420660042068004207000420720042074004207600420780042080004208200420840042086004208800420900042092004209400TURNTURSBLRWC1WC2WC3FPMet data:CCGSAugust 12, 2010Figure 4: Oakley GeneratingStation Worker Chronic HI0

. 1

0 .1

0 . 1 0

. 1 0 . 1 0 .1 0 .1 0
. 1

0 . 1

0 . 1 0

. 1 0
. 1

0 . 1 0 . 1 0 . 1 0 . 1

0 . 1

0 . 1 0 . 1 0 . 1 0 . 1

0 . 1

0 . 1 0 . 1 0 . 1 0 . 1 0

. 1 0 . 1 5

0

. 1 5

0 . 1 5 0 . 1 5

0.2

0 . 2 0 . 2 56082006084006086006088006090006092006094006096006098006100006102006104006106006108006110006112006114006116006118006120004206400420660042068004207000420720042074004207600420780042080004208200420840042086004208800420900042092004209400TURNTURSBLRWC1WC2WC3FPMet data:CCGSAugust 12, 2010Figure 5: Oakley Generating Station Acute HI