_ San Joaquin Valley • AIR POLLUTION CONTROL DISTRICT

OCT 3 0 2008

Jim Rexroad

Avenal Power Center LLC

500 Dallas Street, Level 31

Houston, TX 77002

Re: Notice of Final Determination of Compliance (FDOC)

Project Number: C-1080386 - Avenal Power Center LLC (08-AFC-01)

Dear Mr. Rexroad:

Enclosed is the District's final determination of compliance (FDGC) for the installation of

a nominal 600 MW combined cycle power plant, located at NE~ Section 19, T21 S,

R18E - Mount Diablo Base Meridian on Assessor7sParcei Number 36-170-032 in Avenal,

CA.

Notice of the District's prelim.inary decision was published on July 16, 2008. All

comments received following the District's preliminary decision on this project were

considered. A'summary of the comments received and the District responses to those

comments can be found in Attachments J, K, and L of the enclosed FDGC package.

The changes made to the PDOC were in direct response to comments received from

the oversight agencies and other interested parties. It is District practice to require an

additional 30-day comment period for a project if changes received during the initial 30-

day comment period result in a significant emissions increase that affects or modifies

the original basis for approvaL The changes made were minor and did not increase

permitted emission levels or trigger addition·al public notification requirements.

Therefore, publication of the PDOC for an additional 30-day comment period is not

required.

Also enclosed is an invoice for the engineering evaluation fees pursuant to District Rule

3010. Please remit the amount owed, along with a copy of the attached invoice, within 60

days.

Seyed Sadredin

Executive Director/Air Pollution Control Officer

Northern Region

4800 Enterprise Way

Modesto, CA 95356-8718

Tel: (209) 557-6400 FAX: (209) 557-6475

Central Region (Main Office)

1990 E. Gettysburg Avenue

Fresno, CA 93726-0244

Tel: (559) 230-6000 FAX: (559) 230-6061

www.valleyair.org

Southern Region

2700 M Street, Suite 275

Bakersfield, CA93301-2373

Tel: (661) 326-6900 FAX: (661) 326-6985

Printed onr~~y~iedp~p~~:~
Mr. Jim Rexroad

Page 2

Thank you for your cooperation in this matter. If you have any questions, please

co·ntact Mr. Jim Swaney of the Permit Services Division at (559) 230-5900.

Sincerely,

1: jfl- David Warner

IV. Director of Permit Services

DW:df

En"closures

cc: Eric Walther, Sierra Res~arch
Fresno Bee

NOTICE OF FINAL DETERMINATIO·NOF COMPLIANCE

NOTICE IS HEREBY GIVEN that the San Joaquin Valley Unified Air Pollution Control

District has issued a Final Determination of Compliance (FDOC) to Avenal Power Center

LLC for the installation of a nominal 600 MW combined cycle power plant, located at

NE~ Section 19, T21S, R18E Mount Diablo Base Meridian on Assessor's Parcel

Number 36-170-032 in Avenal, CA.

All comments received following the District's preliminary decision on this project were

considered. Cha'nges were made to the DOC in direct response to comments received

from the oversight agencies and other interested parties. The changes made were

minor and did 'not increase permitted emission levels ·or trigger additional public

notification requirements.

The application review for.project C-1080386 is available for public inspection at the SAN

JOAQUIN VALLEY UNIFIED AIR POLLUTION "CONTROL "DISTRICT, 1990 EAST

GETTYSBURG AVENUE, FRESNO, CA 93726.
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Avenal Power Center Project

California Energy 'Commission

Application for Certification Docket #: 08-AFC-01

Facility ~ame:

Mailing Address:

Contact Na'me:

Telephone:

Fax:

Cell:

E-Mail:

Alternate Contact: .

Telephone:

Fax:

Cell:

E-Mail:

Alternate Contact:

Telephone:

Cell:

E-Mail:

Engineer:

Lead Engineer:

Date:

Project#:

Application #'s:

Submitted:

Avenal Power Center, LLC

500 Dallas Street, Level 31

Houston, TX 77002

Jim Rexroad

(713) 275-6147

(713) 275-6115

-(832) 748-1 060

jim.,Rexroad@macquarie.com

Eric Walther

(916)444-6666

(916) 444-8373

(916) 883-8774

ewalther@sierraresearch.com

Tracey Gilliland

(713)275-6148

(512) 217-3002

tracey.gilliland@macquarie.com

Derek Fukuda, Air Quality Engineer

Joven Refuerzo, Supervising Air Quality Engineer

October 28,2008

C-1080386

C-3953-10-0, C-3953-11-0, C-3953-12-0, C-3953-13-0, and

C-3953-14-0

February 29, 2008
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Table of Contents

Section

I. Proposal

II. Applicable Rules

III. Project Location

IV. Process Description

v. Equipment Listing

Page

1

1

2

3

5

VI. Emission Control Technology Evaluation 5

VII. General Calculations 9

VIII. Compliance 27

IX. Recommendation 110

ATTACHMENT· A

ATTACHMENT B

ATTACHMENT C

ATTACHMENT D

ATTACHMENT E

ATTACHMENT F

ATTACHMENT G -

ATTACHMENT H

ATTACHMENT I

ATTACHMENT·J

ATTACH·MENT K

ATTACHMENT L

f7DOC Conditions

Project Location and Site Plan

eTG Commissioning Period Emissions Data

CTG Emissions Data

SJVAPCD BACT Guidelines 1.1.2, 3~ 1.4, 3.1.8, and

3.4.2

Top Down BACT Analysis (C-3953-10-0, -11-0, -12-0,

-13-0, and -14-0)

Health Risk Assessment and Ambient Air Quality

Analysis

SOx for PM10 Interpollutant Offset Analysis

Additional Supplemental Information

CEC Comments and District Responses

EPA Comments and District Responses

CURE Comments and District Responses
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

I. PROPOSAL:

Avenal Power Center, LLC is seeking approval from the San Joaquin Valley Air Pollution

Control District (the "District") for the installation of a "merchant" electrical power generation

facility (Avenal Energy Project). The Avenal Energy Project will be a combined-cycle power

generation facility consisting of two natural gas-fired combustion turbine generators (CT.Gs)

each with a heat recovery steam generator (HRSG) and a 564 MMBtu/hr duct burner. Also

proposed are a 300' MW steam turbine, a 37.4 MMBtu/hr auxiliary boiler, a 288 hp diesel-fired

emergency Ie engine powering a water pump, a 860 hp natural gas-fired emergencylC engine

powering a 550 kW generator and associated facilities. The plant will have a nominal rating of

600 MW.

During the 30-day public notice period for this project several comments were received by the

District from various community and regulatory entities. These comments and the Districts

responses can be seen in Attachments J, K, and L. Based on these comments, the only

significant change to the DOC was the lowering of the CO emission factor for the two natural

gas-fired CTG's from 4.0 ppmvd @ 15% O2 to 2.0 pp~vd @ 15% O2.

'The Avenal Energy Project is 'subject to approval by the California Energy Commission (CEC).

Pursuant to SJVAPCD Rule 2201, Section 5.8, the Determination of Compliance (DOC) review

is' functionally equivalent to an Authority to Construct (ATC) review. The Determination of

Sompliance (DOC) will be issued an.d submitted to the CEC contingent upon SJVAPCD

approval of the project.

The California Energy Commission (CEC) 'is the, lead agency for this project for the

requirements of the California E~vironmentalQuality Act (CEQA).

Additionally, the Avenal Energy Project is subject to Prevention of Significant Deterioration

requirements by EPA Region IX.

II. . APPLICABLE RULES:

Rule 1080

Rule 1081

Rule 1100

Rule 2010

Rule 2201

Rule 2520

Rule 2540

Rule 2550

Rule 4001

Rule 4002

Stack Monitoring (12/17/92)

Source Sampling (12/16/93)

Equipment Breakdown (12/17/92)

Permits Required (12/17/92)

New and Modified Stationary $ource Review Rule (9/21/06)

Federally Mandated 'Operating Permits (6/21/01)

Acid Rain Program (11/13/97)

Federally Mandated Preconstruction Review for Major Sources of Air Toxics

(6/18/9.8) ,

New Source Performance Standards (4/14/99)

Subpart GG - Standards of Performance for Stationary Gas Turbines

Subpart KKKK - Standards of Performance for Stationary Combustion Turbines

National Emissions Standards for Hazardous Air Pollutants (5/18/00)

1
Rule 4101

Rule 4102

'Rule 4201

RUle 4202

Rule 4301

.Rule 4305

Rule 4306

Rule 4351

Rule 4701

Rule 4702

'Rule 4703

Rule 4801

Rule 8011

Rule 8021

Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Visible, Emissions (2/17/05)

Nuisance (12/17/92).

Particulate Matter Concentration (12/17/92)

Particulate Matter Emission Rate (12/17/92)

Fuel Burning Equipment (12/17/92)

Boilers, Steam Generators and Process Heaters - Phase 2 (8/21/03)

Boilers, Steam Generators and Process Heaters - Phase 3 (3/17/05)

Boilers, Steam Generators and Process Heaters - Phase 1 (8/21/03)

Stationary Internal Combustion Engines - Phase 1 (8/21/03)

Stationary Internal Combustion Engines - Phase 2 (1/18/07)

Stationary Gas Turbines (8/17/06)

Sulfur Compounds (12/17/92)

G~neral Requirements (8/19/04)

Construction, Demolition, Excavation, Extraction and Other Earthmoving Activities

(8/19/04)

Rule 8031 Bulk Materials (8/19/04)

Rule 8041 Carryout and Trackout (8/19/04)

Rule 8051 Open Areas (8/19/04)

Rule 8061' Paved and Unpaved Roads. (8/19/04)

RUle 8071 Unpaved Vehicle/Equipment. Traffic Areas (9/16/04)

Rule 8081 Agricultural Sources (9/16/04)

California Environmental Quality Act (CEQA)

California Code of Regulations (CCR), Section 2423 (Exhaust Emis.sion Standards and Test

Procedures, Off-Road Compression-Ignition Engines and Equipment)

California Health & Safety Code (CH&S), Sections 2423 (Exhaust Emission Standards and

Test Procedures, Off-Road Compression-Ignition Engines and Equipment) 417'00 (Health Risk

Analysis), 42301.6 (School Notice), 44300 (Air Toxic "Hot Spots"), and 93115 (Airborne Toxic

Control Measure (ATCM) for Stationary .Compression-Ignition (CI) Engines)

III. PROJECT LOCATI·ON:

The proposed equipment will be located within NE~ Section 19, Township 21 South, Range 18

East - Mount Diablo Base Meridian on Assessor's Parcel Number 36-170-032 (8ee Attachment

B).. The closest population center is the residential district of Avenal approximately 6 miles to the

southwest. The City of Huron is located approximately· 8 miles to the north, and the City of

Coalinga is lo'cated approximately 16 miles to the west.

The site is located northeast of the city of Avenal, in Kings County. The proposed location is not

within 1,000' of a K-12 school. .

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Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-10_80386

IV. PROCESS DESCRIPTION:

Combined-Cycle Combustion Turbine Gener~tors

Each natural gas-fired General Electric Frame 7 Model PG7241 FA combined-cycle combustion

turbine generator (CTG) will be equipped with Dry Low NOx combustors, a selective catalytic

reduction (SCR) system with ammonia injection, an oxidation catalyst, a duct burner, and a heat

recovery steam generator (HRSG). Each CTG will drive an electrical generator to produce

approximately 180 MW of electricity. The plant will be a "combined-cycle plant," sin<?e the gas

turbine and a steam turbine both turn electrical generators and produce power.

Each CTG will turn an electrical generator, but will also produce power by directing exhaust

heat through its HRSG, which supplies steam to the steam turbine nominally rated at -300 MW,

which turns another electrical generator.

Since two HRSGs will feed a single steam turbine generator, this design is referred to as a "twoon-one" configuration.

The CTGs will utilize Dry Low NOx (DLN) combustors, SCR with ammonia injection, and an

oxidation catalyst to achieve the foUowing emission rates:

'NOx: 2.0 ppmvd @ 15% O2

VOC: 2.0 ppmvd @ 15% O2

CO: 2.0 ppmvd @ 150/0 02

SOx: 0.00282Ib/MMBtu (Hourly and Daily Limits; based on 1.0 gr S/100 dscf)

0.001 Ib/MMBtu (Annual average; based on 0.3,6 gr S/100 dscf»

PM10: 0.0107 Ib/MMBtu - '

Continuous emissions monitoring systems (CEMs) will sample, analyze, and record NOx, CO,

and 02 concentrations in the exhaust gas ,for each CTG.

He'at Recovery Steam Generators (HRSGs)

The HRSGs provide for the transfer of heat from the CTG exhaust gases -to condensate and

feedwater to produce stream. Each HRSG will be approximately 90 "feet high and will have an

exhaust 'stack approximately 145 feet tall by 19 feet in diameter. The size and shape of the

HRSGs, are specific to their intended purpose of high efficiency recycling of waste heat from the

CTG.:

The HRSGs will be multi-pressure, natural-circulation boilers equipped with transition ducts and

duct burners. Pressure components of each HRSG include a low pressure (LP) economizer, LP

evaporator, LP deaerator/drum, LP superheater, intermediate pressure (IP) economizer, IP

evaporator, IP drum, IP superheaters, high pressure (HP) economizer, HP evaporator, HP drum,

and HP superheaters and reheaters. .

Superheated HP steam is produced in the HRSG and flows to the steam turbine throttle inlet.

The exhausted cold reheat steam from the steam turbine is mixed with 'IP steam from the HRSG

and reintroduced into the HRS'G through the reheaters. The hot reheat steam flows back from the

HRSG into the STG. The LP superheated steam from the HRSG is admitted to the LP

.3
Avenal Power Center, LLC' (08~AFC-01)

SJVACPO Determination of Compliance, C-1080386

condenser. The condensate is pumped from the condenser back to the HRSG by condensate

pumps. The condensate is preheated by an HRSG feedwater heater. Boiler feedwater pumps

send the feedwater through economizers and into the boiler drums of the HRSG, where steam is

produced, thereby completing the steam cycle.

Each HRSG is equipped with a SCR system that Uses aqueous ammonia in conjunction with a

catalyst bed to reduce NOx in the CTG exhaust gases. The catalyst bed is contained in a catalyst

cham'ber located within each HRSG. Ammonia is injected upstream of the catalyst bed. The

subsequent catalytic reaction converts NOx to nitrogen and water, resulting in a reduced

concentration of NOx 'in the exhaust gases exiting the stack.

Duct Burners

Duct burners are installed in the HRSG transition duct between the HP superheater and reheat

coils. Through the combustion of natural gas, the duct burners heat the CTG· exhaust gases to

generate additional steam at 'times when peak power is needed. The duct burners are also

used as needed to. control the temperature of steam produced by the HRSGs.. . The duct

burners will have a' maximum heat input rating of 562 MMBtu/hr ona higher. heating value

(HHV) basis per HRSG, and are expected to operate no more·than hours per year.

Steam Turbine Generator

The steam turbine system consists of a 300 MW nominally rated reheat steam turbine

~enerator (STG), governor system, steam admission system, gland steam system, lubricating

oil system, including oil coolers and filters and generator co.olers. Steam from the HP

s'uperheater, reheater and IP superheater sections of the HRSG enters the corresponding

sections of the' STG as described previously. The steam expands through the turbine blading to

drive the steam turbine and its generator. Upon exiting' th'e turbine, the steam enters the

deaerating condenser, where it is condensed to water.

Auxiliary Boiler

. One 37.4 MMBtu/hr Cleaver Brqoks Model CBL700-900-200#ST natural gas-fired boiler

equipped with an Cleaver Brooks Model ProFire Ultra Low NOx burner, capable of providing up

to 25,000 pounds per hour (Ib/hr) of saturated steam. The' boiler will be used to provide ·steam

as needed for auxiliary purposes. .

·Diesel-Fired Emergency Ie Engine Powering a Fire Pump

Emergency firewater will be provided by three pumps (a jockey pump, a main fire pump, and a

back-up fire pump); two powered by electric motors and the other powered by a diesel-fired

internal combustion engine. If the jockey pump is unable to maintain a set operating pressure

in the piping network, the electric motor-driven fire pump will start automatically. If the electric

"motor-driven fire pump is unable to maintain a set operating pressure, the diesel engine-driven

fire pump will start automatically. The diesel-fired engine will be rated at 288 horsepower. The

engine will be limited to no greater than 50 hours per year of non-emergency operation in

accordance with the applicant's proposal.

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A·vena/Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Natural Gas-Fired Emergency IC Engine Powering an Electrical Generator

One 860 hp Caterpillar Model G3512LE natural gas-fired IC engine generator set w.ill provide

power to the essential·service AC system in the event of grid failure or loss of outside power to

the plant. This engine will be limited to no greater than 50 hours per year of non-emergency

operation in accordance with the applicant's proposal.

V. EQUIPMENT LISTING:

C-3953-10-0: 180 MWNOMINALLY RATED COMBINED-CYCLE POWER GENERATING

SYSTEM #1 CONSISTING OF A GENERAL ELECTRIC FRAME 7 MODEL

PG7241FA NATURAL GAS~FIRED COMBUSTION TURBINE GENERATOR

WITH DRY LOW NOx COMBUSTOR, A SELECTIVE CATALYTIC REDUCTION

(SCR) SYSTEM, AN OXIDATION CATALYST, HEAT RECOVERY STEAM

GENERATOR #1 (HRSG) WITH A 562 MMBTU/HR DUCT BURNER AND A

300 MW NOMINALLY RATED STEAM TURBINE SHARED WITH C~3953-11

"C-3953-11-0: 180 MW NOMINALLY RATED COMBINED-CYCLE POWER GENERATING

SYSTEM #2 CONSISTING OF A GENERAL ELECTRIC FRAME 7 MODEL

PG7241FA NATURAL GAS-FIRED COMBUSTION TURBINE GENERATOR

WITH DRY LOW NOx COMBUSTOR, A SELECTIVE CATALYTIC REDUCTION

(SCR) SYSTEM, AN OXIDATION CATALYST, HEAT RECOVERY STEAM

GENERATOR #2 (HRSG) WITH A 562 MMBTU/HR DUCT BURNER AND A

300 MWNOMINALLY RATED STEAM TURBINE SHARED WITH C-3953-10

C-3953-12-0: 37.4 MMBTU/HRCLEAVER "

BROOKS "MODEL CBL-700-900-200#ST

NATURAL GAS-FIRED BOILER WITH A CLEAVER BROOKS MODEL

PROFIRE, OR DISTRICT APPROVED EQUIVALENT, ULTRA LOW .NOX

BURNER

C-3953-13-0: 288 BHP C"LARKE MODEL JW6H-UF40 DIESEL-FIRED EMERGENCY IC

ENGINE POWERING A FIRE PUMP

C-3953-14-0: 860 BHP CATERPILLAR MODEL 3456 NATURAL GAS-FIRED EMERG.ENCY

IC ENGINE POWERING" WITH NON-SELECTIVE CATALYTIC REDUCTION

(NSCR) POWERING A 500 KW ELECTRICAL GENERATOR

VI. EMISSION CONTROL TECHNOLOGY EVALUATION:

i. C-3953-1 0-0·and C-3953-11-0 (Turbines)

Each CTG will be equipped w"ith a Dry Low NOx combustor and will exhaust into a

Selective Catalytic Reduction [SCR] system with ammonia injection, and a CO catalyst.

The use of Dry Low NOx combustors and a SCR system with ammonia injection can

achieve a NOx emission rate of 2.0 ppmvd @ 15% O2. CO" emissions of 2.0 ppmvd @

5
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

150/0 O2 have been demonstrated with the use of an oxidation catalyst (1). And the use of

DLN combustors and good combustion practices can achieve vac emissions of 2'.0

ppmvd@ 15°A> O2.

Emissions from natural gas-fired turbines include NOx, CO, VOC, PM10, and SOx.

NOx is' the major pollutant of concern when combusting natural gas., Virtually all gas

turbine NOx emissions originate as NO. This NO is further oxidized in the exhaust system

or later in the atmosphere to form the mor~ stable N02 molecule. There are two

mechanisms by which NOx is formed in turbine combustors: 1) the oxidation of

atmospheric nitrogen found in the combustion air (thermal NOx and prompt NOx), and 2)

the conversion of nitrogen chemically bound in the fuel (fuel NOx).

Thermal NOx is formed by a series of chemical reactions in which oxygen and nitrogen

present in the combustion air dissociate and subsequently react to form oxides of nitrogen.

Prompt NOx, a form of thermal NOx, is formed in the proximity of the flame front as

intermediate combustion products such as HCN, H, and NH are oxidized to form NOx.

Prompt NOx is formed in both fuel-rich flame zones ,and dry low NOx' (DLN) combustion

zones. The contribution of prompt NOx to overall NOx emissions is relatively small in

conventional near-stoichiometric combustors, but this contribution' is an increasingly

,significant percentage of overall thermal NOx emiss'ions in DLN combustors. For this

reason prompt NOxbecomes an important consideration for DLN combustor designs, and

establi~hes a minimum NOx level attainable in lean mixtures.

Fuel NOx is formed when fuels containing nitrogen are burned. Molecular nitrogen,

present as N2 in some natural gas, does not contribute significantly to fuel NOx formation.

With excess air, the degree of fuel NOx formation is, primarily a function of the nitrogen

content in the fuel. When compared to thermal NOx, fuel NOx is not currently a major

contributor to overall NOx emissions from stationary gas turbines firing natural gas.

The level of NOx formation in a gas turbine, and hence the NOx emissions, is unique (by

design factors) to each gas turbine model and operating mode. The primary factors that

determine the amount of NOx generated are the combustor design, the types of fuel being

burned, ambient conditions, operating cycles, and, the power output of the turbine.

The design of the combustor is the most important factor influencing ,the formation of NOx.

Design parameters controlling air/fuel ratio and the introduction of cooling air into the

combustor strongly. influence thermal NOx formation. Thermal NOx formation' is primarily a

function of flame temperature and residence time. The extent ,of fuel/air mixing' prior to

combustion also affects NOx formation. Simultaneous mixing and combustion results in

localized fuel-rich zones that yield high flame temperatures in which substantial, thermal

NOx production takes place. Injecting water or steam into a conventional combustor

,provides a heat sink that effectively reduces peak flame temperature, thereby reducing

thermalNOx formation. Premixing air and fuel at a lean ratio approaching the lean

'1 Based on information supplied by the CTG manufacturer and information contained in the California Air Resources Board's

September 1999 Guidance for Power Plant Siting and Best Available Control Technology.document.

6
Avenal Power Center, LLC'(08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

flammability .Iimit (approximately 50% excess air) significantly reduces peak. flame

temperature, resulting in minimum NOx formation during combustion. This is known as dry

low NOx (DLN) combustion.

Selective Catalytic Reduction systems selectively reduce .NOx emissions by. injecti.ng

ammonia (NH3) into the exhaust gas stream upstream of a catalyst. Nitrogen oxides, NH3,

and O2 react on the surface of the catalyst to form molecular nitrogen (N2) and H20. SCR

is capable' of over 90 percentNOx reduction. Titanium oxide is the SCR catalyst material

most commonly used, though vanadium pentoxide, noble metals, or zeolites are also used.

The ideal operating temperature for a conventionalSCR catalyst is 600 to 750 of. Exhaust

gas temperatures greater than the upp.er limit (750 OF) will cause NOx and NH3 to pass

through the catalyst unreacted. Ammonia slip will be limited to 10 ppmvd @15°Jlc> O2.

Carbon monoxide is formed during' the combustion process due to incomplete oxidation

of the carbon contained in the fuel. 'Carbon monoxide formation can be limited by

ensuring complete and efficient combustion of the .fuel.. High combustion temperatures,

. adequate excess air a'nd good airifuel mixing during combust~on minimize CO emissions.

Therefore, lowering com.bustion temperatur~s and staging combustion to limit NOx

formation can result in increased GO emissions.

Post-combustion CO controls, such as oxidizing catalysts can also be used to reduce CO

emissions. An oxidation catalyst utilizes a precious metal catalyst bed to convert carbon

monoxide (CO) to carbon dioxide (C02).

Inlet air temperature and density directly affects turbine performance. The hotter and

'drier the inlet air temperature, the lower the efficiency and capacity of the turbine.

Conversely, colder air improves the efficiency and reduces emissions by reducing the

amount of fuel required to achieve the required turbine output. The inlet air cooler will

allow the turbine to operate in a more efficient manner than it would withc;>ut it. The

increased efficiency will reduce the amount of fuel necessary to ach'ieve the required

power output. The reduction in fuel consumption will result in lower combustion

contaminant emissions.

The inlet air filter will remove particulate matter from the combustion air stream, reducing

the.amount of particulate matter emitted.

The lube oil coalescer will result in the merging together of oil mist to form larger

droplets. The larger drop.lets will return to the oil stream instead of being emitted.

ii.C-3953-12-0 (Boiler)

Emissions from natural gas-fired boilers include NOx, CO, VOC, PM10, and SOx.

NOx is the major pollutant of concern when burning natural gas. NOx formation is either

due to thermal fixation of atmospheric nitrogen in the combustion air (thermal NOx) or due

to conversion of chemically bound nitrogen in the fuel (fuel NOx). Due to the low fu'el

nitrogen content of natural gas, nearly .all NOx emissions are thermal NOx. Formation of

7
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

therm'al NOx is affected by four furnace zone factors: (1) nitrogen concentration, (2) oxygen

concentration, (3) peak temperature, and (4) time of exposure at peak temperature.

The Cleaver Brooks b'oiler will control the formation 'of thermal NOx with an Cleaver

'Brooks ultra low NOx burner. Cleaver Brooks burners reduce NOx by pre-mixing

gaseous fuel and' combustion air in a region near the burner exit, at a stoichiometry that

minimizes Prompt NOx. This also eliminates the traditional NOx versus CO tradeoff.

iii. C-3953-13-0 (DiesellC engine powering fire water pump)

The diesel-fired emergency ICengine (fire pump) will be equipped with a turbocharger, an

intercooler/aftercooler, and will be fired on very low (0.00150/0) sulfur diesel.

The emission control devices/technologies and their effect on diesel engine emissions are

detailed below. 2 .

The turbocharger.reduces the NOx emission rate from. the engine by approximately 100k by

increasing the efficiency and promoting more complete burning of the fuel.

The intercooler/aftercooler functions in conjunction with the turbocharger to reduce the inlet

air temperature. By reducing the inlet air temperature, the peak combustion temperature is

lowered, which reduces ·the formation of thermal NOx. NOx emissions are reduced by

approximately 15% with this control technology.

The' use of low sulfur (O.0015°A> by weight sulfur maximum) diesel fuel reduces SOx

emissions by approximately gg0A> from standard diesel fuel.

iv. C-3953-14-0 (Natural gas Ie engine powering electrical generator)

The natural gas-fired emergency IC engine (generator) will be equipped with an

intercooler/aftercooier,. lean burn technology, and will be fired on PUC-Regulated natural

gas.

The emission control devices/technologies and their effect on diesel engine emissions are

detailed below.3

The intercooler/aftercooler functions in conjunction with the turbocharger to reduce the inlet

air temperature. By red.ucing the inlet air temperature, the peak combustion temperature is

lowered, which reduces the formation of thermal NOx. NOx emissions are reduced by

approximately 150/0 with this control technology.

Lean burn technology increases the volume of air in the combustion process and therefore

increases the heat capacity of the mixture. This t~chnology also incorporates improved

2 From "Non-catalytic NOx Con~rol of Stationary Diesel Engines", by Don Koeberlein, CARB.

3 From "Non-catalytic NOx Control of Stationary Diesel Engines", by Don Koeberlein, CARB.

8
Avenal Pow~rCenter, LL·C (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

swirl patterns to promote thorough air/fuel mixing. This in turn lowers the combustion

temperature and reduces NOx formation.

VII. 'GENERAL CALCULATIONS:

i. C-3953-10-0_and C-3953-11-0' (Turbines)

• Heating value of natural gas is 1,013 Btu/scf (per applicant).·

• Maximum daily emissions for each CTG for VOC, PM10 and SOx during the

commissioning period are estimated assuming ,twenty-four (24) hours operating

while firing at fuHload.

• The commissioning period will not exceed 408 hours per CTG 'and the emissions

.' ,emitted during the commissioning period will accrue towards the maximum annual

emissions limit.

• Maximum daily emissions for each CTG for NOx, CO, and VOC are estimated

assuming six (6) hours operating in startup and shutdown mode and eighteen (18)

.hours operating while firing at full load with operation of the duct burner.

• Maximum daily emissions for each CTG for 'PM1o, SOx, and NH3 are estimated

assuming twenty-four (24) hours operating while firing at full load with the

operation ·of the duct burner.

• Maximum annual emissions for each eTG for NOx and VOC are estimated

assuming the CTG is .operated according to a weekend and weekday hot start

scenario~ The weekend and weekday hot start scenario results in CTG operatio~

of 547.5 (1.5 hr/hot start x ·365 .hot start/yr) hours operating in startup and

shutdown mode, 800 hours operating while firing at full load with the duct burner,

and 6,683 hours operating while firing at full load without th~ duct burner.

• Maximum annual emissions for eachCTG for CO are estimated assuming the

CTG is operated· according to a weekend .shutdown and weekday hot start

scenario. The weekend shutdown and weekday hot start scenario results in CTG

operation of 624 «1.5 hr/hot start x 208 hot startlyr) + (6.0 hr/cold start x 52 cold

starts/year)) hours operating in startup and shutdown mode, 800 hours operating

while firing at full load with the duct burner, and 3,800 hours operating while firing

at full load withoutthe duct burner.

• Maximum annual emissions for each CTG for PM10, SOx, and NH3 are estimated

assuming the CTG is operated according to a baseload scenario. The baseload

scenario results in CTG operation of 800 hours operating while ·firi.ng at full load

with the duct burner and 7,960 hours operating while firing at full load without the

duct burner.

9
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C~ 1080386

ii. C-3953-12-0 (Boiler)

• External 02 stack gas concentration is 3%.

• Natural gas F factor is 8,710 dscf/MMBtu (Ref. 40 CFR Part 60, Appendix A,

Method 19).

• Heating value of natural gas is 1,013 Btu/scf(per applicant).

.• The applicant is propo~ing a maximum natural gas usage rate of 37.4 MMBtu/hr.

• Maximum SOx emission factor determined by performing a mass balance

assuming a natural gas sulfur content of 1 gr S/1.00 scf. ,Calculation shown below.

(1 gf-S/100 GsGf x 1 19-5/7000 9f x 64 Ib SOx/32 19-5 x 1 SGf/1 013 SW x 106 SW/MMBtu)

= 0.00282 Ib/MMBtu

• Maximum daily and annual emissions for all pollutants are estimated assuming

twelve (12) hours per day and 1,248 hours per year operating at fullload. 4

• Operating schedule of 12 hr/day and 1,248 hrs/year.

.iii. C-3953-13-0 (DiesellC eng'ine powering fire water pump)

• Diesel F factor (adjusted to 60 OF) is 9,051 dscf/MMBtu.

- Density of diesel is 7.1 Ib/gal.

- Higher heating value of diesel is 137,000 Btu/scf.

• BHP to Btu/hr.conversion is 2,542.5 Btu/hp -hr.

• Thermal efficiency of the engine: commonly 350/0.

• .Emissions are. based on 24 hours per day (maximum emergency use) and 50

hours per year of operation (maximum non-emergency use).

iV. C-3953-14-0(Natural gas Ie engine powering electrical generator)

• EPA F-factor (adjusted to 60 OF) is 8,578 dscf/MMBtu (40 CFR 60 Appendix B)

- Fuel heating value 1,013 Btu/dscf (per applicant)

-Maximum daily SOx emission factor determined by performing a mass balance

assuming a natural gas sulfur content of 1 gr S/100 scf. Calculation shown below.

(1 gf-S/100 GsGf x 1 19-5/7000 9f x 64 Ib SOx/32 19-5 x 1 SGf/1 013 SW x 106 SW/MMBtu)

= 0.00282 Ib/MMBtu '

• BHP to Btu/hr conversion is 2,542.5 Btu/hp -hr.

• Thermal efficiency of the engine: commonly 35%.

• Emissions are based on 24 hours per day (maximum emergency use) and 50

hours ·per year of operation (maximum non-emergency use).

. 4 Applicant has indicated that the unit will be used a maximum of 12 hours on a startup day.

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SJVACPO Determination of Compliance, C-1080386

B. Emission Factors

i. C-3953-10-0 and C-3953-11-0 (Turbines)

The maximum air .contaminant mass emission rates (Ib/hr) during the commissioning

period estimated by the facility (see Attachment C) for the proposed CTGs are

summarized below:

Mass Emission Rate

(per turbine, Ib/hr) 160 1,000 16

The maximum air contaminant mass emission rates (Ib/hr) with and without duct burner

firing, concentrations (ppmvd @ 15% O2), and startup and shutdown emissions rates

(Ib/hr) provided by the applicant (see Attachment D for applicant proposed emissions) for

the proposed CTGs are summarized below.

The emission rates from the turbines and duct burners are calculated below:

Maximum Emission Rate Without Duct Burner Firing:

The worst-case NOx, PM10, CO, VOC, and NH3 mass emission rates are when each

turbine operates at 100% load and an ambient air inlet temperature of 32 of. The worstcase sax mass emission rate will be determined assuming a natural gas sulfur content

of 1 gr 8/100 scf. The following equation will be· used to calculate the emission rate of

the CTG without the duct burner firing:

Emission Rate (Ib/hr) =CTG Max Heat Input (MMBtu/hr) x Emission' Factor (lb/MMBtu)

.NOx Emission Rate (Ib/hr) =(1,856.3 MMBtu/hr)x (0.0073 Ib-NOx/MMBtu)

=13.55 Ib-NOx/hr

CO Emission Rate (Ib/hr) =(1,856.3 MMBtu/hr) x (0.0045 Ib-CO/MMBtu)

=8.35 Ib..CO/hr .

VOC Emission Rate (Ib/hr) =(1,856.3 MMBtu/hr) x (0.0018 Ib-VOC/MMBtu)

=3.34 Ib-VOC/hr

PM10 Emission Rate (Ib/hr) =(1,856.3 MMBtu/hr) x (0.0048 Ib·-PM10/M.MBtu)

= 8.91 Ib-PM10/hr

5 PM10 and SOx emissions during commissioning period are equal to the maximum hourly emissions during baseload facility

operation.

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Avenal Power Center,·LLC (OB-AFC-01)

SJVACPD Determination· of Compliance, C-10B0386

SOx Emission Rate (Ib/hr) = (1,856.3 MMBtu/hr) x (0.00282 Ib-SOx/MMBtu)

= 5.23 Ib-SOx/hr

NH3 Emission Rate (Ib/hr) = ppm x MW·x (2.64x10-9

) x ff x HV x FL x [20.9/ (20.9 - O2%)]

Where:

ppm -is the emission concentration in ppmvd @ 150/0 O2 (10 ppmv)

MW is the molecular weight of the pollutant: (MWNH3 = 17 Ib/lb-mol)

2.64 x 10-9 is one over the molar specific·volume (lb-mol/MMscf, at 60 of)

ff is the F-factor for natural gas: (8,578 scf/MMBtu,'at 60 OF)

HV is the heating value of natural gas: (1,013 Btu/set)

FL is the amount of natural gas each turbine can burn in any given hour: (CTG w/o

duct burner 1.832 MMscf/hour, as calculated below)

(1 ,856.3 MMBtu/hr) .::- (1,013 MMBtu/MMsct) =1.832 MMscf/hr

92 is the stack oxygen content to which the emission concentrations are corrected:

(15°~)

NH3 Emission Rate (Ib/hr) =10 x 17 x (2.64x1·0-9

) (lb-mol/MMsct) x 8,.578 (scf/MMBtu) x

1,013 (Btu/set) x 1.832 (MMscf/hr) x [20.9/ (20.9 - 15.0)]

= 25.31 Ib-NH3/hr

Mass Emission Rates 13.55 8.35 3.34 8.91 5.23 25.31

er turbine, Ib/hr

ppmvd @ 15% O2 2.0 2.0 1.4 10.0 limits

Ib/MMBtu* 0.0073 0.0045 0.0018 ·0.0048 0.00282

* Emission factors were taken from Table 6.2-1.1 in the ATe application submittal.

Maximum Emission Rate With Duct Burner Firing:

The worst-case NOx, SOx, PM10, CO,VOC, and NH3 mass emission rates are when

each turbine operates at tOO% load and an ambient air inlet temperature of 101°F. The

worst-case SOx mass emission rate. will be determined assuming a natural gas sulfur

content of 1 gr 8/100 scf. The following equation will be us~d to calculate the e·mission

rate of the CTG with the duct burner firing:

Emission Rate (Ib/hr) :::: [CTG Max Heat Input + Duct Burner Max Heat Input] (MMBtu/hr)

x Emission Factor (lb/MMBtu)

NOx Emission Rate (Ib/hr) =(2,356.5 MMBtu/hr) x (0.0073 Ib-NOxlMMBtu)

=17.20 Ib-NOx/hr

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Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

CO Emission Rate (Ib/hr) = (2,356.5 MMBtu/hr) x .(0.0045 Ib-CO/MMBtu)

=10.60 Ib-CO/hr

voe Emission Rate (Ib/hr) =(2,356.5 MMBtu/hr) x (0.0025 Ib-VOC/MMBtu)

=5.89 Ib-VOC/hr

PM10 Emission Rate (Ib/hr) =(2,356.5 MMBtu/hr) x (0.0050 Ib-PM10/MMBtu)

- =11.78 Ib-PM10/hr

SOx Emission Rate (Ib/hr) =(2,356.5 MMBtu/hr) x (0.00282 Ib-'SOx/MMBtu)

=.6.65Ib-SOx/hr

NH3 Emission Rate (Ib/hr) =ppm x MW x (2.64x1 0-9

) x ff x HV xFL x [20.9 / (20.9 - O2°/0)]

Where:

ppm is the emission concentration ,in ppmvd @ 15% O2 (10 ppmv)

MW is the molecular weight of the pollutant: (MWNH3 = 17 Ib/lb-mol)

2.64 x 10-9 is onE? over the molar specific volume (lb-mol/MMscf, at 60 of)

ff is the F-factor for natural gas: (8,578 scf/MMBtu, at 60 OF)

HV is the heating value of natural gas: (1,013 Btu/set)

FL is the amount of natural gas each turbine can burn in any given hour: (CTG w

duct burner 2.326 MMscf/hour, as calculated below)

(2,356.5MMBtu/hr) + (1,013 MMBtu/MMsct) =2.326 MMscf/hr

O2 is the stack oxygen conte.nt to which the emission concentrations are corrected:

(15%)

NH3 Emission Rate (Ib/hr) = 10 x17 x (2.64x10-9

) (lb-mol/MMsct) x 8.,578 (scf/MMBtu) x

1,013 (Btu/set) x 2.326 (Mrylscf/hr) x [20.9 / (20.9 - 15.0)]

=32.13Ib-NH3/hr

Mass Emission Rates 17.20 10.60 5.89 11.78 6.65 32.13

er turbine, Ib/hr

ppmvd @ 150/0 O2 2.0 2.0 2.0 10.0 limits

Ib/MMBtu* 0.0074 0.0045 0.0025 0.0050 0.00282

* Emission factors were taken from Table 6.2-1.1 in the ATC application submittal.

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Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Maximum Mass

Emission Rate (per 160 1,000 16 N/A(6) N/A(6)

turbine, Ib/hr)

Average Mass

Emission Rate N/A(6) N/A(6) (per 80 900 16

turbine, Ib/hr)

ii. C-3953-12-0 (Boiler)

F·or the new boiler, the emissions factors for NOx, CO, VOC, and PM10 are provided by

the applicant. The SOx emission factor is calculated as shown below.

NOx 9.0 0.011

CO 50.0 0.037

vae 10.0 0.0043

PM10 0.005

SOx** 0.00282

*Note: Ib/MMBtuequivalent of ppmv values @ 3% O2 as provided by the Applicant

** SOx emission factor based ·on the maxir:num proposed sulfur content of 1 gr/100 dscf.

(1 gf-S/1 OO·GsGf x 1 tb-S/7000 9f x 64 Ib SOx/32 tb-S x 1 SGf/1 013 StY x 106 StY/MMBtu)

=0.00282 Ib/MMBtu

iii. C-3953-13-0 (DiesellC engine powering fire water pump)

For the new emergency diesel-fired IC engine powering a fire water pump, the emissions

factors for NOx, CO,VOC, and PM10 are provided by the applicant and are guaranteed'

by the engine manufacturer. The SOx emission factor is calculated using the sulfur

'content in the diesel fuel (0·.0015°J'c> sulfur).

6 PM10 and SOx emissions during startups and shutdowns are lower than maximum hourly emissions during baseloa'd facility

operation.

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Avenal Power Center, LLC (08-AFC~01)

SJVACPO Determination of Compliance, C-1080386

NOx 3.4 ine Manufacturer

eo 0.447 ine Manufacturer

voe 0.38 ine Manufacturer

PM10 0.059 En ine Manufacturer

*SOx 0.005 Mass Balance Equa ion Below

* 7.1Ib· fuel . 21b· S02 1gal 1hp input 2,542.5 Btu 453.6 g g SOx

0.0015% x x --- x x x x = 0.005 -- gallon lib· S 137,000 Btu 0.35 hp out hp· hr lb hp· hr

iv. C-3953-14-0 (Natural gaslC engine powering electrical generator)

For the new' emergency natural gas-fired Ie engine powering an electrical generator, the

emissions factors for NOx, eo, vae, and PM10 are provided by the applicant and are

guaranteed by the engine manufacturer. The SOx emission factor is .calculated using the

fuel sulfur content from District Policy APR 1720.

NOx

co

voe

**SOx 0.0094

ineManufacturer

ine Manufacturer

ine Manufacturer

En ine Manufacturer

Mass Balance Equation Below

**SOx is calculated as follows:

Ib-SOx IMMBtu 2.,542.5 Btu Ibhpinput 453.6g 0.00285 x x . x x --= 0.0094

MMBtu 1,000,000 Btu bhp - hr 0.35 bhp out lb

C~. Calculations

1. Pre-Project Potential to Emit (PE1)

g-SOx

bhp-hr

Section 3.26 of Rule 2201 defines the potential to emit (PE) as the maximum capacity of

an emissions unit to emit a pollutant under its physical and operational design. Since this

is a brand new facility, the pre-project potential to emit (PE1) for all the emissions units

associated with this project is equal to zero.

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SJVACPO Determination of Compliance, C-1080386

2. Post Project Potential to Emit (PE2):

i. C-3953-10-0 and C-3953-11-0 (Turbines)

a. Maximum Hourly PE

The maximum hourly potential to emit for NOx, eO,and voe fro·m each CTG will occur

when the unit is operating under start-up mode. The maximum hourly PE for both

turbines operating together is when both are starting up and firing their duct burners.

The combined startup NOx emissions from the two turbines will be limited .to 240 Ibs/hr

[maximum startup emission rate (160 Ibs/hr) + average startup emission rate (80 Ibs/hr)].

Similarly, the combined startup eo emissions from the two turbines will be limited to

1,902 Ibs/hr, [maximum startup emission rate (1,000 Ibs/hr) + average startup emission

rate (9'02 Ibs/hr)]-. .

The maximum hourly emissions are summarized in the table below:

NOx 160 17.20 13.55 13.55 240.00

CO 1,000 10.60 8.35 8.35 1,902.00

VOC 16 5.89 3.34 3.34 -~ 32.00

PM10 N/A 11.78 8.91 8.91 23.56

SOx N/A 6.65 5.23 5.23 13.30

NH3 N/A 32.13 25.31 25.31 64.26

b. Maximum Daily PE

'Maximum daily emissions for NOx, eo, and voe occurs when each CTG undergoes six

(6) hours operating in startup or shutdown mode, and eighteen (18) hours operating with

duct burner firing at full load. The startup and shutdown emissions for PM10, SOx, and

NH3 are will be lower or equivalent to the emissions rate when the unit is fired at 100%

load; therefore the maximum daily emissions for PM1o, SOx, and NH3 occurs when each

CTG i~operated for twenty four (24), hours with duct burner firing at full load. The results

are summarized in the table below:

7 PM10 and SOx emissions during startups and shutdowns are lower than maximum hourly emissions.

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Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

NOx

eo

voe

sox

c. Maximum Annual PE '

17.201b/hr

10.601b/hr

5.89lb/hr

11.781b/hr

6.65lb/hr

32.131b/hr

13.03 Ib/hr

8.35lb/hr

3.34,lb/hr

8.91 Ib/hr '

5.23lb/hr

25.31 Ib/hr

789.61b/da

5,590.8 Ib/da

202.01b/da

282.71b/da

159.61b/da

771.1 Ib/da

The facility has indicated that the turbines will be operated in one of three different

scenarios: weekend and weekday hot start scenario, weekend shutdown and weekday hot

start scenario, and baseload scenario. The SOx emission factors used to calculate the

annual potential emissions will be based on the applicant proposed average natural gas

sulfur limit 0.36' gr/1'OO dscf.

SOx EF =(0.36 w:-8/1 00 x (1 tb-S/7000.gr:t x (64 Ib SOx/32 x (1 SGf/1 013 Bkltx (106 Btu/MMBtu)

= 0.001 Ib-SOx/MMBtu

eTG w/o Duct Burner Firing:

SOx Emission Rate (Ib/hr) =(1,856.3 MMBtu/hr) x (0.001 Ib-SOx/MMBtu)

=1.86 Ib-SOx/hr

erG wI Duct Burner Firing:

SOx Emission Rate (Ib/hr) =(2,356.5 MMBtu/hr) x (0.001 Ib-SOx/MMBtu)

=2.36 Ib-SOx/hr '

Potential annual emissions for each pollutant will be calculated for each of the three

scenarios in the tables below:

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Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Scenario 1) Weekend and Weekday Hot Start:

547.5 (1.5 hr/hot start x .365 hot start/yr) hours operating in startup and shutdown mode,

800 hours operating while firing at full load with the duct burner, and 6,683 hours

operating while firing at full load without the duct burner. Since startup and shutdown

emission rates for PM10, sax, and NH3 are less than the emission rate when the eTG is

fired at 100% load w/o the duct burner, the startup and ,shutdown emission rates will be

assumed to be equivalent to the CTG fired at 100% load w/o the duct burner. Since the

CTGs will be fired throughout the year, the emission factors for the unit when fired at the

average ambient temperature (630F) will be used to calculate the potential annual

emissions.

NOx 80 Ib/hr (avg) 16~34 'Ib/hr ' 13.031b/hr

CO 900 Ib/hr av 10'.60 Ib/hr 8.35 Ib/hr

VOC 16 Ib/hr (avg) 5.68 Ib/hr 3.17 Ib/hr

PM10 N/A 11.271b/hr 9.001b/hr

sax N/A 2.36 Ib/hr 1.86 Ib/hr

NH3 ,N/A 32.13 Ib/hr 25.31 Ib/hr

* Emission factors were taken from Table 6.2-1.1 in theATC application submittal.

Scenario 2) Weekend Shutdown and Weekday Hot Start:

143,951 Ibl ear

557,0331bl ear

34,489 Ibl ear

74,091 Ibl ear

15,3371bl ear

20'8,708 Ibl ear

624 «1.5 hr/hot start x 208 hot start/yr) + (6.0 hr/cold start x 52 cold starts/year)) hours

operating in startup and shutdown mode, 800 hours operating while firing at full load with

the duct burner, and 3,800 hours operating while firing at full ·Ioad without the duct

burner. Since startup and shutdown emission rates for PM10, SOx, and NH3 are less

than the emission rate when the CTG is fired at 100% load w/o the duct burner, the

startup and shutdown emission rates will be assumed to be equivalent to the CTG fired

at 100% load w/o the duct burner. Since the CTGs will be fired throughout the year, the

··emission factors for the unit when fired at the ave'rage ambient temperature (630F) will

be used to calculate the potential annual emissions.

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Avenal Power Center, LLC (08-AFC-01)

SJVACPD Determination of·Compliance, C-10B0386

112,506 Ibl ear

601,810 Ibl ear

26,574 Ibl ear

48,832 Ibl ear

10,117 Ibl ear

13·7,675Ibl ear

Scenario 3) Baseload:

80.0 hours operating while firing at full load· with the duct burner, and 7,960 hours

operating while firing at full load without the duct burner. Since the CTGs will be fired

throughout the year, the emission factors for the unit when fired at the average ambient

temperature (630

F) will be used to calculate the potential annual emissions.

116,791 Ibl ear

74,9461bl ear

·29,777 Ibl ear

80,656 Ibl ear

16,694 Ibl ear

219,972 Ibl ear

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SJVACPO Determination of Compliance, C-1080386

Maximum Annual Potential to Emit:

The highest annual potential emissions, for· each pollutant, from the three different

scenarios will be taken to determine the maximum annual potential to emit for the CTG.

The results are summarized in the table below:

NOx

co

VOC

sax

143,951 Ibl ear

601,8101bl ear

34,489 Ibl ear

80,656 Ibl ear

16,694 Ibl ear

219,972 Ibl ear

Scenario 1

Scenario 2

Scenario 2

Scenario 3

Scenario 3

Scenario 3

d. Maximum Quarterly PE

Maximum quarterly emissions for each unit will be determined by dividing the maximum

annual emissions into 4 quarters:

15 Quarter

2" Quarter

3r Quarter

4 Quarter

35,987'.75

35,987~75

35,.987.75

35,987.75

150,452.5 8,62,2.25

150,452.5 ,8,622.25

150,452.5 8,622.25

150,452.5 8,622.25.

20,164

20,164

20,164

20,164

4,173.5

4,173.5

4,173.5

4,173.. 5

54,993

54,993

54,993

54,993

ii. C.-3953-12-0 (Boiler)

The potential to emit for the boiler is calculated 'as follows, and summarized in the' table

below.

PENOx = (0.011 Ib/MMBtu) * (37.4 MMBtu/hr)

= 0.41 Ib NOx/hr

= (0.011 Ib/MMBtu) * (37.4 MMBtu/hr) * (12 hr/day)

= 4.9 Ib NOx/day

= (0.011 Ib/MMBtu) * (37.4 MMBtu/hr) * (1,248 hr/year)

= 513 Ib ,NOx/year

= (513 IbNOx/year) + (4 qtr/year)

= 128 IbNOx/qtr

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Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

PEco = (0.037 Ib/MMBtu) * (37.4 MMBtu/hr)

= 1.38 Ib CO/hr

= (0.037 Ib/MMBtu) * (37.4 MMBtu/hr) * (12hr/day)

= 16.6 Ib CO/day

= (0.037 Ib/MMBtu) * (37.4 MMBtu/hr) * (1,248hr/year)

= 1,727 Ib CO/year

= (1,727 Ib COlyear).* (4 qtr/year)

= 432 Ib CO/qtr

PEvoc = (0.0043 Ib/MMBtu) * (37.4 MMBtu/hr)

= 0.16 Ib VOC/hr

= (0.0043 Ib/MMBtu) * (37.4 MMBtu/hr) * (12 hr/day)

= 1.9 Ib VOC/day

= (0.0043 Ib/MMBtu) * (37.4 MMBtu/hr) * (1,248 hr/year)

= 201 Ib VOC/year

= (2011:b/year) * (4 qtr/year)

50lbVOC/qtr

PEpM10 = (0.005 Ib/MMBtu) * (37.4 MMBtu/hr)

= 0.19 Ib PM10/hr

= (0.005 Ib/MMBtu) * (37.4 MMBtu/hr) * (12 hr/day)

= 2.2 Ib PM10/day

= (0.005 Ib/MMBtu) * (37.4 MMBtu/hr) * (1,248 hr/year)

= 233 Ib PM10/year

= (233 Ib/year) * (4 qtr/year)

= 58 Ib PM10/qtr

PEsox = (0.00282 Ib/MMBtu) * (37.4 MMBtu/hr)

= 0.11 Ib SOx/hr

= (0~00282 Ib/MMBtu) * (37.4 MMBtu/hr) *(12 hr/day)

= 1.31b SOx/day

= (0.00282 Ib/MMBtu) * (37.4 MMBtu/hr) * (1,248 hr/year)

= 132 Ib SOx/year

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SJVACPO Determination of Compliance, C-1080386

= (132 Ib/year) * (4 qtr/year)

= 33 Ib SOx/qtr

NOx 0.41 4.9 128 513

eo 1.38 16.6 432 1,727

voe 0.16 1.9 50 201

PM10 0.19 2.2 58 233

sox 0.11 1.3 33 132

iii. C-39'53-13-0 (DiesellC engine powering fire water pump)

The emissions for the emergency fire pump engine is calculated as follows, and

summarized in the table below:

PENOx -- (3.4 g/hp· hr) * (288 hp) ..;- (453.6 glib)

= 2.161b NOx/hr

= (3.4g/hp·hr)* (288 hp) ..;- (453.6 glib) * (24 hr/day)

= 51.8 Ib NOx/day

= (3.4 g/hp·hr) * (288 hp)..;- (453.6 glib) * (12.5 hr/qtr)

= 27 Ib NOx/qtr

= (3.4 g/hp· hr) * (288 hp) ..;- (453.6 glib) * (50 hr/year)

= 108 Ib NOx/year

PEco = (0.447 g/hp· hr) * (288 hp) ..;- (453.6 glib)

= 0.28 Ib CO/hr

= (0.447 g/hp· hr) * (288 hp) ..;- (453.6 glib * (24 hr/day)

= 6.8 Ib CO/day

= (0.447 g/hp· hr) * (288 hp) ..;- (453.6 glib) * (12.5 hr/qtr)

= 41b CO/qtr

= (0.447 g/hp· hr) * (288 hp) ..;- (453.6 glib) * (50 hr/year)

= 14 Ib CO/year

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SJVACPO Determination of Compliance, C-1080386

PEvoc = (0.38 g/hp· hr) * (288 hp) -;- (453.6 glib)

= 0.24 Ib VOC/hr

= (0.38 g/hp -hr) * (288 hp) -;- (453.6 glib) * (24 hr/day)

= 5.8 Ib VOC/day

= (0.38 g/hp -hr) * (288 hp) -;- (453.6 glib) * (12.5 hr/qtr)

= 31b VOC/qtr

= (0.38 g/hp hr) * (288 hp) -;- (453.6 glib) * (50 hr/year)

= 12lbVOC/year

PEpM10 = (0.059g/hp· hr) * (288 hp) -;- (453.6 glib)

= 0.04 Ib PM10/hr

= (0'.059 g/hp -hr) * (288 hp) -;- (453.6 glib) * (24 hr/day)

= 0.9 Ib PM10/day

= (0.059 g/hp hr) * (288 hp) + (453.6 glib) * (12.5 hr/qtr)

= 0.51b PM10/qtr

= (0.059 g/hp-hr) * (288 hp) -;- (453.6 glib) * (50 hr/year)

= 1.9 Ib PM10/year

PEsox = (0.005 g/hp -hr) * (288 hp) -;- (453.6 glib)

= 0.00 Ib SOx/hr

= (0.005 g/hp-hr) * (288 hp) + (453.6 glib) * (24 hr/day)

= 0.1 Ib SOx/day

= (0.005 g/hp-hr) *.(288 hp) -;- (453.6 glib) * (12.5 hr/qtr)

= oIb SOx/qtr

= (0.005 g/hp -hr) * (288 hp) -;- (453.6 glib) * (50 hr/year)

= oIb SOx/year .

NOx 2.16 51.8 27 108

CO· 0.28 6.8 4 14

voe 0.24 5.8 3 12

PM10 0.04 0.9 0.5 2

sax 0.00 0.1 0 0

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Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

iv. C-3953-14-0 (Natural gaslC engine powering electrical generator)

The emissions for the emergency Ie engine is calculated as follows, and summarized in

the table below: '

PENOx = (1.0 g/hp· hr) * (860 hp) + (4~3.6g/lb)

= 1.90 Ib NOx/hr

= (1.0 g/hp· hr) * (860 hp) + (453.6 glib) * (24 hr/day)

= 45.5 Ib NOx/day

= (1.0 g/hp· hr) * (860 hp) + (453.6 glib) * (12.5 hr/qtr)

= 24 Ib NOx/qtr

= (1.0 g/hp·hr) * (860 hp)+ (453.6 glib) * (50 hr/year)

= 95 Ib NOx/year .

PEco = (0.6 g/hp· hr) * (860 hp) + (453.6 glib)

= 1.14IbCO/hr

= (0.6 g/hp· hr) * (860 hp) + (453.6 glib) * (24 hr/day)

= 27.3 Ib CO/day

= (0.6 g/hp· hr) * (860 hp) + (4'53.6 glib) * (12.5 hr/qtr)

= 141b CO/qtr

= (0.6 g/hp· hr) * (860 hp) + (453.6 glib) * (50 hr/year)

- 57 Ib CO/year

PEvoc = (0.33 g/hp·hr).* (860 hp) + (45~.6 glib)

= 0.63 Ib VOC/hr

= (0.33 g/hp· hr) * (860 hp) + (453.6 glib) * (24 hr/day)

= 15.0 Ib VOC/day

= (0.33 g/hp· hr) * (860 hp) + (453.6 glib) * (12.5 hr/qtr)

= Sib VOC/qtr

= (0.33g/hp· hr) * (860 hp) + (453.6 glib) * (50 hr/year)

= 31 IbVOC/year

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SJVACPD Determination·ofCompliance, C-1080386

PEpM10 = (0.034 g/hp· hr) * (860 hp) + (453.6 glib)

= 0.061b PM10/hr

= (0.034g/hp·hr) * (860 hp) + (453.6 glib) * (24 hr/day)

= 1.5 Ib PM10/day

= (0.034 g/hp·hr) * (860 hp) + (453.6 glib) * (12.5 hr/qtr)

= 1 Ib PM10/qtr

= (0.034 g/hp· hr) * (860 hp) + (453.6 glib) * (50 hr/year)

= 3 Ib PM10/year

PEsox = (0.0094 g/hp· hr) * (860 hp) + (453-.6 glib)

= 0.02 Ib SOx/hr

= (0.0094 g/hp· hr) * (860 hp) + (453~6 glib) * (24 hr/day)

= 0.4 Ib SOx/day

= (0.0094 g/hp· hr) * (860 hp) + (453.6 glib) * (12.5 hr/qtr)

= oIb SOx/qtr

= (0.0094 g/hp· hr) * (860 hp) + (453.6 glib) * (50 hr/year)

= 1 Ib SOx/year

NOx

co

voe

SOx

1.90

1.14

0.63

0.06

0.02

45.5

27.3

15.0

1.5

0.4

24

14

8

1

o

95

5-7

31

3

1

3. Pre-Project Stationary Source Potential to Emit (SSPE1)

Pursuant to Section 4.9 of District Rule 2201, the Pre-project Stationary Source Potential _

to Emit (SSPE1) is the Potential to Emit (PE) from all units with valid Authorities to

Construct (ATG) or Permits to Operate (PTO) at the Stationary Source and the quantity

of emission reduction credits (ERG) which have been banked since September 19, 1991

for Actual Emissions Reductions that have occurred at the source, and which have not

been uS.ed on-site. Since this is a new facility, there are no valid ATGs, PTOs, or ERGs

at the Stationary Source; therefore, the SSPE1 will be equal to zero.

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SJVACPO Determination of Compliance, C-1080386

4. Post-Project Stationary Source Potential to Emit (SSPE2)

Pursuant to Section 4.10 of District Rule 2201, 'the Post Project Stationary Source

Potential to Emit (SSPE2) is the Potential to Emit (PE) from all units with valid Authorities

to Construct (ATC) or P'ermits to Operate (PTa) at the Stationary Source and the

quantity of emission reduction credits (ERC) which have been banked since September

19,1991 for Actual Emissions Reductions that have occurred at the source, and which

have not been used on-site. '

C-3953-10-0 143,951 601,810 34,489 80,656 16,694 219,972

C,-3953-11-0 ' 143,951 601,810 34,489 80,656 16,694 219,972

C-3953-12-0 513 1,727 201 233 132 ° C-3953-13-0 108 14 12 2 ° C-3953-14-0 95 57 31 3 1

°

0

Post-project SSPE 288,618 1,205,418 69,222 161,550 33,521 439,944 (SSPE2)

5. Major Source Determination

Pursuant t9 Section 3.24 of District Rule 22°1, a major source is a stationary source with

post-project emissio'ns or a Post-project Stationary Source Potential to Emit (SSPE2),

equal to or exceeding one or more, of the following threshold-values.

1,205,418

200,000

Yes

6. Annual Baseline Emissions (BE)

Per District Rule 2201, Section 3.7, the baseline ·emissions, for a given pollutant, shall be

equal to the pre-project potential to emit for:

• Any emission unit located at a non-major source,

• Any highly 'utilized emission unit, located at a major source,

• Any fully-offset emi~sion unit, located at a major source, or

• Any clean emission unit located at a majorsource

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Avenal Power Center, LLC(OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

otherwise·,

BE = Historic Actual Emissions (HAE), calculated pursuant to Section 3.22 of District

Rule 2201

·Asshown above, this facility will be a major so.urce for NOx, CO, VOC, and PM10

emissions after this project. However, since the units in this project are all new

emissions units, there are no historical actual emissions or pre-project potential to emit.

Therefore, the baseline NOx, CO, VOC, PM10 and sax emissions will be set equal to the

following:

BE =0 Ib/year

7. Major M·odification

Major Modification is defined in 40 CFR Part 51.165 as "any physical change in or

change in the method of operation of a major stationary source that would result in a

.significant net emissions increase of any pollutant subject to regulation under the Act."

. Since this isa n·ew facility, this project cannot be considered a Major Modification.

8. Federal Major Modification

As shown above, th·is. project 'does not. constitute a Major Modification. Therefore, in.

accordance with District Rule 2201 , Section 3.17, this project does not constitute a

Federal Major Modification 'and no further discussion is required.

VIU. COMPLIANCE:

Rule 10BO Stack Monitoring

This Rule grants .the APGO the authority to request the installation and use of continuous

emissions monitors (GEMs), and specifies performance standards for the equipment and

administrative requirements for recordkeeping, re.porting, and notification.

i. C-3953-10-0 and .C-3953-11-0 (Turbines)

The two GTGs will be equipped with operational GEl\lls for NOx, CO, and 02. 'Provisions

included in the operating permit are consistent with the requirements of this Rule.

Compliance with the requirements of this Rule is anticipated.

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Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Proposed Rule 1080 Conditions:

• The owner or operator shall install, certify, maintain, operate and quality-assure a

Continuous Emission M'onitoring System (CEMS) which continuously measures

and records the exhaust gas NOx, CO and 02 concentrations. Continuous

emissions monitor(s) shall be capable of monitoring emi.ssions during normal

operating conditionsJ. and during startups and shutdowns., provided the CEMS

passes the relative accuracy requirement for startups and s'hutdowns specified

herein. If relative accuracy of CEMS cannot be demonstrated during startup'

conditions, CEMS results during startup and shutdown events shall'be replaced

'with startup emission rates obtained from source testing to determine compliance

with emission limits contained in this document. [District Rules 1080 and 4703

.and 40 CFR 60.4340(b)(1)]

• The CEMS shall complete a minimum of one cycle of operation (sampling,

analyzing, and data recording) .for each successive 15-minute period or shall meet

equivalent specifications established by mutual agreement of the District, the ARB

and the EPA. [District Rule 1080 and 40 CFR 60.4345(b)]

• The NOx, CO and O2 CEMS shall meet the requirements. in 40 CFR 60, Appendix

F Procedure 1 and Part 60, Appendix. B Performance Specification 2 (PS 2), or

shall meet equivalent specifications established by mutual agreement of the

District, the ARB, and the EPA. [District Rule' 1080 'and 40' CFR 69.434.5(a)]

• Audits of continuous emission monitors shall be conducted quarterly, except

during quarters in which relative accuracy and compliance source testing are both

performed, in accordance with EPA guidelines. The District shall be notified prior

to completion of the audits. Audit reports shall be submitted along with quarterly

compliance reports to the District. [District Rule 1080]

• The owner/operator shall perform a relative accuracy test audit (RATA) for NOx,

CO and O2 as specified by 40 CFRPart 60, Appendix F, 5.11, at least once every

four calendar quarters. The permittee shall comply with the applicable

requirements for quality assurance testing and maintenance of the continiJous

emission monitor equipment in accordance with the procedures and guidance

specified in 40 CFR Part 60, Appendix F. [District Rule 1080]

• APCO or an authorized representative shall be allowed to inspect, as determined

to be necessary, the required monitoring devices to ensure that such devices are

functioning properly. [District Rule 1080]

• Results of the CEM system shall be av~raged over a one hour period for NOx

emissions and a three hour period for CO emissions using consecutive 15-minute

sampling periods in accordance with all applicable requirements of CFR 60.13.

[District Rule 4703 and 40 CFR 60.13]

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Avena/Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

• Results of continuous emissions monitoring shall. be reduced according to the

procedures established in 40 CFR, Part 51, Appendix P, paragraphs 5.0 through

5.3.3, or by other method.s deemed equivalent by mutual agreement with the

District, the ARB, and the EPA. [District. Rule 1080]

• ·The owner or operator shall,upon written notice from the APCO, provide a

.summary of the data obtained from the CEM systems. This summary shall be in

the form and the manner prescribed by the APCO. [District Rule 1080]

• The facility shall install and maintain equipment,facilities, and systems compatible

with the District's CEM data polling software system and shall make CEM data

available to the District's automated polling system on a daily basis. [District Rule

1080]

• Upon notice .by the District that the facility's CEM system is not providing polling

data, the facility may continue to operate without providing automated data for a

maximum of 30 days per calendar year provided the CEM data is sent to the

District by a District-approved alternative method. [District Rule'1 080]

• The permittee shall maintain the following records:' the date, time and .duration of

any m·alfunction of the continuous monitoring equipment; dates of performance

testi.ng; dates of evaluations., calibrations, checks, .and adjustments of the

continuous monitoring equipment; date and time peri'od which a continuous

monitoring system or monitoring device was in,operative. [District Rules 1080 and

2201 and 40 CFR 60.8(9)]

• The owner or operator shall submit a written report of CEM operations for each

calendar quarter to the APCO. The report is due on the 30th day following the end

of the calendar quarter and shall include the following: Time intervals, data and

magnitude of excess NOx emissions, nature and the cause of excess (if known),

corrective actions taken and 'preventive measures adopted; Averaging period used.

for data reporting corresponding to the averaging period specified in the emission

te~t period used to determine compliance with an emission standard; Appl,icable

time and date of each period during which theCEM was inoperative (monitor

downtime), except for zero and span checks, and the nature of system repairs and

adjustments; A negative declaration when no excess emissions occurred. [District

Rule 1080 and 40 CFR 60.4375(a) and 60.4395] \"

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Avenal Power Center, LLC (08-AFC';'01)

SJVACPD Determination·ofCompliance, C-10B0386

ii. C-3953-12 (Boiler)

The boiler will be equipped with operational CEMs for NOx, CO, and 02. Provisions

included in the operating permit are consistent with the requirements of this Rule.

Compliance with the requirements of this Rule is anticipated.

Proposed Rule 1080 Conditions:

• {1832} The exhaust stack shall be equipped with a continuous emissions monitor

(CEM) for NOx., CO, and 02. The CEM shaH meet the requirements of 40 CFR parts

60 and 75 and shall be capable of monitoring emissions during startups and shutdowns

as well as during normal operating conditions. [District Rules 2201 and 1080]

• {1833} The' facility shall install and maintain equipment, facilities, and" systems

compatible with the District's GEM data polling software system and shall make CEM

data available to the District's automated pollin·g system on a daily basis. [District Rule

1080]

• {1834} Upon notice by the District that the facility's CEM system is not providing poUing

data, the facility may continue to \operate" without providing automated data for a

maximum of 30 days per ·calendar year provided the GEM data is sent to the District by

a I;)istrict-approved alternative method. [District Rule 1080]

• {1836} Results of continuous emissions monitoring shall be reduced according to ·the

procedure established in 40 GFR, Part 51, Appendix P,paragraphs 5.0 through 5~3.3,

or by other methods deemed equivalent by mutual agreement with the District, the

ARB, and the EPA. [District Rule 1080]

• {1837} Audits of continuous emission monitors shall be conducted quarterly,except

during quarters in which relative accuracy and total accuracy testing is performed, in

accordance with EPA guidelines. The District shall be notified prior to completion of the

audits. Audit reports shall be submitted along with quarterly compliance reports to the

District. [District Rule 1080]

• {1838} The owner/operator shall perform a relative accuracy test audit (RATA) as

specified by 40 CFR Part 60, Appendix F, 5.11, at least once evety four calendar

quarters. The permittee" shall comply with the applicable requirements for quality

assurance testing and maintenance of the continuous emission monitor equipment in

accordance with the procedures and guidance specified in 40 CFR Part 60, Appendix

F. [District Rule 1080] . .

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Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

• {1839} The permittee shall submit a written report to· the APCO for each calendar

quarter, within 30 days ·of the end of the quarter, including: time intervals, data and

ma'gnitude of excess emissions, nature and cause of excess emissions· (if known),

corrective actions taken and preventive measures adopted; averaging period used for

data reporting .shall correspond to the .averaging period for each respective emission

standard; applicable time and date of each period during which the C.EM was

inoperative (except for zero and span checks) and the nature of system repairs and

adjustments; and a negative declaration when no excess emissions occurred. [District

Rule 1080]

Rule 1081 Source Sampling

This RuJe requires adequate 'and safe facilities for use in sampling to determine

. compliance with emissions limits, and specifies methods and .procedures for source

testing and sample collection.

i. C-3~53-1 0-0 .and C-3953-11-0 (Turbines)

The requirements of this Rule will be included in the operating permits. Compliance with

this Rule is anticipated.

Proposed Rule 1081 Conditions:

• The exhaust stack shall be equipped with permanent provisions to allow collection

of stack gas samples consistent with EPA test methods and shall be equipped

with safe permanent provisions to sample stack gases with a portable NOx, CO,

and 02 .analyzer during District inspections. The sampling ports shall be located

in accordance with the CARB regulation titled California. Air Resources Board Air

Monitoring Quality Assurance Volume VI, Standard Operating Procedures for

Stationary Emission Monitoring and Testing. [District Rule 1081]

• Source testing to measure startup NOx, CO, and VOCmass emission rates shall

be conducted for one of the gas turbines (C-3953-10 or C-3953-11) pri"or to the

end of the commissioning period and at least once every seven' years thereaft~r.

GEM relative accuracy shall be determined during startup source testing in

accordance with 40 CFR 60, Appendix B. [District Rule 1081]

• Source testing (with and without duct burner firing) to measure the NOx, CO, and

VaG emission rates (Ib/hr and ppmvd @ 15°1'<> 02) shall be conducted within 60

days after the end of the commissioning period and at least once every twelve

months thereafter. [District Rules 1081 and 4703]

31 .
Avenal Power Center, LLC (OB-AFC-01)

SJVACPD Determination of Compliance, C-10803'86

• Source testing. (with and without duct burner firing) to measure the PM10 emission

rate (Ib/hr) and the ammonia emission rate shall be conducted within 60 days after

the end of the commissioning period and at least once every twelve months

thereafter. [District Rule 1081]

• Compliance with natural gas sulfur content limit shall be demonstrated within 60

.days after the end of the commissioning period and weekly thereafter. After

demonstrating compliance with the fuel sulfur content limit for 8 consecutive

weeks for a fuel source, then the testing frequency shall not be less than monthly.

If a test shows noncompliance with the sulfur content requirement,the source

must return to weekly testing until eight- consecutive weeks show compliance.

[District Rules 1081,2540, and 4001]

• Demonstration of compliance with the annual average ·sulfurcontent limit shall be

demonstrated by a 12 month rolling average of. the sulfur content either· (i)

documented in a valid purchase contract, a supplier certification, a tariff sheet or

transportation contract or (ii) tested using .ASTM Methods D1072, D3246, 04084,

04468, 0481-0,D6228, 06667 or Gas Processors· Association Standard 2377.

[District Rules 1081 and 2201]

• Compliance demonstration (source testing). shall be District witnessed, or

authorized and samples shall be collected by a California Air Resources Board

certified testing laboratory.. Source testing shall be conducted using the methods

and procedures approved ·by the District. The District must be notified 30 days

prior to any compliance source test, and a source test plan must be submitted for

approval 15 days prior to testing. The results of each source test shall be

submitted to the District within 60 days thereafter. [District Rule 1081]

• The following test .methods shall ·be used: NOx - EPA Method 7E ·or 20; CO - EPA

Method 10 or 10B;VOC - EPA Method 18 or 25; PM10 - EPA Method 5 (front half

and back half) or 201 and 202a; ammonia - BAAQMD ST-1B; and O2 - EPA

Method 3·, 3A, or 20. EPA approved alternative test methods as approved by the

District may also be used to address the source testing requirements of this

permit. [District Rules 1081 and 4703 and 40 CFR 60.4400(1 )(i)]

32
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

ii. ' C-3953-12-0 (Boiler)

The requirements of this Rule will be included in the operating permit. Compliance with

this Rule is 'anticipated.

Proposed Rule 1081 Conditions:

• The exhaust stack shall be equipped with permanent provisions to allow collection

of stack gas samples consistent with EPA test methods and shall be equipped

with safe permanent provisions to sample stack gases with a portable NOx, CO,

and 02 analyzer during District inspections. The sampling ports shall be located

in accordance with the CARB regulation titled California Air Resources Board Air,

Monitoring Quality Assurance Volume VI, Standard Operating Procedures for

S~ationary Emission Monitoring and Testing. [District Rul'e 1'081]

• {tOg} Source testing shall be conducted using the methods and procedures

approved by the District. The District m,ust be notified at least 30 days prior to any

compliance source test, and a source test plan must be submitted for approval at

least 15 days prior to testing. [District Rule 1081]

• {110} The results of each source test shall be submitted to the District within 60

days thereafter. [District Rule 1081 ]

Rule 1100 Equipment Breakdown

This Rule defines a breakdown condition and the procedures to follow if one occurs. The

. corrective action, the issuance of an emergency -variance, and the reporting requirements

are also specified.

i. C-3953-10-0 and.C-3953-11-0 (Turbines)

The requirements of this Rule will be included in the operating permits. Compliance with

this Rule is anticipated.

Proposed Rule 1100 Conditions:

• Permittee shall notify the District of any breakdown condition as soon as

reasonably possible, but no later than one hour after its detection, unless the

owner or operator demonstrates to the District's satisfaction that, the longer

reporting period was necessary. [District Rule 1100, 6.1]

33
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SJVACPO Determination of Compliance, C-1080386

• The District shall be notified in writing within ten days following the correction of

any, breakdown condition. The breakdown' notification shall include a description

of the equipment malfunction or failure, the date and cause of the initial failure, the

estimated emissions in excess of those allowed, and the methods utilized to

restore normal operations. [District Rule 1100,7.0]

Rule 2010 Permits,Required

This Rule requires any person building', altering, or replacing any operation" article,

machine, equipment, or other contrivance, the use of which may cause the issuance of air

contaminants, to first obtain authorization from the District in the form of an ATC.By the

submission of an ATC application, Avenal Power Center, LLC is complying with the

requir~ments of this Rule.

Rule 2201 New and Modified Stationary Source Review Rule

A. BACT:

1. BACT Applicability

BACT requirements are triggered on a poll~tant-by-pollutant basis and on an emissions

unit-by-emissions unit basis for the following*:

a. Any new emissions unit with a potential to emit exceeding two pounds per day,

b. The relocation from one Stationary Source to another of an existing emissions unit

with a potential to emit exceeding two pounds per day,

c. ' Modifications to an existing emissions unit with a valid Permit to Operate resulting' in an

,AIPE exceeding two pounds per day, and/or

d. Any new or modified emissions unit, in a stationary source project, which results in a

Major Modification.

*Except for CO emission's from a new or modified emissions unit at a Stationary Source with an SSPE2 of

less than 200,000 pounds per year of CO.

i. C-3953-10-0 and C-3953-11-0 (Turbines)

As seen in Section, VII.C.2.b of this evaluation, the applicant is proposing to install two

new combustion turbine generators with PEs greater than 2 Ib/day for NOx, CO, VOC,

.PM10, and SOx. BACT is triggered for NOx, CO, VOC, PM1o, and SOx criteria pollutants

since the PEs are greater than 2 Ibs/day, and since the SSPE2 for CO is greater than

200,000 Ibs/year, as demonstrated in Section VII.C.5 of this document.

The PE of ammonia is greater than two pounds per day for the two CTGs. However, the

ammo,nia emissions are.intrinsic to the operation of,the SCR system, which is BACT for

NOx. The emissions from a control device that is determined by the District to be BACT

are not subject to BACT.

34
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

ii. C~3953-12-0 (Boiler)

As seen in Section VII.C.2 of this evaluation, the applicant is proposing to install a new

boiler with a PE greater than 2 Ib/day for NOx, CO, voe, PM10, and SOx. BACT is

triggered for NOx, CO, VOC, and PM10 criteria pollutants since the PEs are greater than

2 Ibs/day, and si'nce the SSPE2 for CO is greater than 200,000 Ibs/year, as

demonstrated in Section VII.C.S of this document.

iii. C-3953-13-0 (DiesellC engine powering fire water pump)

As seen in Section VII.C.2 of this evaluation, the applicant is proposing to install a new

diesel-fired IC engine (fire pump) with a PE greater than 2 Ib/day for NOx, CO, and VOC.

BACT is triggered for NOx, CO, and. VOC criteria pollutants since the PEs are greater

than 2 Ibs/day, and since the SSPE2 for CO is greater than 200,000 Ibs/year," as

demonstrated in Section VII.C.S of this document.

iv. C-3953-14-0 (Natural gas IC engine powering electrical generator)

As seen in SectionVILC.2of this evaluation, the applicant is proposing to install a new

natural gas.-fired IC engine (generator) with a PE greater than 2 Ib/day for NOx, CO, and

VQC. BACT is triggered for NOx, CO, and VOC criteria pollutants since the PEs are

greater than 2 Ibs/day, and since the SSPE2 for CO is greater than 200,000 Ibs/year, as

demonstrated in Section VII.C.5 of this document.

2. BACT Guidance

The District BACT Clearinghouse was created to assist applicants in selecting

appropriate control technology for new and modified sources, and to assist the District

staff in conducting the necessary BACT analysis. The Clearinghouse will include, for

various class and category of sources, available control technologies and methods that

meet one or more of the following conditions:

• Have been achieved in practice for such emissions unit and class of source; or

• Are contained in any SIP approved by the EPA for such emissions unit category and

class of source; or

• 'Are any other emission limitation or control technique, including process and

equipment changes of basic or control equipment, found to be technologi·cally

feasible for such class or category of sources or for a specific source.

Attachment E will include the BACT Guidelines from the BACT Clearinghouse applicable

to the new emissions units associated with this project.

35
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

i. C-3953-10-0 and C-3953-11-0 (Turbines)

BACT Guideline 3.4.2 is applicable to the two combustion turbine generator installations

[Gas Fired Turbi"ne =or > 50 MW, Uniform Load, with Heat Recovery].

ii. C-3953-12-0 (Boiler)

f3ACT Guideline 1.1.2 is applicable to the 37.4 MMBtu/hr boiler. [Boiler - > 20 MMBtu/hr,

Natural gas-fired, base-loaded or with small load swings.]

iii. C-3953-13-0 (DiesellC engine powering fire water pump)

BACT Guideline 3.1.4, applies to the diesel-fired emergency IC engine powering a fire

pump. [Emergency Diesel Lc. Engine Driving a Fire Pump]

iVa C-3953-14-0 (Natural gas IC engine powering electrical generator)

BACT Guideline 3.1.8, applies to the natural gas-fired emergency Ie engine powering an

electrical generator. [Emergency Gas-Fired I.C. Engine> or =250 hp, Lean Burn]

3. Top-Down Best Available Control Technology (BACT) Analysis

Per Permit Services Policies and Procedures for BACT, a Top-Down BACT analysis shall

be performed as a part of theapplic·ation review for each appli-cationsubject to the BACT

requirements pursuant to the District's NSR Rule.

For Permit Units C-3953-10-0 and -11-0 see Attachment F.

For Permit Unit C-3953-12-0 see Attachment F.

For Permit Unit C-3953-13-0 see Attachment F.

For Permit Unit C-3953-14-0 see Attachment F.

4. BACT Summary:

i. C-3953-10-0 and C-3953-11-0 (Turbines)

BACT has been s.atisfied by the following:

NOx: 2.0 ppmv @ 15% O2 (1-hour rolling average, except during startup/shutdow.n) with

Dry Low NOx Combustors, SCR with ammonia injection and natural gas fuel.

co: 2.0 ppmv @ 15% 02 (3-hour rolling average,. except during startup/shutdown) with

an Oxidation Catalyst and natural gas fuel.
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determinati9n of Compliance, C-1080386

VOC: 1.5 ppmv @ 15% O2 (without duet burner firing;3-hour rolling average).

2.0 ppmv @ 15% O2 (with duct burner firing; 3-hr rolling average).

PM10: Air inlet 'filter cooler, lube oil vent coalescer, and natural gas fuel

sox: 'PUC regulated natural gas with a sulfur content of 1.0 gr/1 00 sef or less

ii. C-3953-12-0 (Boiler)

BACT has been satisfied by the following:

NOx: 9.0 ppmv @ 15°A, O2 with Ultra Low NOx burners and'natural gas fuel.

co: Natural gas fuel.

VOC: Natural gas'fuel.

PM10: Natural gas fuel.

sox: Natural gas fuel.

iii. C-3953-13-0 (DiesellC engine powering fire water pump)

BACT has been satisfied by the following:

NOx: Certified NOx emissions of 6.9 g/hp· hr or less

co: No CO control. Any add on cq control device would void the Underwriters

Laboratory (UL) certification.

voc: No' vac control. Any add on VOC control device would void the Underwriters

Laboratory (UL) certification.

iv. C-3953-14-0 (Natural gas Ie engine powering electrical generator)

BACT has been satisfied by the following:

NOx: =or < 1.0 g/bhp-hr (lean burn natural gas fired engine, or equal)

co: 90% control efficiency (oxidation catalyst, or equal)

VOC: 90% control efficiency (oxidation. catalyst, or equal)

37
Avenal Power Center, LLC(08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Therefore, the following condition will be listed on the DOC to ensure compliance:

• {3492} Th"is Ie engine shall be equipped with a three-way catalyst. [District Rule

2201 ]

C. Offsets:

1. Offset Applicability:

Pursuant to Section 4.5.3, offset requirements shall be triggered on a pollutant by

pollutant basis and shall be required if the Post-project Stationary Source Potential to

Emit (SSPE2) equals to or exceeds emissions of 20,000 Ibs/year for NOx and VOC,

200,000 Ibs/year for CO, 54,750 Ibs/year for SOx and 29,200 Ibs/year for PM10. As seen

in the table below, the facility's SSPE2 is greater than the" offset threshold"s for NOx,CO,

VOC, PM10, and sax emissions. ·Therefore, offset calculations are necessary.

1,205,418

200,000

Yes

2. Quantity of Offsets Required:

Per District Rule 2201, Section 4.6.1, emission offsets shall not be required for increases

in carbon mo"noxide in attainment areas if the applicant demonstrates to the satisfaction

of the APeD, that the Ambient Air Quality Standards are not violated in the areas to be

affected, and such emissions will be consistent with Reasonable Further Progress, and

will not cause or contribute to a violation of Ambient Air Quality Standards.

As shown in section VIII.G below, the increase in CO emissions associated with this

stationary source project does not cause or contribute to a violation of Ambient Air

Quality Standards. CO emissions are n9t addressed in any Reasonable Further

Progress Plans. Therefore, this stationary source project qualifies for the offset

exemption listed in Section 4.6.1.

Per Sectiqns 4.7.2 and 4.7.3, the quantity Of offsets in pounds per yearfo~ NOx, CO,"

vac, and PM10 is calculated as follows for sources with an SSPE1 less than the offset

threshold levels before implementing the project being evaluated.

38
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination· of Compliance, .C-1080386

Offsets Required (Ib/year) = ([SSPE2 Offset Threshold] + ICCE) x DOR, for all new or

modified emissions units in the project,

Where,

SSPE2 = Post Project Facility Potential to Emit, (Ib/year)

ICCE ::: Increase in Cargo Carrier Emissions, (Ib/year)

DOR = Distance Offset Ratio, determined pursuant to Section 4.8

Per Section 4.6.2, emergency equipment that is used exclusively as emergency standby

equipment for electrical power generation' or any other emergency equip'ment as

approved by the APCO that does not operate more than 200 'hours per year of nonemergency purposes and is not used pursuant to voluntary arrangements with a power.

supplier to curtail power, is exempt from providing emission offsets. Therefore, permit

units C-3953~13-0 and C-3953-14-0 will be exempt from providing offsets, and the

emissions associated with these' permit units contributing to the SSPE2 should be

removed prior to calculating actual offset amounts.

, Offset =([SSPE2 - Emergency Equipment - Offset Threshold] + ICCE) x DOR, for all

new or modified emissions units in the project,

NO~ Offset Calculations:

NOx SSPE2 = 288,6181b/year

C-3953-13-0 (NOx) = 108 Ib/year

C-395.3-14-0 (NOx) = 95lb/year

NOx offset threshold = 20,000 Ib/year

Offsets = [288,618 - (108) - (95) - 20,000]

= 268,415 Ib/year * DOR

Calculating the appropriate quarterly emissions to be offset is as follows:

Offsets = (268,415 Ib/year + 4 qtr/year) * DOR

= 67,103.75Ib/qtr'* DOR

PE1stOtr = 67,103.75Ibs of NOx * DOR

PE2ndOtr= 67,103.75Ibs of NOx * DOR

PE3rd Otr = 67.,103.75 Ibs of NOx * DOR

PE4th Otr = 67,103.75 Ibs of NOx * DOR

Pursuant to Section 4.8 of District Rule 2201" the distance offset ratio shall be 1.0:1 if the

emission offsets originated at the same Stationary Source as the new or modified

emissions unit; 1.2.1 for Non-Major Sources if the emission offsets originated within 15

miles of the new or modified emissions unit's Stationary Source; 1.3.1 for Major Sources

if the emission offsets originated within 15 miles of the new or modified emissions unit's

39
Avenal Power Center, LLC(08-AFC-01)

SJVACPD Determination of Compliance, C~1080386

Stationary Source; or 1.5:1 if the emi~sion offsets originated 15 miles or more from the

new or modified emissions unit's Stationary Source.

Assum~ng a worst case offset ratio of 1.5:1, the amount of NOx ERG's that need to be

withdrawn is:

Offsets Required =268,415 Ib-NOx/year x 1.5

Offsets Required =402,623 Ib-NOx/year

Ca'iculating the appropriate quarterly emissions to be offset is as follows:

NOx

,Th'e applicant has stated that the facility plans to use ERC certificates C-899-2, C-902-2,

N~720-2, N-722-2, N-726-2, ,N-728-2, 8-2814-2, and S-2321-2 to offset the increases in

NOx emissions associated with this project. The above Certificates have available

quarterly NOx credits as follows:

*ERC certificate split from this ERe.

2,243

8,539

437

1,422

o

5,171

11,461

51,000

2,243

1,086

1,255

88,317

4,728

2,487

18,914

51,000

1,166

o

3,731

2,243

6,131

-9

13,869

51,000

6,121

51,000

o

o

10,542

2,243

13,879

o

ERC #C-899~2

ERC #C-902-2

ERC #N-720-2

ERC #8-2814-2

ERC #S-2321-2*

ERC #N-722-2

ERC #N-726-2

ERC #N-728-2

Project NO~ offset requirements

The applicant states that NOx ERC certificates C-899-2, C-902-2, N-720-2, N-722-2, N726-2, N-728-2,S-2814-2, and 8-2321-2 will be utilized to supply the NOx offset

requirements.

Per Rule 2'201 Section 4.13.8, Actual Emission Reductions (i.e. ERCs) that occurred

from April through Nove~ber (i.e. 2nd and 3rd Quarter), inclusive, maybe used to offset

increases in NOx or VOC during any period of the year. 8ince 3rd quarter NOx ERCs will

be used to offset NOx emissions, the above applies to the NOx ERCs.

40
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

NOx Emissions to be offset: (at a 100,655 100,656 100,656 100,656 1.5:1 DOR):

Available ERCs from certificates

C-899-2,C-902-2, N-720-2, N- 83,784 78,147 170,027 80,269 722-2, N-726-2, N-728-2, S2814-2, and 8-2321-2*:

3rd qtr. ERCs applied to 1st qtr. 16,871 0 -16,871 ERGs: °

3rd qtr. ERCs applied to 2nd qtr. ° 22,509 -22,509 ERGs: °

3rd qtr. ERGs applied to 4th qtr. 0 ° -20,387 20,387 ERGs:

Remaining ERGs from 0 ° 9,604 certificates 8-2321-2: °

Remaining NOx emissions to be ° 0 ° ° offset (at a 1.5:1 DOR):

As seen above, the facility has sufficient credits to fully offset the quarterly NOx , emissions increases associated with this project.

voe Offset Calculations:

vaG 8SPE2 =69,222 Ib/year

G-3953-13~0 (VOG) =12 Ib/year

G-3953-14-0 (VOG) = 31 Ib/year

VOG offset threshold = 20,000 Ib/year

Offsets =[69,222 - (12) - (31) - 20,000]

=49,179 Ib/year * DOR

Calculating the appropriate quarterly emissions to be offset is as follows:

Offsets =(49,179 Ib/year -:- 4 qtr/year) * DOR

=12,294.75 Ib/qtr* offset ratio

PE1st Qtr = 12,294.75 Ibs of VOG * DOR

PE2nd Qtr = 12,294.75 Ibs of voe * DOR

PE3rdQtr = 12,294.75Ibs ofVOC * DOR

PE4th Qtr =' 12,294.75Ibs ofVOC * DOR

'41
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Pursuant to Section 4.8 of District Rule 2201, the distance offset ratio shall be 1.0:1 if the

emission offsets, originated at the same Stationary Source as the new or modified

emissions unit; 1.2.1 for Non-Major Sources if the emission offsets originated within 15

miles of the new or modified emissions unit's Stationary Source; 1.3.1 for Major Sources

if the emission· offsets originated within 15 miles of the new or modified emissions unit's

Stationary Source; or 1.5:1 if the emission offsets originated .15 'miles or more from the

new or modified emissions unit's Stationary Source.

Assumi,ng a worst case offset ratio of 1.5:1, the amount of VaG ERG's that need to be

withdrawn is:

PE1st Qtr = 12,294.75 Ibs of VaG * 1.5 =18,442 Ibs

PE2nd Qtr= 12,294.75 Ibs of vaG * 1.5 =18,442 Ibs .

PE3rd Qtr = 12,294.75 Ibs of vaG * 1.5 = 18,442 Ibs

PE4th Qtr = 12,294.75 Ibs of vae * 1.5= 18,442 Ibs

Calculating the appropriate quarterly emissions to be offset is as follows:

vac

The applicant has stated that the' facility plans to use ERG certificates G-897-1, C-898-1,

N-724-1, N-725-1, S-2812-1, S-2813-1, and S~2817 -1 to offset the increases inVOC

emissions associated with this project. The above Certificates have available quarterly

VaG credits as follows: .

ERC #C-897-1 45 45 45 45

ERG #C-898-1 5,480 6,496 4,696 6,616

ERC #N-724-1 O' 0 241 0

ERG #N-725-1 0 0 709 0

ERC#S-2812-1 31,432 31,424 31,417 31,417

ERC #S-2813-1 12,500' 12,500 12,500 12,500

ERC#S-2817-1 11,431 11,424 11,417 11',417

42
Avenal Power Center, LLC (OB-AFC-01)

, SJVACPD Determination of Compliance, C-10B0386

Project vac offset requirements

The, applicant states th'at ,Nax ERC certificates C-897-1, C-898-1, N-724-1, N-725-1, 5-2812-

1,5-2813-1, and 8-2817-1 will be utilized to supply theVOC offset requirements.

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

vac Emissions to be offset: (at a 18,442 18,442 18,442 18,442 1.5:1 DaR):

Available ERCs from certificates

C-897-1, C-898-1, N-724-1, N- 5,525 6,541 5,691 6,661

725-1,

Remaining vac emissions to be 12,917 11,901 12,751 11,781 offset (at a1.5: 1 DaR):

vac Emissions to be offset: (at a 12,917 11 ,901 12,751 11,781 1.5:1 DOR):

Available ERCs from certificates

8-2812-1, 8-281'3-1, and 8-2817- 55,363 55,348 55,334 55,334

1

Remaining ERCs from

certificate's 8-2812-1, 8-2813-1, 42,446 43;447 42,583 43,553

and 8-2817-1:

Remaining vac emissions to be 0 0 0 0 offset (at a 1.5:1 DaR):

'As seen above, the facility has sufficient credits to fully offset the quarterly VOC emissions

increases associated with this project.

PM10 Offset Calculations:

PM10 88PE2 =161 ,545lb/year

C-3953-13-,O (PM10) =2 Ib/year

C-3953-14-0 (PM10) =3 Ib/year

PM10 Offset threshold =29,200 Ib/year

Offsets =[(161,545 - (2) - (3) - 29,200 + 0) x DOR]

=1.32,340 Ib/year x DOR

Calculating the appropriate quarterly emissions to be offset is as follows (in Ib/qtr):

Offsets =(132,340 Ib/year -;- 4 qtr/year) * DOR

=33,085 Ib/qtr * offset ratio

43
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

PE1st Qtr = 33,085 Ibs of PM10 * DOR

PE2nd Qtr =33,085 Ibs of PM10 * DOR

PE3rd Qtr = 33,085 Ibs of PM10 * DOR

PE4th Qtr = 33,085 Ibs of PM10 * DOR

. The applicant is proposing to use ERG Certificates C-894-4, N-721-4, N-723-4, N~762-5,

8-2788-5, 8-2789-5, 8-2790-5, and 2791-5 which have an original site of reduction

.greater than 15 miles from the location of this project. Therefore, a distance offset ratio

of 1.5:1 is applicable and the amount of PM10 ERCs that need to be withdrawn is:

Offsets Required (Ib/year) .= 132,3401b/year x 1.5

= 198,510 Ib/year

Calculating the appropri~t~ quarterly emissions to be offset is as follows (in Ib/qtr):

The applicant has stated that the facility plans to use ·ERC ce.rtificates C-894-4, N-721-4,

. N-723~4, N-762-5, 8-2788-5, 8-2789-5, 8-2790-5, and 2791-5 to offset the increases in

PM10 emissions associated with this project. The. applicant has purchased the following

quarterly amounts of the above certificates:

ERC #C~896-4

ERC #N-721-4

ERC #N-723-4

ERC #8-2791-·5

ERC #8-2790-5

ERC #8-2789-5

ERC #8-2788-5

ERC #·N-762-5

80 80 80 80 ° °

3,215 0

°0 985 0

92,179 23,666 69,157 96,288

12,862 491 a 8,499

6 14 12 8

5 7 3 6

21,000 21 ,000 21,000 21,000

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Avenal Power Center, LLC(OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Project PM10 0ffset requirements

The applicant states either PM10 ERC certificates G-894-4, N-721-4;· N-723-4, N-762-5,

8-2788-5, 8-2789-5, ·S-2790-5, and 2791-5 will be utilized to supply the PM10 offset·

requirements.

1st Quarter 2nd Quarter 3fd Quarter 4th Quarter

. PM10 Emissions to be offset: (at a

1.5:1 ratio):

Available ERCs from certificates

C-896-4, N-721-4, and N-723-4:

ERCs applied from certificates

C-896-4, N-721-4, and N-723-4 fully

. withdrawn as certificates C-896-4,

N-721-4, and N-723-4:

Remaining ERCs from certificate

C-896-4, N-721-4, and N-723.;.4:

Remaining PM10 emissions to be

offset (at a 1.5:1 ratio):

49,630

80

-80

o

49,550

49,629

80

-80

a

49,549

4,280

-4,280

o

45,349

49,630

80

-80

a

49,550

Per Rule 2201 Section 4.13.3.2, interpollutant offsets ·between PM10 a.nd PM10

precursors (i.e. SOx) may be ~lIowed. The applicant is proposing to use interpollutant

offsets SOx for PM10 at an interpollutant ratio of 1.0:1 (see Attachment H). Per Rule

220·1 Section 4.13.7, Actual Emission Reductions (i.e. ERGs) that occurred from October

through March (i.e. 1st and 4th Quarter), inclusive, may be used to offset increases inPM

during any period of the year. Since the SOx ERC·s are being used to offset PM10

emissions, the above applies to the SOx ERGs.

In addition, the overall offset ratio is equal to the multiplication of the distance and

. interpollutant ratios (1.5 x 1.000 =1.5).

45
·Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

Remaining PM10 Emissions to be 49,550 49,549 45,349 49,550 offset: (at a 1.5:1 ratio):·

Remaining PM10 emissions to be

offset with SOx ERGs (at a 1.5:1 49,550 49,549 45,349 49,550 distance ratio and a 1.000:1

interpollutant SOX:PM10 ratio):

Remaining ERGs from certificates

N-762-5, 8-2788-5, 8-2789-5,. and 33,873 21,512 21,015 29,513

8-2790-5:

Remaining ERGs from certificates

N-762-5, 8-2788-5, 8-2789-5, and ° ° 0

8-2790-5:

°

Remaining PM10 emissions to be

offset (at a 1.5:1 ratio and a 1.000:1 15,677 28,037 24,334 20,037

interpollutant SOX:PM10 ratio):

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

Remaining PM10 Emissions to be

offset: (at a 1.5:1 distance ratio and 15,677 28,037 24,334 20,037 a 1.000:1 interpollutant 80x:PM10

ratio):

Remaining ERGs from certificate 92,179 23,666 69,157 96,288 S-2791-5:

1SLqtr. ERGs applied to 2nd qtr. . -4,371 4,371 0

° ERGs:

Adjusted Remaining ERGs from 87,808 28,037 69,157 96,288 certificate 8.-2791-5:

Remaining PM10 emissions to be

offset (at a 1.5:1 ratio and a 1.000:1 15,677 28,037 24,334 20,037

interpollutant SOX:PM10 ratio):

ERGs applied from certificate 15,677 28,037 24,334 20,037 8-2791-5 partially withdrawn:

Remaining ERGs from certificate 72,131 0· 44,823 76,251 8-2791-5:

As seen above, the facility has sufficient credits to fully offset the quarterly SOx and PM10

emissions increases associated with this project.

46
Avenal Power Center, LLC (08-AFC-01)

SJVACPD Determination of Compliance, C-10B0386

Offset Conditions:

The following conditions will ensure c0rr:'pliance with the offset requirements 9f this rule:

• Prior to initial operation of C-3953-10-0, C-3953-11-0, and C-3953-12-0, permittee

shall provide NOx (as N02) emission reduction credits for the following quantities

of emissions: 1st quarter, - 67,103 Ib;2nd quarter - 67,104 Ib; 3rd quarter -

67,104 Ib; and 4th quarter - 67,104 lb. Offsets shall be provided at the

a,ppropriate distance ratio specified in Rule 2201. [District Rule 2201]

• Prior to initial operation of C-3953-10-0, C-3953-11-0, and C-3953-12-0, permittee

shall provide voe emission reduction credits for the following quantities of

emissions: 1st quarter - 12,294 Iq; 2nd quarter - 12,295 Ib; 3rd quarter - 12,295

Ib; and 4th quarter - 12,295 lb. Offsets shall be 'provided at the appropriate

distance ratio specified in Rule 2201. [District Rule 2201]

• Prior to initial operation of C-3953~10-0, C-3953-11-0, and C-3953-12-0, permittee

shall provide PM10 emission reduction credits for the following quantities of

emissions: 1st quarter - 3'3,087Ib; 2nd quarter - 33,086 Ib;.3rd quarter - 33,086

Ib;and 4th quarter - 33,086 lb. Offsets shall be provided at the appropriate

distance ratio specified in Rule 2201.' 80x ERC's may be used to offset PM10

increases at an interpollutant ratio of 1.0 Ib-80x ': 1.0 Ib-PM1 O. [District Rule 2201]

• ERC certificate numbers (or any splits from these certificates) C-897-1, C-898-1,

N-724-1, N-725-1, 8-2812-1, 8-2813-1, 8-2817-1, C-899-2, ,C-902-2, N-720-2, N722-2, N-726-2, N-728-2, 8-2814-2,8-2321-2, C-896-4, N-721-4, N~723-4, 8-

2791-5, 8-2790-5, 8-2789-5, 8-2788-5, or N-762-5 shall be used to s'upply the

required 'offsets, unless a revised offsetting proposal is received and approved by

the District, upon which this determination of compliance (DOC) shall be reissued,

administratively specifying the new offsetting proposal. Original public noti,cing

.requirements, if any, shall be duplicated prior to reissuance of the DOC. [District

Rule 2201]

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Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

D. Public Notification:

1. Applicab'ility

District Rule 2201, section 5.4, requires a public notification for the affected pollutants

from th'e following types of projects:

• New Major Sources

• Major Modifications

• New emission units with a PE > 100 Ib/day of anyone pollutant (IPE Notifications)

• Any project which results in the offset thresholds being surpas.sed (Offset

Threshold Notification), 'and/or

• Any permitting action with a SSIPE exceeding 20,000 Ib/yr for anyone pollutant.

(SSIPE Notice)

a. New Major Source Notice Determination

.New Major Sources are new facilities, which are also Major Sources.

As shown in Section VII.C.6 above, the SSPE2 is greater tha~ the Major Source

thresh,old for NOx, CO, voe., and PM10. Therefore, public noticing is required for this

project for new Major Source purposes because this facility is becoming a new Major

Source.

'b. Major Modification

As demonstrated .in Section'VII.C.? ab'ove, this project does not constitute a Major

'Modification; therefore, public noticing for Major Modification purposes is not required.

c. PE Notification

Applications which include a new emissions unit with a Potential to Emit greater than

100 pounds during anyone day for any pollutant will trigger public noticing

requirements. The potential to emit for each unit is summarized in the table below.

48
· . Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

C-3953-10-0 789.6 5,590.8 202.0 282.7 159.6 771.1

C-3953-11-0 789.6 5,590.8 202.0 282.7 159.6 771.1

C-3953-12-0 4.9 16.6 1.9 2.2 1.3 0

C-3953-13-0 51.8 6.8 5.8 0.9 0.1 0·.

C-3953-14-0 45.5 27.3 15.0 1.5 0.4 0

Threshold (Ib/da ) 100 100 100 1.00 100 100

According to the table above, permit units C-3953-10-0 and -11-0 will each have a

Potential to Emit greater than 100 Ib/day for NOx, CO, VOG, PM10, SO~, or NH3

emissions. Therefore, publi.c noticing will be required for PE > 100 Ibs/day purposes.

e. Offset Threshold

Public notification is required if the Pre-Project Stationary Source Potential to Emit

(SSPE1) is increased from a level below the offset threshold to a level exceeding the

emissions 'offset threshold, for any pollutant.

The following table compares the SSPE1 with the SSPE2 in.order to determine if any

offset thresholds have been surpassed with this project.

NOx

° 288,618 20,000 Ib/year Yes

eo 0 1,205,418 200,0001b/year Yes

vae ° 69,222 20,000 Ib/year Yes

PM10 ° 161,550 29,2001b/year Yes

SOx 0 33,521 54,750 Ib/year No

As detailed above, offset thresholds were surpassed for NOx, CO, VOG, and PM10

em.issions with this project; therefore public noticing is required for offset purposes.

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Avenal Power Center, LLC (08-AFC-01)

SJVACPO 'Determination of Compliance, C-1080386

f. SSIPE Notification

Public notification is required for any permitting action that results in a Stationary

Source Increase in Permitted Emissions (SSIPE) of more than 20,000 Ib/year of any

affected pollutant. According to District policy, the SSIPE is calculated as the Post

Project Stationary Source Potential to Emit (SSPE2) minus the Pre-Project Stationary

Source Potential to Emit (SSPE1), Le. SSIPE = SSPE2 - SSPE1. The values for

SSPE2 and SSPE1 are calculated according to Rule 2201, Sections 4.9 and 4.10,

respectively. The SSIPEis compared to the SSIPE Public Notice thresholds in the

following table:

Pollutant ,SSPE2 SSPE1 SSIPE ,SSIPE Public Public Notice

(Ibl ear) (Ibl ear) (Ibl ear) Notice Threshol'd Required?

NOx 288,618 ° 288,618 20,000 Ibl ear Yes

GO 1,205,418 ° 1,205,418 20,0001bl ear Yes

VOG 69,222 ° 69,222 20,0001bl ear Yes

PM10 161,550 ° 161,550 20,000 Ibl ear Yes

SOx ,33,521 ° 33,521 20,000 Ibl ear Yes

As demonstrated above, the SSIPE's for NOx,GO, VOG, PM10 and SOx emissions

were greater than 20,OOOlb/year; therefore public noticing for SSIPE purposes is

required.

2. Public Notice Requirements

Section 5.5 details the actions taken by the District when pubic noticing is triggered

according to the application types above., Since public noticing requirements are

triggered for this project (Le. New Major Source, PEls > 100 Ibs/day, offset thresholds

being exceeded, and SSIPEs greater than 20,000 Ibs/year), the District shall public

notice this project accordin'g to the requirem,ents of Section 5.5.

E. Daily Emission Limits:

Daily' emissions limitations (DELs) and other enforceable conditions are required by

Section 3.15 to re~trict a unit's maximum daily emissions, to' a level at or below the

emissions associated with the maximum design capacity. Per Sections 3.15.1 and

3.15.2, the DEL must be contained in the latest ATe and contained in or enforced by the

latest PTOand enforceable, ina practicable manner, on a daily basis.

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SJVACPO Determination of Compliance, C-1080386

Proposed Rule 2201 (DEL) Conditions:

i. C-3953-10-0 and C-3953-11-0 (Turbines)

For the turbines, the DELs for NOx, CO, VOC, PM10, sax, and NH3 will consist of Ib/day

and/or emission factors.

• Emission rates from this unit (with duct burner firi·ng), except during startup and·

shutdown periods, shall not exceed any of th.e following limits: NOx (as N02) -

17.201b/hr and 2.0 ppmvd @ 15% 02; vac (as methane) - 5.89 Ib/hr and 2.0

ppmvd @ 15°;002; CO - 10.60 Ib/hr and 2.0 ppmvd @ 15% 02; PM10 -11.78

Ib/hr; or SOx (as S02) - 6.65 Ib/hr. NOx (as N02) emission .Iimits are one hour

rolling averages. All other emission limits are three hour rolling averages. [District

Rules 2201,4001, and 4703]

• Emission rates from this unit (without duct burner firing), except.during startup and

shutdown periods, shall not exceed any of the following limits: NOx (as N02) -

13.55 Ib/hr and 2.0 ppmvd @ 15°;0 02; voe (as methane) 3.34 Ib/hr and 1.4

ppmvd @ 15°;0 02; CO -8.35Ib/hr and 2.0 ppmvd @ 150/0 02; PM10 - 8.91 Ib/hr;

or SOx (as S02) - .5.23 Ib/hr. NOx (as N02) emission limits are one hour rolling

averages. All other emission limits are three hour rolling averages. [District Rules

.2201, 4001, and 4.703]

• During start-up and shutdown, CTG exhaust emission rates shall not exceed any

of the following limits:NOx (as N02) - 160 Ib/hr; CO - 1,000 Ib/hr; VOC (as

methane) - 16 Ib/hr; PM10 - 11.78 Ib/hr; SOx (as S02) - 6.652 Ib/hr; or NH3 -

32.13 Ib/hr. [District Rules 2201 and 4703]

• Daily emissions from the CTG shall not exceed the following limits: NOx (as N02)

- '412.8 Ib/day; CO - 254.4 Ib/day; voe - 141.4 Ib/day; PM10 - 282.7 Ib/day; SOx

(as 802) -159.6Ib/day, or NH3 -771.1 Ib/day. [District Rule 2201]

• Emissions from this unit, on days when a startup andlor shutdown occurs, shall

not exceed the following limits: NOx (as N02) - 789.6 Ib/day; voe - 202.0 Ib/day;

CO - 5,590.8 Ib/day; PM10 - 282.7 Ib/day; SOx (as S02) - 159.6 Ib/day, or NH3 -

771.1 Ib/day. [District Rule 2201]

• The ammonia (NH3) emissions shall not exceed 10 ppmvd @ 150/0 02 over a 24

hour rolling average. [District Rule' 2201]

• The CTG shall be fired exclusively on PUC-regulated natural gas with a sulfur

content no greater than 1.0 grain of sulfur compounds (as S) per 100 dry sef of

natural gas. [District Rule 2201 and 40 CFR 60.4330(a)(2)]

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SJVACPO Determination of Compliance, C-1080386

• Annual average of the sulfur content of the eTG shall not exceed 0.36 grain of

sulfur compounds(as S) per 100 dry scf of natural gas. [District Rule 2201]

In addition to the daily emissions limits specified above, the following conditions will also

'be inclu.ded. to ensure continued compliance for the proposed turbines:

. • Annual emissions from the CTG, calculated on a twelve month rolling basis, shall

not exceed any of the following limits: NOx (as N02) - 143,951 Ib/year; CO -

601,810 Ib/year; VOC - 34,489 Ib/year; PM10 - 80,656 Ib/year; or sax (as S02)-

16,694Ib/year; or NH3 - 208,708 Ib/year. [District Rule 2201]

• Each one hour period shall commence on the hour. Each one hour period in a

.three hour rolling average will commence on the hour. The ttiree hour average

will be compiled from the three most recent one hour periods. Each one hour

period in a twenty-four hour average for ammonia slip will commence on the hour.

[District Rule 2201]

• Daily emissions will be compiled for a twenty-four hour period starting and ending

at twelve·-midnight. Each month in the twelve consecutive month rolling average

emissions shall commence at the beginning of the first day of the month. The

twelve consecutive month rolling average emissions to determine compliance with

annual emissions limitations shall be com.pi.led from the twelve most recent

calendar months. [District Rule 2201]

ii. C-3953-12-0 (Boiler)

The DELs for the boiler will consist of Ib/MMBtu 'and- ppmv emissions I-imits. This will be

sufficient to establish a maximum daily potential to emit based on the maximum daily fuel

use limit.

• Emission rates from this unit shall not exceed any of the following limits: NOx (as

N02) - 9.0 ppmvd @ 3% .02 or 0.011 Ib/MMBtu; VOC (as methane) - 1O~O ppmvd

@ 3% 02; CO - 50.0 ppmvd @ 3% 02 or 0.037 Ib/MMBtu; PM10 - 0.005

Ib/MMBtu; or SOx (as S02) - 0.00282 Ib/MMBtu. [District Rules 2201,4305,4306,

and 4351]

In addition the following permit conditions will appear on the permit:

• {2964} The unit shall only be fired on PUC-regulated natural gas. [District Rule

2201]

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SJVACPO Determination of Compliance, C-1080386

iii. C-3953-13-0 (DiesellC engine fire pump)

For the emergency IC engine powering a fire pump, the DELs will be stated in the form of

emission factors, the maximum,engine horsepower rating, and the maximum operational

time of 24 hours per day.

• Emissions from this IC engine sh,all not exceed any of the following limits: 3.4 gNOx/bhp-hr, 0.447 g-CO/bhp-hr, or 0.38 g-VOC/bhp-hr. [District Rule 2201 and 13

CCR 2423 and 17 CCR 93115]

• Emissions from this IC engine shall not exceed 0.059 g-PM10/bhp-hr based on

USEPA certification using ISO 8178 test procedure. [District Rules 2201 and 4102

and 13 CCR 2423 and 17 CCR 93115]

• {3395} Only CARB certified diesel fuel containing not more than 0.0015% sulfur by

weight is to be used. [District Rules 2201 and 4801 and 17CCR93115]

iv. C-3953-14-0'(Natural gas Ie engine electrical generator)

F'or the emergency Ie engine p,owering a generator, the DELs will be stated in the form

of emission factors, the maximum engine horsepower rating, and the maximum

operational time of 24 hours per day.

• Emissions from this IC engine shall not exceed any of the following limits: 1.0 gNOx/bhp-hr, 0.034 g-PM10/bhp-hr, 0.6 g-CO/bhp-hr, or 0.33 g-VOC/bhp-hr.

[District Rule 2201]

• {3491} T,his IC engine shall be fired on Public Utility Commission (PUC) regulated

natural gas only. [District Rules 2201 and 4801] ,

F. Compliance Certification:

Section 4.1'5.2 of this Rule requires the owner of a new major source or a source

undergoing a major modification to demonstrate to the satisfaction of the District that all

other major sources owned by such person and operating in California are in compliance

with all applicable emission limitations and standards. As discussed above, this facility is

, a new major source; therefore this requirement is applicable. Included in Attachment I is

Avenal Power Center's certification for the Avenal Energy Project.

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SJVACPO·Determination of Compliance, C-1080386

G. Air Quality Impact Analysis:

Section 4.14.2 of this Rule requires that an air quality impact analysis (AQIA) be

conducted for the purpose of determining whether the operation of the proposed

equipment will cause or m.ake worse a vio.lation of an air quality standard. The Technical·

Services Division of the SJVAPCD conducted the required analysis. Refer to Attachment

G of this document for the AQIA summary sheet.

The AQIA performed for this project was analyzed ba·sed on the facility's preliminary

proposal. The facility originally proposed CO emissions from the two CTG's to be limited

to 4.0 ppmvd @ 15% O2. However,. due to comments made during the public notice

period, the facility limited their CO emissions to 2.0 ppmvd @ 15% 02. Since the new

proposed emission .factor is lower than the original emission factor and will not result ·in an

increase in air pollutants, a new AQID will not be required to be performed for this project.

The proposed location is in an attainment area for NOx, CO, and SOx. As shown by the

. table below, the proposed equipment will not cause a violation of an air quality standard

for NOx, CQ, or SOx.

Pollutant 1 hr Average 3hr Average 8 hr Ave~age 24 hr Annual

Average Average.

CO Pass N/A Pass N/A N/A

NOx Pass N/A N/A N/A Pass

SOx Pass .Pass N/A Pass Pass

The proposed location is in a non-attainment area for PM10. The increase in the ambient

PM10 concentration due to the proposed equipment is shown on the table titled·

Calculated Contribution. The levels of significance, from 40 CFR Part 51.165· (b)(2), are

shown on the table titled Significance Levels.

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SJVACPO Determination of Compliance} C-1080386

As shown, the calculated contribution of PM'10 will not exceed the EPA significance level.

This project is not expected to cause or make worse a violation of an air quality

standard.

H. Compliance Assurance:

1. Source Testing

i. C-3953-10-0 and C-3953-11-0

District 'Rule 4703 requires NOx and CO emission testing as well as percent turbine

efficiency testing on an annual basis. The District Source Test Policy (APR. 1705

10/09/97) requires annual testing for all pollutants controlled by catalysts. The control

equipment will include a SCR system and an oxidation catalyst. Ammonia s·lip is an

indicator of how well the SCR system is performing and PM10 emissions are a good

indicator of how well the inlet air cooler/filter are performing.

Therefore, source testing for NOx', CO, vac, PM10, and ammonia slip will be required

within 60 days after the end of the commissioning period and at least once every 12

months thereafter. .

Also; initial source testing of NOx, CO, and VOC startup emissions will be required for

one gas turbine engine initially and not less than every seven years thereafter. This

testing will serve two. purposes: to validate the startup emission estimates used in the

emission calculations and to verify that the CEMs accurately measure startup emissions.

Each CTG will have a separate exhaust stack. The units will be equipped with CEMs for

NOx, CO, and O2. Each CTG will be equipped with an individual CEM. Each CEM will

have two ranges to allow accurate measurements of NOx and CO emissions during

startup. The CEMs must meet ·the installation, performance, relative accuracy, and

quality assurance requirements specified in 40 CFR 60.13 and Appendix B (referenced

in the CEM requirements of Rule 4703) and the acid rain requirements in 40 CFR Part

75.

40 CFR Part 60 subpart, KKKK requires that. fuel sulfur content be documented or

monitored. Refer' to the monitoring section of this document for a discussion of the fuel

sulfur testing requirements.

40 CFR Part 60 subpart Db requires NOx testing for the' duct burners~ The District will

accept the NOx source testing required by District Rule 4703 as equivalent to NOx testing

re'quired by 40 CFR 60 subpart Db.

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SJVACPO Determination of Compliance, C-1080386

ii. C-3953"712-O

This unit is subject to District Rule 4305, Boilers, Steam Generators and Process

Heaters, Phase 2, and District Rule 4306, Boilers, Steam Generators and Process

Heaters, Phase 3. Source testing requirements,in accordance with District Rules 4305

and 4306, will be discussed in Section VIII, District Rules 4305 and 4306, of this

evaluation.

iii. C-3953-13-0 and C-3953-14-0

Pursuant to District Policy APR 1705, source testing is not required for emergency

standby IC engines to demonstrate compliance with Rule 2201.

2. Monitoring

i. C-3953-10-0 and C-3953-11-0

Monitoring of NOx emissions is required by District Rule 4703. The applicant has

proposed a CEMS for NOx.

CO monitoring is not specifically required by any applicable Rule or Regulation.

.Nevertheless; due to erratic CO emission concentrations during start-up and shutdown

periods, it is necessary to limit the CO emissions· on a pound per hour basis. Therefore,

a CO CEMS is necessary to show compliance with the CO limits of this permit. The

applicant has proposed a CO CEMS.

40 CFRPart 60 Subpart KKKK and District Rule 4703 requires monitoring of the fuel

consumption. Fuel consumption monitoring will be required.

40CFR Part 60 Subpart KKKK requires monitoring of the fuel sulfur content. The gas

supplier, Pacific Gas & Electric (PG&E), may deliver gas with a sulfur content of up to 1.0

grlscf. Since the sulfur content of the natural gas would not exceed this value, it is

District practice to allow the facility to demonstrate compliance with the limit by providing

gas purchase contracts, supplier certification, tariff sheet or transportation contract; or, if

these documents cannot be provided, physically monitor the fuel sulfur content weekly

for eight ·consecutive weeks and semi-annually thereafter if the fuel sulfur content

remains below 1.0 grlscf. Avenal Power Center, LLC will be operating these turbines in

complia.nce with the fuel sulfur content monitoring requirements as described in the Rule

4001, Subpart KKKK· discussion below. Therefore, compliance with the monitoring

requirements will be satisfied.

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SJVACPO Determination of Compliance, C-1080386

ii. C-3953-12-0

As required by District Rule 4305, Boilers, Steam Generators and Process Heaters,

Phase 2, and District Rule 4306, Boilers, 'Steam Generators and Process Heaters, Phase

3, this unit is subject to monitoring requirements. Monitoring requirements, in

accordance with District Rules 4305 and 4306, will be discussed in Section VIII, District

Rules 4305 and 4306, of this ·evaluation.

iii.. C-3953-1'3-0 and C-3953-14-0

No monitoring is required to demonstrate compliance with Rule 2201.

3. Recordkeeping

i. C-3953-10-0 and C-3953-11-0

The applicant will be required to keep records of all of the parameters that are required to

. be monitored. Refer to section VIII.F.2 of this document for a discussion of the

. parameters that will be monitored.

ii. C-3953-12-0

As required by District 'Rule 4305, Boilers, Steam Generators and Process Heaters,

Phase 2, and District Rule 4306, Boilers, Steam Generators and Process Heaters, Phase

3, this unit is subject to recordkeeping requirements. Recordkeeping requirements, in

accordance with District Rules 4305 and 4306, will be discussed in Section VIII, District

Rules 4305 and 4306, of this evaluation.

The following permit condition will be listed ~n permit as follows:

• All records shall be maintained and· retained on-site for a minimum of fi"ve (5)

years, and shall be made available for District inspection upon request. [District

f3ules 1070, 4305, and 4306]

iii. C-3953-13-0 and C-3953-14-0

Recordkeeping is required to' demonstrate compliance with the offset, public notification,

and daily emission limit requirements of Rule 2201. As required by District Rule 4702,

Stationary Internal Combustion Engines - Phase 2, these Ie engines are subject to

.recordkeeping requirements. Recordkeeping requirements, in accordance with District

Rule 4702, will be discussed in Section VIII, District Rule 4702, of this evaluation.

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"Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-10803"86

4. Reporting

i. C-3953-10-0 and C-3953-11-0

40 CFR Part.60 Subpart KKKK requires that the facility report the use of fuel with a sulfur

content of more than 0.8%by weight. Such reporting will be required.

40 CFR Part 60 Subpart KKKK requires the reporting of exceedences of the NOx

emission limit of the permit. Such reporting will be required.

ii. C-3953-12-0

No reporting is required to demonstrate compliance with Rule 2201.

iii. C-3953-13-0 and C-3953-14-0

No reporting is required to demonstrate compliance with Rule 2201.

Rule"2520 Federally Mandated"Operating Permits

'This project will be subject to Rule 2520 (Title V) because it will meet the following criteria

specified in section 2.0:

• "Section 2.3 states, "Any major source." The facility will be a major source for NOx., CO,

VOC, and PM10 after this project.

• Section 2.4 states, "Any emissions unit, including an area source, subject to a standard

or other requirement promulgated pursuant to section 111 (NSPS) or 112 (HAPs) of the

CAA..." The turbines are subject to NSPS.

• Section 2.5 states "A source with an acid ra'in unit for which application for an acid rain

permit is required pursuant to Title IV (Acid Rain Program) of the CAA." The turbines

are subject to the acid rain program.

• Section 2.6 states, "Any source required to have a preconstruction review permit

pursuant to the requirements of the prevention of significant deterioration (PSD)

program under Title I of the Federal Clean Air Act." This facility is required to obtain a

PSD permit from the EPA.

Pursuant to Rule 2520 section 5.3.1 Avenal Power Center must submit a Title V

application within 1"2 months of commencing operations. No action is required at this

time.

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SJVACPO Determination of Compliance, C-1080386

• Permittee shall submit an. application to comply with SJVUAPCD O·istrict Rule

2520 - Federally Mandated Operating Permits within twelve months of

commencing operation. [District Rule 2520]

Rule 2540 Acid Rain Program

The proposed CTG's are subject to the acid rain program as phase II units, Le. they will

be installed after 11/15/90 ·and each has a generator nameplate rating greater than 25

MW.

The acid rain program will be implemented through a Title V operating permit. Federal

regulations require submission. of an acid rain permit application at least 24 months

before the later of 1/1/2000 or the date the unit expects ·to generate electricity. The

facility anticipates beginning commercial operation in November of·2011.

The acid rain program requirements for this facility are relatively minimal. Monitoring of

the NOx and ·SOxemissions and a relatively small quantity of SOx allowances (from a

national SOx allowance bank) will be required as well as the use of a NOx CEM.

The following condition will be placed on permits C-3953-10-0, ~11-0 and -14-0 to ensure

thatAvenal Power Center, LLC submits an applicati.on to comply with the requirements of

the acid rain program within the appropriate timeframe: .

• Permittee shall submit an application to comply with SJVUAPCO Oistrict Rule

2540 - Acid Rain Program. [District Rule 2540]

Rule 2550 Federally Mandated Preconstruction Review for Major Sources ofAir

Taxies

SeGtion 2.0 states, "The provisions of this rule shall only apply to applications to construct

or reconstruct a major air toxies source with Authority to Construct issued on or after June

28, 1998."· The applicant has provided the following analysis for Noncriteria

pollutants/HAPs.

Noncriteria pollutants are compounds that have been identified as pollutants that pose a

significant health· hazard. Nine of these pollutants are regulated under the Federal New

Source Review program:· lead, asbestos, beryllium, mercury, fluorides, sulfuric acid mist,

hydrogen sulfide, total reduced sulfur, and reduced sulfur compounds. 8

In addition to these nine compounds, the federal Clean Air Act lists 189 substances as

potential hazardous air pollutants (Clean Air Act Sec. 112(b)(1»). The SJVAPCD has

also published a list of compounds it defines as potential toxic air contaminants (Toxics

8 These pollutants are regulated under federal and state air quality programs; however,. they are evaluated as noncriteria

pollutants by the California Energy Commission (CEC).

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Avenal Po.wer Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Policy, May 1991; Rule 2-1-316). Any pollutant that may be emitted from the project and

is on the federal New Source Review List, the federal Clean ·Air Act list, and/or the

SJVAPCD toxic air contaminant list has been evaluated.

Noncriteria pollutant emission factors for the analysis of emissions from the gas turbines

were. obtained from AP-42 (Table 3.1-3, 4/00, and Table 3.4-1 of the Background

Document for Section 3.1), from the California Air Resources Board's CATEF database

for gas turbines, and from source tests on a similar turbine. Specifically, factors for all

pollutants except formaldehyde, hexane, propylene, and naphthalene and other PAHs

were taken from AP-42.:9 AP-42 did not contain factors for hexane or propylene, and did

not include speciated data for PAHs. Factors for these pollutants and for naphthalene

were taken from the CATEF database (mean values). The 'emission factor for

formaldehyde was taken from the results of· a June 2000 source test on a dry Low NOx

combustor-equ'ippedlarge frame turbine..

Hazardous Air Pollutant Emissions (perCATEF)

Avenal Energy Project - GE Frame 7 (with Duct Burners)"

CATEF Maximum Hourly Maximum Annual Maximum Annual

Hazardous Air Pollutant Emission Factor Emissions per Emissions per Emissions both

(lb/MMSCF)(1) Turbine (Ib/hr) (2) Turbine. (tpy) (3) Turbines (tpy) ..

· Aq~!~l~~!l'yq~ . !!.J~~~__Q? 9_·9_~ Q:.~~ 9.:?! _ Acrolein 3.69E-03 0.01 . 0.03 6.04E-02 ._--------------------------------------------------------------------------------------------------------------------------- Benzene 3.33E-03 0.01 0.03 5.45E-02 ._----------------------------------------------------------------------------------------------------------------------------

· 1!~:~_L!~C!q~~~~ !!·_~~~-_Q1 ~:~?~:Q~ ~_·9_~~~9A ~:. ~~-_~~ _

· ~!~YJ _~~!1_~~~~ ~._~~~-_Q? 9_·9_~ Q:.~? 9.:?~ _ · 9!!1)?J~ ~Y9_~ 1·~9 -_Q1 9_· ~_~ ,. 1:.~9 ?.:! _ Hexane 2.59E-01 0.55 2.12 4.24 -----------------------------------------------------------------------------------------------------------------------------

. ~9~~!~?J~~_~ 1~~~~-J!~ ?:~~~:Q~ ~:9_~~~9~ ~:.~~~~~? _

Polycyqlic aromatic

· ~Y~!9~~~~~n.~ _Q:~} ~~- ~~~ -_-~ . _

Anthracene 3.38E-05 7.22E-05 2.77E-04 5.53E-04 -----------------------------------------------------------------------------------------------------------------------------

. ~~_~~9{~)?!!t!!~C!~~~_~ ~~~~~__Q~ 1:~~~:Q9 ~:~_~~~9~ ~:.~~~:~~_. _ . ~~~~9_(a)~~~~~~ 1~~~~__Q~ ?:~?~:Q9 ~:~!!~~9~ ~:.~~~~~~ _

· ~~~_~~9H?)~!J_q~~~!~!~n.~ 1·_1 ~-_Q~ ?:1 J~:Q9 ~_. ?_~ ~9_~ !:.~~ -_~~ _ · ~~_f!~9{~}~!J_~~~I]!~r~!1_~ 1·_1Q~-_Q~ ?:~9~:Q9 ~_·9_Q~~9_~ ~:.~~~-_~~ _

. ~~fY~~~~ ~~~?~__Q~ ~:~?~:Q9 ?:9_~~~9~ ~:.~?~~~~ _

· Rt~~~~@.,h)~~!~~~9~_~~ ~·_~9~-J!~ ~:Q?~:Q9 ~_·~_~~~9~ ~:.~~~-_~~ _

· l~~~Q9{j .!?.!~~9~)~.Yr-~f]~- ~._~~~-_Q~ ~:Q?~:Q9 :~_~~~91 ~:.~~~-_~~ _

· '='!9.R}!'-~f]~_ ~.?'l~~ ~._~~~-_Q? ~:~?~:Q? ?_·~_~~~9_1 . 9.:~~ _ Toluene 1.33E-01 0.28 1.09 2.18 ._--------------------------------------------------------------------------------------------------------------------------- Xylenes 6.53E-02 0.14 0.53 1.07

Total 6.01 12.02

(1) From AP-42 and CATEF databases and source tests.

(2) Based C?n a maximum hourly turbine fuel use of 2,224.1 MMBtu/hr (with duct burner) and fuel HHV of

1,021 Btu/sef. (2.14 MMscf/hr)

9 Factors for acrolein and benzene reflect the use of an oxidation catalyst and were taken from Table 3.4-1 of the Background

Document for Section 3.1. .

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SJVACPO Determination ofCompliance, C-1080386

(3) Based on a maximum annual turbine fuel use of 16,711,728 MMBtu/year (with duct burner) and fuel HHV

of 1,021 Btu/sef. (16,368 MMscf/yr)

Although. the turbines/HRSGs will be equipped with oxidation· catalyst systems, only the

acrolein and benzene emission factors reflect any control effectiveness. As discussed

above, these factors are based on test data rather than any assumption regarding catalyst

control efficiency.

Therefore, as emissions of each individual HAP are below 10 tons per year and total HAP

emissions are below .25 tons per year, the Avenal Power Center, LLC Project will notb'e a

major air toxics source and the provisions of this rule do not apply.

.Rule 4001 New Source Performance Standards

40 CFR 60 - Subpart Dc

NSPS Subpart Dc appl.iesto steam generating units that are constructed, reconstructed,

or modified after 6/9/89 and have a maximum design heat input capacity of 100

MMBtu/hr or less,but greater than or equal to 10 MMBtu/hr.Subpart Dc has standards

for S9x and .·PM10~

60.42c - Standards for Sulfur Dioxide

Since coal is not combusted. by the bo.iler in this project, the requirements of this section

are not applicable.

60.43c - Standards for Particulate Matter

The boiler is not fired on coal, combusts mixtures of coal with other fuels, combusts

wood, combusts mixtured of wood with other fuels, or oil; therefore it will not be subject

to the requirements of this section.

60.44c - Compliance and Performance Tests Methods and Procedures for Sulfur

Dioxide.

Since the boiler in this project is not subject to the sulfur dioxide requirements of this

subpa.rt, no testing to show compliance is required. Therefore, the requirements of this

section are not a·ppHcab·le to the boiler in this project.

60.45c - Compliance an'd Performance Test Methods and Procedures for Particulate

Matter -

Since the boiler in this project is not subject to the particulae matter requirements of this

subpart, no testing to .show· compliance is required. Therefore, the requirements of this

section are not applicable to the boiler in this project.

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SJVACPO Determination of Compliance, C-1080386

60.46c -- Emission Monitoring for Sulfur Dioxide

Since the boiler ,in this project is not subject to the sulfur dioxide requ"irements of t,his

subpart, no monitoring i.s required. Therefore, the requirements of this section are not

applicable to the boiler in this project.

60.47c - Emission Monitoring for Particulate Matter

Since the boiler in this project is not subject to the particulate matter requirements of this

subpart, no monitoring is req·uired. Therefore, the requirements of this section are not

applicable to the boiler in this project.

60.48c - Reporting and Recordingkeeping Requirements

Section 60.48c (a) states that the owner or operator of each affected facility shall submit

notification of the date of construction or reconstruction, anticipated startup, and actual

startup, as provided by §60.7 of this part. This notification shall include:

(1) The design heat input capacity of the affected facility and identification of fuels to be

combusted in the affected facility..

The design heat input capacity and type of fuel combusted at the facility will be listed

on the unit's equipment description. No conditions are required to show compliance

~ith this requirement.

(2) If applicable, a copy of any Federally enforceable requirement that limits the annual

capacity factor for any fuel mixture of fuels under §60.42c or §40.43c.

This requirement is not applicable since the units are not subject to §60.42c or

§40.43c.

(3) The annual capacity factor at which the owner or operator anticipates operating the

affected facility based on all fuels fired and based on each individual fuel fired.

The facility has not proposed an annual capacity factor; therefore one will not be

required.

(4) Notification if an emerging technology will be used f9r controlling S02,emission.s. The

Administrator will examine the descr~ption of the control device and will determine

whether the technology qualifi~s as an emergin'g technology. In making this

determination, the Administrator may require the owner or operator of the affected

facility to submit additional information concerning the control device. The affected

facility is subject to the provisions of §60.42c(a) or (b)(1), unless and until this

dete'rmination is made by the Administrator

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This requirement is not applicable since the units will not be equipped with an

emerging technology used to control S02 emissions.

Section 60.48 c (g) states that the owner or operator of each affected facility shall record

and maintain records of the amounts of each fuel combusted during eac'h da·y. The

following conditions will be added to the permit to assure compliance with this section.

• A non-resettable~ totalizing mass or volumetric fuel flow meter to measure the amount

of fuel combusted in the unit shall be installed, utilized and maintained. [District Rules

2201 and 40 CFR 60.48 (c)(g)]

.• Permittee' shall maintain daily records of the type and .quantity of fuel combusted by

the boiler. [District Rules 2201 and 40 CFR 60.48 (c)(g)]

Section 60.48 c (i) states that all records required under this section shall be ,maintained

by the owner or operator of the affected facility for a period of twe;> 'years following the

date· of such record. District Rule 4306 'requires that records be kept for five years.

40 CFR 60 - Subpart GG

40 CFRPart 60 Subpart GG· applies to all stationary gas turbines with a heat input

greater than 10.7 gigajoules per hour (10.2 MMBtu/hr), that commence construction,

modification, or reconstruction after October 3, 1977. Avenal Power Center, LLC has

indicated .that the installation and construction of the proposed turbines will be completed

in2011. Therefore, these turbines .meet the applicability requirements of this subpart.

40 .CFR 60 Subpart KKKK, Section 60.4305(a), states that this su.bpart applies to all

stationary gas turbines with a heat input greater than 10.7 gigajoules (10 MMBtu) per

hour, which·commenced construction, modification, or reconstruction after February 18,'

2005. Aven.al .Power Center, LLC' has indicated that the installation and construction of

the proposed turbines will be completed in 2011. Therefore, these turbines also meet

the applicability requirements of this subpart. .:

40 CFR 60 Subpart KKKK, Section 60.4305(b), ... states that stationary combustion

turbines regulated under this subpart are exempt from the requirements of 40 CFR 60

Subpart GG. As discussed above, 40 CFR 60 SubpartKKKK is applicable to these

proposed turbines. Therefore, they are exempt from the requirements of 40 CFR 60

Subpart 'GGand no further discussion is required.

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40 CFR 60 - Subpart 1111

§60.4200 - Applicability

40 CFR Part 60 Subpart 1111 applies to all owners and operators of statio'nary

compression ignited internal combustion engines that commence construction after July

11, 2005, where the engines are:

1) Manufactured after April 1,2006, if not a fire pump engine.

2) Manufactured as a National' Fire Protection Association (NFPA) fire pump engine

after July 1, 2006. '

Since the proposed engines will be instaUed after July 11, 2005 and will be 'manufactured,

after April 1, 2006, this subpart applies.

All of the applicable stands of this subpart are less restrictive than current District

requirements. This engine will comply with all current District standards so further

discussion is required.

40 CFR 60 - Subpart KKKK

40 CFR Part 60 Subpart KKKK applies to all, stationary gas turbines rated at 'greater than

or equal to 10 MMBtu/hr that commence cqnstruction, modification, or reconstruction

after February 18, 2005. The proposed gas turbines involved in this project have a rating

of 1,794.5 'MMBtu/hr and will be installed after February 18, 2005. Therefore, this

subpart applies to these gas turbines.

Subpart KKKK established requirements for nitrogen oxide (NOx) and sulfur dioxide

(SOx) emissions.

Section 60.4320- Standards for Nitrogen Oxides:

Paragraph (a) states that NOx emissions shall not exceed the emission limits specified in

Table 1 of this subpart. Paragraph, (b) states that if you have two or, more turbines that

are connected to a single generator, each turbine must meet the em'ission limits for NOx.

Table 1, states that new, modified, or reconstructed turbines firing natural gas with a

combustion turbine heat input at peak load of greater than 850 MMBtu/hr shall, meet a

NOx emissions limit of 15 ppmvd @'15°!'c> O2 or 54 ng/J of useful output (0.43 Ib/MWh).

Avenal Power Center is proposing a NOx emission concentration limit of 2.0 ppmvd @

15% O2 for each turbine. Therefore, the proposed turbines will be ,operating in

compliance with the NOx emission requirements of this subpart. The following

conditions' will ensure continued compliance with the requirements of this section:

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• Emission rates from this unit (with duct burner firing), except during startup and

shutdown periods, shall not exceed any of the foUowing limits: NOx (as N02) - 17.44

Ib/hr and 2.0 ppmvd @ 15°A> 02; voe (as meth~ne) - 6.13 Ib/hr and 2.0 ppmvd @

15°k 02; CO -10.60 Ib/hr and 2.0 ppmvd @ 15·0/0 02; PM10 -11.78Ib/hr; or SOx (as

802) - 6.72Ib/hr. ·NOx (as N02) emission limits are one hour rolling averages. All

other emission limits are three hour rolling averages. [District Rules 2201, 4001, and

4703]

• Emission rates from this unit (without duct burner firing), except during startup and

shutdown periods, shall not exceed any of the following limits: NOx (as N02) - 13.28

Ib/hr and 2.0 ppmvd @ 150/002; VOC (as methane) - 3.23 Ib/hr and 1.4 ppmvd @.

150/0 02; CO - 8.35 Ib/hr and 2.0 ppmvd @ 15% 02; PM10 - 8.97 Ib/hr; or SOx (as

802) - 5.11 Ib/hr. NOx (as N02) emission limits are one hour rolling averages. All·

other emission limits are three hour rolling averages. [District Rules 2201 , 4001, and

4703]

. Section 60.4330 - Standards for Sulfur Dioxide:

Paragraph (a) states that if your turbine is located in a continental area, you' must comply

with one of the following:

(1) Operator must not cause to be discharged into the atmosphere from the

subject 'stationary combustion turbine any gases which containS02 in excess

of 110 nanograms per Joule (ng/J) (0.90) pounds per megawatt-hour

(lb/MWh)) gross output; or

(2) Operator must not burn in the subject stationary combu·stion turbine any fuel

which contains total potential sulfur emissions in excess of 26 ng S02/J (0.060

Ib S02/MMBtu) heat input.

Avenal Power Center is proposing to burn natural gas fuel in each of these turbines with

a maximum sulfur content of 1.0 grain/ 100 scf (0.00285 Ib/MMBtu). Therefore, the

proposed turbines will be operating in. compliance with the SOx emission requirements of

this section. The following condition will ensure continued compliance with the

requirements of this section:

• The CTG shall be fired exclusively on PUC-regulated natural gas with a sulfur

content of no greater than 1.0 grains of sulfur. compounds (as S) per 100 dry scf of

natural gas. [District Rule 2201 and 40 CFR 60.4330(a)(2)]

Section 60.4335 - NOx Compliance Demonstration, with Water or Steam Injection:

Paragraph (a) states that when a turb'ine is using water or ste.am injection to reduce NOx

emissions, you must install, calibrate, maintain and operate a continuous monitoring

system; to monitor and record the fuel consumption and the ratio of water or steam to fuel

being fired in the turbine when burning a fuel that requires water or steam injection for

compliance.

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Avenal Power Center does not use water or steam injection in their turbines therefore;

the requirements of this section are not applicab'le to the turbines in this project.

Section 60.4340 NO~ Compliance Demonstration,. without Water or Steam Injection:

Paragraph (b) states that as an alternative to annual source testing, the facility may

install, calibrate, maintain and operate one of the following continuous monitoring

systems:

(1) Continuous emi.ssion monitoring as described in §§60..4335(b) and 60.4345, or

(2) Continuous parameter monitoring

Avenal Power Center has proposed to install a CEMS system as described in

§§60.4335(b) .and 60.4345 therefore; the following condition will ensure continued

compliance with the requirements of this section:

• The owner or operator shall install, certify, maintain, operate and quality-assure a

Continuous Emission Monitoring System (CEMS) which continuously measures

. and records the exhaust gas. NOx, CO and 02 concentrations. Continuous

emissions monitor(s) shall be capable of monitoring emissions during normal

operating conditionsJ, and during startups and shutdowns, provided the CEMS

passes the relative accuracy requirement for startups and shutdowns specified

herein. If relative accuracy of CEMS cannot be demonstrated during .startup

conditions, CEMS results during startup and shutdo·wn events shall be ~eplaced

with startup emission rates obtained from source testing to determine compliance

with emission limits contained in this document. [District Rules 1080 and 4703

and 40 CFR 60.4340(b)(1)]

Section 60.4345 -GEMS Equipment Requirements:

Paragraph (a) states that eachNOx diluent CEMS must be installed and certified

according to Performance Specification 2 (PS 2) in Appendix B to this part, except the 7-

day calibration drift is based on unit operating days, not calendar days. With state

approval,' Procedure 1 in Appendix F to this part is not required.. Alternatively, a NOx

diluer)t CEMS that is installed and certified according to Appendix A of Part 75 of this

chapter is acceptable for use under this sut;>part. The relative accuracy test audit (RATA)

, of the CEMS Shall be performed on a Ib/MMBtu' basis~

Paragraph (b) states that as specified in §60.13(e)(2), during eachfuH unit operating

hour, both the NOx monitor and the dilu~nt monitor must complete a minimum of one

cycle of operation (sampling, analyzing, and data recording) for each 15-minute quadrant

of the hour, to validate the hour. For partial unit operating hours, at least one valid data

point must be obtained with each monitor for each quadrant of the hour in which the unit

operates. For unit operating hours in which required quality assurance and maintenance

activities are performed on the CEMS·, a minimum of two va,lid data points (one in each of

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two quadrants) are required for each monitor to validate the NOx emission rate for the

hour.

Paragraph (c) states that eac,hfuel flowmeter shall be installed, calibrated, maintained,

and operated according to the manufacturer's instructions. Alternatively, with ,state

approval, fuel flowmeters that meet the installation, certification, and quality assurance

requirements of Appendix D to Part 75 of this chapter are acceptable for use under this

subpart.

Paragraph (d) states that each watt meter, steam ,flow meter, and each pressure or

temperature measurement device shall be installed, calibrated, ma'intained, and operated

according to manufacturer's instructions.

Paragraph (e) states that the owner or operator shall develop and keep on-site a quality

assurance (QA) plan for all of the continuous monitoring equipment described in

paragraphs (a), (c), and (p) of this section. For the CEMS and fuel flow meters, the

owner or operator may, 'with state approval, satisfy the requirements of this paragraph by

implementing the QA program and plan described in section 1 of Appendix B to Part 75

of this chapter.

Avenal Power Center will be require~ to install and operate a NOx CEMS in accordance

with the requirements of this section. As discussed above, Avenal Power Center'is not

required to install a fuel flow meter, watt meter, steam flow meter, or a pressure or

temperature measurement device to comply with the requirements of this subpart.

Therefore, the proposed turbines will be operating in compliance with the requirements of

this section. ,The following conditions will ensure continued compliance with the

requirements of this section:

• The NOx, CO and O2 CEMS shall meet the requirements in 40 CFR 60, Appendix

F Procedure 1 and Part 60, Appendix B Performance Specification 2 (PS 2), or

shall meet equivalent specifications established by mutual agreement of the

District, the ARB, and the EPA~ [District Rule 1080 and 40 CFR 60.4345(a)]

• The CEMS shall complete a minimum, of one cycle of operation (sampling,

analyzing, and data recording) for each successive 15-'minute period or shall meet

equivalent specifications established by mutual agreement of the District, the ARB

and the EPA. [District Rule 1080 and 40 CFR 60.4345(b)]

Section 60.4350 - CEMS Data and Excess NOx Emissions:

Section 60.4350 states that for purposes of identifying excess emissions:

(a) All CEMS data must be' reduced to hourly averages as specified in §60.13(h).

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(b) For each unit -operating hour- in which a valid hourly average, as described in

§60.4345(b),is obtained for both NOx and diluent monitors, _the data acquisition and

-handling system must calculate and record the hourly NOx emission r~te in :units of ppm

or Ib/MMBtu, using the appropriate equation from Method 19 in Appendix A of this part.

For any hour in which the hourly average O2 concentration exceeds 19.0 percent O2 (or

the hourly average CO2 concentration is less than 1.0 percent CO2), a diluent cap value

of 19.0 percent O2 -or 1.0 percent C02 (as applicable) may be used in the emission

calculations.

(c) -Correction of measured NOx concentrations to 15 percent O2 is not allowed.

(d) If you have installed and certified- a NOx diluent CEMS to meet the requirements of

Part 75 ofthis chapter, states can approve that only quality assured data from the CEMS

shall be used to identify excess emissions under this subpart. Periods where the missing

data substitution procedures in Subpart D of Part 75 are applied are to be reported as

monitor downtim-e in the excess emissions and monitoring performance report required

under §60.7(c).

(e) All required fuel flow rate, steam flow rate, temperature, pressure, and megawatt data

must be reduced to houfly averages.

(f) Calculate the hourly average NOx emission rates, in units of the emission standards

under §60.4320, using either ppm for units comp-Iying with the concentration limit or the

equations 1 (simple cycle turbines) or 2 (combined cycle turbines) listed in §60.4350,

paragraph (f).

Avenal Power Center is proposing to monitor the NOx emissions rates from the turbines

with a CEMS. The CEMS system will be used to determine if, and when, any excess NOx

emissions are released to the atmosphere.from the turbine exhaust stacks. The CEMS will

be operated in accordance with the methods and procedures described above. Therefore,

the proposed turbines will be operating in compliance with the requfrements of this

section. The following condition will ensure continued compliance with the requirements

of this section:

• Results of continuous emissions monitoring shall be reduced according to the

procedure established in 40 CFR, Part 51, Appendix P, paragraphs 5.0 t~rough

5.3.3, or by other methods deemed equivalent by mutual agreement with the

District, the ARB, and the EPA. [District Rule 1080]

Section 60.4355-- Parameter Monitoring Plan:

This section sets forth the requirements for operators that elect to continuously monitor

parameters in lieu of installing a CEMS for NOx emissions. As discussed above, Avenal

Power -Center is proposing to instaliCEMS on each of these turbines that will directly

measure NOx emissions. Therefore, the requirements of this section are not applicable

and no further discussion is required.

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Sections 60.4360, 60.436_5 and 60.4370 - Monitoring of Fuel Sulfur Content:

Section 60.4360 states that an operator must monitor the total sulfur content of the fuel

being fired in-the turbine, except as provided in §60.4365. The sulfur content of the fuel

must be determined using total sulfur methods described in §60.4415. Alternatively, if

the total sulfur content of the gaseous fuel during the most -recent performance test was

less than half the- applicable limit, ASTM 04084, 04810, D5504, or 06228, or Gas

Processors Association Standard 2377 (all of which are incorporated by reference, see

§60.17), which measure the major sulfur compounds, may be used.

Section 60.4365 states that an operator may elect not to monitor the total sulfur content

of the fuel combusted in the turbine, if the fuel is demonstrated not to exceed potential

sulfur emissions of 26 ng S02/J (0.060 Ib S02/MMBtu) heat input for units located in

continental areas and 180 n-g S02/J (0.42 IbS02/MMBtu) heat input for units located- in

noncontinenta-I areas ora continental area that the Administrator determines does not

have access to natural gas and that the removal of sulfur compounds would cause more

environmental harm than benefit. You must use one of the following sources of

"information to make the required demonstration:

(a) The fuel quality characteristics in a current, valid purchase contract, tariff sheet or

transportation contract for the fuel, specifying that the maximum total SUlfur

content for oil use in continental areas is --0.05 weight percent (500ppmw) or less

and 0.4 weight percent (4,000 ppmw) or less for noncontinental areas, the total

sulfur content for natural gas use in continental areas is 20 grains of sulfur or less

per 100 standard cubic feet and 140 grains of sulfur or less per -100 standard

cubic feet for noncontinental areas, has potential sulfur emissions of less than

less than 26 ng S02/J (0.060 Ib S02/MMBtu) heat input for continenta-I areas and

has potential sulfur emissions of less than less than 180 ng S02/J (0.42 Ib

S02/MMBtu) heat input for noncontinental areas; or

(b) Representative fuel sampling data which show that the sulfur content of the fuel

does not exceed 26 ng S02/J (0.060 Ib S02/MMBtu) heat input for continental

areas or 180 ng S02/J (0.42 Ib S02/MMBtu) heat input for noncontinental areas.

At a minimum, the amount of fuel sampling data specified in section 2.3.1.4 or

2.3.2.4 of Appendix 0 to Part 75 of this chapter is required.

Avenal Power Center is proP9sin9 to operate these turbines on natural gas that contains

a maximum sulfur content of 1.0 grains/100 scf. Primarily, the natural gas supplier

should be able to provide a purchase contract, tariff sheet or transportation contract for

- the fuel that demonstrate~ compliance with the natural gas sulfur content limit. However,

Avenal Power Center has a_sked- that the option of either using a purchase contract, tariff

sheet or transportation contract or actually physically -monitoring the sulfur content be

incorporated into their permit.

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Section 60.4370 states that the frequency of determining the sulfur content of the fuel

must be as follows:

(a) Fuel oil. For fuel oil, use one of the total sulfur sampling options and the

. associated sampling frequency described in sections 2.2.3, 2.2.4.1, 2.2.4.2, and

2.2.4.3 of Appendix D to Part 75 of this chapter (i.e., flow propo·rtional sampling,

daily sampling, sampling from the unit's storage tank after each addition of fue·1 to

the tank, or sampling each delivery prior to combining it with fuel oil already in the

intended storage tank).

(b) Gaseous fuel. If you elect not to demonstrate sulfur content using options in

§60.4365, and the fuel is supplied without intermediate bulk storage, the sulfur

content value of the gaseous fuel must be determined and recorded once per unit

operating day.

(c) Custom schedules. ·Notwithstandin.g the requirements of paragraph (b) of this

section, operators· or fuel venqors may develop custom schedules for

determination of the total sulfur content of gaseous fuels, based on the design and

operation of the affected facility and the characteristics of the fuel supply. Except

as provided in paragraphs (c)(1) and (c)(2) of this section, custom schedules shall

be substantiated with data and shall be approved by the Administrator before they

can be used to comply with the standard in §60.4330.

When actually required to physically monitor the sulfur content in the fuel burned in these

turbines, Ave.nal Power Center. is proposing a custom monitoring schedule. The District

and EPA have previously approved a custom monitoring schedule of at least one per

week. Then, if compliance with the fuel sulfur content limit is demonstrated for eight

consecutive we"eks, the monito"ring frequency shall be at least once every six months. If

any six month monitoring period shows an exceedance, weekly monitoring shall re~ume.

Avenal Power Center is proposing to follow this same pre-approved fuel sulfur content

monitoring scheme for the turbines. The following condition will ensure continued

compliance with the requirements of this section:

• The sulfur content of each fuel source shall be: (i) documented in a valid purchase

contract, a supplier certification, a tariff sheet or transportation contract or (ii)"

monitored within 60 days of the end of the commission period and weekly

thereafter. If the sulfur content is de~onstrated to be less than 1·.0 gr/100 scf for

eight conse"cutive weeks, then the monitoring frequency shall be every six months.

If the result of any six m·onth monitoring demonstrates that the fuel does not meet

the fuel sulfur content" limit, weekly monitoring shall resume. [District Rule 2201

and 40 CFR 60.4360, 60.4365(a) and 60.4370(0)] .

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Section 60.4380 - Excess NO~ Emissions:

Section 60.4380 establishes reporting requirements for .periods of excess emissions and

monitor downtime. Paragraph (a) lists requirements for operators choosing to monitor

para'meters associated with water or steam to fuel' ratios. As discussed above, Avenal

Power Center is not proposing to monito~ parameters associated with water or steam to

fuel ratios to predict what the NOx emissions fror:n the turbines will be. Therefore, the

requirements of this paragraph are not applicable and no further discussion is required.

Paragraph (b) states that for turbines' usingCEM's:

(1) An excess emissions is any unit operating period.inwhich the 4-hour or 30-day rolling

average NOx emission rate exceeds the applicable emission limit in §60.4320. For the

purposes of this subpart, a "4-hour rolling average NOx emission rate" is the arithmetic

average of the average NOxemission rafe in ppm or ng/J (lb/MWh) measured by the

continuous emission monitoring equipment for a given hour and the three unit operating

hour average NOx emission rates immediately preceding that unit .operating hour.

Calculate the rolling average if a valid NOx emission'rate is'obtained for at least 3 of the

4 hours. For the purposes of this subpart, a "30-day rolling averag~ NOx emission rate" is

the arithmetic average of all hourly NOx emission data in ppm or ng/J (lb/MWh)

measured by the continuous emission monitoring equipment for a given day and the

twenty-nine unit operating days ·immediately preceding that unit operating day. A new 30-

day average is calculated each unit operating day as the average of all hourly NOx

emissions rates for the preceding 30 unit 'operatfng days if a valid NOx emission rate. is

obtained for at least 75 percent of all operating hours.

(2) A period of monitor downtime is any unit operating hour in which the data for any of

the following· para'meters are either missing or invalid: NOx concentration, C02 or O2

. concentration, fuel flow rate, steam flow rate, steam temperature, steam pressure, or

megawatts. The steam flow rate, steam temperature, and steam pressure are only

required if you will use this information for compliance purposes.

(3) For operating periods during whic·h multiple emissions standards apply, the applicable

standard is the average of the applicable standards during' each hour. For hours with

multiple emissions standards, the applicable limit for that hour is determined based on

the condition that corresponded to the highest emissions standard.

Paragraph (c) lists requirements for operators who choose to monitor combustion

parameters that document proper operation of the NOx emission controls. Avenal Power

Center is not proposing. to monitor combustion parameters that document proper

operation of the NOx emission controls. Therefore, the requirements of this paragraph

are not applicable and no further discussion is required.

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The following condition will ensure continued compliance with the requirements of this

section:

• Excess emissions shall be defined as any operating hour in which the 4-hour or 30-

day rolling average NOx concentration exceeds applicable emissions limit and a

period of monitor downtime shall be a'ny' unit operating hour in which sufficient data

are not obtained to validate the hour for either NOxor 02 (or both). [40CFR

60.4380(b)(1 )]

Section 60.4385 - Excess SOx Emissions:

Section 60.4385 states that if an op'erator chooses the option to monitor the sulfur

content of the fuel, excess emissions and monitoring 'downtime are defined as follows:

(a) For samples of gaseous fuel and for oil samples obtained using daily sampling, flow

proportional sampling, or sampling from the unit's storage tank, an excess emission

occurs each unit operating hour included in the period beginning on the date and hour of

~ny sample for which the sulfur content of the fuel being fired in the combustion turbine

exce~ds the applicable limit and ending on the date and hour that a subsequent sample

is taken that demonstrates compliance with the sulfur·Iimit.

(b) If the option to sample .each delivery of fuel oil has been select~d, you must

immediately switch to one of the other oil sampling options (Le., daily sampling, flow

proportional sampling, or sampHng from the unit's storage tank) if the s'ulfur content of a

delivery e'xceeds 0.05 weight percent. You must continue to use one of the other

sampling options until all of the oil from the delivery has been combusted, and you must

evaluate excess emissions according to paragraph (a) of this section. When all of the

fuel from the delivery has been burned, you may resume using the as-delivered sampling

option.

(c) A period of monitor downtime begins when a required sample is not taken by its due

date. A period of. monitor downtime also begins on ·the date and hour of a required

sample, if invalid results are obtained. The period of monitor downtime ends on the date

and hour of the next valid sample.

Avenal Power Center will be following the d.efinitions and procedures specified above for

determining periods of excess SOx emissions. Therefore, the proposed turbines will be

operating in compliance with the requirements of this section.

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Sections 60.4375. 60.4380. 60~4385 and 60.4395 - Reporting:

These sections establish the reporting requirements for each turbine. These requirements

include methods and, procedures for submitting reports of monitoring parameters, annual

performance tests, excess emissions and periods of monitor downtime. Avenal Power

Center is proposing to m'aintain records and submit reports in accordance with the

requirements specified in these sections. Therefore, the proposed turbines will be

operating in compliance,with the requirements of this section. The following condition will

ensure continued compliance with th~ requirements of this section:

• The owner or operator shall submit a written report of CEM' operations for each

calendar qu'arter to the A-PCO. The report is due on the 30th day following the end

of the calendar quarter and shall include the following: Time intervals, data and

magnitude of excess NOx emissions, nature and the cause of excess (if known),

, corrective 'actions taken and preventative measures adopted; Averaging period

used for data reporting corre,sponding to the averaging period specified in the

emission test period and used to determ'ine compliance with an emissions

- standard; Applicable time and date of each period d'uring which the CEM was

inoperative (monitor downtime), except for zero and span checks, and the nature

of system repairs and adjustments; A negative declaration when no excess

emissions occurred. [District Rule 1080 and 40 CFR 60.4375(a) and 60.4395]

Section 60.4400 - NOx Performance Testing:

Section 60.4400, paragraph (a) states that an operator must cond,uct an initial,

performance test, as required in §60..8. Susequent 'NOx performance tests shall be

conducted on an annual basis (no more than 14 calendar months following the previous

performance test). '

Paragraphs (1), (2) and (3) set fourth the requirements for the methods that are to be

used during source testing.

Avenal Power Center will be required to source test the exhaust of,these turbines within

120 days of initial startup and at least once every 12 months thereafter. They' will be

required to source test in accordance with the methods and procedures specified in

paragraphs ,(1), (2), and (3). Therefore, the proposed turbines will be operating in

compliance With the requirements of this section. The following conditions will ensure

continued compliance with the requirements of this section:

• 'Source testing to determine compliance with the NOx, eo and voe emission

rates (Ib/hr and ppmvd' @ 15°A> O2), NH3 emission rate (ppmvd @ 150/0 O2) and

PM10 emission rate (Ib/hr) shall be conducted at least once every 12 months.

[District Rules 1081,2201 and 4703 and 40 CFR 60.4400(a)]

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SJVACPO Determination of Compliance, C-1080386

• The following test methods sh~1I be used: NOx - ,EPA Method 7E or 20; CO - EPA

Method 10 or 10B; VOG - EPA Method 18 or 25; PM10 - EPA Method 5 (front half

and back half) or 201 and 202a; ammonia - BAAQMD ST-1 B; and O2 - EPA

Method 3, 3A, or 20. EPA approved alternative test methods as approved by the

District may 'also be used to address the source testing requirements of this

permit. [District Rules 1081 and 4703 and 40 GFR 60.4400(1 )(i)]

Section 60.4405 - Initial GEMS Relative Accuracy Testing:

Section 60.4405 states that if you elect to install and certify a NOx-diluent CEMS, then'

the initial performance test required under §60.8 may. be performed in the alternative

manner describ'ed in paragraphs (a), (b), (c) and· (d). Avenal Power Center has not

,ndicated that they would like to perform th.e initial performance test of theCEMS using

the alternative methods described in this section. Therefore, the requirements of this

section are not a,pplicable and no further discussion is required.

Section 60.4410 - Parameter Monitoring Ranges:

Section 60.4410 sets fourth requirements for operators that. elect to monitorcombusti,on

parameters or. p·arameters· indicative of proper operation of NOx emission controls. As

discussed above, Avenal Power Center is proposing to install a CEMS system to monitor

the N'Ox ,emissions from each of these turbines and is not proposing to monitor

combustion parameters or ,parameters indicative of proper operation. Therefore, the

requirements of this section are not applicable and no further discussion is required.

Section 60.4415- SO~ Performance Testing:

Section 60.4415 states that an operator must conduct an initial performance test, as

required in §60.8. Subsequent S02 performance tests shall be conducted on an annual

basis (no more tha'n 14 calendar months followin,g the previous performance test). There

are three methodologies that you may use to conduct the performance tests.

(1) It.you choose to periodically determine the sulfur content of the fuel combusted in the

turbine, a r~presentative fuel sample would be collected following ASTM 05287

(incorporated by reference, see §60.17) for natural gas or ASTM 04177 (incorporated by

reference, see §60.17) for oil. Alternatively, for oil, you may follow the procedures for

manual pipeline sampling in section 14 of ASTM 04057 (incorporated by reference, see

§60.17). The fuel analyses of this section may be performed either by you, a service

contractor retained by you, the fuel' vendor, or any other qualified agency. Analyze the

samples for the total sulfur content of the fuel using:

(i) For liquid fuels, ASTM 0129, or. alternatively 01266, 01552, 02622, 04294, or

05453 (all of which are incorporated by reference, see §60.17); or

(ii) For gaseous fuels, ASTM 01072, or alternatively 03246, D4084, 04468, D4810,

06228, 06667, or Gas Processors Association Standard 2377 (all of which are

incorporated by reference, see §60.17).

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SJVACPO Determination of Compliance, C-1080386

Avenal- Power Center is proposing to periodicaUy determine the sulfur content of the fuel

combusted in each of these turbines when valid purchase contracts, tariff sheets "or

transportation contract is not available. The sulfur content will be determined using the

methods specified above. Therefore, t.he proposed turbines will be operating in

complian"ce with the requirements of this section. The followin·g condition will ensure

continued compliance with the requirements of this section:

• Fuel sulfur content shall be monitored using one of the following methods: ASTM

Methods 01072, D3246, D4084,~ 04468, 04810, 06228, 06667 or Gas Processors

Association Standard 2377. [40 CFR60.4415(a)(1)(i)]

Methodologies (2) .and (3) are applicable to op·erators· that elect to measure the S02

.c.oncentration in the e"xhaust stream. Avenal Power Center is not proposing to measure

the S02 in the exhaust stream of the turbines.. Therefore, the requirements of these

methodologies are not applicable and no further discussion is required.

·Conclusion:

Conditions will be incorporated into these permits in order to ensure compliance with each

applicable section. of this subpart. Therefore, compliance with the requirements of Subpart

KKKK is expected and n"o further discussionis required.

Rule 4002 National Emissions Standards for ·Hazardous Air Pollutants (NESHAP)

Pursuant to Section 2.0, "All sources of hazardous air pollution shall comply with the

standards, criteria, and requirements set forth therein;" therefore, the requirements of this

rule applies to the Avenal PowerCenter. However, there are no applicable requirements

for a non-major HAPs source. As discussed above, Avenal Power Center is not a major

HAP source; therefore, no actions are necessary to show compliance with this rule.

Rule 4101 Visible Emissions

Per Section 5.0, no person shall discharge into the atmosphere emissions of any air

contaminant aggregating. more than 3 minutes in any hour which is as dark as or darker

tha·n Ringelmann 1 (or 20% opacity).

i. C~3953-10~O and C-3953-11-0 (Turbines)

The following condition will be listed on the ATe to ensure compliance:

• {15} No air contaminant shall be. discharged into the atmosphere for a period or

periods aggregating more than three minutes in anyone hour which is as dark as, or

darker than, Ringelmann 1 or 20°A> opacity. [District Rule 4101]

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ii. C-3953-12-0 (Boiler)

Based on past experiences with natural gas-fired boilers, no visible emissions are

expected to be as dark as or darker than Ringelmann 1 (or 20°J'c> opacity). The following

condition will be placed on the ATC to assure compliance with this rule.

• {15} No air contaminant shall be discharged into the atmosphere for a period or

periods aggregating more than three minutes in anyone hourwhich is as dark as, or

darker than, Ringelmann 1 or 200/0 opacity. [District Rule 4101]

iii. C-3953-13-0 (DiesellC engine powering fire water pump)

The following condition wHI be listed on the ATC to ensure compliance:

• {15} No air contaminant shall be discharged into the atmosphere for a period or

periods aggregating more than three minutes in anyone hour which is as dark as, or

darker than, Ringelmann 1 or 20% opacity. [District Rule 4101]

iv. C-3953-14-0 (Natural gas Ie engine electrical generator)

The following condition will be listed on theATC to ensure, compliance:

• {15} No air contaminant shallpe' discharged into the atmosphere for a period or

periods aggregating more than three minutes in anyone hour which is as dark as, or

darker than, Ringelmann 1 or 200/0 opacity. [District Rule 4101]

Rule 4102 Nuisance

Section 4.0 prohibits discharge of air contaminants which could cause injury, detrime.nt,

nuisance or annoyance to the .public. Public nuisance condition·s are not expected as a

result of these operations, provided the equipment is well maintained as required by

permit conditions. Therefore, the following condition will be added to the permit to

assure compliance with this rule.

• {98} No air contaminant shall be released into the atmosphere which causes 'a

public nuisance. [District Rule 41.02]

A. California Health & Safety Code 41700 (Health Risk Analysis)

A Health Risk Assessment (HRA) is required for any increase in hourly or annual

emissions of hazardous air pollutants (HAPs). HAPs are limited to substances included

on the list in CH&SC 44321 and that have an OEHHA approved health risk value. The

installation of the permit units for the power plant result~ in increases in emissions of

HAPs.

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A health risk screening assessment was· performed for the proposed project. The acute

and chronic hazard indices were less than 1.0 and the cancer risk was less than one in a

million. Under the District's risk management poUcy, Policy APR 1905, TBACT is not

required for any proposed emissions unit as shown in the table below:

0.0 0.0 0.02 No

0.0 0.0 0.02 No

0.0 0.0 0.01 No

N/A* N/A* 0.01 No

0.2 0.0 . 0.0 No

B. Discussion of Toxics BACT (TBACT)

TBACT is triggered if the cancer risk exceeds one in one million and if either the chronic

or acute hazard index exceeds 1. The results of the health risk assessment show that

none of the TSACT thresholds are exceeded. TS'ACT is not triggered.

Rule 4201 Particulate Matter Concentration

Section 3.1 prohibits discharge of dust, fumes, or total particulate. matter into the

atmosphere from any single source operation in excess of 0.1 grain per dry standard cubic

foot.

i. C-3953-10-0 and -11-0 (Turbines)

PM Cone. (gr/scf) = (pM emission rate) x.C7GGG gr/lb)

PM10 emission ~ate =11.78 Ib/hr..Assuming 1000Al of PM is PM10

Exhaust Gas' Flow =1,071,653 dscfm

PM Conc. (gr/scf)=[(11.78 Ib/hr) * (7,000 gr/lb)] t- [(1,071,653 ft3

/min) * (60 min/hr)]

PM Conc. =0.0012 gr/scf

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SJVACPO Determination of Compliance, C-1080386

Calculated emissions are well below the allowable emissions level. It'can be assumed

. that emissions from all these turbines will not exceed the.allowable 0.1 grlscf. Therefore,

compliance with Rule 4201 is expected.

• {14} Particulate matter emissions shall not exceed 0.1grains/dscf in concentration.

[District Rule 4201]

ii. C-3953-12-0 (Boiler)

Section 3.1 prohibits discharge of dust, fumes, or total particulate matter into the

atmosphere. from any single source operation in excess of 0.1 grain per dry standard cubic

foot.

8,578 dscf/MMBtu at 60 OF'

0.005 Ib-PM1 O/MMBtu

. F-Factor for NG:

PM10 Emission Factor:

Percentage of PM as PM10 in Exhaust: 100°A>

Exhaust Oxygen (02) Concentration: 30/0

Excess Air Correction to F Factor = 20.9

(20.9 - 3)

GL=(OoOOS lb-PM x 7,OOOgrain) / (8,S78 ft3 x 1.17J

. MMBtu lb·- PM MMBtu

= 1.17

GL = 0.0035 grain/dscf < 0.1 grain/dscf

Therefore, compliance with District Rule 4201 requirements is expected and a permit

co.ndition will be listed on the permit as follows:

• {14} Particulate matter e.missions shall not exceed 0.1 grains/dscf in concentration.

[District Rule 4201]

iii. C-3953-13-0 (DiesellC engine fire pump)

.Particulate matter emissions from the engine will be less than or equal to.the rule limit of

0.1 grain per cubic foot of gas at dry standard conditions as shown by the following:

0.059 g-PM 10 19-PM lbhp-hr 106 Btu 0.35 Btu out 15.43 grain ---x x x x x---

bhp-hr O.96g-PM 10 2,542.5 Btu 9,05ldscf 1Btu in g

0.014 grain-PM

dscf

Since 0.014 grain-PM/dscf is s to 0.1 grain per dscf, comp.liance with Rule 4201 is

expected.

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Therefore, the following condition will be listed on the ATC to ensure compli'ance:

'. {14}, Particulate matter emissions' shall not exceed 0.1 grains/dscfin concentration.

[District Rule' 4201] ,

iv. C-3953-14-0 (Natural gas IC engine electrical. generator)

Particulate matter emissions from the engine will be less than ,or equal to the rule limit of

0,.1 grain per cubic foot of gas at dry standard conditions as shown by the following:

0.034 g-PM 10 19-PM lbhp-hr 106 Btu 0.35 Btu out 15.43 grain -----x x x x x---

bhp-hr O.96g-PM 10 2,542.5 Btu 9,05ldscf 1Btu in g

0.008 grain-PM

dscf

Since 0.008 grain-PM/dscf is =:; to 0.1 grain per dscf, complian,ce with Rule 4201 is

expected.

Therefore, the following conditio.n will be listed on the ATe to ensure compliance:

• {1.4} Particulate matter emissions shall not exceed 0.1 grains/dscf in concentration.

[District Rule 4201]

Rule 4202 Parliculate Matter Emission Rate

Rule 4202 establishes PM emi'ssion limits as a function of process weight rate in tons/hr.

Gas and liquid fuels are excluded' from the definition of process weight. Therefore, Rule

4202 does not apply to any of the permit units in this project, and no further discussion is

required.

Rule 4301 Fuel Burning Equipment

Rule 4301 limits, air contaminant emissions from fuel burning equipment as defined in the

rule. Section 3.1 defines fuel burning equipment as "any furnace", boiler, apparatus,

stack, and all appurtenances thereto, used in the process of burning fuel for the primary

purpose of producing heat or power by indirect heat transfer".

i. C-3953-10-0 and C-3953-11-0 (Turbines)

The CTG's primarily produce. power mechanically, i.e. the products of combustion pass

across the power turbine blades which causes the turbine shaft to rotate. The turbine

shaft is coupled. to an electrical generator shaft which is rotated to produce electricity.

Because the CTG's primarily produce power by mechanical means, it does not meet the

definition of.fuel burning equipment. Therefore, Rule 4301 does Qot apply to the affected

equipment and no further discussion is required. .

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ii. C-3953-12-0 (Boiler)

ATC #C-3953-12-0 (Ib/hr) ,

Rule Limit (Ib/hr)

0.41

140

0.19

10

0.10

200

The above table indicates compliance with the ,maximum Ib/hr emissions in this rule;

therefore, continued compliance is expected.

iii. C-3953-13-0 (DiesellC engine fire pump)

Rule 4301 does not apply to the affected equipment and no further discussion is

required..

iv. C-3953-14-0 (Natural g'as IC engine electrical generator)

Rule 4301 does not apply to the affected equipment and no further discussion is

required.

Rule 4304 Tuning Procedure for Boilers, Steam Generators and Process Heater~

'This rule is only applicable to unit C-3953-12-0.

Pursuant to District Rules 4305 and 4306, Section 6.3.1, the boiler is not required to tune

since it follows, a Distri9t approved Alternate Monitoring scheme where the applicable

emission limits are periodically monitored. Therefore, the unit is not subject to this rule.

Rule 4305 Boilers Steam Generators and Process Heaters - Phase 2 '

This rule is only applicable to unit C-3953-12-0.

The unit is natural gas-fired with a maximum heat input of 37.4 MMBtu/hr. Pursuant to

Section 2.0 of District Rule 4305, the unit is subject to District Rule 4305, Boilers, Steam

. .Generators and Process Heaters - Phase 2.

In addition, the unit is also subject to District- Rule 4306, Boilers, Steam Generators and

Process Heaters - Phase 3.

,Since emissions lim'its of District Rule 4306 and all other requirements are equivalent or

more stringent than District Rule 4305 requirements, compliance with District Rule 4306

requirements will ~atisfy requirements of District Rule 4305.

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SJVACPO Determination r~of Compliance, C-1080386

Conclusion

Therefore, compliance with District Rule 4305 requirements is expected and no further

discussion is required.

Rule 4306 Boilers Steam Generators and Process Heaters - Phase 3

This rule is only applicable to unit C-3953-12-0.

The unit is natural gas-fired with a maximum heat input of 37.4 MMBtu/hr. Pursuant to

Section 2.0 of District Rule 4306, the unit is subject to District Rule 4306.

Section 5.1, NOx and CO Emissions Limits

Section 5.1.1 requires that except for units subject to Sections 5.2, NOx and carbon

monoxide (CO) emissi'ons shall not exceed. the limits specified in the following table. All

ppmv emission limits specified in this section are referenced at dry stack gas conditions

a'nd 3.00 percent by· volume stack gas oxygen. Emissio.n concentrations shall be

corrected to 3.00 percent oxygen in accordance with Section 8.1.

With a maximum heat input of 37.4 MMBtu/hr, the applicable emission limit category is

listed'in Section 5.1.1, Table 1, Category S, from District Rule 4306.

B. Units with a rated heat input greater

than 20.0 MMBtu/hr, except for

categories C, D, E, F, G, H, and I units

9 ppmv

or 400 ppmv

0.011 Ib/MMBtu

40 ppmv

or

0.052

Ib/MMBtu

400 ppmv

For the unit:

- the proposed NOx emission factor is 9 ppmvd @ 3°~ O2 (0.011 Ib/MMBtu), and

- the proposed CO emission factor is 50 ppmvd @ 3% 02 (0.037 Ib/MMBtu).

Therefore, compliance with S'ection 5.1 of District Rule 4306 is expected.

A permit condition listing the emissions limits will be listed on permit as shown in the DEL

section above.

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SJVACPD Determination of Compliance, C-1080386

Section 5.2, Low Use

The unit annua'l heat input will exceed the 9 billion Btu heat input .per calendar year

criteria "limit addressed by this section. Since the unit is not subject to Section 5.2, the

requirements of this section "do not apply to the unit.

Section 5.3, Startup and Shutdown Provisions

Section 5.3 states that on and after the full compliance schedule specified in Section 7.1,

the app'licable emission limits of Sections 5.1, 5.2.2 and 5.2.3 shall not apply during startup or shutdown provided an operator complies with the requirements specified in

Sections 5.3.1 through 5.3.4.

According to boiler manufacturers, low NOx burners will achieve their rated emissions

within. one to two. minutes of initial startup and do not require a special shutdown

procedure. Because of the short duration before achie'ving the rated emission factor

"following startup, the unit will be subject to the applicable emission limits of Sections 5.1,

5.2.2 and 5.2.3 while in operation.

Section 5.4, Monitoring Provisions

Section 5.4.2 requires that permit units subject to District Rule 430.6, Section 5.1

emissions limits shall either install and maintain Continuous Emission Monitoring (CEM)

equipment for NOx, CO and O2, or install and maintain APCO-approved alternate

.monitoring. .

The facility has proposed to install a CEMS system to satisfy the requirements of this

section. The following condition will assure compliance with this section.

• {1832} The'exhaust stack shall be equipped with a continuous emissions monitor

(CEM) for NOx, CO, and 02. The CEM shall meet the requirements of 40 CFR

parts 60 and 75 and shall be capable of monitoring e·missionsd.uring startups and

shutdowns as well as during normal operating conditions. [District Rules 2201 and

1080]

Since. the unit is not subject to the requirements listed in Section 5.2.1 or 5.2.2, it is not

subject to Section 5.4.3 requirements.

.Since the unit is not subject to the requirements of category H (maximum annual heat

input between 9 billion and 30 billion Btu/year)' listed in Section 5.1.1, it is not subject to

'Section 5.4.4 requirements.

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Section 5.5, Compliance Determination

Section 5.5.1 requires that the operator of any unit shall have the option of complying

with either the applicable heat input (lb/MMBtu) emission limits or the concentration

(ppmv) 'emission limits specified in Section 5.1. The emission limits selected to

demonstrate compliance shall b.e specified in the source test proposal pursuant to Rule

1081 (Source Sampling). Therefore, the following condition will be listed on the permit

as follows:

• {2976} The source plan 'shall identify which basis (ppmv or Ib/MMBtu) will be used

to demonstrate compliance. [District Rules 4305 and 4306]

Section 5.5.2 requires that all emissions measurements shall be made with the unit

operating either' at conditions representative of normal operations or condition.s specified

in the Permit to Operate. ~o determination· of compliance shall be established within two

,hours after a continuous period in which fuel flow to the unit is shut off for 30 minutes or

longer, or within 30 minutes after are-ignition asdefiried in Section 3.0. Therefore, the

following permit condition will be listed on the permit as follows:

• {2972} All emissions measurements shall be made with the unit operating either at

co'nditions representative of normal operations or conditions specified in the

Permit to Operate. No determination of compliance shall be established within

two hours after a continuous period in which fuel flow to the unit is shut off for 30

minutt.?s or longer, or within. 30 minutes after a re-ignition as defined in Section 3.0

of District Rule 4306. [District Rules 430,5 and 4306]

Section 5.5.4 requires that for emissions monitoring pursuant to Sections 5.4.2, 5.4.2.1,

and 6.3.1 using a portable NOx analyzer as part of an A'pea approved Alternate

Emissions Monitoring System, emission readings. shall be averaged over a 15

cons,ecutive-minute period by either taking a cumulative 15-consecutive-minute sample

reading or by taking at least five (5) readings evenly spaced out over the 15-consecutiveminute period~

Since the applicant does not use a portable analyzer to satisfy the monitoring

requirements of District Rule 4306 the requirements of Section 5.5.4 do not apply.

Section 5.5.5 requires that 'for emissions source testing performed pursuant to Sectio'n

6.3.1 for the purpose of determining compliance with a'n applicable standard or numerical

limitation of this rule, the ·arithmetic average of three (3) 30~consecutive-minute test runs

shall apply. If two (2) of three (3) runs are above an applicable limit the test cannot be

used to demonstrate compliance with an applicable .limit. Therefore, the following permit

condition will be listed on the permit as follows:

• {2980} For emissions source testing, the arithmetic average of three 30-

consecutive-minute test runs shall apply. If two of three runs are above an

applicable limit the test cannot be used to demonstrate compliance with an

applicable 'limit. [District Rules 4305 and 4306]

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Section 6.1, Recordkeeping

Section 6.1 requires that the records required by Sections 6.1.1 through 6.1.3 ·shaH be

.maintained for five calendar years and shall be made ava·ilable to the APCO upon

request. Failure to maintain records or information contained in the records that

demonstrate noncompliance with the applicable requirements of this rule shall constitute

a violation of this rule.

A permit condition will be listed on the permit. as follows:

• {2983} All records shall be maintained and retained on-site for a minimum of five

(5) years, and shall be made available for District inspection upon request. [District

Rules 1070, 4305, and 43061

Section 6.1.2 requires that the operator of a unit subject to Section 5.2 shall record the

amou.nt of fuel use at' least on a monthly basis. Since the unit is not subject to th~

requirements listed in Section 5.2, it is not subject to Section 6.1:.2 requirements.

Section 6.1.3 requires that the operator of a .unit subject to Section 5.2.1 or 6.3.1 shall

maintain records to verify that the required tune-up and the required monitoring of the

operational characteristics have been performed. The unit is not subject to Section

6.1.3. Therefore, the requirements of this section do not apply to the unit.

Section 6.2, Test Methods

Section 6.2 identifies the following test methods as. District-approved source testing

methods for the pollutants listed:

NOx ppmv EPA Method7E or ARB Method 100

NOx Ib/MMBtu EPA Method 19

CO ppmv EPA Method 10 or ARB Method 100

.Stack Gas O2 % EPA Method 3 or 3A, or ARB Method 100

Stack Gas Velocities ft/min EPA Method 2

Stack Gas Mo'isture Content % EPA Method 4

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SJVACPO Determination of Compliance, C-1080386

The following permit conditions will be listed on the permit as follows:

• {1 09}Source testing shall be conducted using the methods and procedures

approved by the District. The District must be notified at least 3·0 days prior to any

compliance source test, and a source test plan must be submitted for approval at

least 15 days prior to testing. [District Rule 1081]

• {2977} NOx emissions for sourqe test purposes shall be determined using EPA

Method 7E or ARB Method 100 on a ppmvbasis, or EPA Method 19 on a heat

input basis. [District Rules 4305 and 4306]

• {2978} CO emissions for source test purposes shall be determined using EPA

Method 10 or ARB Method 1·00. [District Rules 4305 and 4306]

• {2979} Stack gas oxygen (02) shall be determined usi·ng EPA Method 3' or 3Aor

ARB Method 100. [District Rules 4305 and 4306]

Section 6.3, Compliance Testing

Section·6.3.1 requires that this unit be tested to determine compliance with the

.applicable requirements of section 5.1 and 5.2.3 not less than once every 12 months.

Upon demonstrating compliance on two consecutive. compliance source tests, the

following source test may be deferred for up to thirty-six months.

The following perm.it conditions will be listed on the permit as follows:

• {3467} Source testing to measure NOx and C·O emissions from this unit while fired

on natural gas shall be conducted within 60 days of initial start-up. [District Rules

'2201, 4305, and 4306]

• {3466} Source testi~g to measure NOx and CO emissions from this unit while fired

on natural gas shall be conducted at least once every twelve (12) months. After

demonstrating compliance on two (2) consecutive annual source tests, the unit

shall be tested not less than once every thirty-six (36) months. If the result of the

36-month source test demonstrates that the unit does not meet the applicable

emission limits, the source testing frequency shall revert ·to at least once every

twelve (12) months. [District Rules 4305 and 4306]

• . {11 O} The results of each source test shall be submitted to the District within 60

days thereafter. [District Rule' 1081]

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Section 6.4, Emission Control Plan (ECP)

Section 6.4.1 requires that the operator of any unit shall submit to the APCO for approval

an Emissions Control Plan according to 'the compliance schedule in Section 7.0 of

District Rule 4306.

The proposed modified unit will be in compliance with the emissions limits listed in table

1, Section 5.1 of this rule and wi,th periodic monitoring and source testing requirements.

Therefore, this current application for the new proposed unit satisfies the requirements of

the Emission Control Plan, as listed in Section 6.4 of District Rule 4306. No further

discussion is required.

Section 7.0, Compliance Schedule

Section 7.0 indicates that an operator with multiple units at ,a stationary source shall

comply with this rule in accordance with the 'schedule specified in Table 2, Section 7.1 of

District Rule 4306. ' '

The unit will be in compliance with the emissions limits listed in table 1, Section 5.1 of

this rule, and periodic monitoring and source testing as required by District Rule 4306.

Therefore, requirements 'of the compliance schedule, as listed in Section 7.1 of District'

Rule 4306, are satisfied. ' No further discussion is required~

Conclusion

Conditions will be incorporated into the permit in order to ensure compliance with each

section of this rule, see attached draftpermit(s). Therefore, compliance with District Rule

4306 requirements is expected.

Rule 4351 Boilers Steam Generators and Process Heaters - Phase 1

This rule is only applicable to unit C-3953-12.

This rule applies to boilers, steam generators, and process heaters at NOx Major

Sources that are 'not located west of Interstate 5 in Fresno, Kings, or Kern counties. If

applicable, the emission limits, monitoring provisions, and testing requirements of this

rule are satisfied ,when the unit is operated in compliance With Rule 4306. Therefore,

compliance with this rule is expected.

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Rule 4701 Internal Combustion Engines - Phase 1

This rule is only applicable to units C-3953-13-0 and -14-0.

Pursuant to Section 7.5.2.3 of District Rule 4702, as of June 1,2006 District Rule 4701 is

no longer applicable to diesel-fired emergency standby or emergency IC engines.

Therefore, this diesel-fired emergency IC engine will comply with the requirements of

District Rule 4702 and no further discussion is required.

Rule 4702 Internal Combustion Engines - Phase 2

This rule is only applicable to units C-3953-13-0 and -14-0.

The purpose of this rule is to limit the emissions of nitrogen oxides (NOx), carbon

monoxide (CO), and volatile' organic compounds (VOC) from internal combustion

engines.

This rule applies to any internal combustion engine with a rated brake horsepower

greater than 50 horsepower.

Pursuant to Section 4.2, except for the requirements of Sections 5.7 and 6.2.3, the

requirements of this rule shall not apply to an internal combustion engine that meets the.

following condition:

1) An emergency standby engine as defined in Section 3.0 of this rule, and provided

that it is operated with a nonresettable elapsed· 'operating time meter. In lieu of a

nonresettable time meter,' the owner of an emergency engine may use an

alternative device,' method, or technique, in' determining operating time provided

that the alternative is approved by the APCO. The owner of the engine shall

properly f'Daintain and operate the time meter or alternative device in accordance

with the manufacturer's instructions.

Section 3.15 defines an "Emergency Standby Engine" as· an internal combustion engine

which operates as a temporary replacement for primary. mechanical or electrical power

during an unscheduled outage caus~d by sudden and reasonably unforeseen natural

disasters or sudden and reasonably unforeseen events beyond the control of the

operator. An engine shall be considered to be an emergency standby engine if it is used

only. for the following purposes: (1) periodic maintenance, periodic readiness testing, or

readiness testing during and after'repair work; (2) unscheduled outages, or to supply

power while maintenance is performed or repairs are made to the primary power supply;

and (3) if it is 'Iimited to operate 100 hours or less per calendar year for non-emergency

purposes. An engine shall not be considered to be an emergency standby engine if it is

used: (1) to reduce the demand for electrical power when normal electrical power line

service has not failed, or (2) to produce power for the ·utility·electrical distribution system,

or (3) in conjunction with a .voluntary utility de'mand reduction program or interruptible

power contract.

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SJVACPO Determination of Compliance, C-1080386

Therefore, unit C-3953-14-0, the emergency standby IC engine powering an electrical

9.enerator involved with this project will only have to m.eet the requirements of Sections

5.7 and 6.2.3 of this Rule. .

Pursuant to Section 4.3, except for the requirements of Section 6.2.3, the requirements of

this rule shall not apply to. an .internal combustion engine that meets the following

conditions:

1) The engine is operated exclusively to preserve or protect property, human life, or

public health during a disaster or state of emergency, such as a fire or flood, and

2) Except for operations associated with Section 4.3.1.1, the engine is limited to

operate no more than 100 hours per calendar year as determined by an

operational nonresettable elapsed operating time meter, for periodic, maintenance,

periodicread.iness ·testing, and readiness testing during and after repair work of

the engine, and

3) The engine i~ operated with a nonresettable elapsed operating time meter. In lieu

of installing a nonresettable' time meter, the owner of an engine may use an

alternative device, method,or technique, in determining operating time provi'ded

that the alternative is approved by the APCO. The owner of the engine' shall

properly maintain and operate the time meter or alternative device in accordance

with the manufacturer's instru,ctions.

Therefore, unit C-3953-13-0, the emergency IC engine powering a firewater pump

involved with this project win only have to meet the requirements of Section '6.2.3 of this

Rule.

Sectiqn 5.7 of this Rule requires that the owner of an emergency standby engine shall

comply with the req~irements specified in Section 5.7.2 through Section 5.7.5 below:

1) Properly operate and maintain each engine as recommended by the engine

manufacturer or emission control system supplier.

2) Monitor the operational characteristics of ea.ch engine as recommended by the

engine I}lanufacturer or emission control system supplier.

3) Install and operate a nonresettable elapsed operating time meter. In lieu of

installing a nonresettable time meter, the owner of an engine may use an

alternative device, method, or technique, in determining operating time provided

that the alternative is approved by. the APCO and is allowed by Permit-to-Operate

or Stationary Equipment Registration condition. The owner· of the engine shall

.properly maintain and operate the time meter or alternative device in accordance

with the manufacturer's instructions.

Therefore" the following conditions will be listed on ATe C-3'953-14-0 to ensure

compliance: .

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C-3953-14-0.(Natural Gas Ie engin~ electric~1 generator)

• .This engine shall be operated and maintained in proper operating condition as

recommended by the engine manufacturer. or emissions control system supplier.

[District Rule 4702]

• During periods of operation for maintenance, testing, and required regulatory

purposes, ~he permittee shall monitor the operational characteristics of the engine as

recommended by the manufacturer or emission control system supplier (for example:

check engine fluid levels, battery, cables and connections; change engine oil and

filters; replace engine coolant; and/or other operational characteristics' as

recommended by the manufacturer or supplier). [District Rule 4702]

• This engine shall be equipped with an op~rational non-resettable elapsed time meter

or other APCO approved alternative. [District Rule 4702 and' 17 CCR 93115]

• An emergency situation is an unscheduled electri"cal power outage caused by sudden

and reasonably unforeseen natural disasters or sudden and reasonably unforeseen

events beyond the control of the permittee. [District Rule 4702]

• This engine shall not be used to produce power for the electrical distribution system,

as part of avol~ntary utility demand reduction program, or for an interruptible power

contract. [District Rule 4702]

• This engine shall be operated only for testing and maintenance of the engine,

required regulatory purposes, and during emergency situations. Operation of the

engine for maintenance, testing, and required regulatory purposes shall not exceed

50 hours per calendar year. [District Rule 4702]

Section 6.2.3 requires that an owner claiming an exemption under Section 4.2 or 'Section

4.3 shall maintain annual operating records. This information ·shall be retained for at least

five· years, shall be read'ily available, and submitted to the APCO upon request and at the

end of each calendar year in a manner and form approved by the APCO. Therefore, the

following conditions will be listed on ATCs C-3953-13-0 ~nd -14-0 to ensure compliance:

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C-3953-13-0 (Diesel Ie engine fire pump)

• {3816} This en,gine shall be operated only for testing and maintenance of the engine,

reqUired regulatory purposes, and during emergency situations. For testing

purposes, th,e engine shall only be operated the number of hours necessary to

comply with the testing requirements of the National Fire Protection Association

(NFPA) 25 - UStandard for the Inspection, Testing, and Maintenance of Water-,Based

Fire Protection Systems", 1998 edition. Total hours of operation for all maintenance,

testing, and required regu'latory purposes shall not exceed '5'0 hours per calendar

year. [District Rule 4702 and 17 CCR 93115]

• {3489} The permittee shall maihtain monthly records of emergency and nonemergency operation. Records shall include the number of hours of emergency

operation, the date 'and number of hours of all testing and maintenance operations,

and the purpose of the operation (for example: load testing, weekly testing, rolling

blackout, general area power outage, etc.). For units with automated testing systems,

the operator may, as an alternative to keeping records of actual operation for testing

purposes, maintain a readily accessible written record of the automated testing

schedule. [District Rule 4702 and 17 CCR 93115]

• {3475} All records shall be maintained and retained on~site for a minimum of five (5)

years, and shall be made available for District inspection upon request. [Distri~t Rul~

470,2 and 17 CCR 93115]

In addition, the follow'ing condition will be listed on the ATe to ensure compliance:

• {3404} This engine shall be equipped with an operational non~resettableelapsed time

meter or other APCO approved alternative. [District Rule 4702]

• {3807} An emergency situation is an unscheduled electrical power outage caused by

sudden and reasonably unforeseen natural 'disasters or sudden and reasonably

unforeseen events beyond the control of the permittee. [District Rule 4702]

• {3808} This engine shall not be used to produge power for the electricaJ distribution

system, as part of a voluntary utility demand reduction program, or for an interruptible

power contract. '[District Rule 4702] ,

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C-3953-14-0 (Natural Gas Ie engine electrical generator)

• The permittee shall maintain monthly records of emergency and non-emergency

operation. Records shall include the number of hours of emergency operation, the

date and number of hours of all testing and maintenance operations, the purpose of

the operation (for example: load testing, weekly testing, rolling blackout, general area

power outage, etc.) and records of operational characteristics monitoring. For units

with automated testing systems, the operator may, as an alternative to keeping

records of actual operation for testing purposes, maintain a readily accessible written

record of the automated testing schedule. [District Rule 4702]

• All records shall be maintai.ned and retained on-site for a minimum of five (5) years,

and shall be made available for District inspection upon request. [District Rule 4702]

Rule 4703 Stationary Gas Turbines

This rule is only applicable to units C-3953-10-0 and -11-0.

.Rule 4703 is applicable to stationary gas turbines with a rating greater than 0.3

megawatts. The facility proposes to install two 180 MW gas turbines.. Therefore the

requirements of this rule apply to the proposed ·turbines.

Section 5.1 '- NOx Emission Requirements:

Section 5.1.1 (Tier I) of this rule limits the "NOx emissions from stationary gas turbine

systems greater than 10 MW, and equipped with Selective Catalytic Reduction (SCR).

Sinc.e the proposed turbines will meet the more stringent Tier 2 emission equirements in

Section 5.1.2, compliance with this section is assured.

Section 5.1.2 (Tier 2) of this rule limits the NOx emissions from combined cycle,

stationary gas turbine systems rated at greater than 10 MW to 5 ppmv @ 15% O2

(Standard option) and 3 ppmv @ 15°J'c> O2 (Enhanced Option). Section 7.2.1 (Table 7-1)

sets a compliance date of April 30, 2004 for the Standard Option anq Section 7.2.4 sets

a compliance date of April 30, 2008 for the Enhanced Option. As discussed above, the

proposed turbines will be limited to 2.0 ppmv @ 15% O2 (based on a 1-h.our average),

therefore compliance with this section is expected. The following conditions will ensure

continued compliance with the requirements of this section:

• . E'mission rates from this unit (with duct burner firing), except during startup and

shutdown periods, shall not exceed any of the following limits: NOx (as N02) -

17.201b/hr and 2.0 ppmvd @ 15% 02; VOC (as methane) - 5.89 Ib/hr and 2.0

ppmvd @ 15°1'<> 02; CO - 10.60 Ib/hr and 2.0 ppmvd @ 15°1'<> 02; PM10 ~11.78

Ib/hr; or SOx (as 802) - 6.65 Ib/hr. NOx (as N02) emission limits are one hour

rolling averages. All other emission limits are three hour rolling averages. [District

Rules 2201,4001, and 4703]

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• Emission rates from this unit (without duct burner firing), except during startup and

shutdown periods, shall not exceed any of the following limits: NOx (as .N02) -

.13.55 Ib/hr and '2.0 ppmvd @ 15% 02; voe (as methane) - 3.34 Ib/hr and 1.4

ppmvd @ 150

M02; ·CO - 8.35 Ib/hr and 2.0 ppmvd @ 150/0 02; PM10- 8~91 Ib/hr;

or SOx (as S02) - 5.23 Ib/hr. NOx(as N02) emission limits are one hour rolling

averages. All other emission limits are three hour rolling averages. [District Rules

2201, 4001, and 4703]

Section 5·.2 - CO Emission Requirements:

, Per Table 5-3 ofsectiqn 5.2, the CO emissions concentration from the proposed turbines

(General Electric Frame 7) must be less than 25 ppmvd @ 150

M O2 . Rule 4703 does not

include a specific averaging period requirement for demonstrating compliance with the

eo emission limit~ However, District practice is to have an applicant demonstrate

compliance· with the CO emissions on a turbine with three hour averaging periods.

Therefore, com·pliance with the CO emission limit shall be demonstrate.d by an average

over a three hour period.

Avenal Power Center is proposing a CO emission concentration limit of 2 ppmvd@ 15%

O2 and will demonstrate compliance using three hour averaging periods. Therefore, the

proposed turbines will be operating the turbine in compliance with the CO emission

requirements of this rule. The DEL conditions shown in the Section 5.1.2 compliance

section will ensure continued compliance with the requirements of this section.

S"ection 5.3 - Startup and Shutdown Requirements:

This section states that t.he emission limit requirements of Sections 5.1.1, 5.1.2 or 5.2

shall not apply during startup, shutdown, or a reduced load period provided an operator

complies with the requirements specified below:

- The duration of each startup or each shutdown shall not exceed two hours, and

. the duration of each reduced load period shall not exceed one hour, except as

provided below.

The emission control system shall be in operation and emissions shall be

minimized insofar as technologically feasible during startup, shutdown, or a

reduced load period.

- An operator may submit an application to allow more than two hours for each

startup or eaQh shutdown or more than one hour for each reduced load period

provided the operator m~ets all of the conditions specified in the" rule.

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Avenal Power Center is proposing to incorporate startup and shutdown provisions into

the operatingrequi~ements for each of·the proposed turbines. They have proposed that

the duration of each startup' or shutdown event will last no more than six hours per day.

Since this proposed duration is longer than what is allowed in Section 5.3.1.1, the facility

must meet the requirements of Section 5.3.3.2. Section 5.3.3.2 states that at a minimum,

a justification for the incre.ased duration shall include the following:

A.clear identification of the control technologies or strategies to be utilized; and

The facility has identified the following control technologies:

•. Dry low-NOx combustors in the turbines;

• Oxidation catalyst in the HRSG~;

• SCR in theHRSGs;

• Good combustion practices;

• Upon startup, the ammonia injection upstream of the SCR catalyst will be started

as soon as the catalyst and ammonra injection system warm to their minimum

operating temperatures specified by the SC.R vendor.

A description of 'what physical conditions prevail during the period that prevent the

controls from being effective; and

The combined-cycle equipment startup duration depends on how fast the thick steel

walls of the common steam turbine-'can be warmed to operating temperature without

generating stress cracks. Steam developed in the HRSG from the heated turbine

exhaust is admitted into the steam turbine at a controlled temperature to heat it as

ra'pidly as possible without causing stress cracking. The steam temp~rature is

controlled by limiting the load on the gas turbine. The allowable rate of temperature

increase at the steam turbine is the limiting factor determining how quickly the gas

turbines can achieve higher loads. This, in turn, limits how quickly the gas turbine

combustors can achieve the lowest emitting operating 'mode, and this latter step is

necessary for the units to be able to comply with the limits of Rule 4703.

A reasonably precise estimate as to when the physical conditions will have reached a

state that allows for the effective control of emissions; and

Startup information provided by the turbine and HRSG vendors indicates that for a

cold startup, a minimum of four hours is required for the unit to come into compliance

with the limits of Rule 4703. Depending on the temperature of the steam turbine at

the time the start is initiated, shorter durations may be possible.

A detailed list of activities to be performed during the period and a reasonable

explanation for the length of time needed to complete 'each activity; and

The facility has provided the District with a 'detailedlist of activities to be performed

during the period and a reasonable explanation for the length .of time needed to

complete each activity.

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A description of the material process flow rates and system operating parameters, etc.,

the operator .plans to 'evaluate during the :process optimization; and an' explanation of

how the activities and process flow affect the ·operation of the emissions control

eguipm.ent; and

The startup duration depends on the allowable ramp rate of the steam temperature to

the steam turbine, which depends on the acceptable rate of increase of the metal

temperature of the HRH and HP bowls. at the steam turbine inlets. The maximum

steam temperature is set by applying an allowable differential above the metal

temperature. The differential is determined by the steam turbine supplier, and is

imposed by the supplier's control system to avoid damage to the steam turbine from

thermal stress. The control system limits gas turbine load to control the steam

temperature. Manual override of the gas turb.ine load limit by the operator reduces the

life expectancy of the steam turbine.

In addition, the time prior.to initiation of ammonia flow to the SCR system depends on

the temperature of the SCR catalyst. The catalyst bed is warmed by the exhaust flow

from the gas turbine. The total mass of metal and water in the HRSG tubes, piping,

and drums removes heat from the gas turbine exhaust as it warms. This extends the

time required to heat the SCR catalyst to the minimum t~mperature .at which

ammonia may be injected upstream of the catalyst bed to begin reducingNOx to N2.

The steam turbine and SCR catalyst temperatures are all monitored by the plant

control system, and the turbine ramp rate and SCR initiation sequence are governed

by the equipment/system manufacturer's recommended procedures.

The basis for the requested additional duration.

The startup curve in Attachment I and the description of activities above demonstrate

that the minimum time required for a cold startup of the plant as currently configured

is approximately'4 hours. This startup time is contingent upo~ all of the activities

being performed in time to support subsequent activities..Any delay in preparation of

the supporting systems will result in a corresponding delay in startup and/or loading of

the gas turbines. To be confident that the startup time allowed is adequate and will

not be exceeded, one hour is added to the above startup time to account for possible

delays.

Since' the facility has demonstrated compliance and provided all the information asked

for in Section 5.3.3.2, the pr9Posed increase in startup and shutdown emissions is

compliant with District Rule 4703. The following conditions will ensure continued

compliance with the requirements of this section:

• During start-up and shutdown, eTG exhaust emission rates shall not exceed any

of the following limits: NOx (as N02) - 160 Ib/hr; CO - 1,000 .Ib/hr; vac (as

methane) - 16 Ib/hr; PM10 - 11.78 Ib/hr; sax (as S02) - 6.652 Ib/hr; or NH3 -

32.13 Ib/hr. [District Rules 2201 and 4703]

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• Startup shall be defined as. the period of time during which a unit is brought from a

shutdown status to its operating temperature and pressure, including the time

required by the unit's emission control system to reach full·operations. Shutdown

shall be defined as the period of time during which a unit is taken from an

operational to a non-operational status by allowing it to cool down from its

operating temperatur~ to ambient temperature as the fuel supply to the unit is

completely turned off. [District Rules 2201 and 4703]

• The duration of each startup or shutdown shall not exceed six hours. Startup and

shutdown emissions shall be counted toward' all applicable emission limits.

[District Rules 2201 and 4703]

• The emission control systems shall be in operation and emissions shall be

minimized insofar as technologically feasible during startup and shutdown. [District

Rule 4703] .

Section 6.2 - Monitoring an.d Recordkeeping:

Section 6.2.1 requires the owner to operate and maintain continuous emissions

monitoring equipment for NOx and oxygen, or install and maintain APCO-approved

alternate monitoring. As discussed earlier in this evaluation, the applicant operates, a

, Continuous Emissions Monitoring System (CEMS) that monitors the NOx and oxygen

content of the turbine exhaust. Therefore, the requirements of this' section have been

satisfied. The following condition will ensure continued compliance with the requirements

of this section:

• The owner or operator shall install, certify, maintain, operate and quality-assure a

Continuous Emission Monitoring System (CEMS) which continuously measures

and records the exhaust g.as, NOx, CO and O2 concentrations. Continuous

emissions monitor(s) shall be capable of monitoring emissions during normal

operating conditionsJ. and during startups and shutdowns, pro'vided the CEMS

pass the relative accuracy requirement for startups and shutdowns specified

herein. If relative accuracy of CEMS 'cannot be demonstrated during startup

conditions, CEMS' results during startup and shutdown events shall be replaced

with startup emission rates obta,ined from source testing to determine compliance

with emission limits contained in this document. [District Rules 1080 and 4703

and. 40 CFR 60.4335(b)(1)]

Section 6.2.2 specifies monitoring requirements for turb·ines without exhaust-gas NOx

control device.s. Each of the proposed turbines will be equipped with an SCR system

that· is designed to control NOx emissions. Therefore, the requirements of this section

are not ·applicable and no further discussion is required.

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Section 6.2.3 requires that for units 10 MW and greater that operated an average of

more than 4,000 hours per year over the last three years before August 18, 1994, the

owner or operator shall monitor the exhaust gas NOx emissions. The proposed turbines

have not been installed~ Therefore, they were not in operation prior to August 18, 1994

and the requirements of this section are not applicable. No further discussionis

required.

Section 6.2.4 requires the facility to maintain all records for.a period of five years from

the date of data entry and shall make such records available to the APCO upon request.

Avenal PowerCeriter will be required to maintain all records for at least five years and

make them available to the APCO upon request. Therefore, the proposed turbines will

be operating in compliance with the five year recordkeeping requirements of this rule.

The following condition will ensure continued compliance w·ith the requirements of this

section:

• The owner or operator of a stationary gas turbine system shaH maintain all records

'of requiredmon'itoring data and support information for inspection at. a·ny time for a

period of five years. [District Rules 2201 and 4703]

Section 6.2.5 requires that the owner or operator shall submit to the APCO, before

.issuance of the· Permit to Operate, information ·correlatin·g the control system operating to

the associated measure NOx output. This information may be used by the APCO to

determine compliance when .there is no continuous emission monitoring system for NOx

available or when the continuous emis'sions monitoring system is not operating properly.

Avenal ~ower Center will be requir~d, by permit condition, to submit information correlating

the NOx control system operating parameters to the associated measured NOx output.

Therefore, the proposed turbines will be operating incompliance with the control system

operating parameter requirements of this rule. The following condition will ensure

continued compliance with the requ·irements of this section:

• The permittee shall submit to. the District information correlating the NOx control

system operating parameters to the associated measured .NOx output. The

information must be sufficient to allow the District to determine compliance with

the NOx emission limits of this permit during times that the CEMS is not

functioning properly. [District Rule 4703]

Section 6.2.6 requires the facility to maintain a stationary gas turbine system operating log

that includes, 00· a daily basis, the actual local startup and stop time, length and reason for

reduced load periods, total hours~ of operation, and the type and quantity 'of fuel used.

Avenal Power Center \will be required to maintain records of each item listed above.

Therefore', the proposed turbines will be operating in compliance with the recordkeeping

require.ments of this rule. The following conditions will ensure continued' compliance with

the requirements of this section:

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.' The permittee shall maintain the following r~cords: date and time, duration, and

type of any startup, shutdown, or malfunction; performance testing,evaluations,

calibrations, checks, adjustments, any period' during which a continuous

monitoring ,system or monitoring device was inoperative, and maintenance of any

continuous emission monitor. [District Rules 2201 and 4703]

• The permittee shall maintain the following records: hours of operation" fuel

consumption (scf/hr and scf/rolling twelve month period), continuous emission

monitor measurements, calculated ammonia slip, and, calculated NOx mass

emission rates (Ib/hr and Ib/tweIve month rolling period). [District Rules 2201 and

4703]

Section 6.2.7 establishes recordkeeping requirements for units that are exempt pursuant to

the requirements' of Section 4.2. Each of the proposed turbines is subject to the

requirements of this rule. Therefore, the requirements of this section are not applicable

and no further discussion is required.

Section 6.2.8 requires owners or operators performing startups or shutdowns to keep

records of the duration of each startup and shutdown. As 'discussed in the Section 6.2.6

discussion above for this rule, Avenal Power Center will be required, by permit condition, to

maintain records of the date, time and duration or each startup ~nd ~hutdown. Therefore,

the proposed turbines will be operating in compliance with the recordkeeping requirements

of this rule.

Sections 6.3 and 6.4 - Compliance Testing:

Section 6.3.1 states that the owner or operator of any stationary gas turbine system subject

to the provisions of Section 5.0 of this rule shall provide source test inform~tion annually

regarding the exhaust gas NOx and CO concentrations. The turbines operated by Avenal

Power Center are .subject to the provisions of Section 5.0 of this rule. Therefore, each

turbine is required to test annually to demonstrate compliance with the exhaust gas NOx

and CO concentrations. The following condition will ensure continued compliance with

the requirements of this section:

• Source testing to determine compliance with the NOx, CO and vac ,emission

rates (Ib/hr and ppmvd @ 15% O2), NH3 emission rate (ppmvd @ 15% O2) and

PM10 emission rate (Ib/hr) shall be conducted at least once every 12 months.

[District J:{ules 1081, 2201 and 4703 and 40 CFR 60.4400(a)]

,Section 6.3.2 specifies source testing requirements for units operating less than 877 hours

per year. As discussed above, the proposed turbines will be allowed to operate in excess

of 877 hours per year. Therefore, the requirements of this section are not applicable and

no further discussion is required.

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Section 6.3.3 states that units with intermittently operated auxiliary burners shall

demonstrate compliance with the auxiliary burner both on and off. The'following condition

will ensure continued compliance with the requirements of this section:

.• Compliance with the NOx and CO emission limits' shall be demonstrated with the

auxiliary burner both· on and off. [District Rule 4703]

, Section 6.4 states that the facility must demonstrate compliance annually with the NOx

and CO emission limits using the following test methods, unless otherwise approved by

the APeO and EPA:

- Oxides of nitrogen emissions for compliance tests shall be determined by using

EPA Method 7E or EPA Method 20.

- Carbon monoxide emissions for compliance tests shall be determined' by using

EPA Test Methods 10 or 10B.

- Oxygen content of the exhaust gas shall be determined by using EPA Methods

3, 3A, or 20.

HHV and LHV of gaseous fuels shall be determined by using ASTM 03588-91,

ASTM 1826-88, or ASTM 1945-81.

The following condition will ensure continued compliance with the test method

requirements of this section:

• The following test methods shall be used: NOx - EPA Method 7E or 20; CO - EPA

Method 10 or 10B; VaG - EPA Method 18 or 25; PM10 - EPA Method 5 (front half

and back half) or 201 and 202.a; 'ammonia - BAAQMO 8T-18; and O2 EPA

Method 3, 3A, or 20. EPA approved alternative test methods as approved by the

District may also be used to address the source testing requirements of this

permit. [District Rules 1081 and 4703 and 40 CFR 60.4400(1 )(i)]

Conclusion:

Conditions will be incorporated into these permits in order to ensure compliance with each

applicable section of this rule. The'refore, compliance with the requirements of Rule 4703

is expected and no further discussion is requir~d.

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Rule 4801 Sulfur Compounds

. Per Section 3.1, a person shall not discharge into the atmosphere sulfur compounds,

which would exist as a liquid or gas at standard conditions, exceeding in concentration at

the point of discharge: 0'.2 OJ'<> by volume calculated as S02 on a dry basis averaged over

15 consecutive minutes:

i. C-3953-10-0 and -11-0 (Turbines)

·The sulfur of the natural gas fuel is 1.0 gr/100 dscf.

The ratio of the volume of the SOx exhaust to the entire exhaust for one MMBtu of fuel

combusted is:

Volume of SOx: V =_h_·R_._T

P

Where:

• i1 =number of moles of SOx prod'uced per MMBtu of fuel. .

• Weight of SOx as .S02 is 64 Ib/(Ib-mol)

• n = 0.00282 lb x 1 (lb - mol) = 0.000045 (lb - mol)

MMBtu 64lb

• R = 0.7302ft3 · atm

(lb - mol)OR

• T =500 oR

• P =1 atm

Thus, volume of SOx per MMBtuis:

v = _n_·R_·T_

P

0.000045 (lb - mol) . 0.7302 ft3 · atm . 500 OR

V = (lb - mol) 0 R

1 atm

v = 0.016 ft3

Since the total volume of exhaust per MMBtu is 8,578. scf, the ratio of SOx volume to

exhaust volume is

0.016 . =-- = 0.0000019 = 1.9 ppmv = 0.00019% by volume

8,578 .

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1.9 ppmv ::; 2000 ppmv, therefore the turbines, the boiler, and the gas engine are

expected. to comply with Rule 4801.

ii. C-3953-12-0 (Boiler)

Using the ideal. gas equation and the emission factors presented in Section VII, the sulfur

compound emissions are calculated as follows:

Volume S02 = n RT

p

With:

N = moles S02

T (Standard Temperature) =60°F =5200

R

P (Standard Pressure) = 14.7 psi

. 10.73 ps'i . ft 3

R (Universal Gas Constant) = .. - . Ib·mol·oR

0.002821b - SOx x MMBtu x lIb ·mol x 10.73 psi · ft3 x 5200R x 1,000,000· parts =1.97 parts

MMBtu 8,578 dscf 64lb lb ·mol ·oR 14.7psi million million

parts . SulfurConcentration =1.97 < 2,000 ppmv (or 0.2°A»

million

Therefore, compliance with District Rule 4801 requirements is expected.

iii. C-3953-13-0 (DiesellC engine powering a fire water pump)

Using the ·ideal gas equation, the sulfur compound emissions are calculated as follows:

Volume S02= (n x R x T) + P

n = moiesS02

T (standard temperature) =60°F or 520 ~R

R ( . Itt) 10.73psi· ft3 . unlversa gas cons an = ----

Ib·mol·OR

O.OOOOI5Ib - S 7.llb 64lb - S02 1MMBtu 1gal . lb - mol 10.73 psi - ft3 5200 R

x -. x x' x x x x -.-. x 1,000,000 = '1.0 ppmv

lb - fuel gal 32lb - S 9,051scf 0.137 MMBtu 64lb - S02 . lb - mol- OR 14.7 pSI

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SJVACPO Determination of Compliance, C-1080386

Since 1.0 ppmv is 2,000 ppmv, this engine is expected to comply with Rule 4801.

Therefore, the follqwing condition (previously proposed. in this engineering evaluation)

will be listed on the ATC to ensure compliance:

• {3395} Only CAR~ certified diesel fuel containing not more than O~0015% sulfur by

weight is to be used. [District Rules 2201 and 4801 and 17 CCR 93115]

iv. C-3953-14-0 (Natural gas IC engine powering an electrical generator)

Volume 502 =(nx R x T) + P

n =moles 502

T (standard temperat.ure) =60 OF or 520 oR

. 10.73p·si.ft3

R (unlversal·gas constant) =. - Ib·mol·OR

2.85 lh - S Isef - gas IMMBtu lib - mol 10.73 psi - ft3 5200 R 1 --~-x x x x - x---xl,OOO,OOO= .97 ppmv MMsef - gas 1,000 Btu 8,578 sef 64lh - S lb - mol - OR 14.7 psi

Since 1.97 ppmv is 2,000 ppmv, this engine is expected to comply' with Rule 4801.

Therefore, the following condition (previously proposed in this engineering evaluation)

will be listed on the ATC to ensure compliance:

• {3491} This IC engine shall be fired on Public Utility Commission (PUC) regulated

natural gas only. [DistriGt Rules 2201 and 4801]

District Rule 8011 General Requirements

District Rule .8021 Construction, Demolition, Excavation, Extraction And Other

Earthmoving Activities

·District Rule 8031 Bulk Materials

District Rule 8041 Carryout And Trackout

District Rule 8051 Open Areas

District Rule 806.1 Paved And.Unpaved Roads

District Rule 8071 Unpaved Vehicle/Equipment Traffic Areas

District Rule 8081 Agricultural Sources

The construction of this new facility will involve excavation, extraction, construction,

demolition, outdoor storage piles, paved and unpaved roads.

.The regulations from the 8000 Series District Rules contain requirements for the control

of fugitive dust. These requirements apply to' various sources, inc'luding construction,

demolition, excavation, extraction, mining activities, outdoor storage piles, paved and

unpaved roads. Compliance with these regulations will be re~uired by the following

permit conditions, which will be listed on each permit as follows:

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• Disturbances of soil related to any construction, demolition, excavation, extraction,

or other earthmoving activities shaH comply with the requirements for fugitive dust

co.ntrol in District Rule 8021 unless specifically. exempted under Section 4.0 of Rule

8021 or Rule 8011. [District Rules 8011 and 8021]

• An owner/operator shall submit a Dust Control Plan to the APeO prior to the start of

any construction activity on any site that will include 10 acres or more of disturbed

surface area for residential developments, or 5 acres or more of disturbed surface

·area for non-residential development, or wiU include moving, depositing, or

relocating more than 2,500 cubic yards per day of bulk materials on at least three

days. [District Rules 8011 and 8021]

• An owner/operator shall prevent or cleanup any carryoutor trackout in accordance

with the requirements of District Rule 8041 Section 5.0, unless specifically

exempted under Section 4.0 of Rule 8041 (8/19/04) or Rule 8011 (8/19/04). [District

Rules 8011 and 8021]

• Whenever open areas are disturbed, or vehicles are used in open areas, the facility

shall comply with the requirements of Section 5.0 of District Rule 8051, unless

specifically exempted under Section 4.0 of Rule 8051 or Rule 8.011. [District Rules

8011 and 8051] . .

• Any paved road or unpaved road shall comply with the requirements of District Rule

8061 unless specifically exempted under Section 4.0 of. Rule 8061 or Rule 8011.

[District Rules 8011 and 8061] .

"Water, gravel, roadmix,or chemi,cal/organic dust stabilizers/suppressants,.

vegetative materials, or other District-approved control measure shall be applied to

unpaved vehicle travel areas as required to limit Visible Dust Emissions to 200/0

opacity and comply with the requirements fqr a stabilized unpaved road as defined

in Section 3.59 of District Rule 8011. [District Rule 8011 and 8071]

• Where dusting materials are allowed to accumulate on paved surfaces, the

accumulation shall be removed daily or water and/or chemical/organic dust

stabilizers/suppressants shall be applied to the paved surface as required to

maintain continuous compliance with the requirements'for a stabilized unpaved road

as defined in 'Section 3.59 of District ·Rule 8011 and limit Visible Dust Emissions

(VDE) to 20% opacity. [District Rule 8011 and 8071]

1·02
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SJVACPO Determination of Compliance, C-1080386

• On each day that 50 or more Vehicle Daily Trips or 25 or more Vehicle Daily Trips

with 3 axles or more will occur on an unpaved vehicle/equipment traffic area,

permittee shall apply .water, gravel, roadmix, or chemical/organic dust

stabilizers/suppressants, vegetative materials, or other District-approved control

measure as required to limit Visible Dust Emissions to 200/0 opacity and comply with

the requirements for a stabilized unpaved road as defined in Secti.on 3.59 of District

Rule 8011. [Distric~ Rule 8011 and 8071]

• Whenever any portion of the site becomes inactive, Permittee shall restrict access

and periodically stabilize any disturbed surface to comply with the conditions for a

stabilized surface as defined in Section 3.58 of District Rule 8011. [District Rules

8011 and 8071]

• Records and other supporting documentation shall be maintained as required to

demonstrate comp.liance with ,the requirements of the rules under Regulation VIII

only for those days that a control measure was implemented. Such records shall

include the type of control measure(s) used, the location, and extent of coverage,

and the date, amount, and frequency of application of dust suppressant,

manufacturer's dust suppressant product information sheet that identifies the name

of the dust suppressant and application instructions. Records shall be kept for, one

year following project completion'that results in the termination of all dust generating

activities. [District Rules 8011, 8031, and 8071]

California Environmental Quality Act (CEQA)

The District determined that the California Energy Commission (CEC) is the public

agency having principal responsibility for approving the project, therefore establishing the

CEC as the Lead Agency (CEQA Guidelines §15051(b). The District is a Respon'sible

Agency for- the project because of its discretionary approval power over. the project via its

Permits Rule (Rule 2010) and New Source Review Rule (Rule 2201), (CEQA Guidelines

§15381). The District's en,gineering evaluation of the project (this document)

demonstrates that 'compliance with District rules and permit conditions would reduce

Stationary Source emissions from the project to levels below the District's significance

thresholds for criteria pollutants. The District has determined that no additional findings

are required (CEQA Guidelines §15096(h»).

California Health &' Safety Code, Section 42301.6 (School Notice)

As discussed in Section III of this evaluation, this site is not located within 1,000 feet afa

school. Therefore, pursuant to California 'Health and Safety Code 42301.6, aschoal

notice is not required.

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. SJVACPD Determination of Compliance, C-1080386

California Health & Safety 'Code, Section 44300 (Air Toxic "Hot Spots")

Section 44300 of the California Health and SafetyCod~ requires submittal of an air

toxics "Hot' Spot" information and assessment report for sources with criteria pollutant

emissions greater than 10 tons per year. H'owever, Section 44344.5 (b) states th'at a

new facility shall not be required to submit such a report if all of the following conditions

are met:

1. The facility is, subject to a district permit program established pursuant to Section

·42300.

2. The district conducts an assessment of the potential emissions or their associated

risks, and finds that the emissions will not result in a significant risk.

3. The district issues a permit authorizing construction or operation of the new

facility.

A health risk screening assessment was performed for the proposed project. The acute

and chronic hazard indices are les.s than 1.0 and the cancer risk is less than ten (10) in a

million, which are the thresholds of significance for toxic air contaminants. This project

qualifies for exemption per the above exemption criteria. '

Title' 13 California Code of Regulations (CCR), Section 2423 -, Exh'aust Emission

Standards and Test Procedures, Off-Road Compression-Ignition Eng,ines and

Equipment (Required by Title 17 CCR, Section 93115 for New E~ergency Diesel Ie

Engines)

The requirements of this section are only applicable to C-3953-13-0.

Particulate Matter and vac + NOx, and CO Exhaust Emissions'Standards:

This regulation stipulates that off-road compression~ignition ~ngines shall ,not exceed the

following applicable emissions standards.

Title 13 CCR, Section. 2423 lists a' diesel particulate emission standard of 0.15 g/bhp-hr

(with 1.341 bhp/kVV, equivalent to 0.20 g/kW-hr) for 2003 - 2005 model year engines with

maximum power ratings of 174.3 - 301.6 bhp (equivalent to 130 - 225 kW). The PM

standards given in Title 13 CCR, Section 2423 are less stringent than the PM standards

given in Title 17 CCR, Section 93115 (ATCM), thus the ATCM standards are the required

standards and wil·1 be discussed in the following section.

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SJVACPO Determination of Compliance, C-1080386

Title 17 CCR, Section 93115, (e)(2)(A)(3)(b) stipulates that new stationary emergency

diesel-fueled CI engines (> 50 bhp) must meet the voe + NOx, and eo standards for

off-road engines of the same model year and maximum rated power as specified in the

Off-Road Compression-Ignition Engine Standards (Title ·13 CCR, Section 2423) or the

Tier 1 standards for an off-road engine if no standards have been established for an offroad engine of the same model year and maximum rated power.

In addition, Title 17 CCR, Section 93115, (e)(2)(A)(4)(a)(II) allows new direct-drive

emergency fire pump engines to meet the .Tier 2 emission standards specified in the OffRoad Compression Ignition Engine Standards for off-road engines with the same

maximum rated power (title 13 CCR, section 2423) until three years after the date the

Tier 3 standards .are applicable for off-road engines with the' same maximum rated

power. At that time, new direct7'"drive emergency diesel-fueled fire-pump eng.ines (>50

bhp) are required to meet the. Tier 3 emission standards, until three years after the date

the Tier 4 standards are applicable for off-road engines with the same ·maximum rated

.power. At that time, new direct-drive emergency diesel-fueled fire-pump engines (>50

bhp) are required to meet the Tier 4 emission sta.ndards; and not operate more than the

number of hours necessary to comply with the testing requirements of the National Fire

Protection Association (NFPA) 25 - "Standard for the Inspection,Testing, and

Maintenance of Water-Based Fire Protection Systems," 1998 edition, which is

incorporated herein by reference. In addition, this subsection does not limit engine

operation for emergency use and for emission testing to show compliance with

(e)(2)(A)4. For this project the proposed emergency diesel IC engine will b'e used to

power a firewater pump and is therefore allowed to meet the Tier 2 emission standards

specified in the Off-Road Compression Ignition En.gine Standards for off-road engines

three years after the applicable dates specified. This additional three-year allowan.ce is

reflected in the fOllowing table.

The engine involved with this project is a certified 2007 model engine. The following

table compares the requirements of Title 13 CCR, Section 2423 to the emissions factors

for the 288 bhp Cummins Model #CFP83-F40 diesel-fired emergency IC engine as given

by the manufacturer (for, NOx + vae and PM emissions).

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SJVACPO Determination of Compliance, C-1080386

Title 13 CCR, 174.3 - 301.6 bhp 1996-2002 6.9 g/bhp-hr 1.0 g/bhp-hr 8.5 g/bhp-hr 0.40 g/bhp-hr

§2423 . (130 - 225 kW) (Tier 1) (9.2 g/kW-hr) (1 ..3 g/kW-hr) (11.4 g/kW-hr) (0.54 g/kW-hr)

Title 13·CCR, 174.3 - 301.6 bhp 2003-2005, 4.9 g/bhp-hr 2.6 g/bhp-hr 0.15 g/bhp-hr extended to §2423 (130- 225 kW) 2008 (Tier 2) (6.6 g/kW-hr) (3.5 g/kW-hr) (0.20 g/kW-hr)

Title 13 CCR, 174.3 - 301.6 bhp 2006 and later, 3.0 g/bhp-hr· 2.6 g/bhp-hr 0.15 g/bhp-hr

§2423 (130 - 225 kW) extended to (4.0 g/kW-hr) (3.5 g/kW-hr) (0.20 g/kW-hr) 2009 (Tier 3)

Cummins, 3.8g/bhp-hr 0.447 g/bhp-hr 0.059 g/bhp-hr

Model 288 bhp 2007 (5.1 g/kW-hr) (0.60 g/kW-hr) (0.079 g/kW-

#CFP83-F40 hr)

N/A N/A Yes Yes Yes

As presented in the table above, the proposed engine will satisfy the requirements of this

section and compliance is expected.

.The engine manufacturer's data and/9f CARB/EPA ·engine certification for this· engine

lists a Noxemissions factor of 3.4 g/bhp-hr,8 VoCemiss.ionsfactor of 0.38 g/bhp-hr, a

Nox + VOC emission factor of 3.8 g/bhp~hr, a CO emission factor of 0~447 g/bhp-hr, and

a PM10 emissions factor of 0~059 g/bhp-hr, all of which satisfy the requirements of .13

CCR, Section 2423. Therefore, the following conditions (previously proposed in this

. engineering evaluation) will be listed on the ATC to ensure compliance:

• Emissions from this IC engine shall not exceed any of the following limits: 3.4 gNox/bhp-hr, 0.447 g-Co/bhp-hr, or 0.38 g-VoC/bhp-hr. [District Rule 2201 and 13

CCR 2423 and 17 CCR 93115]

• Emissions from this IC engine shall not exceed 0.059 g-PM10/bhp-hr based on

USEPA certification using ISO 8178 test procedure. [District Rules 2201 and 4102

and 13 CCR 2423 and 17 CCR 93115]

Right of the District to Establish More Stringent Sta.ndards:

This regulation also stipulates that the District:

1. May establish more stringent diesel PM, Nox +. VaG, VaG, NOx, and GO

emission rate standards; and

2.· May establish more stringent limits on hours of maintenance and testing on a sitespecific basis; and

3. Shall determine an appropriate limit on the number of hours of operation for

demonstrating compliance with other District rules and initial start-up testing

The District has not established more stringent stanqards at this time. Therefore, the

standards previously established in this Section will be utilized.

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.SJVACPO Determination of Compliance, C-1080386

Title 17 California Code of Regulations (CCR), Section 931'15 - Airborne Toxic

Control Measure (ATCM) for Stationary Compression-Ignition (CI) Engines

The requirements of this section are only applicable to C-3953-13-0.

Emergency Operating Requirements:

This regulation stipulates that no owner or operator shall operate any new or in-use

stationary diesel-fueled compression ignition (CI) emergency standby engine, in

response to the notification of an impending rotating outage, unless sp'ecific criteria are

met.

This section applies to ~mergency standby IC engines that are permitted to operate

during non'-emergency conditions for the purpose of providing electrical power.

However, District, Rule 4702 states that emergency standby' IC engines may. only be

operated during n'on-emergency conditions for the purposes' of maintenance and testing.

Therefore, this section does not apply and no further discussion is required. .

Fuel an'd Fuel Additive Requirements:

This regulation also stipulates that as of January 1, 2006 an owner or operator of a new

orin-use stationary diesel-fue·led CI emergency standby engine shall fuel the engine with

CARS' Diesel Fuel.

Since the engine involved with this project is a new or in-use stationary diesel-fueled CI

emergency standby engine, these fuel requirements are app.licable. Therefore, the

following condition (previously proposed in this engineering evaluation) will be listed on

the ATC to ensure compliance:

• {3395} Only CARS certified diesel fuel containing not more than 0.00150/0 sulfur by

weight is to be used. [District Rules 2201 and 4801 and 17 CCR 93115]

At-School and Near-School Provisions:

This regulation stipulates that no owner or operator shall operate a new stationary

emergency diesel-fueled CI engine, with a PM10 emissio.ns factor> than 0.01 g/bhp-hr,

for non-emergency use, including maintenance. and testing, during the following periods:

1. Whenever there is a school sponsored activity, if the engine is located on school

grounds, and

2. Between 7:30 a.m. and 3:30 p.m. on days when school is in session, if the engine

is located within 500 fe~t of school grounds.

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SJVACPD Determination of Compliance, C-10B0386 .

The District has verified that the engine is not located within 500 feet of a K-12 school.

Therefore, conditions prohibiting non-emergency usage of the engine during school

hours will not.be placed on the permit.

Recordkeeping Requirements:

This regulation stipulat~s that as of January 1, 2005, each owner or operator of an

emergency diesel-fueled CI engi·ne shall keep a monthly log .of usage that shall list and

document the nature of use for each of the following:

a~ Emergency use hours of operation;

b. Ma·intenance and testing hours of operation;

c. Hours of operation for emission testing;

d. Initial start-up hours; and

e. If applicable, hours of operation to comply with the testing requirements of

National Fire Protection Association (NFPA) 25 - "Standard for the I.nspection,

Testing, and Maintenance of Water~Based Fire Protection Systems.," 1998 edition;

f. Hours of operation for all uses other than those specified in sections 'a' through cd'

above; and

g. For in-use emergency diesel-fueled engines, the ·fuel used. The owner or

operator shall document fuel use through the retention ,of fuel purch·ase r~cords

that account for all fuel used in the ~ngine and all fuel purchased for use in.. the

engine, and, at a minimum, contain the following information for each in.dividual

fuel purc·hase transaction:

I. Identification of the fuel purchased as either CARB Diesel, or an alternative

d·iesel fuel that meets the requirements of the Verification Procedure, or an

alternative fuel, or CARB Diesel fuel used with additives that meet· the

requirements of the Verification Procedure, or any combination of the above;

·11. Amount of fuel purchased;

III. Date when the fuel was purchased;

IV. Signature of owner or operator or representative of owner or ·operator who

received the fuel; and

V. Signature of fuel provider indicating fuel was delivered.

The proposed new emergency diesel Ie engine powering a firewater pump is exempt

from the operating hours limitation provided the engine is only operated the amount of

hours· necessary to satisfy National Fire Protection Association (NFPA) regulations.

Therefore, the following conditions (previously proposed in this engineering evaluation)

will be listed on the ATC to ensure compliance:

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SJVACPO Determination of Compliance,. C-1080386

• {3489} The permittee shall maintain monthly records of emergency and nonemergency operation. Records shall include the number of hours of emergency

operation, the date and number of hours of all testing and maintenance

operations, and the purpose of the operation (for example: load testing, weekly·

testing, rolling blackout, general area power outage, etc.). For units with

automated testing systems, the qperator may, as an alternative to keeping records

of actual operation for testing purposes, maintain a readily accessible written

record of the a~tomated testing schedule. [District Rule 4702 and 17 CCR 93115]

• {3475} All records shall be maintained and retained on-site for a minimum of five (5)

years, and shall be made available for District inspection upon request. [District Rule

4702 and 17 CCR 93115]

PM Emissions and Hours of Operation Requirements for New Diesel Engines:

This regulation stipulates that as of January 1, 2005, no person shall operate any new

stationary emergency diesel-fueled CI engine that has a rated brake horsepower greater

than 50, unless it meets all of the following applicable emission standards and operating

requirements.

1. Emits diesel PM at a rate greater than 0.01 g/bhp-hr or less than or equal to 0.15

g/bhp-hr; or

2. Meets the current model year diesel PM standard specified in the Off-Road·

Compression Ignition Engine Standards for off~road engi·nes with the sam~

maximum rated power (Title 13 CCR, Section ·2423), whichever is more stringent;

and

3·. Does not operate more than 50· hours per year for maintenance and· testing

purposes. Engine operation is not limited during emergency use and during

emissions source testing to show compliance with the ATCM.

The proposed emergency diesel IC engine powering a firewater pump is exempt from the

operating hours limitation provided the engine is only operated the amount of 'hours

necessary to satisfy National Fire Protection Association (NFPA) regulations. Therefore,

the following conditions (previously proposed in this engineering evaluation) will be listed

on the ATC to ensure compliance:

• Emissions from this IC engine shall not exceed·0.059g-PM10/bhp-hr based on

USEPA certification using ISO 8178 test procedure. [District Rules 2201 and 4102

and 13 CCR 2423 and 17 CCR 93115]

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• {3816} This engine.shall be operated only for testing and maintenance of the

engine, required regulatory purposes, and during emergency situations. For

testing purposes, the engine shall only be .operated the number of hours

necessary to comply with the testing requirements of the National Fire Protection

Association (NFPA) 25 - "Standard for the Inspection, Testing, and Maintenance

of Water-Based Fire Protection Systems", 1998 edition. Total hours of operation

for aU mainte"nance, testing, and required regulatory purposes shall not exceed 50.

hours per calendar year~ [District Rule 4702 and 17 CCR93115]

IX. RECOMMENDATION:

Compliance with all applicable prohibitory rules and regulations is expected. Issue the

Final Determination of Compliance for the facility subject to the conditions presented in

Attachment A.

X. BILLING INFORMATION:

C-3953-10-0

C-3953-11-0

C-3953~ 12-0

C-3953-13-0

C-3953-14-0

3020-088-8

3020-088-8

3020-02-H

3020-10-C

3020-10-E

180,000 kW

180,000 kW

37.4 MMBtu/hr boiler

288 bh IC en ine

860 bhp Ie en ine

110

$12,229.00

$12,229.00

$953.00

$222.00

$557.00
Avenal Power Center, LLC. (OB-AFC-01)

SJVACPD Determination of Compliance, ·C-10B0386

.~

Attachment A - 1

ATTACHMENT A

FDOC CONDITIONS
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

EQUIPMENT DESCRIPTION, UNIT C-3953-10-0:

180 MW NOMINALLY RATED COMBI~ED-CYCLE POWER GENERATING SYSTEM #1

CONSISTING OF A GENERAL ELECTRIC FRAME 7 MODEL PG7241 FA NATURAL GASFIRED' COMBUSTION TURBINE GENERATOR WITH DRY LOW NOx COMBUSTOR, A

SELECTIVE CATALYTIC REDUCTION (SCR) SYSTEM, AN OXIDATION CATALYST,HEAT

R·ECOVERYSTEAI\I1 GENERATOR #1 (HRS·G) WITH A 562 MMBTU/HR DUCT BURNER

AND A 300 MW NOMINALLY RATED. STEAM TURBINE SHARED WITH C-3953-11

1. Permittee shall submit an application to comply with' SJVUAPCD District Rule 2520 -

Federally Mandated Operating Permits within twelve months of commencing operation.

[District Rule 2520]

2. Permittee shall submit an application' to comply with SJVUAPCD District Rule 2540 -

Acid Rain Program. [District Rule 2540]

3. Prior to initial operation of C-3953-10-0, C-3953-11-0, and C~3953-12-0, permittee shall

provideNOx (as N02) emission reduction credits for the following· quantities of

emissions: 1st quarter - 67,103 Ib; 2nd quarter - 67,104 .Ib; 3rd quarter- 67,104 Ib; and

4th quarter - 67, 104 lb. Offsets shall be provided at the appropriate distance ratio

specified in Rule 2201. [District Rule 2201]

4. Prior to initial operation of C-3953-10-0, C-3953-11-0, and C-3953-12-0,perm~ttee shall

.provide voe emission reduction credits for the following quantities of emissions: 1st

quarter - 12,294 Ib; 2nd quarter - 12,295 Ib; 3rd q·uarter -12,295 Ib; and 4th quarter -

12,295 lb. Offsets shall be provided at the appropriate distance ratio specified in Rule

2201. [District Rule 2201]

5. Prior to initial operation of C-3953-10-0, C-3953-11-0, and C-3953-12-0, permittee shall

provide PM10 emission reduction credits for the following quantities of emissions: 1st

'quarter - 33,085Ib; 2nd quarter - 33,085 Ib; 3rd quarter - 33,085Ib; and 4th quarter -

33,085 lb. Offsets shall be provided at the appropriate distance ratio specified in' Rule

2201. sax ERC's may .be used to offset PM10 increases at an interpollutant ratio of 1.0

Ib-SOx: 1.0 Ib-PM10. [District Rule 2201]

6. ERC certificate numbers (or any splits from these certificates) C~897-1, C-898-1, N-724-

1, N-725-1, 8-2812-1, 8-2813-1, 8-2817-1, C-899-2, C-902-2', N-720-2, N-722-2, N-726-

2, N-728-2, S-2814-2, S-2321-2,C-896-4, N-721-4, N-723-4, S-2791-5, S-2790-5, S2789-5, 8-2788-5, or N-762-5 shall be used to supply the required offsets, unless a

revised offsetting proposal is received and approved by the District, upon which this

determination of compliance (DOC) shall be reissued, administratively specifying the new

offsetting proposal.. Original public noticing requirements, if any, shall be duplicated prior

to reissuance of the DOC. [District Rule 2201]

7. {15} No air contaminant shall be di$charged into the atmosphere for a period or periods

aggregating more than three minutes in· anyone hour which' is as dark as, or darker than,

Ringelmann 1 or 20% opacity.[~istrict Rule 4101]

Attachment A - 1 ,
Avenal Power Center, LLC (OB-AFC-01)

SJVACPD Determination of Compliance, C-1080386

8. {98} No air contaminant shall be released into the atmosphere which causes a public .

nuisance. [District Rule 4102]

9. {14} Particulate matter emissions shall not exceed 0.1 grains/dscf in concentration.

.[District Rul'e 4201]

10. The CTG shall be fired exclusively on PUC-regulated n'atural gas with a sulfur content of no

greater than 1.0 grains of sulfur compounds (as S) per 100 dry sct of natural gas. [District

Rule 2201 and 40 CFR 60.4330(a)(2)]

11. Annual average of the sulfur content of the CTG shall not exceed 0.36 grain, of sulfur

compounds (as S) per 100 dry scf of natural gas.. [District

Rule 2201]

12. The owner or operator shall install, certify, maintain, operate and quality-assure a

Continuous Emission Monitoring System (CEMS) which continu'ously. measures and

records the exhaust gas NOx, CO and .02 concentrations. Continuous emissions

monitor(s) shall be capable of monitoring emissions during normal operating conditionsJ.

and during startups and shutdowns, provided the CEMS passes the relative accuracy

requirement for startups and shutdowns specified herein. If rela'tive accuracy of CEMS

cannot be demonstrated during startup conditions, CEMS results during startup and

shutdown events shall be replaced with startup emission rates obtained from source

testing ,to determine compliance with emission limits contained in this document. [District

Rules 1080 and 4703 and 40 CFR 60.4340(b)(1)]

13. The CEMS shall complete a minimum of one cycle of operation (sampli·ng, analyzing, and

data recording) for each successive 15-minute period or shall meet equivalent

specifications established by mutual agreement of the District, the ARB and the EPA.

[District Rule 1080 and 40 .CFR 60.4345(b)]

14. The NOx, CO and O2 CEMS ,shall meet the requirements in 40 CFR 60, Appendix F

Procedure 1 and Part 60, Appendix 8 Performance Specification 2 (PS 2), or shall meet

equivalent specifications established by mutual agreement of the District, the ARB, and

the EPA. [District Rule 1080 and 40 CFR60.4345(a)]·

15. Audits of continuous emission monitors shall be conducted quarterly, except during

quarters in which relative accuracy and compliance source testing are both performed, in

accordance with EPA guidelines. T'he District sh'all be notified prior to completion of the

audits. Audit reports shall be submitted along with quarterly compliance reports to the

District. [District Rule 1080]

16. The owner/operator shall perform a relative accuracy test audit (RATA) for NOx, CO and

O2 as specifie.d by 40 CFR Part 60, Appendix F, 5.11, at least once every four calendar

quarters. The permittee shall comply' with the applicable requirements for quality

assurance testing and maintenance of the continuous' emission monitor equipment .in

accordance with the procedure.s and guidance specified in 40 CFR Part 60, Appendix Fa

[District Rule 1080]

Attachment A - 2
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

17. APCD or an authorized representative. shall be allowed to inspect, as determined to be

necessary, the required monitoring devices to ·ensure that such devices are functioning

properly. [District Rule 1080]

18.. Results of the CEM system shall be averaged over a one hour. period forNOx emissions

and a three hour period for CO .emissions using consecutive 15-min·ute sampling periods in

a~cordance with all applicable requirements of CFR 60.13. [D·istrict Rule 4703 and 40 GFR

60.13]

19. Results of continuous emissions monitoring shall be reduced according to the procedures

established .in 40 CFR, Part 51, Appendix P, paragraphs 5.0 through 5.3.3, .or by other

methods deemed equivalent by mutual agreement with the District, the ARB, and the

EPA. [District Rule 1080]

20. The owner or operator shall, upon written notice from the APGO, provide a summary of

the data obtained from the CEM systems. This .summary shall be in the form. and the

.manner·prescribed by the APCO. [District Rule 1080]

21. The facility shall install and maintain equipment, facilities, and systems compatible with

the District's CEM data polling software system and shall make CEM data available to the

. District's'automated polling system on a daily basis. [District Rule 1080]

22. Upon notice by the District that the facility's GEM system is not providing polling data, the

·facility may continue to operate without providing automated data for a maximum of 30

days per calendar year provided the CEM data is sent to the District by a Districtapproved alternative method. [District Rule 1080]

23. The owner or operator shall submit a written report of CEM operations for each calendar

quarter to the APCO. The rep.ort is due on the 30th day following the. end of the calendar

quarter and shall include the following: Time intervals, data. and magnitude of excess NOx

emissions, nature and the cause of excess (if known), corrective .actions taken and

preventive measures adopted; Averaging period used for data reporting corresponding to

the averaging period specified in the emission test period used to determine compli~nce

with an emission standard; Applicable time and date of each period during which·the ·GEM

was inoperative (monitor downtime), except for zero and span checks, and the nature of

system repairs and adjustments; A negative declaration when no excess emissions

occurred. [District Rule 1080 and 40 CFR 60.4375(a) and 60.4395]

24. Permittee shall notify the District of any breakdown condition as soon as reasonably

possible, but no later than one hour after its detection, unless the owner or operator

demonstrates to the District's satisfaction that the longer reporting period was necessary.

[District Rule 1100, 6.1]

25. The District shall be notified in writing within ten days following the correction of any

breakdown condition. The breakdown notification shall include a description. of the

equipment. malfunction or failure, the date and cause of·theinitial failure, the estimated

emissions in excess of those allowed, and the methods utilized to restore normal

operations. [District Rule 1100, 7.0]

Attac.hment A - 3
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

~6. Emission rates from this unit (with duct burner firing), except during startup and shutdown

periods, shall not exceed any of th.e following limits: NOx (as N02.) - 17.20Ib/hr and 2.0

ppmvd @ 150/0 02; voe (as methane) - 5.89 Ib/hr and 2.0 ppmvd @ 15% 02; CO -

10.60 Ib/hr and 2.0 ppmvd @ 15% 02; PM10 - 11.78 Ib/hr; or SOx (as 802) - 6.65Ib/hr.

NOx(as N02) emission limits are one hour rolling averag·es. All other emission limits are

three hour rolling averages. [District Rules 2201,4001, and 4703]

27. Emission rates from this unit (without duct burner firing), except during startup and

shutdown periods, .shall not exceed any of the following limits: NOx (as N02) - 13.55 Ib/hr

and 2.0 ppmvd@ 15% 02; VOC (as methane) - 3.34 Ib/hr and 1.4 ppmvd @ 15~/0 02;

eo - 8.35 Ib/hr and 2.0 ppmvd @ 15% 02; PM10 - .8.91 Iblhr; or SOx (as S02) - 5.23

Ib/hr. NOx (as N02) emission limits are one hour rolling averages. All other emission

limits are three h'our rolling averages. [District Rules 2201, 4001, and 4703]

28. During start-up and shutdown, CTG exhaust emission rates shall not exceed any of the

following limits: NOx (as N02) - 160 Ib/hr; eo - 1,000 Ib/hr; vae (as 'methane) - 16

Ib/hr; PM10 - 11.78 Ib/hr; SOx (as 802) - 6.652 Ib/hr; or NH3 - 32.13 Ib/hr. [District Rules

2201 and 4703]

29. Daily emissions from theCTG shall not exceed the following limits': NOx (as N02) - 412.8

Ib/day;' CO - 254.4 Ib/day; vac - 141.4 Ib/day; PM10 282.7 Ib/day; SOx (as 802) -

159.6 Ib/day, orNH3 - 771.1 Ib/daY. [District Rule 2201 ]

30. Emissions 'from t.his un'it, on days when a startup and/or shutdown occurs, shall not

exceed the following limits:NOx (as N02) - 789.6Ib/day; VOC- 202.0 Ib/day; CO -

5,590.8 Ib/day; PM1.0 - 282.7 Ib/day'; SOx (as S02) - 159.6 Ib/day·, or NH3 - 771.1

Ib/day. [District Rule 2201]

31. the ammonia (NH3) emissions shall not exceed 10 ppmvd @ 15% 02 over a 24 hour

rolling average. [District Rule 2201]

32. The CTG shall be fired exclusively on PUC-regu'lated natural gas with a sulfur 'content no

greater than 1.0 grain of sulfur compounds (as 8) per 100 dry scf of natural gas. [District

Rule 2201 and 40 eFR 60.4330(a)(2)] .

33. Annual emissions from the CTG, calculated on a twelve month rolling basis, shall not

exceed ·anyof the following limits: NOx (as N02) - 143,951 Ib/year; CO - 601,810 Ib/year;

. VOC - 34,489 Ib/year; PM10 - 80,656 Ib/year; or sax (as S02) - 16,694 Ib/year; or NH3 -

208,708 Ib/year. [District Rule 2201]

34. The duration of each startup or shutdown shall not exceed six hours. Startup and

shutdown emissions shall be cc;>unted toward all applicable emission limits. [District Rules

2201 and 4703]

35. Each one hour period shall commence on the hour. Each one h'our period in a three hour

rolling average will commence on the hour. The three hour average will be compiled from

.the three most recent one hour periods. Each one· hour .period in a twenty-four hour

.average for ammonia slip will commence on the hour. [District Rule 2201]

Attachment A 4
Avenal'PowerCenfer, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

36. Daily emissions will be compiled for a twenty-four hour period starting and ending at

twelve-midnight. Each month in the twelve consecutive month rolling average·emissions

shall com·mence at the beginning of the first day of the month.. The twelve .consecutive

month rolling average emissions to determine compliance with annual emissions

limitations shall be compiled from the twelve most recent calendar months. [District Rule

2201] . .

37. Startup shall be defined as the period of time during which a unit is brought from a

shutdown status to its operating temperature and pressure, incl~ding the time required by

the unit's emission control system to reach full operations. Shutdown shall be defined as

the period of time during which a unit .is taken from an operational toa non-operational

status by allowing it to cool down from its operating temperature to ambient temperature

as the fuel supply to the unit is completely turned off. [Qistrict Rules 2201 and 4703]

38. The emission control systems shall be in operation and emissions shall be minimized

insofar as· technologically feasible during startup and shutdown.. [District Rule 4703]

39. The exhaust stack shall be equipped with permanent provisions to allow collection of

stack gas samples con·sistent with EPA test methods and shall be equipped with safe

permanent provisions to sample stack gases with a portable NOx, CO, and 02 analyzer

during Di$trict inspections. The sampling ·ports shall be located in 'accordance with the

CARB regulation titled California Air Resources Board Air Monitoring Quality Assurance

Volume VI, Standard .Operating Procedures for Stationary Emission Monitoring and

Testing. [District Rule 1081]

40. Source testing to measure startup, NOx, CO, and vae mass .emission rates shall be

conducted for one of the gas turbines (C-3953-10 or C-3953-11) prior to the end of the

commissioning period and at least once every seven years thereafter. CEM relative

accuracy shall be determined during startup source testing in accordance with40CFR

60,'Ap'pendix B. [District Rule 1081]

41. Source testing (with and without duct burner firing) to measure the NOx, CO, and voe

emission rates (Ib/hrand ppmvd @ 15% 02) shall be conducted within 60 days after the

end of the commissioning period and at least once every twelve months thereafter.

[District Rules 1081 and 4703]

42. Source testing (with and without duct burner firing) to measure the PM10 emission rate

(Ib/hr) and the ammonia emission rate shall be conducted within 60 days after the end of

the 'commissioning period and at least once every twelve months thereafter. [District Rule

1081] . .

43. Com.pliance with natural gas sulfur content limit shall be demonstrated within 60 days

after the end of the commissioning period and weekly thereafter. After demonstrating

compliance with the fuel' sulfur content limit for 8 consecutive weeks for a fuel source,

then the testin.g frequency shall not be less than monthly. If a test shows noncompliance

. with the sulfur content requirement, the source must return to weekly testing until eight

consecutive weeks show compliance. [District Rules 1081, 2540, and 4001].

AttachmentA - 5
Avenal Power Center, LLC (OB-AFC-01j

SJVACPO Determination of Compliance, C-1080386

44. Demonstration of compliance with the annual average sulfur content limit shall be

demonstrated by a 12 month rolling average of the sulfur content either (i) 'documented in.

a valid purchase contract, a supplierc~rtification, a tariff sheet or transportation contract

or (ii) tested using ASTM Methods 01072, 03246,04084, 04468, 04810, 06228, D6667

or Gas.ProcessorsAssociation Standard 2377. [District Rules 1081 and 2201]

.45. Source testing to determine compliance with the NOx, CO and voe emission rates (Ib/hr

and ppmvd .@ 15% O2), NH3 emission rate (ppmvd @ 150/0 O2) and PM10 emission rate

(Ib/hr) 'shall be conducted at least once every '12 months. [District Rules 1'081, 2201 and

4703 and 40 CFR 60.4400(a)]

46. 'Compliance with the NOx and CO emission limits shall be demonstrated with the auxiliary

burner both on and off. [District Rule 4703]

41.. Compli.ance demonstration (source testing) shall be District witnessed, or authorized and

samples shall be collected by a California Air Resources Board certified testing

laboratory. Source testing shall be conducted using the methods and procedures

approved by the District. The District must be notified 30 days prior to any compliance

source test, and a source test plan must be submitted for approval 15 days prior to

testing. The results of each source test shall be submitted to the District within 60 days

.thereafter. [District Rule 1081]

48. The following test methods shall be used: NOx - EPA Method 7E or 20; CO - EPA

Method. to or 10B; VOC - EPA Method 18 or 25;PM10- EPA Method 5 (front half and

back half) OJ 201 and 202a; ammonia- BAAQMD ST-1 B; and O2 - EPA Method 3, 3A,or .

.20. EPA approved alternative test methods as approved .by the District may also be used

to address the source testing requirements of this permit. [District Rules 1081 and 4703

and 40 CFR 60.4400(1 )(i)]

,49. The sulfur content of ea'ch fuel sou~ce shall be: (i) documented in a valid purchase

contract, a supplier certification, a tariff sheet or transportation contract or (ii) monitored

within 60'days 'of the end of the commission period and weekly thereafter. If the SUlfur

content is demonstrated to be less than 1.0 grl100 sct for eight consecutive weeks, then

the monitoring frequency shall be every six months. If the result of any six month

monitoring demonstrates that the fuel does not meet the fuel .sulfur content limit, we~kly

monitoring shall resume..[District Rule 2201 and. 40 CFR 60.4360, 60.4365(a) and

60.4370(c)] .

50. Excess emissions shall bedefi'ned as any operating .hour in which the 4-hour or 30-day

rolling average NOx concentration exceeds applicable emissions limit a.nd a period of

monitor downtime shall be any unit 'operating hour in which sufficient data are not obtained

to validate the hour for either NOx or 02 (or both). [40 CFR 60.4380(b)(1)]

51. Fuel sulfur content shall be monitored using one of the following methods: ASTM Methods

01072, D3246, 04084, 04468, 04810, 06228, 06667 or 'Gas Processors Association

Standard 2377. [40 CFR60.4415(a)(1)(i)]

52. The permittee shall submit to the District information correlating the NOx control system

operating parameters to the associated' measured NOx output. The information must be

, Attachment A - 6
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

sufficient to allow the District to determin.e compliance with the NOx emission limits of this

permit during times that the CEMS is not functioning properly. [District Rule 4703]

53. The permittee shall maintain the following records: the date, time and duration of any

malfunction of the continuous monitoring equipment; dates of performance testing; dates

of evaluations, calibrations, checks, and adjustments of the continuous monitoring

equipment; date and time period which· a continuous monitoring system or monitoring

device was inoperative. [District Rules 1080 and 2201 and 40 CFR 60.8(d)]

54. The permittee shall maintain the following records: date and time, duration, and type of

any startup, shutdown, or malfunction; performanc~ testing, evaluations, calibrations,

checks, adjustments, any period during. which a continuous monitoring system or

monitoring devicew~s inoperative, and maintenance of any continuous emission m'onitor.

[District Rules 2201 and 4703]

55. The permittee shall maintain the following records: hours of operati'on, fuel consumption

(scf/hr and scf/roll.ing twelve month period), continuous emission monitor measurements,

calculated ammonia slip, and calculated NOx mass emission rates (Ib/hr and Ib/twelve

.month rolling period). [District Rules 2201 and 4703]

56. The owner or operator of a stationary gas turbine system shall maintain all records of

required monitoring data and support information for inspection at any time for ·.a period of

five years. [District Rules 2201 and 4703]

57. Disturbances of soil related to any construction, demolition, excavation, extraction, or other

earthmoving activities shall comply with the requirements for fugitive dust control in District

Rule 8021 unless specifically exempted under Section 4.0 of' Rule 8021 or Rule 8011.

[District Rules 8011 and 8021]

58. An owner/operator shall submit a Dust Control Plan to the APCO prior to the start of any

construction activity on any site that will include 10 acres or more· of disturbed' surface area

for residential developments, or 5 acres or more' of disturbed .surface area for nonresidential development, or will include moving, depositing, or relocating more than 2,500

cubic yards per day of bulk materials on at least three days. [District Rules 8011 and 8021]

59. An owner/operator shall prevent or cleanup any carryout or trackout in accordance with the

requ.irements of District Rule 8041 Section 5.0, unless specifi'cally exempted under Section

4.0 of Rule 8041 (8/19/04) or Rule 8011(8/19/04). [District Rules 8011 and 8021]

60. . Whenever open areas are disturbed, or vehicles are used in open areas, the facility shall

comply with the requirements of Section 5.0 of District Rule 8051, unless specifically

exempted under Section 4.0 of Rule 8051 or Rule 8011. [District Rules 8011 and 8051]

61. Any paved road or unpaved road shall comply with the requirements of District Rule 8061

unless specifically exempted under Section 4.0 of Rule 8061 or Rule 8011. [District Ru.les

8011 and 8061]

62. Water, gravel, roadmix, or chemical/organic dust stabilizers/suppressants, vegetative

materials, .or other District-approyed control measure shall be applied to unpaved vehicle

Attachment A - 7
Avenal Power Center, LLC (OB-AFC-01) .

SJVACPO Determination of Compliance, C-10B0386

travel areas as required to limit Visible Dust Emissions to 20% opacity and comply with the

requirements for a stabilized unpaved road as defined in Section 3.59 of District Rule 8011.

[District Rule 8011 and 8071]

63. Where dusting materials are allowed to accumulate on paved surfaces, the accumulation

shall be removed daily or water and/or chemical/organic dust stabilizers/suppressants shall

be ap·plied to the paved surface as required to ·maintain continuous compliance with the

requirements for a stabilized unpaved road as defined in Section 3.59 of District Rule 8011

and limit Visible Dust Emissions (\IDE) to 20% opacity. [District Rule 8011 and 8071]

64. On each day that 50 or more Vehicle Daily Trips. or 25 or more Vehicle Daily Trips with 3

axles or more will occur on an unpaved vehicle/equipment traffic area, permittee shall

apply water, gravel, roadmix, or chemical/organic dust stabilizers/suppressants, vegetative

materials, or other District-approved control measure as required to limit Visible Dust

Emissions to 20% opacity and comply with the requirements for a stabilized unpaved road

as defined in Section 3.59 of District Rule 8011. [District Rule 8011 and 8071]

65. Whenever any portion of the site becomes inactive, Permittee shaltjrestrict access and

periodically stabilize any .disturbed surface to comply with the conditions for a stabilized

surface as defined in Section 3.58 of District Rule 8011. [District Rules 8011 and 8071]

66. Records and other supporting documentation shall be maintained as required to

demonstrate compliance with the requirements of the rules under Regulation VIII only for

those days that a control measure was implemented. Such records shall include the type of

controlmeasure(s) used, ·the location and. extent of coverage, a.nd the date, amount, and

frequency of application of dust suppressant, manufacturer's dust suppressant product

information sheet that identifies the name of the dust suppressant and application

instructions. Records shall be kept for one year following project completion that results in

the termination of all dust generating activities. [District Rules 8011, 8031, and 8071]

Attachment A - 8
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

EQUIPMENT DESCRIPTION, UNIT C-3953-11-0:

180 ·MW NOMINALLY RATED COMBIN·ED-CYCLE POWER GENERATING SYSTEM #2

.CONSISTING ·OF A GENERAL ELECTRIC FRAME 7 MODEL PG7241FA NATURAL GASFIRED COMBUSTION TURBINE GENERATOR WITH DRY LOW NOx COMBUSTOR, A

SELECTIVE CATALYTIC REDUCTION (SCR) SYSTEM, AN OXIDATION CATALYST, HEAT

RECOVERY STEAM GENERATOR #2· (HRSG) WITH A 562 MMBTU/HR DUCT BURNER

AND A 300 MW·NOMINALLY RATED STEAM TURBINE SHARED WITH C-3953-10

1. Permittee shall submit an appli.cation to comply with 8JVUAPCD District Rule 2520 -

Federally Mandated Operating Permits within twelve months of commencing operation.

[District Rule 2520]

2. Permittee shall su~mit an application to comply with 8JVUAPCD District Rule 2540 - Acid

Rain Program within 12 months of commencing operation. [District Rule 2540]

3. Prior to initial operation of C-3953-10-0, C-3953-11-0, and C-3953-12-0, permittee shall

provide NOx (as N02) emission reduction credits for the following quantities of emissions:

·1 st quarter - 67,103 Ib; 2nd quarter - 67, 104 Ib; 3rd quarter -·67,104 Ib; and 4th quarter -

67,104 lb. Offsets shall be provided at the appropriate distance ratio specified in Rule

2201. [District Rule 2201]

Prior to initial ·operation of C-3953-10-0, C-3953-11-0, and C-3953-12-0, permittee shall

provide VOC emission reduction credits for the following quantities of emissions: 1st

quarter 12,294 Ib; 2nd quarter - 12,295 Ib; 3rd quarter - 12,295 Ib; and 4th quarter -

12,295 lb. Offsets shall be provided at the appropriate distance ratio specified in Rule

2201. [District Rule 2201]

5.. Prior to .initial operation of C-3953-10-0, C-3953-11-0, and C-3953-12-0, permittee shall

provide PM10 emission red~ctioncredits for the following quantities of· emissions: 1st

quarter - 33,087 Ib; 2nd quarter - 33,086 Ib; 3rd quarter. - ,33,086 Ib; and 4th quarter -

33,086 lb. Offsets shall be provided at the appropriate distance ratio specified in Rule

2201. SOx ERG's may be used to offset PM10 i·ncreases at an interpollutant ratio of 1.0

Ib-SOx: 1.0 Ib-PM10. [District Rule 2201]

6. .ERG certificate numbers (or any splits from these certificates) C-897-1, C~898-1, N-724-1,

N~725-1, 8-2812-1, 8-2813-1, S-2817-1, C-899-2, C-902-2, N-720-2, N-722-2, N-726-2, N728-2, 8-2814-2, 8-2321-2, C-896-4, N-721-4, N-723-4, 8-2791-5, S-2790-5, 8-2789-5, S2788-5, or N-762-5 shall be used to supply the required offsets, unless a revised offsetting

proposal is received and approved by the District, upon which this determination· of

compliance (DOC) Shall be reissued, administratively specifying the new offsetting

proposal. Original public noticing requirements,if any, shall be duplicated prior to

reissuance of the DOC. [District Rule 2201]

{15} No air contaminant shall be disch·arged into the atmosphere for a period or periods

aggregating more than three minutes in anyone hour which is as dark as, or darker than·,

Ringelmann 1 or 200/0 opacity. [District Rule 4101]

Attachment A - 9
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance,C-1080386

{98} No air contaminant shall be released into the atmosphere which causes a public

nuisance..[District Rule 4102]

9. {14} Particulate matter emissions shall not exceed·0.1 grains/dscf in concentration. [District

Rule 4201]

10. The CTG shall be fired exclusively on PUC-regulated natural gas with a sulfur content of no

greater than 1.0 grains of sulfur compounds (as S) per 100 dry scf 'of natural gas. [District

Rule 2201 and 40 CFR 60.4330(a)(2)]

11. Annual average of the sulfur content of the CTG shall not excee'd 0.36 grain of sulfur

compounds (as .S) per 100 . dry scf of natural gas. [District

Rule 2201]

. 12. ·The owner or operator shall' install, certify, maintain, operate and quality-assure a

Continuous Emission Monitoring System (CEMS) which continuously measures· and

records the exhaust gas NOx, CO .and02 concentrations. Continuous emissions'

.monitor(s) shall be capable of monitoring emissions' during normal operating conditionsJ.

and during startups and shutdowns, provided the CEMS passes the relative accuracy

requirement for startups and shutdowns specified herein. If relative accuracy of CEMS

cannot be. demonstrated during startup conditions, CEMS results during startup and

shutdown events shall be replaced with startup emission rates obtained from 'source testing·

to determine compliance with emission limits contained in this document. [District Rules

1080 and 4703 and 40 CFR 60.4340(b)(1)]

13. The CEMS shall complete a minimum of one cycle of operation (sampling, analyzing, and

data recording) for each successive 15-minute period or shall ·meet equivalent

specifications established by mutual agreement of the District, the ARB and the EPA.

[District Rule 1080 and 40 CFR 60.4345(b)]

14. 'The NOx, CO and 02 CEMS shall meet the requiremeflts in 40 CFR 60, Appendix F

Procedure 1 and Part '60, Appendix B Performance Specification 2 (PS 2),. or shall meet

equivalent specifications established by mutual agreement of the District, the ARB, and the

EPA. [District Rule 1080 and 40 CFR 60.4345(a)]

15. Audits of continuous emission· monitors shall be conducted quarterly, except during

quarters in which relative accuracy and compliance source testing are both performed', in

a'ccordance with EPA guidelines. The District shall be notified prior to co.mpletionof the

aud·its. Audit re.ports shall be submitted along with quarterly compliance reports to the

District. [District Rule 1080]

16.· The owner/operator shall perform a, relative accuracy test audit (RATA) for NOx, CO and

02 as specified by 40 CFR Part 60, Appendix F, 5.11, at least once every four calendar

quarters. The permittee shall comply with the applicable requirements for quality

assurance testing and maintenance of the continuous. emission monitor equipment in

accordance with the procedures and guidance specified in 40 CFRPart 60, Appendix F..

[District Rule 1080]

Attachment A - 10
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

7. APCO or an authorized representative shall be allowed to inspect, a.s determined to be

necessary, the required monitoring devices to ensure 'that such devices are functioning

properly. [District Rule 1080]

18. Results of the GEM system shall be averaged over a one hour period for NOx'emissions and

a three hour period for CO emissions using consecutive 15-minute sampling periods in

accordance with all applicable requirements of CFR 60.13. [District Rule 4703 a.nd 40 CFR

60.13]

19. Results of·continuous emissions monitoring shall be reduced according to the procedures

established in 40 GFR, Part 51, Append'ix P, paragraphs 5.0 through 5.3.3, or by other

methods deemed equivalent by mutual agreement with the District, the ARB, and the EPA.

[District Rule 1080]

20. The owner or operator shall, upon written notice from the APCO, provide a summary of the

data obtained from the CEM systems. This summary shall·be in the form and the manner

prescribed by the APGO. [District Rule 1080]

21. The facility shall install and maintain equipment, facilities, and systems compatible with the

District'sCEM data polling software system and shall make CEM data availa.ble to the

District's automated polling system on a daily basis. [District Rule·1 080]

22. Upon notice by the District that the facility's GEM system is not provid.ing polling data, the

facility may continue to operate without providing automated data for a maximum of 30

days per calendar year provided the GEM data is sent to the District by a District-approved

.alternative method. [District Rule 1080]

23. The owner or operator shall submit .~ written report of GEM operations for each calendar

quarter to the APCO.The report is due on the 30th day following the end of the calendar

quarter and shall include the following: Time ~ntervals,data and magnitude of excess NOx

~missions, nature and the cause of excess (if known), corrective actions ta.ken and

preventive meas'ures adopted; Averaging period used for data reporting corresponding to the

averagi·ng period specified in the emission test period used to determine compliance with an .

emis'sion standard; Applicable time and date of each period .during which the GEM was

inoperative. (monitor downtime), except for zero and span checks, and the 'nature of system,

repairs and adjustments; A negative declaration when no excess emissions occurred.

[District Rule 1080 and 40 GFR 60.4375(a) and 60.4395]

24. Permittee shall notify the District of any breakdown condition as soon as reasonably

. possible, but no later than one', hour after its detection, unless the owner or operator

demonstrates to the District's satisfaction that the longer reporting period was necessary.

. [District Rule 1100, 6.1]

25. The District shall be notified in writing within ten days following the correction of any

breakdown condition. The breakdown notification shall include a description of the

equipment malfunction or failure, the date and cause of the initial failure, the estimated

emissions in excess of those aIIowe'd, and the methods utilized to restore normal

operations. [District Rule 1100,7.0]

Attachment A - 11
Avenal Power'Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

1. Emissi'on rates from this unit (with duct burner firing), except during startup and shutdown

periods, shall not exceed any of the following limits: NOx (as N02) - 17.20 Ib/hr and 2.0'

ppmvd @ 15% 02; voe (as methane) - 5.89 Ib/hr and 2.0 ppmvd @ 15% 02; CO -10.60

Ib/hr and 2.0ppmvd @ 150/0 02; Pry110 - 11.78 Ib/hr; or sax (a~ 802) - 6.65 Ib/hr. NOx

(as N02) emission limits are one hour rolling averages. All other emission limits are three

hour rolling averages. [District Rules 2201, 4001, and 4703]

27. Emission rates from this unit (without duct burner firing), except during startup and

shutdown periods, shall not exceed any of the following limits: NOx (as N02)- 13.55 Ib/hr

and 2.0 ppmvd @ 15% 02; VaG (as methane) - ,3.34 Ib/hr and 1.4 ppmvd @ 15°/b 02; CO

- 8.35 Ib/hr and 2.0 ppmvd @150/0 02; PM10 - 8.91 Ib/hr; or SOx (as S02) -:- 5.23 Ib/hr.

NOx (as N02) emission limits are one hour rolling averages. All other emission limits are

three hour rolling averages. [District Rules 2201, 4001, and 4703]

28. During start-up and shutdown, CTG exhaust emission rates shall not exceed any' of the

following limits: NOx (as N02) -160.lb/hr; CO -1,000 Ib/hr; voe (as methane) -16Ib/hr;

,PM10 - ·11.78Ib/hr; SOx (as 802) - 6.652 Ib/hr; orNH3 - 32.13 Ib/hr. [District Rules 2201

and 4703] .'

29. Daily emissions from the eTG shall not exceed the following limits: NOx(asN02) -'412.8

Ib/day; eo - 254.4 Ib/day; voe -141.4 Ib/day; PM10 - 282.7 Ib/day; sax (as S02) - 159.6

Ib/day, or NH3 - 771.1 Ib/day. [District Rule 2201]

J. Emissions from this unit, on days when a startup and/or shutdown occurs, shall not exceed

the 'follo,wing limits:NOx (as N02) - 789.6 Ib/day; voe - 202.0 Ib/day; CO -5,590.8

Ib/day; PM10 '-:- 282.7 Ib/day; sax (as 802) - 159.6Ib/day, ,or NH3 - 771.1 Ib/day. [District

Rule 2201]

31. The ammonia (NH3) emissions shall not e,xceed 10 ppmvd @ 15%02 over a 24 hour

rolling average. [District Rule 2201]

32. The eTG shall b'e fired exclus'ively,on PUC-regulated natural gas with. a 'sulfur content no

greater than 1.0 grain of sulfur compounds (as S) per 100 dry scf of natural gas. [District Rule

2201 and 40 CFR 60.4330(a)(2)]

33. Annual emissions from the GTG" calculated on a twelvemonth rolling .basis, shall not

exceed any o.f the following limits: NOx (as N02) - 143,951 Ib/year; .CO - 601,810 Ib/year;

voe - 34,489 Ib/year; PM10 - 80,656 Ib/year; or SOx (as S02) - 16,694 Ib/year; or NH3 -

208,708 Ib/year. [District Rule 2201] .

34. The duration of each startup or shutdown shall not exceed six hours. Startup and

shutdown emissions shall ,be counted toward all applicabl,e emission limits. [District Rules

2201 and 4703]

,. Each one hour period shall commence on the hour. Each one hour period in a three hour

tolling average,will.commence on the hour. The three' hour average will be compiled from

the three most recent one hour periods. Each one. hour period ina twenty-four hour

average for ammonia slip will commence on the hour. [District Rule 2201]

Attachment A - 12
Avenal Power Center, LLC (OB-AFC-01)

SJVACPD Determination of Compliance, C-1080386

J. Daily emissions will be compiled for a twenty-four hour period starting and ending at "

twelve-midnight. Each month in the twelve consecutive month rolling average emissions

shall commence at the ,beginning of the first day of the month. The twelve consecutive

month rolling average emissions to determine compliance with a'nnual emissions limitations

shall be compiled from the twelve most recent calendar months. [District Rule 2201]

37. Startup shall be defined as the period of time during which a unit is brought 'from a

shutdown status to its operating temperature and pressure, including the time required by

the unit's emission control system to reach full operations. Shutdown 'shall be defined as

the period of time during which a unit is taken from an operational to a non-operational

status by allowing it to cool down from its operating temperature to ambient temperature as

the fuel supply to the unit is compl,etely turned ,off. [District Rules 2201 and 4703]

38. The emission control systems shall be in operation and emissions shall be, minimized

insofar as technologically feasible during startup and shutdown. [District Rule 4703]

39. 'The exhaust stack shall be equipped with permanent provisions to allow collection qf stack

gas sam'plesconsistent with EPA test methods and shall be equipped with safe permanent

provisions to sample stack gases with a portable NOx, CO, and 02 analyzer during District

inspections. The sampling ports shall be located in accordance with the CARB regulation

titled California Air Resources Board Air Monitoring Quality Assurance Volume VI,

Standard Operating Procedures for Stationary Emission Monitoring and Testing. -[District

Rulet081]

40. Source testing to measure startup NOx, CO, andVOC mass emission rates shall be

conducted for one of 'the gas turbines (C~39,53-10 or C-3953-11)" prior to the end "of the

commissioning period and at least once every seven years thereafter. CEM relative

accuracy shall be determined during startup source testing in accordance with 40 CFR 60,

Appendix B. [District Rule1 081 ]

41. Source testing (with and without duct,burner firing) to measure the NOx, CO, and"voe

emission, rates (Ib/hr and ppmvd @ 150/0 02) shall be conducted within 60 days after the

end of the commissioning period and at least once every twelve months thereafter. [District

Rules 1081 and 4703]

42. Source testing (with and without duct burner firing) to measure the PM10 emission rate

(Ib/hr) and the ammonia emission rate shall be conducted within 60 days after the end of

the commissioning period and at least once every twelve months thereafter. [District Rule

1081]

43. Compliance with natural gas sulfur content limit shall 'be demonstrated within 60 days after

the end" of the commissioning pe"riod and weekly thereafter. After demonstrating

compliance with the fuel sulfur content limit for 8 consecutive weeks"for a fuel source, then

the testing frequency shall not be less than monthly. If a test shows noncompliance with

the sulfur content requirement, the source must return to weekly testing until eight

consecutive weeks show compliance. [District Rules 1081,2540, and 4001].

44. Demonstration of compliance with the annual average sulfur content limit shall be

demonstrated by a 12 month rolling'average of the sulfur content either (i) documented in a

Attachment A- 13
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

valid purchase contract, a supplier certification, a tariff sheet or transportation contract or

(ii) tested using. ASTM Methods 01072, 03246,04084,04468,04810,'06228,06667 or

Gas Processors Association Standard 2377. [District Rules 1081 and 2201]

4,5. Source testing to determine compliance with the NOx, CO and voe emission rates (Ib/hr

and ppmvd @ 150/0 O2), NH3 emission rate (ppmvd @ 15% O2) and PM10 emission rate

(Ib/hr) shall be conducted at least once every 12 months. [District Rules 1081, 2201 and

4703 and 40 CFR 60.4400(a)]

46. Compliance with the NOx and CO emission limits shall be demonstrated with the auxiliary

burner both on and off. [District Rule 4703]

47. Compliance demonstration (source testing) shall ,be Oistrict witnessed, or authorized and

samples shall be collected by a California Air Resources Board. certified testing laboratory.

Source testing shall be conducted using th,e methods and procedures approved by the

District. The District must be notified 30' days prior to any compliance source test, and a

source te'st plan must be submitted for approval 15 days prior to testing. The results of

each source test shall b'e SUbmitted to the District within 60 days thereafter. [District Rule

1081]

48. The following test methods shall be u'sed: NOx -.EPA Method 7E or20; CO - EPA Method

10 or 10B; VOC - EPA Method 18, or 25; PM10 - EPA Method 5 (front half and back half) or

201 and 202a; ammonia.;. BAAQMD ST-1 B; and O2 - EPA Method 3, 3A, or 20. EPA

approved alternative test methods as approved by the District may also be used to address

the' source testing requirements of this permit. [District Rules 1081 and 4703 and 40 CFR

60.4400(1 )(i)]

49. The sulfur content of each fuel source shall be: (i) documented in a valid purchase

contract, a supplier certification, a tariff sheet or transportation. contract or (ii) monitored

within 60 days of the end of the commission period and weekly thereafter. If the sulfur

content is demonstrated to be less than 1.0 gr/100 scf for eight consecutive weeks, then

the monitoring frequency shall be every six months. If the result of any si'x month

monitoring demonstrates that the fuel does not meet the fuel sulfur content limit, weekly

monitoring shall resume. [District Rule 2201 and 40 CFR 60.43.60, 60.4365(a) and

60.4370(c)]

50. Exce'ss emissions shall be defined as any operating hou'r 'in which the 4-hour or 30-day

rolling average NOx concentration exceeds applicable emissions ·Iimit and a period of monitor

downtime shall be any unit operating hour in which sufficient data. are not obtained to validate

the hour for either NOx or 02 (or both). [40 CFR 60.4380(b)(1)]

51. Fuel sulfur content shall be monitored using one of the following methods: ASTM Methods

01072, 03246, 04084, 04468,.04810, 06228, 06667 orGas Processors Association

Standard 2377. [40 CFR 60.4415(a)(1)(i)]

2. The permittee shall submit to the District information correlating the NOx control system

operating parameters to the associated measured NOx output. The information mustb~

sufficient to allow the District to determine compliance with the NOx emission limits of this

'permit during times that the CEMS is not functioning properly. [District Rule 4703]

Attachment A -' 14
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination ofCompliance, C-1080386

JJ. The permittee shall· maintain the following records: the date, time and duration of any

malfunction of the continuous monitoring equipment; dates of performance testing; dates of

evaluations, ca·librations, checks, and adjustments of the continuous monitoring equipment;

date and time period which a continuous monitoring system or monitoring device was .

inoperative. [District Rules 1080 and 2201 and 40 CFR 60.8(d)]

54. The permittee .shall maintain the following records: date and time, duration, and type of any

startup, shutdown, or malfunction; performance testing, evaluations, calibrations, checks,

adjustments, any period during which a continuous monitoring system or monitoring device

was inop.erative, and maintenance of any continuous emission monitor. [District Rules

2201 and 4703]

55. The permittee shall maintain the following records: hours of operation, fuel consumption

(scf/hr and scf/rolling twelve month period), continuous emission monitor measurements,

. calculated ammonia slip, and ~alculated NOx mass emission rates (Ib/hrand Ib/twelve

month rolling period). [District R·ules 2201 and 4703]

56. The owner or operatorofa stationary gas turbine system shall maintain all records of

required monitoring data and support information for inspection at any time for a period of

five years. [District"Rules 2201 and 4703]

Attachment A - 15
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

EQUIPMENT DESCRIPTION, UNIT C-3953-12-0:

37.4MMBTU/HR CLEAVER' BROOKS MODEL CBL-700-900-200#ST NATURAL GAS-FIRED

BOILER WITH A CLEAVER 'BROOKS MO'DEL PROFIRE, OR DISTRICT APPROVED

EQUIVALENT, ULTRA LOWNOX BURNER

1. Permittee shall submit an application to comply with 8JVUAPCD District Rule 2520 -

Federally Mandated Operating Permits wifhin twelve months of commencing operation.

[District Rule 2520]

2. Prior to initial operation. of C-3953-10-0, C-3953-11-0, and C-3953-12-0, permittee shall

provide .NOx (as N02) emission reduction credits for the following quantities of

emissions: 1st quarter - 67,103 lb.; 2nd quarter - 67,104 Ib; 3rd quarter - 67, 104 Ib; and

4th quarter -67,104 lb. Offsets shall be provided at the appropriate distance ratio

specified in Rule 2201. [District Rule 2201]

3. P~ior to initial operation of C-3953~10-0, C-3953-11-0, and C-3953-12-0, permittee shall

provide VOC emission reduction' credits for the following quantities of emissions: 1st

quarter - 12,294 Ib; 2nd q.uarter 12,295 Ib; 3rd quarter - 12,295 Ib; and 4th quarter -

12,295 lb. Offsets shall be provided at the appropriate distance ratio specified in Rule

2201. [District Rule 2201]

4. Prior to initial operation of C-3953-10.-0, ·C-3953-11-0, and C-3953-12-0, permittee shall

provide PM10 emission·reduction credits for the foUowing quantities of emissions: 1st

quarter -. 33,087 Ib; 2nd quarter - 33,086 Ib; 3rd quarter - 33,086 Ib; and 4th quarter -

33,086 lb. Offsets shall .be provided at the appropriate distance ratio specified in Rule

2201. 80x ERC's m.ay be used to offset PM1

°increases at an interpollutant ratio of 1.0

Ib-SOx : 1.0 Ib-PM1 O. [District Rule 2201]

5. ERC certificate numbers (or any splits from these certificate,S) C-897-1, C-898-1, N-724-

1, N~725-1, 8-2812-1, 8-2813-1, 8-2817-1,.C-899-2, C-902-2, N~720-2, N-722-2, N-726-

2, N-728-2, 8-2814-2, 8-2321-2, C-896-4,N-721-4, N-723-4, 8-2791-5, 8-2790-5, 8-

2789-5, 8-2788-5, or N-762-5 shall be used to supply the required offsets, unless a

revised offsetting proposal is received and approved by the District, upon which this

determina~ion of compliance (DOC) shall be reissuE3d, administratively specifying the new·

offsetting proposal. Original public noticing requirements, if any, shall be duplicated prior

to reissuance of the DOC. [District Rule 220,1]

6. The permittee shall obtain written District approval for the use of any equivalent equipment

not specifically approved by this Authority to Construct. Approval of the equivalent

equipment shall be m.ade only after the District's determination that the submitted desig'n

and performance of the proposed alternate equipment is· equivalent to the ,specificaHy·

authorized equipment. [District Rule 2201']

7. The permittee's request for approval of equivalent .equipment shall include the make,

model,' manufacturer's maximum rating, manufacturer's guaranteed emission rates,

equipment drawing(s), and operational characteristics/parameters. [District Rule 2010]

8. Alternate equipment shall be of the same class and category of source as the equipment

authorized by the Authority to Construct. [District Rule 2201]

Attachment A - 16
Avenal Power Center, LLC.(OB-AFC-01)

SJVACPO Determination of Compliance, C-1'OB0386

9. No emission factor and no emission shall be greater for the alternate equipment than for

the proposed equipment. No changes in the hours of operation, 9perating rate,

throughput, or firing rate may be· authorized' for any alternate equipment.. [District Rule

2201] .

10. {1407} All ~quipment shall be maintained in good operating condition and shall be

operated in a manner to minimize emissions of air contaminants into the atmosphere.

[District Rule 2201] .

11. {98} No air contaminant shall be released into the atmosphere which causes a public

nuisance. [District Rule 4102]

12. {15} No air contaminant s·hall. be discharged into the atmosphere for a period or periods

aggregating more than three minutes in anyone hour which is as dark as, or darker than,

Ringelmann 1 or 200/0 opacity. [District Rule 4101]

13. {14} Particulate matter emissions shall not exceed 0.1 grains/dscf in concentration.

[District Rule 4201]

14. . {2964} The unit shall only be fired on PUC-regulated naturaLgas. [District Rule 2201]

15. Emission rates from this unit shall not exceed any of the following limits: NOx (as N02) -

9.0 ppmvd @ 3% 02 or 0.011 Ib/MMBtu; VOC (as methane) - 10.0ppmvd @ 3% 02; CO

- 50.0 ppmvd @ 3% 02 orO.037 Ib/MMBtu; PM10 -0.005 Ib/MMBtu; or SOx (as S02) -

0.00285 Ib/MMBtu. [District Rules 2201,4305, and 4306]

16. {2972} All emis.sions· measurements shall be made with the un-it .operating either at

conditions representative of normal operations or conditions specified in the Permit to

Operate. No determination of complia·nce shall be established within two hours after a

.continuous period in which fuel flow to the unit is shut off for 30 minutes or longer, or

.within 30 minutes after a re-ignition as defined in Section' 3.0 of ,District' Rule 4306.

[District Rules 4305 and 4306]

17. {3467} Source testing to measure NOx and CO emissions from this unit while fired on

natural gas shall be conducted within 60 days of initial start-up. [District Rules 220·1,

4305, and 4306]

. 18. .{3466} Source testi.ng to measure NOx and CO emissions from this unit while fired on

natu'ral gas shall be conducted at least once every twelve (12) months. After

demonstrating compliance on two (2) consecutive annual s'ource tests, the unit shall be

tested ~ot less than once every thirty-six (36) months. If the result of the 36-month

. source test demonstrates that the unit do'es' not meet the 'applicable emission limits, the

.source testing frequency shall revert to at least once every twelve (12) months. [District

Rules 4305 and 4306]

19. {2976} The source test plan shall identify which bas.is (ppmv or Ib/MMBtu) will be used to

demonstrate compliance. [District Rules 4305 and 4306]

Attachment A - 17
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

~O. {109} Source testing shall be conducted using the methods and procedures approved by

the District. The District must be notified at least 30 days prior to any compliance source

test, and a source test plan must be submitted·. for approval at least 15 days prior to

testing. [District Rule 1081]

21. {2977}NOx emissions for source test purposes shall be determined using EPA Method

7E or ARB Method 100 on a ppmv .basis, or EPA Method 19 on a heat input basis.

[District Rules 4305 and 4306]

22. {2978} CO emissions for source test purposes shall be determined using EPA Method 10

or ARB Method 100. [District Rules 4305 and 4306]

.23. {2979} Stack gas oxygen (02) shall be determined using EPA Method 3 or 3A or ARB.

Method 100. [District Rules 4305 and 4306]

24. {2980} For emissions source testi.ng, the arithmetic average of three 30-consecutiveminute test runs shall apply. If two of three runs are above an applicable limit the test

cannot be used to demonstrate compliance with an applicable limit. [District Rules 4305

and 4306]

25. {110} The results of each source test shall be submitted to the District within 60 days

thereafter. [Distr~ct Rule 1081]

26.. A non-resettable, totalizing mass or volumetric fuel flow meter to measure the amount of

fuel combusted in the unit shall be installed, u.tilized and maintained. [District Rules 2201

and 40 CFR 60.48 (c)(g)]

27. Permittee shall maintain daily records of the type and quantity of fuel combusted by the

boiler. [District Rules 2201 and 40 CFR 60.48 (c)(g)]

28. {2983} All records· shall be maintained and retained on-site for a minimum of five (5)

years, and shall be made available for District inspection upon request. [District Rules

1070, 4305, and 4306]

29. {1832} The exhaust stack shall be equipped with a continuous emissions monitor (CEM)

for NOx, CO, and 02. The CEM shall meet the requirements of 40GFR parts 60 and 75·

and shall be capable of monitoring emissions during startups and shutdowns as well as

during normal operating conditions. [District Rules 2201 and 1080]

27. {1833} The facility shall install and maintain equipment, facilities, and systems

.compatible with the District's GEM data polling software system and shall· make CEM

data available to the District's automated polling system ona daily basis. [District Rule

1080]

28. {1834} Upon notice by the District that the facility's CEM system is not providing polling

data, the facility m·ay continue· to operate without providing automated data for a

maximum -of 30 days per calendar year provided the GEM. data is sent to the District by a

District-approved alternative method. [District Rule 1080]

Attachment A - 18
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

29. {1835} The exhaust stack shall be equipped with permanent 'provisions to allow collection

of stack gas samples consistent with EPA test methods and shall be· equipped with safe

permanent provisions to sample stack gases with a portable NO'x, CO, and 02 analyzer

during District inspections. The sampling ports shall be located in accordance with the

CARB regulation titled California Air Resources Board Air Monitoring Quality Assurance

Volume VI, Standard Operating Procedures for Stationary Source Emission Monitoring

and Testing. [District Rule1081l

30. {1836} Results of continuous emissions monitoring shall be reduced according to the

procedure established in 40 CFR, Part 51, Appendix P, paragraphs 5.0 through 5.3.3, or

by other methods deemed equivalent by mutual agreement with the District, .the AR.B,

and the EPA. [District Rule 1080]

31. {1837} Audits of continuous emission monitors shall· be conducted quarterly, except

during quarters in which relative accuracy and total accuracy testing is performed, in

accordance with EPA guidelines. The District shall be notified prior to completion of the

audits. Audit reports shall be submitted along 'with quarterly compliance reports to the

. District. [District Rule.1 080]

32. {1838} The owner/operator shall perform a relative accuracy test audit (RATA) as

specified by 40 CFR Part 60, Appendix F, 5.11 ,at least. once every four calendar

quarters. The permittee shall 'comply with the applicable requirements for quality

assurance testing' and maintenance of the continuous emission monitor equipment in

accord'ance with the procedures .and guidance specified' in 40 CFR Part 60, Appendix F.

[District Rule 10801

33.' {1'839} The permittee shall submit a written report to the APCO for each calendar

quarter, within 30 days of the end of the quarter, ·including: time intervals, data and

magnitude of excess emissions,nature and c.ause of' excess emissions (if known),

corrective actions taken and preventive measures adopted; averaging period used for

data ·.reporting shall correspond to the averaging period for each respective emission

standard; applicable time and date of each period during which.the CEM was inoperative

(except for zero and· span checks) and the nature of system repairs and adjustments;

and a negative declaration when no excess emissions occurred. "[District Rule 1080]

Attachment A - 19
Avenal P9wer Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

~QUIPMENT DESCRIPTION, UNIT C-3953-13-0:

288 BHP' CLARKE MODEL JW6H-UF40 DIESEL-FIRED EMERGENCY IC ENGINE

POWERING A FIRE PUMP

1. Pe'rmittee shall submit an application to comply with SJVUAPCD District Rule 2520 -

Federally Mandated Operating Permits within twelve months of commencing o·peration.

[District Rule 2520]

2. {98} No air contaminant shall be released into the atm·osphere which causes a public

nuisance. [District Rule 4102] .

3. {14} Particulate matter emissions shall not exceed 0.1 grains/dscf in concentration.

[District Rule 4201]

4. {15} No air contaminant shall be discharged i.nto the atmosphere for a period or periods

. aggregating more than three minutes in anyone hour which is as dark as, or darker than,

Ringelmann 1 or 20% opacity. [District Rule 4101] ,

5. {1898} The exhaust stack shall vent vertically upward. The vertical exhaust flow shall not,

be impeded by a rain cap, roof overhang, or any other obstruction. [District Rule 4102]

6. {3395} Only CARB certified diesel fuel containing not more than 0.0015% sulfur by

weight is to be used. [District Rules 2201 and 4801 and 17 CCR 93115]

7. {3403} This engine 'shall be equipped with an operational non-resettable elapsed time

meter or other APCO approved alternative. [District Rule 4702 .and 17 CCR 93115]

8. Emissions from this IC engine shall not exceed any of the following limits: 3.4 gNOx/bhp-hr, 0.447 g-CO/bhp-hr, or 0.38 g-VOC/bhp-hr. [District Rule 2201 and 13 CCR

2423 and 17 CCR 93115]

9. Emissions from 'this IC engine shall not exceed 0.059 g-PM10/bhp-hr based on USEPA

certification using ISO 8178 test procedure. [District Rules 2201 and 4102 and 13 CCR

2423 and, 17 CCR 93115] ,

10. This engine shall be operated only for testing and maintenance of the engine, required

regulatory purposes, and during emergency situations. For testing purposes, the engine'

shall only be operated the number of hours necessary to comply with the testing

requirements of the National Fire Protection Association (NFPA) 25 - "Standard for the

Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems", 1998

edition. Total hours of operation for all maintenance, testing, and required regulatory

purposes shall not exceed 50 hours per calendar year. [District Rule 4702 and 17 CCR

93115]

11. {3807} An emergency situation is an unscheduled electrical power outage caused' by

sudden an.d reasonably unforeseen natural disasters or sudden and reasonably

unforeseen events beyond the control of the permittee. [District Rule 4702]

Attachment A - 20
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

'12. {3489} The permittee shall maintain monthly records of emergency and- non~emergency

operation. Records shall include the number of hours of emergency operation, the date

and number of hours of all testing and mainten-ance operations, and the purpose of the

operation (for example: load testing, weekly testing, rolling blackout, general area power

outage, etc.). _For units with automated testing systems, the operator may, as an

alternative to keeping records of actual operation for testing purposes, maintain a readily

-accessible written record Of the automated testing schedule. [District Rule 4702 and 17

CCR 93115]

13. {3475} All records shall be maintained a-nd retained on-site for a minimum of five (5)

years, and- shall be made available for District inspection upon request. [District Rule

4702 and 17 CCR93115]

Attachm-entA - 21
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

EQUIPMENT DESCRIPTION, UNIT C-3953-14-0:

860BHP CATERPILLAR MODEL 3456 NATURAL GAS-FIRED EMERGENCY IC ENGINE

POWERilNG WITH NON-SELECTIVE CATALYTIC REDUCTION (NSCR) POWERING A 500

KW ELECTRICAL GENERATOR

1. Permittee shall submit an application to comply with' SJVUAPCDDistrict Rule 2520 -

Federally Mandated Operating Permits within twelve months of commencing operation.

[District Rule 2520]

2. Permittee shall subniitan application to comply with SJVUAPCD District Rule 2540 - .

Acid Rain Program within 12 months of commencing operation. [District Rule 2540]

3. {98} No air contaminant sh~1I be released into the atmosphere which causes a public

nuisance. [District Rule 4102]

4. {14} Particulate matter emissions shall not exceed 0.1 grains/dscfin concentration.

[District Rule 4201]

5. {15} No air co·ntaminant shall b'e discharged into the atmosphere for a period or periods

aggreg~ting more than three minutes in anyone hour which is as dark as, or dark~r than,

Ringelmann 10r 20% opacity. [District. Rule 4101]

6. {1898} The exhaust stack shall vent vertically upward. The vertical exhaust flow shall not

be impeded by a rain cap, roof overhang, or any other obstruction. [District Rule 41 02] .

7. {3492} This IC engine shall be equipped with a three-way catalyst. [District Rule 2201.] .

8. {3404} This engine shall be equipped with an operational non-resettableelapsed time

meter or other APCO approved alterl'1ative. [District Rule 4702]

9. Emissions from this IC engine shall not exceed· any of the' following limits: 1.0 gNOxlbhp-hr, 0.034 g-PM1 O/bhp-hr, 0..6 g-CO/bhp-hr, or 0.33 g-VOC/bhp-hr. [District Rule

2201]

10. {3405} This engine shall be operated and maintained in proper operating conditi.on as

recommended by the engine manufacturer or emissions control system supplier. [District

Rule 4702]

11. {3478} During periods of operation for maintenance, testing, and required regulatory

purposes, the permittee shall monitor the operational characteristics of the engine as

recommended by the manufacturer or emiss'ion control system supplier (for example:

check e'ngine fluid levels, battery, cables and connections; change engine 'oil and filters;

replace engine coolant; and/or other operational characteristics as recommended by the

manufacturer or supplier). [District Rule 4702]

12. This engine shall be operated only for testing and maintenance of the engine, required

regulatory purposes, and' during emergency situations. Operation of the engine for

maintenance, testing, and re.quired regulatory' purposes shall not exceed 50 hours per

calendar year. [District Rule 4702]

Attachment A - 22
Avenal Power Center, LLC, (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

13. {3807} An emergency situation is an unscheduled electrical power outage caused by

sudden and, reasonably unforeseen natural disasters or sudden ~nd reasonably

unforeseen events beyond the control of the permittee. [District Rule 4702]

14. {380B} This engine shall not be used to produce power for the electrical distribution

syste'm, as part of a voluntary utility demand reduction progra,m, or for an interruptible

power contract. [District Rule 4702]

15. {3496} The permittee shall maintain monthly records of emergency and no,n-emergency

operation. Records shall include the number of 'hours of emergency operation, the date

and, number of hours of all testing and maintenance operations, 'the purpose of the

operation (for example: load testing, weekly testing, rolling blackout, general area power

outage, etc.) and records of operational characteristics monitoring. For, units with

automated testing systems, the operator may, as an alternative to keeping records of

actual operation for testing purposes, maintain a readily accessible written record of the

automated testing schedule. [District Rule 4702]

16., {3497} All records shall be maintained and retained on-site for a minimum of five (5)

years, and shall be made available for District inspection upon request. [District Rule

4702]

Attachment A - 23
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination·of Compliance, C-1080386

.Attachment B-1

ATTACHMENT B .

Project Location and Site Plan
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A VEN{lL ·E~RGY FIGURE 2.0-1
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REFERENCE: CITY OF A'(ENAL GENERAl'pLAN.

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NATURAL GAS.AND ELECTRICAL

INTERCONNECTION ROUTES

REFERENCE:

U.S.G.S 7.5 MINUTE TOPOGRAPHIC SER'IES MAP

OF LA CIMA, CALIFORNIA, DATED 1978.

. .

o 2,000 4,000 FEET l I . . I

S'CALE FEDERAL POWER AVENAL LLC

AVENAL ENERGY I FIGURE 2.1-1A
· Avenal Power Center, LLC (OB-AFC-01)

SJVACPD Determination ofCompliance, .C-1080386

ATTACHMENT C

·crG CommissioningrPeriod Emissions Data

Attachment C - 1
SECTION 6.2 AIR QUALITY

rrhe maximum heat input rates (fuel consumption rates) for the gas turbines, duct burners, and

auxiliary boiler are shown in Table 6.2-22.

TABL·E 6.2-22

MAXIMUM FACILITY FUEL USE1 (\'{l\'IBTU (HE-IV).

Gas Turbines and Duct Total Fuel Use

Period Burners (eacha

) Auxiliary Boiler (aU Units)

Per Hour 2,356.5 37.4 4,750

Per O'ay 56,55Sb 449c ll3,llld

Per Year 16, I76,OOOe 46~650f 32,353,OO~

Notes:

a Each of two trains.

b Bas~d on 24 hou'rs per day ofduct firing.

C Based on a'startup day, during which the auxiliarY boiler \vould be used.l2 hours.

d The maximum facility fuel use day, during which the turbines run 24 hours vvith duct firing, has no use ofthe

auxiliary boiler (i.e., no'startup).' .

e Based on maximum fuel use of 7,960 hours per year without duct firing, and 800 hours per year with duct

firing, per turbine_

f Based on 1,248 hours of operation per·year.· .

g Based on baseload scenario (see Footnote d) that includes' no operation ofthe auxiliary boiler. .

CTG Emissions During Startup a·nd Shutdo.wn

Maximum emission rates expected to'occur duri·ng a startup or shu.tdown are shown in

Table 6.2-23. PM10 and SOl emissions have not been included in this table because emissions of

these pollutants depend on fuel flow, which will be lower during a startup period than during.

baseload· facility operation.

TABLE 6.2-23

FACILITY STARTUP/SHUTDOWN EMlSSlON RATES4

NOx CO voe

Startup/Shutdown, Ib/hour, 80 900 16

average

Startup/Shutdov/n, Ib/~.It>~'Z- 160· 1,000 16

. maximum

a Estimated based on vendor data and source test data.. See Appendix 6.2- L, Table 6.2... L6 and -1.7.

The .analysis of maximum facility emissions of eac~ criteria poLlutant was based on the

turbine/HRSG and auxiliary boiler emission factors shown in Tables 6.2-l9, 6.2-20, and 6.2-21;

the startup emission rates shown in Table 6.2-23; the three operating scenarios des~ribed above,

.a~dthe ambient conditions that result.in the highest'emission rates'. The maximum annual, daily,

and hourly emissions of each criteria pollutant for the P.roject are shown in Table 6.2-.24 ·and are

based on the following operating conditions and scenario parameters:

Avenal Energy AFC 6.244
SECTION 6.2

CTG Efliissions During COlnfflissiofliflg

Gas turbine commissioning is the process of initial startup~ tuning and adjustment ofthe new

eTas and auxiliary equipment and ofthe emission controlsysterns. ·The commissioning process

consists ofsequential test operation of eacll ofthe two gas turbines up through increasing load

levels, and with successive application ofthe air pollution control systems. The total setof . '

commissioning tests will require approximately 410 operating hours for each eTG. With the

planned sequential testing ofthe two gas turbines, the overall length ofthe cornmiss.ioning period

would be approximately 3 months. Commissioning ofthe proposed project may be phased into.

two commissioning periods each approximately l.5 months long.

There are several commissioning modes. The first is the period prior to SCR system" insta.llation,

when the combustor is being tuned. "During this mode, the NO" emissions control system would

not be functioning and the combustor wouLd not be tuned for optimum perfo~ance. CO

emissions would also be affected because combust9r perfonnance would not yet.be optimized.

The second emissions scenario will occur when the combustor has been tuned but the SCR

installation is not comp.fete, and other parts.ofthe gas turbine op~rating system are being checked

out. Because the combustor would be tuned but the emission control system installati~nwouLd

not be complete, NO" and CO levels could again be affected.

Noncriteria Pollutant Emissions

Noncriteria pollutants are compounds that have been identified as pollutants that pose a pote-ntial

health hazard. Nine ofthese pollutants are regulated under the· federal Ne\Y Source Review

.program: lead, asbestos, beryllium, mercury, fluorides, sulfuric acid mist, hydrogen sulfide, total

reduced sulfur, and reduced sulfur compounds.24 In addition to these nine compounds; the

federal Clean Air Act listed l87 to 18925 substances at different times as potential hazardous air

pollutants (Clean Air Act Sec. 112(b)(1». The State ofCalifornia defined a set oftoxic air

contaminants through Assembly Bill (AB) 2588, the Air Taxies "Hot Spots" Infonnation and

Assessment Act. The SNAPCD publislled a list of cqmpounds it defined as. potential toxic air

contaminants in its May 1991 Toxics Policy. Any pollutant that .may be emitted" from the Project

and is on the federal New Source Review list, the. federal Clean Air Act list, the AB2588 list or

24 These pollutants are regulated under federal and state air quality programs; however, they are evaluated as

noncriteria pollutants by t~e California Energy Commission.

25" . . Currently 187 substances are listed.

Avenal Energy AFC 6.2-47
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Attachment 0 - 1

ATTACHMENT D

CTG Emissions Data'
1/23/2008

Table a.2-1.1

Eml·sslonsand Operating Parameters for New Turbines

£\..... 11 .... _II"'" MI'''' "' ....

Case 1 Case 5 Case 9 . Cae.! 2 Case 6 Case 10 Case 4 Case·8 Case ~2

·101·F 63'F 3Z'F 101·F 63°F 32'F 101°F 63·F 32'F

Full Load wI DsC1

) Full Load wI Dg1

) ·Full Load wI DS<t) Full Load no D8 Full Load no D8 .Full Load no DB 50% Load 50% L.oad 50% Load

Ambient Temp, of 101 . 63 32 101 63 '32 101' 63 '32

G1' Load, % 100% 100% 100% 100:% 100% 100% 50% 50% 50%

Both OTs Gross Power, MW 344.8 345.0 359.0 345,.5 '345:6 359.5 144.1 168.6 163.2

sra Gross Power. MW 290.8 273.3 254.7 171.6 176.1 177~7 118.3 127.6 130.6

Plant Gross Power Output, MW 635.8 818.3 613.,.1 517.2 521.7 537.2 262.5 296.. 2 313.9

Plant Net Power Output, MW 600.0 600.0 600:0 483.7 SOe.5 525.5 250.3 286.3 204.8

OT! Fuel Flow, kpph 156.4 156.4 161..8 156.4 156.4 161.8 87.2 96.2 102.2

08s FuelFlow, kpph 49.0' 39.6 ,31.0 0,0 0.0 0.0· 0.0 0.0 0.0

OTs Heat Input, MM8tu/hr (HHV) 1,794.2 1,794.3 1,855.4 1,795.6 1,795.4 1,856,3 1,001.04 1,104.3 ',171.9

.D88 Heat Input, MMStu/hr (HHV) 562.3 454.4 356.3 0.0 0.0 0.0 0.0 0.0 O~O

Total Heat Input, MM8tulhr (HHV) 2,356.5 2.248.6 2,211.8 1,795.6 1,795.4' 1,856.3 1,001.4 1,104.3 1,111.9

Stack Flow, Ib/hr 3,653,000 3,650,000 3,759,000 3,628,000 3,.830,000 3,743,000 2,23'2,700 2,336,800 2,413,300

Stack Flow, tcfm 1,044,365 1,025,495 1,059,836 -1,051,631 1,037,822 1,011,653. 620,528 644,316 666,146

Stack Temp, 'F 195.3 184.9 189.0 207.4 198.8 200.9 180.2 175.8 177.4

Stack eXhaust, vol%

O2 (dry) 11.40% 11.87% 12.34% 13.76°(0 13.77% . 13.78% 14.46% 14.11% 13.93%

CO2 (dry) 8.42% 5.16% 4.89% 4.0.9% 4~08°(o 4.08% 3.70% 3.69% 3.99%

H2O 10.54% '10.03% 9.12% 8.39%' 8.28% 7.78% 8,01% 7.97% 7.63%

Emissions

NO., ppm:Vd @, 15% O2 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0

NO", Ib/hr(2 ) 17.13 16.34 16.06 13~03 13.03 13.47 7.26 8.01 8.51

NO", Ib/MMStu (HHV) 0.0073 0.0073 0.0073 0.0073 0.0073 0.0073 0.0073 0.0073 . 0.0073

S02, ppmvd.@ 15% O2 IJ) 0.139 0..139 -0.140 0.140 0.140 0.140 0.140 0.140 0.140

S02, Ib/h~2.3) '1.66 1.59 1.58 1.27 1.21 1.31 0.71 0.78 0.83

5021 IblMMBtu (HHVi3

) 0.0007 0.0007 0.0007 0.00'07 0.0007 0.0007 0.0001 0.0007 0.0007

CO. ppmvd <m 15% O2 4.0 4,0 4,0 . 4.0 4.0 4.0 4.0 4.0 4.0

CO,lblhr2) 20.86 19.90 19.56 15.86 15.86 1e~39' 8.84 9.75 10.36

CO, IblMMBtu (HHV) 0.0089 0.0088 0.0088 . o.ooea o.ooea 0.0088 0.0088 0.0088 0.008a

voe, ppmvd @15% O2(4) 2.0· 2.0 2.0 1.4 1.4 1.4 1.4 1.4 1.4

v.oe. Ib/hr2,,,, 5.96 5.68 5.59 3.17 3.17 3.28 1.77 1.95 2.07

voe, Ib/MMS.tu (HHvjil) 0.0025 0.0025 . 0.0025 0.0018 0.0018 0.00'18 ·0.0018 0.0018 0.0018

. PM,o, tblhr2•

O) 11.81 ·11.27 10.78 ·9.00 9.00 '9.00 9.qo 9.00 9.00

PM,o, IbIMM8tu (HHV)t5

) 0.0050 0.0050 0.0049 0.0.050 ' 0.0050 . 0.0,048 0~O090 0.0081 0.0077

PM,o, grlSCF (dry)(5) 0.00189 0.001'79 0.00"65' 0.0,0142 0.00142 0~00137 0.00230 0.00220 0.00212

NH3' 'ppmvd 15% O2 10~O 10.0 10.0 10.0 10.0 10.0 10.0 10.0 10.0

NH3• Ib/hr1

) . 35.39 33.57 32.66 26.28 26.25 2e.9~ 14.60 16.0e 17.02

CO2, Ib/MMBtu (HHVf' 117.0 117.0 . 11i.o 117.0 117.0 117.0 111.0 117.0 117.0

CH~, Ib/MMStu (HHV)(6) 0.013 0.013 0.013 ' 0.013 '0.013 0.013 0.013 '0.013 0.013

N20, tbIMM8tu (HHVi8

) 0.00022 0.0'0022 0.00022 0.00022 0.00022 ' 0.00022 0.00022 0·.00022 0.00022

CO2, Ib/hr (5) 275,599 2a2,984 258,674 210;0.00 . 209;976 21'7,102 117,114 129,153 137,055

CHiI,lbl.tlr(6) 30.7 29.2 2e~a 23.4 23.4 2'4.1 13.0 . 14.4 15.2

N20, Iblhr (5) 0.52 0.50 0.49 0.40 0.40 0.41 0.22 0.24 0.26
1/23/2008 '

1) Includes duct bum'er firing only up to plant maximum output of eOO'MW.

2) All mass now values reported are on a per staCk basis. Plant total mass flows are double these values. ,

3) All of t"'e assum~d 0.25 gr S In 100 sc:f of the fuel Is assumed to be converted'to S~ wlthno S~ conversion.

4) Sased 9n ,an assumption that 20% of reported UHC emissions are VOCs.

5) Includes front-hatf (filterable) portion only. Back-haff '(condensible) portion Is excluded.

8) CH~ emlss/on factor (kgIMM8.tu) :: O~0059 ,

A~B. Draft Emission ractorS fo( Mandatory Reporting Program, Table of Methane and Nitrous Oxide Emission Factors for StatlonarY' Combustion by Sector and Fuel TYPia,

August 10, 2007.

7) CO2 emission factor (kg/MMBtu) It S3.05

AR8. Draft Eml$$/cn ;:actcrs lor Mandatory Reporting Program,rable of Carbon Dioxide Emission Factors and Oxidation Rates for Stationary Combustion, August 10,

2001.

S)N20 emission (actor (kglM~8tu) • 0.0001

AR8.DraffEmlss/on rsctors for Mandatory Reporting Program, 'Table of Methane and Nitrous Oxide Emission Factors for Stationary CombustIon by Sector and Fuel Type,

August 10,2007. '
Avenal Power Center, LLC (OB-AFC-01J .

SJVACPO Determination of Compliance, C-1080386

ATTACHMENT·E

SJVA,PCD BACT Guidelines 1.'1.2, 3.1.4, 3.1.,8, and 3.4.2

Attachment E - 1
San Joaquin Valley'

Unified Air Pollution 'Control District

,Best Available Control Techn.ology (BACT) Guid.eline 1.1 ;.2*

Last Update: 3/14/2002

Boiler: > 20.0 MMBtulhr, Natura'i gas fired, .base-Ioad'ed or with small load

swings.**

Pollutant Achieved in Prac'tice or

cO'ntaine'd in the SIP

CO Natural gas fuel with LPG

backup

Technologically'

Feasible

Alternate Basic

Equipment

NOx

PM10

so

vac

9.0 ppmvd @ 3% 02

(0.0108 Ib/MMBtu/hr)

Ultra-Low NOx main

burrier system burner

system· and a naturalgas or'

LPG fired igniter system (

if the igniter system is used

to heat the boiler at low

fire).

Natural gas fuel with LPG

backup

Natural gas fuel with LPG

backup

Natural gas fuel with LPG

backup

9.0 ppmvd @3% 02 (0.0108

Ib/MMBtu/hr) Selective Catalytic

Reduction, Low Temperature

Oxidizer~ or equal and a < 30 ppmv

NOx@ 3°k 02 igniter system ('if the

igniter system i~ used to heat the

boiler at low·fire).

U For the purpose of this determination, "small load swings" are defined as normal,operationalload

fluctuations which are within the operational response range of an Ultra-Low NOx burner system(s}.

BACT is the m·ost stringent control technique for the emissions unit and class of source. Control techniques that are no.t achieved in practice

qr contained ins a state implementation plan must be cost effective as wen as feasible. Economic analysi's to demonstrate cost

effectiveness is requried for all determinations that are not achieved in practice or contained in,an EPA approved State Implementation Plan.

*This is aSummary 'Page for this Class of Source Permit Specific BACT Determinations on (\Iext Page(s)
San Joaquin Valley

Unified Air Pollution Control ,District

Best AvaUable Control Technology (BACT) Guideline 3..1.4*:

Last Update: 6/30/2001

Em,ergehcy Diesel I.C.Engi'ne Driving a, Fire Pum'p

Pollutant Achieved in Practice or

contained 'in the SIP

co

Technologically

Feasible

Oxidation Catalyst

, Alternate Basic

Equipment

NOx

,PM10

SOx

VOC

Certified NOx emissions of

6.9

g/bhp-hr or less

0.1 grams/bhp-hr (if TBACT

is

triggered) (c<?rrected '7/16/01 )

0.4 grarns/bhp-hr'(if 1SACT

is

not trigg'ered)

Low-sulfur diesel fuel (500

ppmw sulfur or less) or Very

Low-sulfur dtesel fuel (15

ppmw

sulfur or less), where

available~

Positive' crankcase

ventilation

[unless it voids the

Underwriters

Laboratories (UL)

certification]

Catalytic Oxidation

1. Any engine model included in the ARB or EPA di~sel engine certification lists and identified as having a PM1 0 emission

~ate of o. 149 grams/bhp-hr or less. based on. ,ISO 8178 test procedure. shall be deemed to meet the 0.1 grams/bhp-hr

requirement.

2_ A site-specific Health Risk Analysis is used to determine if TBACT is triggered. (Clarification added 05/07/01 )

BACT is the most stringent control technique for the emissions unit and class of source. Control techniques that are not achieved in practice

or contained in s a state implementation plan must be cost effective as well as feasible. Economic analysis to demonstrate cost

effectiveness is requried for all determinations that are not achieved in practice qr contained in an·EPA approved State Imptementation Plan.

*This is a Summary Page forthis Class of'Source -'Permit Specific BACT Determinations on Next Page(s}
San Joaquin Valley.

Unified Air Pollution Control District

Best Available Control Technology (BACT) Guideline 3.1.8*

lastUpdate: 4/4/2002

Emergency Ga's-Fired Ie .Engine - > or = 250 hp, Lean ~urn

Pollutant Achieved in.Practi,ce or

contained in the SIP

co = or < 2.75 g/bhp-hr (Lean

burn

natural gas fired

engine, or'equal)

Technologically

Feasible

90% control efficiency

(Oxidation catalyst, or

equal)

Alternate Basic

Equipment

> qr = 800k control

efficiency (Rich-burn

engine with NSCR, or

equal)

NOx

. PM10

vae

=or < 1.0 g/bhp-hr (Lean

burn

natural gas fired

engine, or equal)

Natural gas fuel

= or < 1.0 g/bhp-hr' (Lean

burn

natural gas fired

engine, or equal)

90% control efficiency

(Oxidation catalyst, or,

equal), '

= or > 90% control

.efficiency (Rich-burn

engine 'with NSCR, or

equal)

= or > 50% control

effi'ciency'(Rich-burn

~ngine with NSCR, or

eq~al)

'BACT, is the most stringent control technique torthe emissions unit and class of source. Con'trol techniques that are not achieved in practice

or cO'ntained in s a stateitnple~entation plan must be cost effective as weB as feasible. Economic ,analysis to demonstrate cost .

~ffectivenessis requriedfor all determinations that are not achieved in practice or contained in an EPA approved State Implementation Plan. , ,

*'~rhis is' a Sutnmaty Pag.e for th'isClass of Source - Permit Specific BACT Determinations on Next Page(s)
San Joaquin V'alley

Unified Ai'r Pollution Control District

Best Available Control Technolqgy (BACT) Guideline 3.4.2*

Last Update: 10(1/2002

·Ga·s.Turbine - = or > 50 MW, Uniform Load, with Heat .Recovery

Pollutant Achieved in Practice or

con.tain~d·in the Sl~

Technologically

Feasible

Alternate Basic

Equipment

co

. NOx'

PMlO

SOx

VO'C'

6.0 ppmv @ 15% 02

(Oxidation catalyst, or equaf)

2.5 ppmv dry @ 15% 02 (1-

hr.

average, excluding startup

and

shutdown), (Selective

catalytic

reduction, or··equal)

Air inlet filter cooler, lube oil'

vent coalescer and natural

gas '.

fuel, or equal

1. PUC-regulated natural gas

or

2. Non-PUe-regutated gas

with no more that 0.75

.grams 8/100' dscf, or equal.

2.0 ppmv @ 15% 02

4.0 ppmv @ 15% 02

(Oxidation catalyst, or equal)

2.0.ppmv dry @ 15% 02 (1-hr

average, excluding startup and

shutdown), (Selective catalytic

reduction, or equal)

1.5 ppmv @ 15% 02

*'.* Applicability lowered to> 50 MW pursuant to CARB Guidance for Permitting Electrical Generation

Technologies~ Change effective 10/1/02. Corrected.error in applicability to read 50 MW not 50 MMBtu/hr

effective 4/1 /O~.

BACT is the most stringent control technique for the emissions unit and class of source. Control techniques that are not achieved in practice

or contained in sa state implementation pla'n must be cost effective as well as feasible. Economic analysis to demonstrate cost

effectiveness is requried for all determinations that are not achieved in practiceor contained in an EPA approved State Implementation PI.an.

*This is a ·Summary.pag·e for this Class,of Source - Permit Specific BACT Determinations on Next 'Page(s)

'3.4-_-2
Avenal Power Center, LLC (08-AFC-01) ,

SJVACPO Determination ofCompliance, C-1080386

ATTACH'MENT F

Top Down BACT Analysis

(C-395'3-10-0, -11-0, -12-0, -13-0, and -14-0)

Attachment F - 1
Avenal Power Center, LLC (08-AFC~01)

SJVACPO Determination of Compliance, C-1080386

Units C-3953-10-0 and ....11-0 (Turbines)

I. ' NOx Top-Down BACT Analysis

Step 1 - Ide,ntify All Possible Control Technologies

SJVAPCD BACT Clearinghouse Guide'line 3.4.2 identifies achieved in practice BACT as

the following:

• 2.5 ppmvd @ 15% O2 (1 hr average, excluding startup and shutdown),

(Seleqtive catalytic reduction, or equal)

SJVAPCD BACT Clearinghouse Guideline 3.4.2 identifies technologically feasible BACT

as the following:

• 2.0 ppmvd @15% O2 (1 hr average, excluding startup and shutdown),

(Selective catalytic reduction, orequal)'

SJVAPCD BACT Clearinghouse Guideline 3.'4.2 does not identify any alternate basic

equipment BACT control altern~tives.

ste,p 2 - Eliminate Technologically Infeasible Options

AII'control options listed in step 1 are technologically feasible.

Step 3 - Rank Remaining Control Technologies ,by Control Effectiveness

The following options are ranked based on their emission factor:

1. 2.0 ppmvd @ 15% O2 (1 hr average, excluding startup and shutdown),

(Selective catalytic reduction, or equal)

2. 2.5 ppmvd @, 15%02 (1 hr average, excluding startup a,nd shutdown),

(Selective catalytic reduction, or equal)

Step 4 - Cost Effective Analysis

A cost effective analysis must be peiiormed for all control 'options in the list from step 3

in the order of their ranking to d~termine the cost effective option with the lowest

emissions.

The applicant is proposing the use of a selective catalytic reduction system with NOx

emissions of 2.0 ppmv @ 15% 02 (1 'hr average, excluding startup and shutdown),

(Selective catalytic reduction, or equal). This is the highest ranking control option listed in

Step -3 above. Therefore, in accordance with District policy APR 1305 (BACT), Section

IX.D, a cost effective analysis is not necessary and no further discussion is required.

Attachment F - 2
Avenal Power Center, .LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386 .

Step 5 - Select BACT

BACT for the emission unit is determined to be the use ofa Selective Catalytic Reduction

system with emissions of less than or equal to 2.0 ppmvd @ 150/0 O2 (1 hr average,

excluding startup and shutdown), (Selective catalytic reduction, or equal). The facility has

. proposed to use an inlet air filtration and cooling system, water .injection, and a Selective

.Catalytic Reduction system on each of these turbines to achieve .NOx emission.s of less

than or equal to 2.0 ppmv @ 15% O2 (1 hr average, excluding startup and .shutdown),

(Selective catalytic reduction, or equal). Therefore, BACT is sati~fied.

Attachment F - 3
Avenal Power Center,.LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Units C-3953-10-0 and -11-0 (Turbines)

II. CO Top-Down BACT Analysis

Step 1 - Identify All Possible Control Technologies

SJVAPCD BACT Clearinghouse Guideline 3.4.2 identifies achieved in practice BACT as

the following:

•. 6.0 ppmv @ 150/0 O2 (3-hour rolling average, except during startup/shutdown)

with ~n Oxidation .Catalyst and natural gas. fuel.

SJVAPCD BACT Clearinghouse Guideline 3.4.2 identifies technologically feasible BACT

as the following:

• 4.0 ppmv @ 15% O2 (3-hourrolling average, except during startup/shutdown)

with an Oxidation Catalyst and natural gas fuel.

SJVAPCD BACT Clearinghouse Guideline 3.4.2 does 'not identify any alternate basic

equipment BACT control alternatives.

Step 2 - Eliminate Technologically Infeasible Options

All control options listed in step' 1 are technologically feasible.

Step 3 - Rank Remaining Control Technologies by Control Effectiveness

The following options are ranked based on their emission factor:

1..4.0 ppmv @ 15% O2 (3-hour rolling average, except during startup/shutdown) with

an Oxidation Catalyst and natural gas fuel.

2. 6.0 ppmv@ 15% O2 (3-hour rolling average, except during sta·rtup/shutdown) with

an Oxidation Catalyst and natural. gas fue.1.

Step'4 - Cost Effective Analysis

A cost effective analysis must .be performed for all cO'ntrol options in the list from step 3

in the order of their ranking to determine the cost effective option with the lowest

emissions.

The applicant is proposing to limit CO .emissions to 2.0 ppmv @ 15%. O2 (3-hour averag'e,

excluding startup and shutdown). This will be achieved with the use of ·an oxidation

catalyst and firing on n~tural gas. fuel. This is higher than the highest ranking control option

listed in Step 3 above. Therefore, in accordance with District policy APR 1305 (BACT),

Section IX.O, a cost effective analysis is not necessary and- no further discussion is

required.

Attach.ment F - 4
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Step 5 -Select BACT

BACT for the emission unit is determined to be limiting the CO emissions to 2.0ppmv @

.15% O2 (3-hour average, .excluding startup and shutdown) using an oxidation catalyst and

firing on natural gas fuel. The facility has proposed to use an oxidation catalyst and fire

the units on natural gas, to assure these turbines achieve CO emissions of less than or

equal- to 2.0 ppmv @ 15°Jb 02 (3-hour average, excluding startup' and shutdown).

Therefore, BACT is satisfied.

Attachment F - 5
Avena/Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Units C-3953-10-0 and -11-0 (Turbines)

III. VOC Top-Down BACT Analysis

Step 1 - Identify All Possible Control Technologies

SJVAPCO BACT Clearinghouse Guideline 3.4.2 identifies achieved in practice BACT as

the following:

• 2.0ppmvd vae @ 15% O2

SJVAPCO BACT Clearinghouse Guideline 3.4.2 identifies technologically feasible BACT

as the following:

• 1.5 ppmvd vae @ 150/0 O2'

SJVAPCD BACT Clearinghouse Guideline' 3.4.2 does not identify any alternate basic

equipment BACT control alternatives.

Step 2 - Eliminate Technologically Infeasible Options

All control options listed in step 1 are technologically feasible.

Step 3 - Rank Remaining Control Technologies ~y Control Effectiveness·

1. 1.5 ppmvd vac @ 15% O2

2. 2.0 ppmvd vae @15% O2

Step 4 - Cost Effectiveness Analysis

A cost effective analysis must be performed for all control option's in the list from step 3

in the order of their ranking to. determine the cost effective option with the lowest

emissions.

The applicant is proposing voe emissions of 1.4 ppmvd @ 15% 02 when the unit is fired

, without the duct burner and 2.0 ppmvd @ 15% O2 when it is fired with the duct burner.

The BACT analysis that established the Technologically Feasible BACT option' of 1.5

ppmvd @ 15% O2 did not take into account emissions from a duct burner. Therefore the

applicants proposed 1.4 ppmvd VOC @ 15% 02 emission factor will .be determ,ine to meet

the highest ranking control option listed in Step 3 above. Therefore, in accordance with

District policy APR 1305 (BACT), Section IX.O, a cost effective analysis is not necessary

and no further discussion is required.

Attachment F - 6
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Step 5 - S.elect BACT

BACT for the emission unit is determined to be the use of natural gas fuel or LPG with

emissions of less than or equal to 2.0 ppmv @ 150/0 O2. The facility has proposed to use

natural gas fuel with emissions ,of less than or equal to 2.0 ppmv .@ 15°A> O2; therefore,

BACT is satisfied.

Attachment F - 7
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Units C~3953-10-0 and' -11-0 (Turbines)

IV. PM10 Top-Down BACT Analysis

Step 1 - Identify All Possible Control.Tech·nologies

General control for PM10 emissio.ns include the following options:

SJVAPCD BACT Clearinghouse Guideline 3.4.2 identifies achieved in practice BACT as

the following:

• Air inlet filter, lube oil vent coalescer and natural' gas fuel or equal

SJVAPCD BACT Clearinghouse Guid.eline 3.4..2 does not identify any technologically

feasible BACT control alternatives.

SJVAPCD BACT Clearinghouse Guideline 3.4.2 does not identify any alternate basic

equipment BACT control alternatives.

Step 2 - Eliminate Technologically Infeasible Options

All of the listed controls are cQnsider~d technologically feasible for this application.

Step 3 - Rank Rema.ining Control Technologies by Control Effectiveness.

1. Air inlet filter, lube oil vent coal'escer and natural gas fuel or equ.al

Step 4 - Cost Effectiveness Analysis

A cost effective analysis must be perform~.d for all control options i.n the list from step'3

in the order of the.ir ranking to determine the cost effective option with the lowest

emissions.

The applicant is proposing to use an air in inlet fi.lter, lube oil'vent coalescer and natural

gas fuel or equal. This is the highest ranking control option listed in Step 3 above.

-Therefore, in accordance with 'District policy APR 1305 (BACT), Section IX.D, a cost

effective analysis is not necessary an.d no further discussion is required.

Step 5 - Select BACT

BACT for the emission unit is determined to be the use of an air inlet filter,. lube oil vent

coalescer and natural gas fuel or equal. .Avenal Power Center is proposing to use an air

inlet filter, lube oil vent coalescer and n~tural gas fuel or ~qual; therefore, BACT .is

satisfied.

.Attachment F - 8
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance,' C-1080386

Jnits C-3953-10-0 and -11-0 (Turbines)

v. SOx Top-Down BACT Analysis

Step 1 - Identify All Possible CO.ntrol Technologies

SJVAPCD BACT Clearinghouse Guideline ·3.4.2 identifies achieved in practice BACT as

the following:

• PUC-regulated natura·1 gas fuel; or

• Non-PUC-regulated gas with no more than 0.75 grains 8/100 dscf, or equal

SJVAPCD BACT Clearinghouse Guideline 3.4.2 does nqt identify any technologically

feasible BACT control alternatives.

SJVAPCD BACT Clearinghouse Guideline 3.4.2 does not identify any alternate basic

equipment BACT control alternatives.

Step 2 - Eliminate Technologically Infeasible Options

All of the listed controls are considered.technologically feasible for this application.

Step 3 - Rank Remaining Control Technologies by Control Effectiveness

1. PUC-regulated natural gas fuel

2. Non-PUC-regulated gas with no more than 0.75 grains S/10'0 dscf, or equal

Step 4 - Cost Effectiveness Analysis

A cost effective analysis must be performed for all .control option's .in the list from step 3

in .the order of their ranking to determine the cost effective option with the lowest

emissions. .

The applicant is proposing to use PUC-regulated natural gas fuel. This is the highest

ranking control option listed in Step 3 above. Therefore, in accordance with District policy

APR 1305 (BACT), Section IX~D, a cost effective analysis is not neces~ary and no further

discussion is required.

Step 5 - Select BACT

BACT for the emission unit is determined to be the use of PUC-regulated natural gas

fuel. Avenal Power Cent~r has proposed to fire each of the turbines solely on PUCregulated natural gas fuel; therefore, BACT is satisfied.

Attachment F - 9
Avenal Power Center, LLC (OB-AFC-01)

'SJVACPO Determination of Compliance, C-1080386

Units C-3953-12-0 (Boiler)

I. NOx Top-DownBAC'T Analysis

Step 1 -, Identify All Possible Control Technologies

SJVAPCD BACT Clearinghouse Guideline 1.1.2 identifies achieved in practice BACT as

the following:

• 9.0 ppmvd @ 3% 02 (0.0108 Ib/MMBtu) Ultra-Low NOx main burner system

and a natural gas or LPG fired igniter system (if the igniter system is used to

heat the boilerat low fire)

SJVAPCD BACT Clearinghouse Guideline 1.1.2 identifies. technologically feasible BACT

as the following:

• 9.0ppmvd @ 3% 02 (0.0108 Ib/MMBtu) Selective Catalytic Reduction, Low

Temperature .Oxidizer, or equal and a < 30 ppmv NOx @ 3% 02 igniter

system (if the igniter system is used to heat the boiler at low fire)

SJVAPCD BACT Clearinghouse Guideline 1.1.2 does not identify any alternate basic

equipment BACT control alternatives.

Step'2- Eliminate 'Technologically Infeasible Options

All control options listed in step 1 are techno'iogically feasible.

Step 3 - Rank Remaining Control Technologies by Control. Effectiveness

.The following options are ranked based on their emission factor:

1. 9.0 ppmvd @ 3% 02 (0.0108 Ib/MMBtu) Selective Catalytic Reduction, Low

Temperature Oxidizer, or equal and a < 30 ppmv NOx @ 3% 02 igniter

system (if the igniter system is use'd to heat the boiler at low fire)

2. 9.0 ppmvd @ 30/0 02 (0.0108 Ib/MMBtu) Ultra-Low NOx main burner system

and a natural gas or LPG fired igniter system (if the igniter system is used to

heat the boiler at low fire)

Step 4 - Cost Effective Analysis

A cost effective analysis must be performed for all control options in the list from step 3

in the orde.rof their ranking to determine the cost effective option with the lowest

emissions..

The applicant has proposed the NOx emissions from the boiler will not exceed 9.0 ppmv @

3°Jb O2. This is the ~ighest. ranking control option listed. in Step 3 above. Th'erefore, in

accordance with District policy APR 1305 (BACT), Section IX.D, a cost effective analysis is

not necessary and no further discussion is required.

Attachment F - 10
Avenal Power Cente~ LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Step 5 - Select BACT

BACT for the ·emission unit is determined to be NOx emissions of less than 9.0 ppmvd @.

3% O2. The facility has proposed NOx emissions of less than 9.0 ppmv @ 3°A> O2.

Therefore, BACT is satisfied.

AttachmentF - 11
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386 )

'Jnits C-3953-12~O.(Boiler)

II.. CO Top-Down BACT Analysis

Step 1 - Identify All Possible C·ontroITechnologies·

General control for CO emissions· include the following options:

SJVAPCD BACT Clearinghouse Guideline 1.1.2 identifies achieved in practice BACT as

the following:

·.Natural gas fuel with LPG backup

SJVAPCD BACT Clearinghouse Guideline 1.1.2 does not identify any technologically.

feasible BACT control alternatives.

SJVAPCD BACT Clearinghouse Guideline 1.1.2 does ·not identify any alternate basic

equipment BACT control alternatives. .

Step 2 - Eliminate Technologi.cally Infeasible Options

AU of the listed controls are considered technologically feasible for this application.

Step 3 - Rank Remaining Control Technologies by Control Effectiven.ess

1. Natural gas fuel with LPG backup

Step 4 .. Cost Effectiveness Analysis

A cost effective analysis must be performed for all control options in the list from step 3

in the order of their ranking to determine the cost effective option with the lowest

emissions.

The applicant is proposing to solely use naturai gas fuel. This is the highest ranking

control option listed in Step 3· above. Therefor~, in accordance with. District policy APR

1305 (BACT), Section IX.D, a cost effective analysis is not necessary and no further

discussion is required.

·Step 5 - Select BACT

BACT· for the emission unit is determined to be the use of natural· gas fuel. Avenal

Power Center is proposing to use natural gas fuel; therefore, BACT is satisfied.

Atta.chment F - 12
Avenal P.ower Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Units C-3953-12-0 (Boiler)

III. vac Top-Down BACT Analysis

Step 1 - Identify All Possible Control Technologies

.General control for vac em·issions include the following options:

SJVAPCD BACT Clearinghouse Guideline 1.1.2 identifies achieved in practice BACT as

the following:

• Natural gas fuel with LPG backup

SJVAPCD BACT Clearinghouse Guideline 1.1.2 does not identify any technologically

feasible BACT control alternatives.

SJVAPCD BACT Clearinghouse Guideline 1.1.2 does not identify any alternate basic

equipment BACT control alternatives.

Step 2 -Eliminate Technologically Infeasible Options

All. of the listed controls· are considered technologically feasible for this application.

Step 3 -. Rank Remaining Control Technologies by Control Effectiveness

1. Natural gas fuel with LPG backup

Step 4 -Cost Effectiveness Analysis

A cost effective analysis must be performed for all control options in the list from step 3

in the order of· their ranking to determine the. cost effective option with the lowest

emissions.

The applicant is proposing to solely use natural gas fuel. This is the highest ranking

control option listed in Step 3 above. Therefore, in accordance with District policy APR

1305 (BACT), Section IX.D, a cost effective a·nalysis is not necessary and no further

discussion is required. .

.Step 5 -.Select BACT

BACT for the emission unit is determined to be the use of natural gas fuel. Avenal

Power Center is proposing. to use natural gas fuel; therefore, BACT is satisfied.

Attachment .F - 13
Avenal Power Center, LLC' (OB-AFC-01)

SJVACPO Determination of Compliance,C-1080386

'Units C-3953-12-0 (Boiler)

IV. PM10 Top-Down BACT Analysis

Step 1 - Identify All Possible Control Technologies

General control for PM10 emissions include the following options:

SJVAPCD BACT Clearinghouse Guideline 1.1.2 identifies achieved in practice BACT as

the following:

• Natural gas fuel with LPG backup

SJVAPCD BACT Clearinghouse Guideline 1.1.2 does not identify any technologically

feasible BACT control alternatives.

SJVAPCD BACT 'Clearinghouse Guideline 1.1.2 does not identify a'ny alternate bas'ic

equipment BACT control alternatives.

'Step 2 - Eliminate Technologically Infeasible Options

All of the listed controls are considered technologi~ally feasible for this application.

Step 3 - Rank Remaining Control Technologies by Control Effectiveness .

1. Natural gas fuel with LPG backup

Step 4 - Cost Effectivenes.s Analysis

A cost effective analysis must be performed for all control options in the list from step 3

in the order of their ranking to determine the cost effe'ctive option with the 'Iowest

emissions.

The applicant is proposing to solely use natural gas fuel. This is the highest ranking

control option listed in Step 3 above. Therefore, in accordance with District policy APR

1305 (BACT), Section IX.D, a cost effective analysis is not. necessary and no further

discussion is required.

Step 5 - Select BACT

BACT for the emission unit is determi~ed to be the use of natural gas fuel. Avenal

.Power Center is proposing to use natural gas fuel; therefore, BACT is satisfied.

. Attachment F - 14
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Units C-3953-13-0 (Diesel IC engine powering fire water pump)

I.· NOx Top-Down BACT Analysis

Step 1 - Identify All Possible Control Technol.ogies

SJVAPCD BACT Clearinghouse Guideline 3.1.4 identifies achieved in practice BACT as

the following:

• Certified NOx emissions of 6.9.g/bhp-hr or less

SJVAPCD BACT Clearinghouse Guideline 3.1.4 does not identify any technologically

feasible BACT control alternatives.

SJVAPCD BACT. Clearinghouse Guideline 3.1.4 does not identify any alternate basic

.. equipment BACT control alternatives.

Step 2 - Eliminate Technologically Infeasible Options

All control options listed in step 1 are technologically feasible.

Step 3 - Rank Remaining Control Technologies by Control Effectiveness

The following options are ranked based on ~heir emission factor:

1. Certified NOx emissions of 6.9·g/bhp-hr or less

Step 4 - Cost Effective Analysis

A cost ·effective analysis must be performed for all contr91 options in the list from step 3

in the order. of their ranking to determine the cost effective option with the lowest

emissions.

Th·e applicant has proposed the NOx emissions from the engine will not exceed 3.4 g/bhphr. This is the highest ranking control option listed in Step 3 above. Therefore, i~

accordance with District policy APR 1305 (BACT), Section IX.D, a cost effective analysis js

not necessary and no furtherdiscussion is required.

Step 5 - Select BACT

BACT for the emission unit is determined to be CertifiedNOx emissions of 6.9. g/bhp-hr

or less. The facility has proposed NOx emissions of less than 6.9 g/bhp-hr. Therefore,.

BACT· is satisfied.

Attachment F - 15
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Units C-39S3-13-0 (Diesel IC engine powering fire water pump)

II. CO Top-Down BACT Ana'lysis

Step 1 - Identify All Possible Control Technologies

.SJVAPCD BACT Clearinghouse Guideline 3.1.4 does not identify.any achieved in

practice BACT control alternatives.

SJVAPCD BACT' Clearinghouse Guideline 3.1.4 identifies technologically feasible BACT

as the following:

• Oxidation Catalyst·

SJVAPCDBACT Clearinghouse Guideline 3.1.4 does not .. identify any alternate basic l

equipment BACT control alternatives.

Step 2 - Eliminate Technologically Infeasible Options

AII:control options listed in step 1 are technologically feasible.

. ·Step.3 - Rank Remaining Control Technologies' by Control Effectiveness

The foll.owing options are ranked based on their control efficiency:

·1. Oxidation Catalyst

Step 4 - Cost Effective Analysis

A cost effective analysis must be performed for all control options in the list from Step 3

in the order of their ranking to determine the cost effective option with the lowest

emissions.

However, this engine has been UL Certified, and the ULcertification does not include a

oxidation catalyst, and the addition of a oxidation catalyst would void the UL certification,

which is required for firewater pump engines. Therefore, the oxidation catalyst oA>ption will

not be required. .

Step'S -'Select BACT

BACT for the emission unit is satisfied by the facility's proposeq CO emissions of 0.447

g/bhp-hr. Therefore, BACT is. satisfied.

Attachment F - 16
Avenal Power Center, LLC (OB-AFC-01)

SJVACPD Determination of Complian~e, C-10B0386

Units C-3953-13-0 (DiesellC engine powering fire water pump)

III. VOC Top-Down BACT' Analysis

Step 1 - Identify All Possible Control Technologies

SJVAPCD BACT Clearinghouse Guideline 3.1.4 identifies achieved in practice BACT as

the following:

• Positive crankcase ventilation [unless it voids the Underwriters Laboratories

(UL) certification]

SJVAPCD BACT Clearinghouse Guideline 3.1.4 identifies technologically feasible BACT

as the following:

• Catalytic Oxidation

SJVAPCD BACT Clearinghouse Guideline 3.1.4 does not identify any alternate basic

equipment BACT control alternatives.

Step 2 - Eliminate Technologically Infeasible Options

All control options listed in step 1 are technologically feasible.

Step 3 - Rank Rem'a,ining Control Technolo'gies by Control, Effectiveness

The following options are ranked, based on their control efficiency:

1. Catalytic Oxidation

2. Pos,itive crankcase ventilation [unless it vOids the Underwriters Laboratories

(UL) certification]

Step 4 - Cost Effective Analysis

A cost effective analysis must be performed for all control options in the list from Step 3

in the order of their ranking to determine the cost effective option with the lowest

emissions.

However, this engine has been UL Certified, and the UL certification does not include a

catalytic oxidation system or a positive crankcase ventilation system, and the addition of a

catalytic oxidation system or a positive crankcase ventilation system Would void the UL

certification, which is required for firewater pump engines. Therefore, both the catalytic

'oxidation sy~tem and the positive crankcase ventilation system options will not be

required.

Attachment F - 17
Avenal Power Center,LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Step 5 - Select BACT

BACT for vac emissions from this emergency diesel .IC engine powering a firewater

pump is·having no control technology for vae emissions. The applicant has proposed to

install a 288 bhp emergency diese·1 IC engine powering a firewater pump with no control

technology for vac emissions; thetefore BACT forV~e emiss·ions is satisfied.

Atta·chment F - 18
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Units C-3953-14-0 (Natural gas Ie engine powering electrical generator)

I. NOx T'op-Dow~ BACT Analysis

Step 1 - Identify All Possible Contro'l Technolog'ies

SJVAPCD·BACT Clearinghouse Guideline 3.1.8 identifies achieved in practice BACT as

the following:

• NOx emissions of 1.0 g/bhp-hr (lean-burn n.atural gas fired engine or equal)

SJVAPCD BACT Clearinghouse Guideline 3.1.8 does not identify any tec·hnologically

feasible BACT control alternatives.

.SJVAPCD BACT Clearinghouse' Guideline .3.1.8 identifies alternate basic equipment BACT

as the following:

• 2:: 90% control efficiency (rich-burn engine w·ith NSCR or equal)

Step 2 - Eliminate Technologically Infeasible Options

All control options listed in step 1 are technologically feasible.

Step 3 - Rank Remaining Control Technologies .byControl Effectiveness

The following options are ranked based on their control efficiency:

1. 2:: 90% control efficiency (rich-burn engine with NSCR or equal)

2. NOx emissions of 1.0 g/bhp-hr (lean-burn natural gas fired engine or equal)

Step 4 - Cost Effective Analysis

A cost effective analysis must be performed for all control options i·n the list from step 3

in the order of their ranking to determine the cost effecti've option with the lowest

emissions.

1. 90% cO,ntrol efficiency (rich-burn engine w·ith NSCR or equal)

District Policy establishes annual cost thresholds for imposed control based upon the

amount of pollutants abated by the controls. If the cost of control ·is at or below the

threshold, it is considered a cost effective control. If the cost exceeds the threshold, it is

not cost effective and the control is not required. Per District BACT Policy, the maximum

cost limit for NOx reduction is '$9,700 per ton of NOx reduced.

Attachment F' - 19
Avenal Power Center, LLC (OB-AFC-01) .

SJVACPO Determination of Compliance, C-1080386

Based 'upon the fact that there are only a few existing Ie engine installations within this

class and category of source that operate with emissions of 1.0 g NOx/hp~hr, the .

. .District will assume that the Industry Standard will be 2.8 g NOx/hp-hr. (lb/MMBtu

converted tog/hp-hr, Attachment I), pursuant to a AP-42 (07/00) values of uncontrolled

four-stroke lean burn Ie engines « 90% load).

AP-42 publishes an uncontrolled NOx value of 2.21 Ib/MMBtu (90 - 1'05% load), which is

approximately 13.4 g NOx/hp-hr. Several major engine manufacturers were surveyed

(Cummins, Caterpillar, and Waukesha) and the District found that lean burn engines sold

by these engine manufacturers do not emit emissions close to the uncontrolled value for 90

- 105% load, published in AP-42. Based on the disc.ussions with service representatives

of each engine manufacturer, emissions were closer to the AP-42 value published forthe <

90% load, which was around 2.5 g NOx/hp-hr than it was for the value published for the 90

- 105% load. Therefore, industry standard for lean burn natural gas-fired emergency IC

engine will be 2.8 g NO·x/hp-hr.

. The proposed annual emissions from a lean burn ICengine using industry standard values

can be calculated as:

!iQx (annual):

~2~._8~9~~_·8~6_0·_~~~~lb~~~50_.~~.~_ 2651bNOJ~ar Rp-~ 1 453.6-9 year

PENox=265 Ib NOx/year =O. 1325.tons NOx/year

The proposed annual emissions from a rich burn engine equipped the a Non-Selective

Catalytic Reduction system with a NOx control effici.ency of 90% can be calculated as:

tillx (annual):

. 7.4 9 (1) I (1 - 0.9) I 860 I . Ib I 50 Rp-Rf 1 1 453.6i}·· .year· = 70 Ib NOx/year .

PENox = 70 Ib NOx/year = 0.035 tons NOx/year'

District BACT policy demonstrates how to calculate the cost effectiveness of alternate

basic equipment or process:

CEalt = (COStalt - Costbasic) + (Emissionbasic- Emissionalt)

1 Pursuanfto AP-42 (07/00) the NOx value for.uncontrolled four-stroke rich burn Ie engine~ @ < 900/0 load. (lb/MMBtu

converted·to g/hp-hr, Attachment I)

Attachment F"- 20
Avena/Power Center, LLC (OB-AFC-01)

SJVACPD Determination, of Compliance, C-1080386

where,

CEalt

Co~talt

= the cost effectiveness of alternate basic equipment expressed as dollars per

ton of emissions reduced

= the equivalent annual capital cost of the alternate basic equ'ipment plus its

annual operating cost

COstbasic = the equivalent annual capital cost of the proposed basic equipment, without

BACT, plus its annual operating cost

Emissionbasic= the emissions from the proposed basic equipment, without BACT.

Emissionalt = the emissions from the alternate basic equipment

The District conducted research to determine the appropriate cost information for

installing a rich burn Ie engine with a Non-Selective Catalytic Reduction System versus

the cost information for installing a uncontrolled lean burn IC engine. Based on'

information' from various engine manufacturers, the i~itial costs for installing an

un~ontrolled rich burn engine versus an uncontrolled lean burn engine would be minimal.

The main difference in cost would be incurred in the installation of the NSCR system

and the airto fuel ratio controller to the rich burn IC engine.

According to the guidance document "RACT/BARCT for Stationary Spark-Ignited 10

Engines" (pgs. V-2 &V-3), the approximate capital, cost for installing a NSCR system for a

1;000 hpengine would be approximately $28,000, the capital cost for installing an air to

fuel ratio controller would be $5,300" and the overall installation cost would be $2,500. The

CARB RACT/BARCT document also states the annual cost for operating and maintenance

is between ,$8,000 - 10,000, but these values ,are assuming full time operation. Sincethe

,proposed installation will be limited only to emergency operation and testing and

maintenance, a conservative assumption of $1 ,000 per, y~ar will be utilized for this

evaluation. '

Per District BACT Policy, the equivalent annual capital cost is calculated as follows:

A ($/yr) = P x [i x (1 + i)"] + [(1 + i)" - 1]

A =

P =

i =

n =

Using a total capital cost of $35,800 in the above equation results in an equivalent

'annual cost of $5,826/year. Adding this equivalent annual cost to the annual operating

cost of $1 ,ODD/year, the (CoStalt - Costbasic) is equal to $6,826/year. It should be noted that

the operating the rich burn IG engine versus a lean burn IC engine would result in an

efficiency loss and would potentially result in higher ann.ual fuel expenses. These costs

will be set aside for the present and only a partial' cost analysis will be performed.

Attachment F - 21
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

District BACT policy also requires the use of a Multi-Pollutant Cost Effectiveness

Threshold' (MCET) fora BACT option controlling more than one pollutant.· The

installation of a NSCR system will control NOx, CO, and vac emissions. ,Therefore, the

MCET is calculated as follows:

MCET ($/yr) = (ENoxx TNOx) + (Eeo x Teo) + (Evoe x Tvoe)

Where: ENox = tons-NOx controlled/yr

Eeo = tons-CO controlled/yr

Evoe = tons-VQC controlled/yr

TNOx = District's cost effectiveness threshold for NOx

= $9,700Iton-NOx

Teo = District's cost effectiveness threshold for CO

= $300/ton-CO.

Tvae = District's cost effectiveness threshold for VOCs

$5,OOO/ton-VOCs

Since this BACT cost effectiveness analysis is analyzing alternate basic equipment with

a control technology which controls multiple pollutants; in order to calculate the cost

effectiveness for the alternate basic equipment, the District will take the MCET and

compare that value with the (Costalt - CoStbasic), to determine if this control tech'nology is

cost effective.

To determine Eeo, the District has to establish what Industry ~tandard is for CO

emissions. As detailed above, engines with NOx emissions of 2.8 g/hp-hr (per AP-42)

were deemed as the industry standard for this class and category of source. Th~refore,

the District will also take AP-42 values for CO emissions @ < 900/0 load (1.83 g CO/hphr) and deem that value as industry standard for this class and category of source.

Therefore, the proposed annual emissions from a lean burn ·I~ engine using industry

standard values can be calculated as:

CO (a·nnual):

~1_.8_3~.9~~I_._86_0_~~.~~_lb~~~50_~~.~_ 173IbCO~~r hp-hf . 1 453.6-9 year ' ,

PEeo =173 Ib CO/year =0.0865 ton CO/year

Pursuant to the guidance document "RACT/BARCT for Stationary Spark-Ignited IC

Engines" created by CARB (pg. 8-20), the CO control effectiveness from a NSCR system

is greater than 80%. Therefore, the proposed 'annual emissions from a rich burn engine

equipped the a Non-Selective Catalytic Reduction system with a CO .control efficiency of

800k can be calculated as:

Attachment F - 22 .
Avenal Power Center, LLC (OB-AFC-01)

SJVACPD Determination of Co.mpliance, C-1080386

CO (annual):

11.6,,9 ,(2), I (1 -,. 0.8) I 860!!i3 I Ib I 50,Af Rp-fH: 1 1. 453.6-{}··· year - 220 Ib CO/year

PEco = 220 Ib CO/year = O. 11 ton CO/year

As demonstrated above, the CO emissions from the rich burn IC e~gine with a NSCR

system are higher than the uncontrolled CO emissions from the lean burn IC engine.

Therefore, CO will not be included in the MCET calculations.

To determine Evoc', the District has to establish what Industry Standard is for VOC

. emissions. Again, as detailed above, engines with NOx emissions of·2.8 g/hp-hr (per

AP-42) were deemed as the industry standard for this class and category of source.

Therefore, the District will also take AP-42 values for voe emissions (0.39 g VQC/hp-hr)

and deem that value as industry standard for this class and category of source.

Th.erefore, the proposed annual emissions from a· lean burn IC engine using industry

standard values can be calculated as:

'VOC (annual):

~.0_.3_9~i_,~1~~_0~!!i3~,'~~lb~~~5_0_Af~_ 37lbVOC~ear Rp-hf 1 453.6iJ year

PEvoc = 37 Ib VOG/year = 0.0185 ton VaC/year

Pursuant to the guidance document "RACT/BARCT for Stationary Spark~lgriited IC

Engines" created by CARB, the VOC control effectiveness from a NSCR system is greater

than 50%. Therefore, the proposed annual emissions from a rich burn engine equipped

the a Non-Selective Catalytic Reduction system with a vac control efficiency of 50%

can be calculated as:

VOC (annual):

0.10 9 (3) 1,(1, - 0.5) I 860!!i3 I Ib 1 50 hf Rp-lH: 1 1· 453.6-{}· year - 5 Ib VOC/year

PEvoc= 51b VaG/year =0.0025 ton vaC/year,

2 P~rsuant to AP-42 (07/00) the CO value for uncontrolled four-stroke rich burn IC engines @ <'90°J'o load. (lb/MMBtu converted

to g/hp-hr" Attachment I) .

3 Pursuant to AP-42 (07/00) the voe value for uncontrolled four-stroke rich burn IC engines. '(ib/MMBtu converted to g/hp-hr,

Attachment I)

Attachment F -23
Avenal Power Center, LLC (OB-AFC-01)

SJVACPD Determination of Compliance, C-10B0386

Calculating forthe MCET derives the following:

ENOx =0.1325 tpy - 0.035 tpy = 0.0975· tpy

Evoc =0.0185 tpy - 0.0025 tpy =0.016tpy

MCET ($/yr) = (0.0975 x $9,700) + (0.016 x·$5,OOO) =$1 ,026/year

As presented above, (Costalt - Costbasic) is equal to $6,826/year.

This value is greater than the MCET; therefore, it has been determine that the installation

of a rich burn IC engine with a NSCR system as alternate basic equipment is not cost

effective using just the partial cost analysis.

2. NOx emissions of S 1.0 g/bhp-hr (lean-burn natural gas fired engine or equal)

The applicant has proposed that the NOx emissions from the engine will not exceed 1.0

g/bhp-hr. This is the highest ranking remaining control option listed in Step 3 above.

Therefore, in accordance with District policy APR 1305 (BACT), S'ection IX.D, a cost

effective analysis is not necessary and no further discussion is required.

Step 5 - Select BACT

BACT for the emission unit is determined to be NOx emissions of 1.0 g/bhp-hr or less.

The facility has.pro·posed NOx emissions of less than '1.0 g/bhp-hr. Therefore, BACT is

satisfied.

Attachment F - 24
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Units C-3953-14-0 (Natural gas IC engine powering electrical gener-ator)

II. .CO Top-Down BACT Analysis

Step 1 - Ide.ntify All Possible Control Technologies

SJVAPCD BACT Clearinghouse Guideline 3.1.8 identifies achieved in practice BACT as

the following: (

• S 2.75 g/bhp-hr (Lean burn natural gas fired engine, or equal)

SJVAPCD BACT Clearinghouse Guideline 3.1.8 identifies te-chnologically feasible BACT

as the following:

• 90 % control efficiency (Oxidation catalyst, or equal)

SJVAPCD BACT Cleari.nghouse Guideline 3.1.8 identifies alternate basic equipment BACT

as the following:

• '800/0 CO control efficiency catalyst (ri'ch-burn engine with NSCR or equal)

Step 2 Eliminate Technol,?gically Infeasible Options

All control options ·listed in step 1 are technologically feasible.

Step 3 -Rank Remaining Control Technologies by Control. Effectiveness

The following options are ranked based on their control efficiency:

1. 90% control efficiency (Oxidation catalyst, or equal)

-2. 800/0 CO control efficiency catalyst (rich-burn engine with NSCR or equal)

3~ S 2.75 g/bhp-hr (Lean burn natural gas fired engine, or equal)

Step 4 - Cost Effective Analysis

A cost effective analysis must be performed for all control options in the list from step 3

in the order of their ranking to determine the cost effective option with the lowest

.emissions.

The applicant has proposed the engine will be equipped with an oxidation catalyst that will

provide 900/0 control of CO emissions. This is the highest 'ranking control option listed in

Step 3 above. Therefore, in accordance with District policy APR 1305 (BACT), Section

IX.O, a cost effective analysis is not necessary and no further discussion is required.

Attachment F- 25
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

Step·· 5 - Select BACT

BACT for the emission unit is determined to be the used of a~ oxidation catalyst with

900/b· control of CO emissions. The facility ha·s proposed to install an· oxidation .catalyst

with 900/0 control of CO emissions. Therefore, BACT is satisfied.

Attachment F - 26
Avenal Power Center, LLC.(OB-AFC-01)

SJVACPD Determination of Compliance, C-1080386

Units· C-3953-14-0 (Natural gas IC engine powering e·lectrical generator)

III. vac Top-Down BACT Analysis

Step 1 - Identify All. Possible Control Technologies

SJVAPCD BACT Clearinghouse Guideline 3.1.8 identifies achieved in practice BACT as

the following:

• 1.0g/bhp-hr (Lean burn natural gas fired engine, or equal)

SJVAPCD BACT Clearinghouse Guideline 3.1.8 identifies technologically feasible BACT

as the following:

• 90% control efficiency (Oxidation catalyst, or equal)

SJVAPCD BACT Clearinghouse Guideline 3.1.8 identifies alternate basic equipment BACT

as the following:

• 50% control efficiency catalyst (rich-burn engine'with NSCR or equal)

Step 2 -Eliminate Technologically Infeasible Options

,All control options listed in step 1 are technologically feasible.

Step 3 - Rank Remaining Control Technologies by Control Effectiveness

The·following options are ranked based on their control efficiency:

1. 90% control efficiency (Oxidation catalyst, or equal)

2. 500/0 control efficiency catalyst (rich-burn engine with NSCRor equal)

3. 1.0 g/bhp-hr (Lean burn natural gas fired engine, or equal)

Step 4 - Cost Effective Analysis

·A cost effective analysis must be performed for all control options in the list from step 3

in the order of their ranking to· determine the 'cost' effective option with the lowest

emissions.

The a,pplicanthas proposed the engine will be equipped with an oxidation catalyst with

90% control of VOC emissions. This is the highest ranking control option listed in Step 3

above. Therefore, in accordance with, District policy APR 1305 (BACT), Section IX.D, a

cost effective analysis ,is not necessary and no further discussion is required.

Attachment F - 27
Avenal Pow~rCenter, LLC (08-AFC-01)

SJVA.CPD Determination of Compliance, C-1'080386'

Step 5 - Select BACT

BACT for the emission unit is determined to be the used of an oxidation catalyst with .

90% control of vac emissions. The facility has proposed to install an oxidation catalyst

with 900/0 control of VOCemission. Therefore,BACT is satisfied.

Attachment F - 28
Avenal Power Center, LLC(OB-AFC-01)

SJVACPD Determination of Compliance, C-1080386

ATTACHMENT G

Health Risk Assessment-and Ambient Air Quality Analysis

Attachment G - 1
To:

From:

Date:

San JO(3:QuinVaUeY' Air POII!UUQIil Control District

Risk Management·Review

Derek. Fukuda

.Matthew Cegielski - Technical Services

A.pc-if 28,2008

Facility Name:

Location:

Application #(s):

Project #:

.A~ RMR SUMMARY

Avenal Power Center

Avenal Cutoff Road and San· Luis Canal, Aven~l, CA

C-3953 10-0,'11-0, 12-0,.13-0, 14-0

(;-1080386

Project' ,Facility

Totals Totals

Gategories

Prioritization Sco're

'Acute ·Hazard In'dex

C·hronic·Hazard

Ind~x "

Maximum Individual

Ca,ncer,Risk (1 O~6)

T-BACT'Re ' ~ir~d?

Special Permit,

Conditions?

10-0

CT#1

0.6

0.0 .

, 0.0

0.02

,No

No

. 11-0

CT#2

0.6·

0.0

0.0

0.02

No

No

12~O

NGAux

Boiler'

0.0

0.0

0.0

0.01

No.

No

, 13-0

DICE

Eme'g

F.ire

Pump

NA

'N/A'

N/A~

0.01

Yes

14-0

NGICE

Emeg

Gen

0.1

0.2

0.0

0.0

, No

1.3

O~2

0.0

0.1

1'.3

0.2 '

0.1

1 Prioritizatibn for this unit was not conducted s,ince it-has been determined that all diesel-fired ic ~ngines will '

result in a prioritization score greater than 1.0~ .

2 Acute and Chronic Hazard Indices were not calculated since there is not risk factor or the risk factor is so

low that it has been determined to be insignificant for this type of unit.

.Proposed Permit Conditions

To,ensure that human health risks ,will not exceed District'allowable levels; the following permit

conditions must be included for: .

Units 10-0,'11-0, 12~O, 14-0

N'o speci~1 conditions required..

'Units '13-0

1. The PM10 emission,S rate shall not exceed 0.1'5 g/hp-hr based on' US E.PA certification

using ISO 8178 test procedure. [District Rules 2201 and 4102' and 13CCR 2423 and 17

CCR 9311,5]
Avenal Power Center, C3953, 1080386

Page 2 of 4

2. {18gB} The exhaust stack .shall vent vertically upward. The vertical exhaust flow shall

not be impeded by a rain cap, roof ov~rhang,orany other obstruction. [District Rule

4102] N

3. Th.e engine shaH be operated only for 'maintenance, testing, ~nd required regulatory

purposes,and during emergency situations. Operation of t~e engine for maintena~ce,

testing,. and required regulatory' purposes shall not exceed 50 hours per year. [District

Rules 2201, and 4702 and 17 CCR 93115.] N

B. RMR REPORT

I. Project Description

Technical Services received a request on April 28, 2008 to perform' a Risk Management

Review for'a proposed installation of a 600 MW. Power Plant.

',11. Analysis

Technical Services performed a prioritizationu~ing the District's HEARTs. d~tabase. Siflce

the total facility prioritization score was greater than one, a rE?fined health risk assessment

.·was required. Emissions calculations were calculated for the units as referenced in' the

following table.

Unit Source Reference

Co.mbustion Turbine tO~O. HEARTS NG Turbine VCAPCD

'Co'mbustion .Turbi·ne1"1-0 HEARTS. N~ Turbine VCAPCD

HEARTS NG.10-100

NG Auxiliary Boiler 12~O MMS'TU/Hr External VCAPCD

Combustio"tl

NG Emergency ICE 14,-0 HEARTS NG Internal VCAPCD Combustion' <1 OOOHP

The A·ERMOD model'was used, with the parameters outlined below and meteorological data

.' for 2004'frdm Fresno to determine the dispersion'factors (Le.; the predicted' concentration or

X divided by the normalized source' strength or Q) for' a' receptor grid. These dispers.iori

factors were input into the Hot Spots Analysis and Reporting Program (HARPY risk

assessment mod'ule to' calculate the chronic and acute hazard indices and the carcinog.enic

risk for the project. . .

The following parameters were used for the review:

Analysis Parainete'rs .

Combustion Turbines.' Unit 10-0,11-0

Source Type

Stack Height (m)

Stack Diameter. (m)

.Stack Exit Velocity (m/s)

Point Location Type

44.2 . Closest R~ceptor(m)

5.78 Type ofReceptor

19.3 Max Hours per Year:

···Rural

1202

Residential

8760

Stack Exit Temp'. (OK)

Burner Rating (MMBtu/hr)

NG
Avenal Power Center, C3953, 1080386

Page 3 of 4

Analys'is Parameters

NG Auxiliary..Boiler 12-0

Source Type'

sta'ck Height (m)

Stack Diameter. (m)

Point Location Type

11.3 Closest Receptor (m) .

0.81 Type of Receptor

Rural

1202

Residence

Stack Exit Velocity (m/s)

Stack Exit Temp. (OK)

37.4

.Source Type

Stack Height (m)

Analysis Parameters

Diesell'CE Emer enc Fire,P.ump 13~O

Point location·Type

5.49 Closest Receptor em)

Rural

. 1202

Stack Diameter. (m)

Stack Ex~tVelocity(m/s)

0.15' Type ofReceptor " '

42.2 PM10 g/hp.-hr .

Residence

0.15

Stack Exit Temp,; (O~)

Ma'xHours per Year

288

.~o~rce Type

Stack Height (m)

Stac~ Diarneter~ (m)

An,alysis ·Parameters

NG ,Emer eiic IC'E .Unit14-0.·

Point, ,Location Type ,

3.05 Closest Receptor,(m) ..

0.2 Type of Receptor

"Rural

1202

R~sidence

Stack Exi't Velocity (m/s)

Stack Exit·Temp. (OK)

71.3

698

Throughput

. (MMBTUI 'r)

BHP. '

355

860

Max Hours per Year

AAQA.. In addition to' the, RMR, Technical Services performed an Ambient Air Quality

Analysis (AAQA) on. the proje'ct. Emissions are listed in the table below, ·for concentratiorls

refer to the AAQA modeling profile.

Stacks 1 and 2 Stack 5 U.nit 14

Unit 10 and 11 Stack 3 U'nit 12 Stack 4 Unit 13 NGEmergency

Ibs/hr EachCTs Aux Boiler DiesefFire.Pump , Generator

NOx 16.4 0.41 2.16 1.9

CO' 72.8 ' 1.38 0.28 1.14'

PM10 9.2 0.19 0.04 0.06

SOx 1.9 0.11 0.0 0.02"
Avenal Power Center, C3953, 1080386

Page 40f4

Emergency

Ibs/yr Each CTs Aux Boiler Diesel Fire Pump Generator

hours!yr 8760 1251 50 . 50

NOx 143,95.1 513 108 95

CO 637,788 1727 14 57

PM10 80,656 233 2· 3

SOx 16,694· 132 0 1

Criteria Pollutant Modeling Results*

co

PM10 X. . X

*Results wete taken from the ~ttached PSO·spreadsheet. . ..

1The predicted ambient air .<ll,ialityimpaGts .for these criteria pollutants are below EPA9s level of significance

as found ·in 40 CFR Patt 51.16S·(b)(2).

Th~ acute and chronicin'di·ces are below 1.0 and the .cancer risk factor associated with each

un·it· is less than 1.0 .in a million. In accordance with the District's ·RiskManag·ement

Policy, the project i.s. approved without Toxic Best Available Control Te.chn<;>log·y(TBACT).

The emissions from theproposedeq·uipment will not cause or contribute significantly to a .

violation of the State and National AAQS. .

:To ensure that hu·man health risks will not exceed District allowable .levels; the permit

co~ditions listed on page 1·of this report must·be inclu~~led fai'th.is ·proposed unit.

These conclusions are based on the·. data· provided by the applicant and the project

engineer. The~efo(eJ this analysis is valid only as long as the proposed data and

parameters do not change.

Attachments:

A. H·ARP output files &AERMOD dispersion map

B. Prioritization sCOre with toxic em~ssions summary" AAQA

C. RMR request fram·the project engineer· .
Avenal Power Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-10$0386

ATTACHMENT H

SOx for PM10 Interpollutant Offset Analysis

Attachment H - 1
SOX for PM10 Interpollutant Offset Analysis

Avenal Power Center, LLC

Date: June 12, 2008

Engineer: Derek. Fukuda

Lead Engineer: Joven Refuerzo

Facility Name:

Mailing Address:

Contact Person:

Telephone:

Application #:

Project #:

Location:

Complete:

I. Proposal

Avenal Power Center, .LLC

500 Dallas Street. Level 31

Houston, TX 77002

Jim Rexroad

(713) 275-6147

C-3953-10-0, -11-0, -12-0, -13-0, and -14-0

C-1080386

NE% Section 19, Township 21 South, Range 18 East - Mount Di.ablo Base

Meridian on Assessor's Parcel Number 36-170-032

June 12, 2008

Avenal Power Center, LLC is seeking approval from the S,an Joaquin Valley Air

Polluti.on Control District (the "District") for the installatio'n of a "merchant" electrical

power generation facility (Avenal Energy ProJect). The Avenal Energy Project will bea

combined-cycle power 'generation facilityconsi.sting of two' natural gas-fired combustion

turbine generators (CTGs) each with a heat recovery steam generator (HRSG) and 'a

5·62.3MMBtu/hr duct burner. Also proposed ·are a 300..MW steam turbine, a 37.4

MMBtu/hr auxiliary boiler, a 288 hp diesel-fired emergency ICengine powering a water

pump, a 860 hp natural gas-fired emergency IC engine powering a 550 kW generator

and associated facilities. The p'lant will have a nominal rating of 600 MW.

FacilityC-3953 will become a major source for NOx, VOC, andPM·1o. There will be a.n

.increase in emissions for all pol.lutants and offsets are required for NOx, VOC, and PM10

emissions.

II. Applicable Rules

Rule '2201 New and Modified Stationary Source Review Rule (9/21/06)

(Section 3.30 and 4.13.3.2) .
Avenal Power Center

Facility C-3953, Project # C-1 080386

III. Process Description

.Combined-Cycle Combustion Turbine Generators

Each natural· gas-fired General Electric Frame 7 Model PG7241FA combined-~ycle

combustion turbine generator (CTG) will be equipped with Dry Low NOx combustors, a

selective catalytic reduction (SCR) system with ammonia injection, ·an oxidation

catalyst, a duct burner, and a heat recovery steam generator (HRSG).. Each CTG will

drive an electrical. generator to produce approximately 180 MW of electricity. The plant

will be a "combined-cycle plant," since the gas turbine and a steam turbine both turn

electrical generatorsand··produce power.

Each CTG will turn an electrical generator, but will also produce power by directing

exhaust heat through its .HRSG, which supplies steam to the steam turbine nominally,

rated at 300 MW, which turns another electrical generator.

Since two HRSGs will feed a single steam turbine generator, this desig'n is referred to

as a "two-on-one" configuration.

The CTGs will utilize Dry Low NOx (DLN) combustors, SCR with ammonia injection,

.and an oxidation catalyst to achieve the following emission rates:

NOx: 2.0 ppmvd @ 15% 02

VOC: 2.0 ppmvd @ 15% 02

CO: 4~0 ppmvd @ 1·5% O2

SOx: 0.00282 Ib/MMBtu

PM10: 0.005 Ib/MMBtu

Continuous emissions monitoring .systems (CEMs) will sample, analyze, and record

NOx, CO, and O2 concentrations in the exhaust gas for eachCTG.

Heat Recovery Steam Generators (HRSGs)

The HRSGs provide for the transfer of heat from the CTG exhaust gases to condensate

and feedwater to produce stream. Each HRSG will be approximately 90 feet hig'h and

will have an exhaust stack approximately 145 feet tall by 19·feet in diameter. The size

and shape of the HRSGs are specific to their intended purpose of high efficiency

recycling of waste heat from the CTG. '

TheHRSGs will be multi-pressure, natural-circulation boilers equipped with transition

ducts' and duct burners. Pressure components of each HRSG include a low pressure

(LP) economizer, LP evaporator, LP deaerator/drum, LP superheater, intermediate

pressure (IP) economizer, IP evaporator, I·P drum, IP superheaters, high pressure (HP)

economizer, HP evaporator, HP drum, and HP superheaters and reheaters.

Page -2-
Avenal Power Center

Facility C-3953'- Project # C-1080386

SuperheatedHP steam is produced in the HR.SG and flows to the steam turbine throttle

inlet. The exhausted cold reheat steam from the steam turbine is mixed with IP steam

from the HRSG and reintroduced into the HRSG through the reheaters. The hot reheat

steam flows back from' the' HRSG into the STG. T.he LP superheated steam from the..

HRSG is admitted to the 'LP condenser. Theconden~ate is pumped from the

conc;Jenserback to the HRSG by condensate pumps. The condensate' is preheated by

.an HRSG fee"dwater heater. Boiler feedwater pumps send the feedwater throu.gh

economizers and into the boiler drums of the HRSG, where steam is produced, thereby

completing the steam cycle.

Each HRSGis equipped with a S'CR system that uses aqueous ammonia in conjunction

with a catalyst bed to reduce NOx in the CTG exhaust gases. The catalyst bed is

contained in a catalyst chamber located within each HRSG. Ammonia is' injected

up~tre'am of the catalyst bed. The subsequent catalytic reaction 'converts NOx 'to

nitrogen and .water, resulting in a reduced concentration of NOx in the exhaust gases

exiting the stack.

Duct Burners

Duct burners are installed in theHRSG transition duct between the HP superheater and

reheat coils. Through the combustion of natural gas, the duct burners heat the CTG

exhaust gases to generate additional steam at times when 'peak power is needed. The

duct burners are also used as needed to control the temperature of steam produced by

the HRSGs. The duct burners will have a maximum heat input rating of 562 MMBtu/hr

.on a higher heating value (HHV) basis per HRSG, and are expected to operate no more

than 800 hours pet year.

Steam Turbine Generator

The steam turbine system consists of a 300 MW nominally rated reheat steam turbine

generator (STG), governor system, steam admission system,' gland steam system,

lubricating oil system, including oil coolers and filters and generator coolers. Steam

from the HP superheater, reheater and IP superheater sections of the HRSG enters the

correspond'ing sections of the STG as described previously. The. steam expands

through the turbine blading to drive the .steam turbine' and its generator. Upon exiting

the turbine, the ste'am enters the deaerating condenser, where it is condensed to water.

Auxiliary Boiler

.One 37.4 MMBtu/hr Cleaver Brooks Model CBL700-900-200#ST natural gas-fired boiler

equipped with an Cleaver Brooks Model ProFire Ultra· Low NOx burner, capable of

providing up to 25,000 pounds per hour (Ib/hr) of saturated steam. The. boiler will be

used to provide steam as needed'for auxiliary purposes.

Diesel-Fired Emergency ICEngine P<>.wering a Fire Pump

.Emergency firewater will be provided by three pumps (a jockey pump, a main fire pump,

and a back-up fire pump); two powered by electric motors and the other powered by a

diesel-fired internal combustion engine. If the jockey pump is' unable to maintain a set

operating pressure in the piping network, the electric motor-driven fire pump will start

Page -3-
Avenal Power Center

Facility C-3953, Project # C-1080386

automatically. If the electric motor-driven fire pump is unable to maintain a set

operating. pressure, the diesel engine-driven fire pump will start automatically. The

diesel-fired engine will be rated at 288 hors~power. Th.e engine will be limited to no

greater than 50 hours per year of non~emergency operation in accordance with the

applicant's proposal.

Natural Gas-Fired Emergency ICEngine Powering an Electrical Generator

.One860 hp Caterpillar Model G3512LE natural gas-firedl·C engine generator set will,

provide power to the essential servi.ce AC system in the event of grid failure or loss of

outside power to the plant. This engine will be limited to no greater than 50 hours per

year of non-emergency operation· in accordance with the applicant's proposal. .

IV. Equipment Listing

C-3953-10-0: 180 MW NOMINALLY RATED COMBINED~CYCLE POWER

GENERATING SYSTEM #1 CONSISTING OF A GENERAL ELECTRIC

FRAME 7 MODEL PG7241FA NATURAL GAS-FIRED COMBUSTION

TURBINE· GENERATOR W·ITH DRY LOW NOx COMBUSTOR, A

SELECTIVE CATALYTIC REDUCTI.ON (SCR) SYSTEM, AN

OXIDATION CATALYST, HEAT RECOVERY STEAM GENERATOR #1

(HRSG) WITH A 562 .MMBTUIHR DUCT BURNER AND A 300 MW

NOMINALLY RATED STEAM TURS·INESHARED WITH C-3953-11 .

C-3953~11-0: 180 MW NOMINALLY· RATED COMBINED-CYCLE POWER

GENERATING SYSTEM· #2 CONSISTING OF A GENERAL ELECTRIC

FRAME 7 MODEL PG7241FA NATURAL GAS-FIRED COMBUSTION

TURBINE GENERATOR WITH DRY LOW NOx CO~BUSTOR, A

SELECTIVE CATALYTIC REDUCTION (SCR) SYSTEM, AN

OXIDATION CATALYST,. HEAT RECOVERY STEAM GENERATOR #2

(HRSG) WIT·H A 562. MMBTUIHR DUCT BURNER' AND A 300MW

·NOMINALLY RATED STEAM TURBINE SHARED WITH C-3953-10

C-3953-12-0: 37.4 MMBTUIHR CLEAVER BROOKS MODEL CBL-700-900-200#ST

NATURAL GAS-FIRED BOILER WITH A CLEAVER BROOKS MODEL

PROFIRE, OR DISTRICT APPROVED EQUIVALENT, ULTRA LOW

NOX BURNER

C-3953-13-0: 288 BHP . CUMMINS MODEL CFP83-F40 ·DIESEL-FIRED

.EMERGENCY IC ENGINE POWERING A FIRE PUMP

C-3953-14-0: 860BHP CATERp·ILLAR MODEL G3512LE NATURAL .GAS-FIRED

EME·RGENCY IC ENGINE POWERING A 500 KW ELECTRICAL

GENERATOR

Page -4-
Avenal Power Center

Facility C-3953, Project # C-1080386

v. Interpollutant Offset Ratio Proposal SOx for PM10

Rule 2201, New and Modified Stationary Source Review, specifically allows the use of

PM10 precursor ERGs to offset PM10 increases:

4.13.3 Interpollutant offsets may be approved by the APCO on a case-by-case basis,

provided that the applicant demonstrates to the satisfaction of the AP'CO; that the

emission increases from the new or modified source will not cause or contribute to a

violation of an Ambient Air Quality Standard In such cases, the APeo shall, based on

an air quality-analysis, impose offset ratios equal to or greater than the requir~ments of

this rule.

4.13.3.2 Interpollutant offsets between PM10 and PM10 precursors may be allowed

Based on this language, an· applicant must demonstrate an appropr.iate interpollutant

offset ratio, based on an air quality analysis (that is, base'd on the science of the

precursor-to-PM10 relation·ship given the atmospheric Che.mistry and the meteorology of .

the locale).

The SOx for PM10 interpollutant ratio of 1.000:1 is based on District analysis (see

Appendix A). The originating location of reduction'of the proposed ERG certificates are

greater than 15 miles from the proposed project. Therefore,a distance offset ratio' of

1.5 applies. Combining the interpollutant and distance offset ratio, an overall SOx for

PM10 offset ratio of 1.000 x 1.5 =1.5:1 is valid for project C-1080386.

VI. Project Offset Calcu.lations

i. C-3953-10-0 and C-3953-11-0 (Turbines)

a. Maximum Hourly PE

The maximum hourly potential to emit for NOx, CO, ·and 'vac from each GTG will

occur when the unit is operating und~r start-up mode. The maximum hourly PE

for both turbines operating together is when both. are starting up and firing their

duct burners.

Page -5-
Avenal Power Center

Facility C-3953, ·Project # C.-1080386

The combined startup NOx emissions from the two turbines will be limited to 240

tbs/hr [maximum startup emission rate (160 Ibs/hr) + average startup emission rate

(80 Ibs/hr)]. Similarly, the combined startup CO emissions from the two turbines

will be limited to 1,902 Ibs/hr, [maximum startup emission rate (1,000 Ibs/hr) +

average startup emission rate (902 Ibs/hr)]..

The maximum hourly emissions are summarized in the table below:

NOx 160 17.20 13.55 13.55 240.00

CO 1,000 20.97 16.34 16.34 . 1,902.00

voe 16 5.89 3.34 3.34 32.00

PM10 N/A 11.78 8.91 8.91 23.56

'SOx N/A 6.65 5.23 .5.23 13.30

NH'3 N/A 32.13 25.31 25.31 64.26

b.. Maximum Annual PE

The facility has indicated that the turbines will be operated in one of three different

scenarios: weekend and weekday hot start scenario, weekend shutdown. and

weekday hot start scenario, and baseload s·cenario. The sax emission factors

used to calculate the annual potential emissions will be based on the applicant

proposed average natural gas sulfu~ limit 0.36gr/100 dscf.

sax EF =(0.36 §f-S/1 00 x (1 ·lb-S/7000 §f1 x (64 Ib SOx/32 tb--S}x (1

SGf/1 013 Btut x (1 06 SW/MMBtu)

= 0.001 Ib-SOx/MMBtu

CTG wlo Duct Burner Firing:

sax Emission Rate (Iblhr) =(1,856.3 MMBtu/hr) x(0.001Ib-SOx/MMBtu)

=1.86 Ib-SOx/hr

CTG wI Duct Burner Firing: ,

SOx Emission Rate (Ib/hr) =(2,356.5MMBtu/hr) x (0.001 Ib-SOx/MMBtu)

=2.36 Ib-SOx/hr

Potential annual emissions for each pollutant will be calculated for each of the

three scenarios in the tables below:

1 PM10 and SOx emissions during startups and shutdowns are lower than maximum hourly emissions'.

Page -6-
Avenal Power Center

Facility C-3953, Project # C-1 080386

Scenario 1) Weekend and Weekday Hot Start:

547.5 (1.5 hr/hot start x 365 hot startlyr) hours operating in startup and shutdown

mode, 800 hours operating while firi·ng at full load with the duct burner, and' 6,683

hours operating while firing at fU'1I load .without the duct burner. Since startup and

shutdown emission rates for PM10, SOx, and NH3 are less than the emission. rate

when the CTG is fired at 100% load w/o the duct burner, the startup and shutdown

emission rates will be assumed to be equivalent to the CTG fired at 100% load w/o

the duct burner. Since the CTGs will be fired throughout the year, the emission

factors for the unit when fired at the average ambient t~mperature (630

F) will be

used to calculate·the potential anflual emissions.

NOx 80 Ib/hr (avg) 16.341b/hr 13.03 Ib/hr

CO 900 Ib/hr av 19.901b/hr 15.86 Ib/hr

VOC 161b/hr (avg) 5·.68Ib/hr 3.171b/hr

PM10 N/A 11.27 Ib/hr 9.00 Ib/hr

SOx N1A 2~36 Ib/hr 1.86 Ib/hr

NH3 N/A 32.13 Ib/hr 25.31 Ib/hr

* Emission factors were taken from. Table 6.2-1.1 in the ATe application submittal.

Scenario 2) Weekend Shutdown and Weekday Hot Start:

143,951 Ibl ear'

614,662 Ibl ear.

34,489 Ibl ear

74,0.91 Ib/ear

'15,337 Ibl ear'

208,7081bl ear

624 «(1.5 hr/hot start x 208 hot startlyr) + (6.0 hr/cold start x 52 cold starts/year))

hours operating in startup and shutdown mode, 800 hours operating while firing at

full load with the duct burner, and 3,800 hours operating while firing at full load

without the duct b·urner. Since startup and shutdown emission rates for PM10,

sax, and NH'3 are less than the emission rate when the CTG is fired at 100% load

w/o the duct burner, the startup and shutdown emission rates will .be assumed to

be equivalent to the CTG fi"red at 1000/0 load w/o the duct burner. S,ince the CTGs

win be fired throughout the year, the emission factors for the unit when fired at the

average ambient temperature (630

F) will be used to calculate the potential annual

emissions.

Page -7-
AvenalPowerCe~er

Facility C-3953, Project # C-1080386

NOx 16.341b/hr 13.031b/hr

eo 19~90 Ib/hr 15.86 Ib/hr

voe 5.68 Ib/hr 3.17 Ib/hr

PM10 11.27 Ib/hr 9.00 Ib/hr

sox 2.36 Ib/hr 1.86 Ib/hr

NH3 N/A 32.13 Ib/hr 25.31 Ib/hr

* Emission factors werE~ taken from Table 6.2-1.1 in the ATC application submittal.

Scenario 3) Baseload:

112,506 Ibl ear

637,788 Ibl 'ear

26,574 Ibl ear

48,8321bl ear

10,117 Ibl ear"

137,675 Ibl ear

800 hours operating while firing at full load with the duct burner, and 7,960 hours

operating while firing at full load without the duct burner. Since the CTGs will be

fired throug.hout the year, the emission factors for the 'unit ~hen fired at the

average ambient temperature (63°F) will be used to calculate the potential annual.

emissions.

116,791.lb/ear

142,166 Ibl ear

29,77771bl ear

80,656 Ibl ear

16,694 Ibl ear

219,972 Ibl ear

Page -8-
Avenal Power Center

Facility C-3953, Project# C-1 080386

Maximum Annual Potential to Emit:

The high'est annual poten.tialemissions, for each pollutant, from the three different

scenarios will be taken to determine the maximum annual potenti·al to emit for the

CTG.· The results are summarized in the table below:

NOx

co·

vae

SOx

143,951 Ib/year

637,7881.b/ear

34,489 Ibl ear

·80,656Ibl ear

16,694 Ibl ear

219,972 Ibl ear

Scenario 1

Scenario 2

Scenario 2

Scenario 3

Scenario 3

Scenario 3

ii.. C-3953-12-0 (Boiler)

The PM10 potential to emit for the boiler is calculated as follows, and summarized·

in the table below..

PEpM10 = (0.005 Ib/MMBtu) * (37.4 MMBtu/hr)

- . 0..19 Ib PM10/hr

= (0.005 Ib/MMBtu) * (37.4.MMBtu/hr) *(1-2 hr/day)

= 2.2 Ib PM10/day

= (0.005 Ib/MMBtu) * (37.4 MMBtu/hr) * (1,248 hr/year)

= 2331b PM10/year

= (233 Ib/year) * (4 qtr/year)

= 58 Ib PM10/qtr

Page -9-
Avenal·Po.werCenter

Facility C-3953,.Project # C-1080386

iii. C-3953-13-0 (DiesellC engine powering fire water pump)

ThePM10 em.issions for the emergency fire pump engine is calculated as follows,

and summarized in the table below:

PEpM10 = .(0.059 g/hp· hr) * (288 hp) -;- (453.6 glib)

= 0.04 Ib PM101hr

= (0.059 g/hp· hr) * (288 hp) + (453~6 glib) * (24 hr/day)

= 0.9 Ib PM10/day

= (0.059 g/hp· hr) *(288 hp) -;- (453.6 glib) *(12.5 hr/qtr)

= 0.5 Ib PM10/qtr

= (0.059 g/hp· hr) * (288 hp) -;- (453.6 glib) * (50 hr/year)

= 1.9 Ib PM10/year

iv. C-3953-14-0 (Natura·1 gas Ie engine powering electrical generator)

The PM10 emissi.ons for the emergency Ie engine is calculated as follow~, and

summarized in the table below:

PEpM10 = (0.034 g/hp ·hr) * (860 hp) -;- (453.6 glib)

= 0.06 Ib PM10/hr

= (0.034 g/hp· hr) * (860 hp) -;- (453.6 glib) * (24 hr/day)

= 1.5 IbPM10/da·y

= (0.034 g/hp· hr)* (860hp) -;- (453.6 glib) * (12.5 hr/qtr)

= 1 Ib PM10/qtr

= (0.034 g/hp'ehr) * (860hp) -;- (453.6 ·g/tb) * (50 hr/year) .

= 3 Ib PM10/year

Page .;.10-
Avenal.Power Center

Facility 'C-3953, Project # C-1 080386

Post-Project Stationary Source Pot~ntial to Emit,(SSPE2)

Pursuant to Section 4.10 of District Rule 2201, the Post Project Stationary Source

Potential to Emit (SSPE2) is the Potential to Emit (PE) from all units with valid

AuthC?rities to Construct (ATC) or Permits to Operate (PTO) at the .. Stationary

Source and the quantity of emission reduction credits (ERC) which have been

. banked since September 19, 1991 for Actu'al Emissions Reductions .that have

occurred at the source, and which have not been used on-site.

C-395371 0-0· 143,951 ·637,788 34,489 80,656 16,694 219,972

C-3953~11-0 143,951 637,788 34,489 80,656 16,694 ·219,972

C-3953-12-0 ·51.3 1,727 201 233 132

C-3953-13-0 108 14 12 2 0

°

0

C:"3953-14-0 95 57 31 3 1 0

Post-project.S.SPE 288,618 1,277,374 69,222 161,550 33,521 439,944 (SSPE2)

Total Emissions to be Offset

Pursuant to District Rule 2201, Section 4.6, emission offsets shall not be required

for emergency equipment that is used exclusively as emergency standby

equipment for electric power generation or any other emergency equipment as

approved by the APeO that does not operate more than 200 hours per year for

non-emergency purposes and is not used pursuant to voluntary arrangements with

a power supplier to curtail power. Therefore the emission from the diesel-fired fire

water pump and the natural gas-fired emergency standby generator are not

required to be offset. .

Page -11-
Avenal Power Center

Facility C-3953,. Project #C-1.080386

C-3953-10-0

C-3953~11-0

C-3953-12-0

Post-project SSPE

(SSPE2)

Offset Calculations:

637,788

637,788

1,727

288,415 1,277,303 69,179161,545 33,520 439,944

SSPE2 (PM10)

Offset threshold (PM10)

ICCE

Offsets Required (Ib/year)

= 161 ,545lb/year

= 29,200 Ib/year

=Olb/year

= [(161,545-29,200 + 0) x DaR]

= 132,345 Ib/year x DaR

Calculating the appropriate quarterly emissions·to ·be offset is as follows (in Ib/qtr):

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

33,'087 33,086 33,086 33,086

The applicant is proposing to use ERC Certificates C-894-4, N-721-4, N-723-4, N762-5, 8~2788-5, 8-2789-5, 8-2790-5, and 2791-5 which have an original site of

reduction greater than 15 miles from the location of this project. Therefore, a

distance offset ratio of 1.5:1 is applicable and the amount of PM10 ERCs that need

to be withdrawn is:

Offsets Required (Ib/yeat) = 132,345 Ib/year x 1.5

198,5181b/year

=99.26 ton/yr

Calculating the appropriate quarterly emissions to be offset is as follows (in Ib/qtr):

. 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

·49,630 49,629 49,629 49,630

The a.pplicant has stated that the facility plans to use ERC certificates C-894-4, N721-4, N-723-4, N-762-5,S-2788-5, 8-2789-5, 8-2790-5, .and 2791-5 to offset the

increases in PMto emissions associated with this project. The applicant' has

purchased the following quarterly amou'nts of the above certificates:

Page -12-
Avenal Power Center

Facility C-3953, Project # C-1080386

ERC #C-896-4

ERC #N-721-4

ERC#N-723-4

ERe #S-2791-5·

ERC' #S-2790-5

ERC #S-2789-5

ERC #S-2788-5

ERe #N-762-5

1st Quarter

80

o

a

92,179

12,862

6

5

21,000

2nd Quarter

80

o

o

23,666

491

14

·7

21,000

3rd Quarter

80

3,215 '

985

69,157

O' .

12

3

21,000

4th 'Quarter

80

a

a

96,288

8,499

8

6

21,000

Project PM10 offset requirements

The applicant states either PM10 ERC certificates C-894-4, N-721-4, N-723~4, N762-5, 8-2788-5, 8-2789-5, 8-2790-5, and 2791-5 will be utilized to supply the PM10

offset requirements.

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

PM10 Emissions to be offset: (at

1.5:1 ratio):

Available ERCs from certificates

C-896-4, N-721-4,andN-723-4:

ERCs applied from certificates

C-896-4, N~721-4, and N-723-4 fully

withdrawn as certificates C-896-4,

N-721-4, and N-723-4:

RemainingERCs from ce~ificate

C-896-4, N-721-4, and N-723-4:

RemainingPM10 emissions to be

offset (at a 1.5:'1 ratio):

·49,630

80

-80

o

49',550

49,629

80

-80

o

49,54.9

49,629

4,280

-4,280

o

45,349

80

. -80

·0

49,550

Pe~ Rule 2201 Section 4.13.3.2, interpollutant offsets between PM10 .and PM10

precursors (Le. SOx) may be allowed. The' applicant is proposing to use

interpollutant offsets SOx for PM10 at an interpollutant ratio of 1.0:1 (see Append·ix

A). This interpollutant ratio has been evaluated by the District's modeler, James

Sweet, Air Quality Project Planner. Per Rule 2201 Section 4.13.7, Actual

Emission Reductions (i.e. ERCs) that occurred from October' through March (i.e.

1

st and 4th Quarter), inclusive, may be used to offset increases in PM during any

period of the year. Since the SO'x ERCs are being used to offset PM10 emissions,

the above applies to the SOx ERCs.

In addition, the overall offset ratio is equal to the. multiplication of the distance and

interpollutant ratios (1.5 x 1.000 = 1.5).

Page -13-
Avenal Power Center

Facility C-3953, Project # C-1080386

1st Quarter 2nd Quarter 3rd Quarter .4th Quarter

Remaining PM10 Emissions to be 49,550 49,549 45,349 49,550 offset: (at a1.5: 1 ratio):

Remaining PM10 emissions to be

offset with SOx ERCs (at a 1.5:1 .49,550 49,549 45,349 49,550 distance ratio and a 1.000:1

interpollutant SOX:PM10 ratio):

Remaining ERCs from certificates

N-762-5, 8-2788-5, 8-2789-5, and 33,873. 21,512 21,015 29,513.

8-2790-5:

Remaining ERCs from certificates

N..762-5, 8-2788'-5,S-2789-5, and 0 0 0, 0

8~2790-5:

'Remaining PM10 emissions to be

offset (at a 1.5:1 ratio and a 1.000:1 15,677 28,037 24,334 20,037

interpollutant SOX:PM10 r~tio):

1st Quarter 2nd Quarter 3rd Quarter 4th Quarter

Remaining PM10 Emissions to be

, offset: (at a1.5:1 distanc'e ratio and 15,677 28,037 24,334 20,037 a 1.000:1 interpollutant '80x:PM10

ratio):

Remaining' ERCs from certificate 92,179 23,666 69,157 96,288 8-2791-5:

1st qtr. ERCsapplied to 2nd qtr. -4,371 4,371 0 0 ERCs:

Adjusted Remaining ERCs from 87,808 28,037 69,157 96,288 certificate 8-2791-5:

Remaining PM10 emissions to be

offset (at a 1.5:1 ratio and a 1.000:1 . 15,677 28,037 24,'334 20,037

interpollutant SOX:PM10 ratio):

ERCs applied from certificate 15,677 28,037 24,334 20,037 8-2791-5 partially withdrawn:

Remaining ERCs from certificate 72,131 0 44,823 '76,251 8-2791-5:

As ,seen above, the facility has sufficient credits to fully .offset the quarterly SOx

and PM10 emissions increases associated with this project.

VII. Conclusion

Approve use of an overall SOx for PM10 interpollutant offset ratio of 1.5:1 (1.000 x 1.5).

Page -14-
Avenal Power Center

FacilityC-3953, Project # C~1080386

VIII. Recommendation

Compliance with all applicable rules and .regulations is expected. Issue Authorities to

.. Construct C-3953-10-0, -11-0, -12~O, -13~O, and -14-0 .with a SOx "for PM10 interpollutant

offset ratio of 1.00.0:1.

Page -15-
County

Fresno/Madera

Kern

SOx for PM10

1.866

1.055

PM10 Interpollutant Offset Ratio Analysis*

NOx for PM.1 0 Notes

4.202" Fresno/Madera is a combined evaluation with a shared source"area

2.157

Kings

Tulare

1.000

1.000

2.282

2.298

KfngslTulare is aco.mbined evaluation with a shared source area

Separate annual evaluations were made for the SIP, but the results establish

this as one" shared area

The KingslTulare area has a small inventory of local SOx sources and is

dominated by pollutant transport from the region; therefore the SOx for PM1.0

ratio is set to the minimum technical value of 1.000

* Minimum offset ratio before consideration of distance or other adjustments
Notes for the Kings-Tulare Interpollutant Analysis

Combined emissions·and inventories from Kings and Tulare Counties are used due to the evaluations of source interactions.

This relationship was established by analysis performed for the SJVAPCD PM10 SIP.

The interpollutant relationship established for Kings County in this analysis would also be applicable to Tulare County.

Tons of SOx to Equal Effect of 1 Ton of PM10 See SOxPM10 worksheet for calculations

Tons of SOx to Equal Effect of 1 Ton of PM10 1.000 See SOxPM1 0 (2) worksheet for calculations Tulare County

A minimum value of 1.000 is established for technical reasons.

A relationship of less than one-to-one indicates that regional emissions are more dominant than local emissions.

Tons of NOx to Equal ·Effect of 1 ton Pry110

Tons of NOx to Equal Effect of 1 ton PM10 2·.298

See NOxPM10 worksheet for calculations l<,'l\""~W;"

See NOxPM10 (2) worksheet for 'calculations Tulare County

Input data for the interpollutant worksheets are from the Annual and Annual based on Monthly worksheets

These worksheets are data and analyses submitted for the PM10 SIP

The AO.! worksheet provides area of influence evaluations used to analyze specific episodes in the PM10 SIP

Episode evaluations reveal a variety of source areas for different episodes.

This justifies the use of the entire county, and in some cases more than one county, as the source area for annual interpollutant evalaution.

Episode trajectories revealed mixing between Kings and Tulare counties during episodes. Annual analysis showed· almost identical contributions.

The combined emissions inventories of the two counties are evaluated in comparison to the annual chemical mass balance modeling for

each site, and while the observations are slightly different, the resulting interpollutant relationships are almost identical.
PM10 Interpollutant Offset Ratio Analysis

Annual

PM10·

Notes Wnits Estimate Uncertainty

1 J.lg/m3

2 J.lg/m3 1.97

3 J.lg/m3 0.39

J.lg/m3 1.57

4 J.lg/m3 . 0.79

5 ton/day

J.lg/m3 per ton 0.23 0.30

0.16

"Vegetative Burning" Total

Industry Component (300/0)

Regional Backg"round (20%)

Industry minus Background

County Contribution

Organic Carbon PM10 Inventory - Kings and Tulare County

County Impact

Nitrate

6 J.lg/m3

7 f.!g/m3 1.00

J.lg/m3 14.66

8 f.!g/m3 7.33

9 ton/day

J-lg/m3 per ton 0.10 0.11-

0.09

10 2.48 2.73

1.74

Tons of NOxtoEqual Effect of 1·ton PM.10

Ammonium Nitrate

Regional Background

Ammonium Nitrate minus Background

County Contribution

NOx Inventory - Kings and Tulare County

County Impact

1. Per SJVUAPCD and CARB, PM10 emissions from stationary industrialcom~ustion sources are included

in the Vegetative Burning category from Chemical Mass Balance modeling performed for the SJVUA~CD

2003 PM1 oAttainment ·Plan (Kings - Hanford monitoring. station).

2. Per SJVUAPCD, 30% of this category is attributed to stationary industrial combustion ·sources.

3. Per SJVUAPCD, regional background is estimated to be 20% of net con~entration after previous

adjustment to Vegetative Burning category.

4. Contribution from sources within Kings County is 500k of net concentration after previous

adjustments to Vegetative Burning category.

5. Organic carbon PM10 inventory for·Kings County that contributes to this monitoring location;

from ·SIP inventory with updates and adjustments based on CCOS study.

6. Ammonium nitrate category from Chemical Mass. Balance modeling performed for the SJVUAPCD

2003 PM10 Attainment Plan (Kings - Hanford monitoring station).

7. Per SJVUAPCD, regional background of ammonium nitrate is estimated to b.e 1 f.!g/m3.

8. Contribution from sources within Kings County IS 500k of net concentration after previous

adjustment to Vegetative Burning category.

9. NOx inventory for Kings· County that contributes to this monitoring location;

from SIP inventory with updates and adjustments based on ·ceos study.

10. PM10 County Impact divided ~y Ammonium nitrate County Impact.
"Annual based on Monthly" speciation worksheet cells G7 and H7

"Kings - Hanford" worksheet for speciated rollback analysis

" Required to use base year emissions that are related to the observed sp~ciation

Annual based on Monthly. speciation worksheet Cells M7 and N7

"Kings - Hanford" worksheet for speciated rollback analysis

" Required to use base year emissions that are related to the observed speciation

1. Per SJVUAPCD and CARB. PM10 emissions from stationary industrial combustion SQurces are included

in the Vegetative Burning category from Chemical Mass Balance modeling performed for the SJVUAPCD

2003 PM10 Attainment Plan (Kings -Hanford monitoring station).

2. Per SJVUAPCD. ~O% of this category is attributed to stationary industrial combustion sources.

3. Per SJVUAPCD. regional background is estimated to be 20% of net concentration after previous

adjustment to Vegetative Burning Category.

4. Contribution from sources within Kings County is 50% of net concentration after previous

adjustments to Vegetative Burning ~tegory.

'5. Organic carbon PM10 inventory for Kings County that contributes to thi.s monitoring location;

from SIP inventory w~th updates and adjustments based on CCOS study. .

6. Ammonium sulfate category from Chemical Mass Balance modeling performed"for the SJVUAPCD

2003 PM10 Attainment Plan (Kings - Hanford monitOring station). .

7. Per SJVUAPCO. regional background of ammonium sulfate is estimated to be 1 J,lg/m3

•

8. Contribution from sources within Kings County is 50% of net concentration after previous

adjustment to Vegetative Burning category.

9. NOx inventory for Kings County that contributes to this monitoring location;

from SIP inventory with updates and adjustments based on CCOS study.

10. PM10 County Impact divided by Ammonium Sulfate County Impact. .

The KingslTulare area has a small inventory of local SOx sources and is dominated

by pollutanttransport from the region; therefore the SOx for PM10 ratio is set to the

minimum technical value of 1.000
60.9543

305.5217

45.81837627

13.44158539

565.1907

4.5846

34.9152

2.96197731

1.704288207

249.4981

1241.6439

91.01532476

277.6758466

34.3569

205.9787

~.87213601

26.9341378

0.0 0.0 0.4 1.4 1.0

4.0 0.5 1.6 3.2 2.0 0.0

70%PM10 50%PM2.5 70%PM10 50%PM2.5 70%PM10 50%PM2.5 70%PM10 50%PM2.5

of net of net of net of net of net ofn!!t

2.0 0.4 0.8 1.6

.15%PM10 30%PM2.5 15%PM10 30%PM2.5 15%PM10 30%PM2.5 15%PM10 30%PM2.5

1.2 0.1 0.48 1.0

10%PM10 15%PM2.5 10%PM1 0 15%PM2.5 10%PM10 15%PM2.5 10%PM10 15%PM2.5

0.6 0.1 . 0.24 0.5

5%PM10 5%PM2.5 5%PM10 5%PM2.5 5%PM10 5%PM2.5 5%PM10 5%PM2.S

49.32181 2.5364

230.94631 14.9086

10.627264011 0.34354204

39.3104583511.76730805

1.0

PM10 paved roads+

PM10 unpaved roads+

PM10 off road mobile+

PM10 farm operations+

PM10 construction+

PM10 windblown

5.801 1.9

7.781' 4.0

45.221 19.2

10.611 2.9

R=SJV

Sr= Tulare, Kings

L1= Area 5

L2= Areas 5,6,7,8

L2= Areas 5,6,7,8

L1= AreaS

Sr= Tulare, Kings

L2= Areas 5,6,7,8

R=SJV

Sr= Tulare, Kings

R=SJV

L1= Area 5

R=SJV

Rolled back against Valleywide emission estimates ·!5%PM1 0 5%PM2.5

episode specific adjustments based on meteorology

and episode duration

Sr= Tulare, Kings

L1= Area 5

L2= Areas 5,6,7,8

Net for Rollback, default percentages adjustable for

episode characteristics, applicable to all columns

except as indicated.

9.·~ :,.:·.,: :..,,:~

.'i1J~~~:~:ewear~

~at?j~l;! ii (area of influence emissions inventory, each on a se~arate line for automated calcuiatio~r .··;/2/;.···."',;·

'0 Rolled back against specified County(ies) emission I10%PM10 15%PM2.5

estimates· episode specific adjustments based on

meteorology and episode duration

From CMS monthly analysis Feb 2000 to Dec 2000,1 From CMS

.' adding January 2001. episode for chemistry

:\:: equivalent to annual design value

;~;; . .. 53.00 23.20 4.00 0.50 1;98 4~62 15.70. 3.00 0.00 0 I

N;' Portion not included in rollback analysis, removed see background sheet for 0, no natural background, 0, no natural background, see background sheet for numerical see background sheet for numerical see backgroundsheet for numerical see background sheet for 100% because marine 0, background estimatel

:.;;i prior to rollback as not subject to local control, numerical estimate and episode transport estimated at 0 transport estimated at 0 estimate and episode adjustment estimate and episode adjustment. estimate and episode adjustment numerical estimate and episode salls are a natural at maximum, no

";::l added back to projected future concentrations adjustment Removed prior to . Removed prior to rollback as not Removed prior to rollback as not Removed prior to rollback as not adjustment. Removed prior to emission additional background

rollback as not subject to local subject to local control, added back subject to local control, added back to SUbject to local control, added back to rollback as not subject to·local estimate for

control, added back to projected to projected future concentrations. projected future concentrations. projected future concentrations control, added back to unexplained mass

future concentrations Includes biogenic emissions. Includes wildfires and biogenic. projected future concentrations

= 20% =20% + 10%

<; ~:~~:~::=:~~r:~~a:~:~~~~~~ ~~~~:~e;r~:,17~~~~1 0

50%PM2.5

.:. includes all PM size emissions in the area· Rolled'

;~;:' back against local area of influence emission

~if;:; estimates

.:'i.;;:', .' 26.55 13.4

'::,'~;;; Rolled back against local PM2.5 area of influence 15%PM10 30%PM2.5

:·f:;": emission estimates - episode specific adjustments

:;.;:;~f.!{ based on meteorology and episode duration

NOx

SOx

TOG

\J 12
0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

0.0

M

1.7466

33.341

27.083

1.7246

3.49721152

3.453160991

2.537472797

. 2.569842275

364.0558

401.6368

52.7948

47.6723089

44.57374446

13.78371425

12.44632963

49.36328821

322.0508

321.5428

1458.6195

1484.1355

354.3705663

112.9643685

112.7861796

353.8115854

::1 0.5

0.1 0.3

0.1

0.0

0.0

Q2

0.5

0.1

0.1

0.0

0.0

D.7

0.6

20.4143

0.3

20.4143

111.1259

111.1259

14.8601553

14.8601553

3.40459935

3.40459935

0.9

1.7

0.5

0.5

0.9

0.3

D.1

2.1

3.2

2.6

1.7

Q.9

12.2'

14.8

1.1

4.0

25.2

4.0

21.4

54.7212\ 2.2327

44.87321· 2.14909268

255.07941 13.3523

205.83041 12.8523

9.608135471 0.30493694

43.744740241 '1.5914437

35.872138721 1.53184933

=(2010 L211999 L2) * LINE 5

=(2010 L1/1999 L1) * LINE 4

R=SJV

Sr= Tulare, Kinas

L2= Areas 5,6,7,8

L2= Areas 5,6,7,8

Sr= Tulare, Kings

L2= Areas 5,6,7,8

Sr= Tulare, Kings

Sr= Tulare, Kings

R=SJV

L2= Areas 5,6,7,8

R=SJV

R=SJV

Sr= TUlare, Kings

R=SJV

R=SJV

Sr= Tulare, Kings

L2= Areas 5,6,7,8

R=SJV

R=SJV

L2= Areas 5,6,7,8

Sr= Tulare, Kings

L2= Areas 5,6,7,8

L2= Areas 5,6,7,8

Sr= Tulare, Kings

SOx 2010 EI with new controls IL1= Area 5

NOx 2010 EI with new controls IL1= Area 5

TOG 2010 Elwith new controls IL1= Area 5

PM10 2010 EI with new controls IL1= Area 5

SOX 2010 EI without new controls IL1= Area 5

NOx 2010.EI without new controls IL1= Area 5

TOG 2010 EI without new controls IL1= Area 5

N22
Annual t .J on Monthly

ANN.UAL Average, based on eMS results .for Februarv to December 2000 Dlusthe Jan 2001 EDisode

57:7 3.6 98.5 57.0 55.6 6.3 2.3 3.6 2.4 1.1 1.2 3.0 0.3 14.9

49.5 3.2 98.4 50.0 46.9 7.5 2.4 4.6' 2.8 0.7 0.7 2.6 0.3 12.0

51.5 3.3 104.1 53.0 52.9 4.0 2.3 0.5 0.7

52.5 3.3 99.6 54.0 51.8 4.0 2.5 0.5 1.0 ;;:

This analysis provides a seasonally adjusted annual average, using the January episode to reflect the dominant winter chemistry.

PageN 12

5.8 FDKERANN

3.3 FOFSDANN

4~2 FDHANANN

3.8 FDVCSANN
. Annuall ...d on Monthly

IBGS 11/1/01 I 2051 10.31 93.61 1.01 0.91 23.31 . 6.3/ 6.71. 4.71 1.31 1.71 7.01 0.71 95.41 7.81 58.21 9.6

I~~ ~~--lli=~h~~Jj'-~-=-;~ ~G~:,'_'w, k~G~w_.J~_~L_~>,~ __y~" ~w~~w§ 34.6 -~.:~~ . _w"}~~+-_l18·Plw*._,._1·qJ.~,.w,,,,-.9~~_w~~ ..,~.,~..~.gt---"~~.-. '-._6·r.. .._W_""~_~~~-"~~~.~~tWff\~~·'~t--_-:-~-~-~--",-:-+",_., __w._w__~3.?~.,~ __.."....~~.1! '.~.i'.I.~:,~.~,.WJm ....•. 0.,:~.5,i~.J..:.:'~~ .. .•.• "~.I'.--~}-*. ...~-_.-:.-.t~--~-"~Af--_~w~«>W_" --*.w.¥i.---~ __'''':'-'1

IBGS'IJun* 41.3 2.7! 102.71 1.01 0.61 0.91 0.41 5.1~ 2.6A~.4tI:\~~~:j>~.> 3.8j 0.3j 3.11 0.41 29.4! ,6.0l IBwGS·_·~ti.1JUi*-~.0 ...·_·_.._--w·~·6l-"1·o1·~31-·w·_·_·--O~91.-·~. 7lT.w,w'-'-.-"·_·_··-·t1-·I.·-··o~t. 1.4" 2A ~.--.v·-2~11.--"--··_M·--5'~21wm----"-2~t-'----Q31 23.4+.-''''---'M_·-5~91

rSGs-.-'lAug*--.--i-----43.51 --··----2~6r.--..'-·§7-:-8f.M'·---r.Ol---1.2, -4:fr"--··'---O..8r22r---:f~t ".- Q.5r-~1~. ... -------o.~-.0Af30.2\-------u. i lo----.-"'-t-""'----=tw~---<..~w._.~.-y-w<~-- ..>....0-<..-~-...,~'~-,w_-~~;.t_~~.w_k_""",-~~-·--r-... ,...~_.~.-,.--~---' ~r--'-_wt.~~~~--+--~~~ ..--r---_.-·""""'i'-«••~-"""~_l__-.~~-'~'~--_.•~_.--~

•. ~.~-'-_- ..,.~~~i-?,~,~~.~t-~.51~.Q:..~·~--~~~--'~~-.·-.".M __~-9-:~.-"~.-1~

~fi~~~~!.---~-· -Hr :~~~~.,,~.r.HI 6::1 6:~-'-~ ~~:~--+T1 ~IDe_cr~<i.~~.2Qjtj.~4t- Y2:2j·.·- H

Min

Avg

Max

22.2

57.7

205.0

1.9 83.9

3.6 98.5

10.3 118.5

0.9 0.4

1.0 0.9

1.0 2.2

0.3

6.3

23.3

0.4 0.2

2.3 3.6

6.3 1.0

1.3 0.5 0.6

2.4 1.1 1.2

4.7 2.4 2.7

1.2

3.0

7.0

0.1

0.3

0.7

2.2

14.9

95.4

0.3 10.9

1.3 26.7

7.8 ·61.9

3.1

5.8

12.5

FSD 1/1/01 186 9.4 87.9 1.0 1.1 40.1 11.3 18.5 9.6 2.5 1.5 5.0 0.7 62.4 5.1 35.1 6.8

~~-+-1I~1 - ~%'-li~-~:;t_-~:~---HI it-~::I '~it-~~-~~f------N ~pr 1-.24.8~[..'·~'--1·~Ot.·--Q6 .' 3.4·.r--·-···---·--~.2.71-·-2'~4r.:~~l.-.:-.:-0.• -.•... 2.·- ....•.. -.. ~.'- ·..-:0.-·.·.·:..·.·.·.5'.r---TI..~I-_M_b~5t-'--1.4.4r. "m _" "".M,w--'3']'1 . WSD~20£= :z·W9:Sc=ror· ··O.:§ 0.3~~~_·1.4~ ~321~12rl.~ run~ ._34'l ~V5~ o.~ 3.81~_'w._...i:~Lvm ....._~~L.N __.....~~_:-~L.~,. Q:~~?:~~ __. .w••M'_3.8j

~L~u-i!=-~ ~FS~__~3.~9t .0.5, .... tit~tl=ttDt~~~ ~30~3.~

~~~_"_?:§L~_1:31~~0.~~.?J~1.~!:§j lf~£2.~_.lQec.__..--L,__". 65.~, .._.~.9i ....._w.~~-:.~ ~~~.,,_13. 7 ~, __~._4.31_~L_3.81 __Q:~L_._._Q:§J. ~:...?J'_~M_0.3j_, __23.41 _._ 2.01 ~{)..:~i __....__. ~~

. Min

Avg

Max

20.0

49.5

186.0

2.1 87.9

3.2 98.4

9.4 116.0

0.9 0.4

1.0 0.9

1.0 .'~ 2.7

0.3

7.5

40.1

0.3 0~9

2.4 4.6

11.3 18.5

1.3 0.0 0.4

2.8 0.7 0.7

9.6' 2.5 1.5

1.1

2.6

5.0

0.2

0.3

0.7

2.5

12.0

62.4

0.3 6.8

1.1 19.5

5.1 40.6

1.7

3.3

6.8

Page N22
Annual'l j on Monthly

HAN 1/7/01 185 9.6 '102.9' 1.0 0.4 27.6 9.7 14.7 7.8 1.7 1.1 7.2 0.7 96.9 7.9 42.4 7.7

lti!-N~-+_..~10~t-~~1~~ __~-M-0.9~ 1!L~-l~+-~~.~Q:~J--~L~~~~•.... ?2l~I·3L~_~~_~_~

~~;*+1~:~--}+I~~-+m--%.i-n~--0.35~5H~i·":.:.·'·~·2.4~~.7 i~~g4~1 ~~:h79:J. ~~-·-~~~.~i~ iRAN'Tur-+~r-2:6f~--0:9-----o.-~-02h7l--s.4~.6~--4:71 ~~~-~ ~Q~2~

iHAN~Au-rl-43Y-2]r-1in7t-+~-f]rM_·-1.s!-0.3Io:ar~ OAr 33~-_·M_[71. mA~p*-~0.~~~-o.sr-"2":5i-~~~-or-s]i---"-·(f71~5aar-----·"--8]i

t·~FiAN--.1ocr-r.:... '--"~"M-5~8t. _w-,,-_w·~3:'4t.:-. --~w~90~91.---:rol-~-1- ..ol'-··'.w_,w"~-",.,,w..o.-:-sr--.3i1."--'-'-22~..~,·····_~"o ..2r-'·-·~6Bt: ~.4(------0:3r-~.61- 0.81"32.2t----W----.,.-wsi IHAN1Nov-----r--46~1D7."61~~~'3~4.8r----2.9~0.5~-.-1.5[J~

~~t62."8~~=1·L.Q:5t= 1~_3.41_4.41-i.~~L_~0.71-281

Min

Avg'

Max

20.0

51'.5

185.0

1.8 89.4

3.3 104.1

9.6 120.6

0.9 0.3

1.0 0.4

1.0' 0.7

0..4

6.6

27.6

0.3 1.4

2.0 4.0

9.7 14.7

1.0 0.0 0.3

2.3 0.5 0.7

7.8 1.7 1.2

1.4

3.0

'7.2

0.2

'0.3

0.7

2.7

15.7

96.9

0.4 4.6

1.4 23.2

7.9 58.8

1.3

4.2

8.8

HAN 1/7/01 185 9.6 102.9 1.0 0.4 27.6 9.7 14.7 7.8.1.7 1.1 7.2 0.7 96.9 7.9 42.4 7.7

~~f;~ ~j~!t_ U~~4--=-" ~:ij=tlt=~-~-= iHi=-~:~tJl= -~i _2·~~L_ 0.7L-5A,~~:.<.:·.· ...~l--...Q~~J.-4~--.-EJ lYC~ IJun* ---l--S..01_~~0.8~.~~.;;''''t~:" .. :~~ ~.5.2L.....4 2~.1 3.9! f 2.5U07.~_......Q~~.!j. 3.71 ..... 0.61 ..1.81 ... -!1L~~_. q1L_......~,,_~:~L.~. __0.~+-.23.7,_.. --~

__~L~_1_.~1.6! 9.:.~_~~~2~~

~~~. FS~~I~n- e~~..- __._ ._ 59.*-..~' ~~.5:_~.!w,..'w•.".,_.w.~Q:.~1._.._~.:~ '_2,:.. __. W._._M'~:.~4__J...:..9.p~ ~~.~~~ .._ _:'_.0.._.:7•..~.! '..__.:••........•.,._:._:1._.: ,.•__..6.-.•r.1

__

~~~~_~_ 1~_.·Q~~-~~·TI 0.61 36.~~. ._-~

~gQ;f==t-·:~:~t-=irdL~

Min

_;:~t- ~~ok~_-OC ~=~

Avg

Max

25.0

52..5

185.0

2.1 83.6

3.3 99.6

9.6 115.3

0.9 0.4

1.0 0.9

.1.0 1.4

0.8

6.7

27.6

0.4 1.4

2.5 4.0

9.7 14.7

1.3 0.0 0.5

2.5 0.5 1.0

7.8 1.7 1.6

1.1

3.1

7.2

0.1

0.3

0.7

3.8

15.9

96.9

0.5 7.6

1.5 21.7

7.9. 42.4

1.9

3.8

7.7

Page N 32.
Annual b, J on Monthly

NOTES: Burning profile was switched from wood burning to agricultural burning based on ARB monthly emissions inventory estimates.

Astetisk * denotes AgBWheat profile used; ** denotes WBAlmond (some AgBWheatIWBAlmond used in April/May)

Burning

Sulfate

Nitrate

Motor Vehicle

TirelBrake

Geological

Source Profiles

Jan-May and NovDec

22 WBOakEuc

57 Amsul

60 Amnit

65 CAMV

67 TireBrke

92 FDHANANN

93 FDFREANN

94FDVCSANN

95FDKERANN

June-Oct

27 AgBWheat*

57 Amsul

60 Amnit

65 CAMV

67 TireBrke

92 FDHANANN

93 FDFREANN

94 FDVCSANN

95 FDKERANN

Note: (not used ifrun came out negative)

Page N 42
)1

Rollback default percentage, adjust by episode properties

Local PM2.5 Sub regional Regional Total

Default 2.5-10 I 70 15 10 5 100

Default 2.5 - I 50 30 15 5 100

Note: distributi~n of ant~ropogeniccontribution after subtraction of background

Mapping of local, PM2.5-local,

and sub-regional based on

trajectory analysis Areas used

24-hr date ISite Name Value PM2.5 Sub.regional IRegional 1# of dates

199

159

160

1/12/99 Oildale-3311 Manor Street 156 12 12,13 Kern SJV 1

10/21/99 Corcoran-Patterson Avenue 174 6 5,6,7,8 Kings-Tulare SJV 2

Fresno-Drummond Street 162 3 3,4 Fresno-Madera SJV 3

Turlock-S Minaret Street 157 1 1,2 _ Stanislaus-Merced SJV 4

11/14/991 Bakersfield-Golden State 183 12 6,7,8,10,12 Kings-Tulare-Kern SJV 5

12/17/99 Cotcoran-Patterson Avenue 6 6,8 Kings-Tulare SJV

12/23/99 Street 3 3,4,7 Fresno-Tulare SJV

5 5,6,8 Kings-Tulare SJV

1/1/011Bakersfield-5558 California Avenue 186 12 9,10,11,12 Kern SJV 9

Bakersfield-Golden State Highway 205 -12 9,10,11,12 Kern SJV 10

Clovis-N Villa Avenue 155 .-3 3,4 Fresno-Madera SJV 11_

Fresno-1st Street 193 3 3,4 Fresno-Madera SJV 12

Fresno-Drummond Street 186 -3- 3,4 Fresno-Madera SJV 13

Oildale-3311 Manor Street 158 .12 9,10,11,12 Kern SJV 14

1/4/011 Bakersfield-5558 California Avenue 1 12 - 10~12, 13 Kern SJV 15

Bakersfield-Golden 12 10,12,13 Kern SJV

3 3,4 Fresno-Madera SJV

1 Manor 12 10,12,13 Kern SJV

1/7/011Bakersfield-5558 Cal.ifornia Avenue 159 12 10,12 Kern SJV 19

Bakersfield-Golden State Highway 174 12 10,12 Kern SJV 20

Corcoran-Patterson Avenue 165 6 6,8,10,12 Kings-Tulare-Kern SJV 21

Hanford-S _Irwin Street 185 5 5,6,7,8,10 Kings-Tulare-Kern SJV 22

Mod-esto-14th Street 158 1 1,2 St-Me':':Ma- Fr-Tu SJV 23

11/9/01 IHanford-S Irwin Street 155 5 5,7,8 Kinas-Tulare SJV 24
Annu~I' ICounty

Kern

Value

57

Local

12

. ,vi

Areas used

PM2.5 Sup regional

Kern Kern

Regional

SJV'

Pl·M·1·0: SIIPR,sgioin:.s.

b:.8SQd, ,g,n

4k CCAQ.S :D:Olm:aiiin

(COiunty .inftuencedceUs)
Page I of2

Derek "Fukuda

From: Jim Rexroad [Jim.Rexroad@macquarie.c·om]

Sent: Monday, June 09, 2008 3:"51 PM

To: Derek Fukuda

Cc: "Eric Walther; Tracey Gilliland

Subject: Certificates used for Avenal PDOC

" "

We are still finishing up the formal table submissions so you can see the actual breakdowns, but here is the list of

certificates that we· will be using for the project. Note that S-2813-1 will ~hortly have a transaction coming that will

reduce the volume to 50 Tons and the· S232"1-2certificate {I have a contract and the ownership change

documents will come next we~k. We should be able to"send you the formal table tomorrow or by Thursday. Call

me if you havequestions~

ERC Certificate No..

·vac

C-897-1

C-898-t .

N-724-1

N-725-1"

S-2813-1 (derived.·from)

NOx"

C-899-2

N-722-2

N-720-2

N-726·-2

N-728-2·

C·-902-2

8-2814-2

8-2321-2 (derived from)..

SOx (conversion to PM10.at 1.4:1)

S-2791-5

8-2790-5

S-2789-5

S-2788-5

N"-762-5

1/?OOR
Page 2 of'2

PM10

C-896-4

N-721-4

N-723-4

Jim Rexroad

Macquarie Cook 'Power Inc.

713-27g~6147 (0)

832-748-1060 (c)

71 3-275 ~611 5 (f)

500 Dallas' ~treet, Level 31

Houston, TX 77002 USA

-jim.rexroad@macquarie.com

EmaiJ disclaimer for Macquarie Cook Power Inc.: http://wwW..macquarie.com/us/mcp_disciaimer.htm

This. communication has been prepared by MacquarieCook Power Inc., and is confidential and intended for specific recipient(s) only. If you

are not the intended recipient, please notify us by telephone or return emaif and delete the communication without using, copying or

qisseminating the·information contained therein. '

Any'use, copying or dlssemihation of the information, without the express written consent of.Macquarie .Cook Power Inc.• is strictly prohibited

and le~al proceedings may be commenced against you. .

11 1 I~()()Q
Avenal Power'Center, LLC (OB-AFC-01)

SJVACPO Determination of Compliance, C-1080386

ATTACHMENT I

Additional Supplemental Information

Attachment I - 1
Table 3.2-2. UNCONTROLLED ·EMISSION FACTORS FOR 4-STROKE LEAN-B.URN ENGINESa

(sec 2-02-002-54)

Pollutant

Emission Factor

(lb/MMBtu)b

(fuel inP':lt) .

Emission factor

Rating

Criteria Pollutants and Greenhouse Gases

NOxC 90 - l05°h> Load

c NOx <90% Load

" c

CO 90 - 105.% Load

cac .<90% Load

C02

d

S02e

TOCf

Methaneg

VOCh

PM"lO "(filterable)l

·PM2.5 (filterable)i

PM Condensabld

Trace Organic Compounds

4.08 E+OO B

8.47 E~OI B

3.17E-OI C

5.57 E-Ol B

1.10 E+02 A

5.88 E-04 A

1.47 E+OO A

1.25 E+OO C

l.18 E-Ol C

7.71 E-05 b·

7.71 E-05 D

9.91 E-03 D

k 1;.1 ,2,2-Tetrachloroethane

1,1,2-Trichloroethanek

1,1-Dichloroethane

1,2,3-Trimethylbenzene

1,2,4-Trimethylbenzene

1,2-0ichlotoethane

1,2-Dichloropropane

1,3,5-Trirnethylbenzene

1,3-Butad~enek

1,3.:.Dichloropropenek

" k 2-Methylnaphthalene

2,2,4-Trimethylpentanek

Acehap~thenek

<4.00 "E~05

<3.18E-05

<2.36 E-05

2,30 E-05

1.43·E-05

<2.36 E-05

<2.69 E-05

3·.38 E-05 .

2.67E-04

<2.64 E-05

3.32 E-05

2.50 E-04

1.25 E-06

E

E

E

o

C

E

E

D

D

E

C

C

C
Table 3.2-3. UNCONTROLLED EMIS'SION FAC'rORS FOR4-STROKE RlCH-BURN

ENGINESa

(SC~ 2-02-002-53)

Emission F'aetor

(lbIMMBtu)b Emission Factor

Pollutant (fuel input) Rating

Criteria Pollutants and Greenhouse Gases

NOxC 90 - 105% Load 2.21E+OO A

C

NO 2.27 E+OO C x <90% Load

cac 90 - 105% Load 3.72 E+OO' A

cac <90o~ Load 3.51 E+OO C ..

. CO d

2 1..1.0 E+O.2 A

SO2e 5..88 E-04 A

TOCf 3.58 E-Ol C

Methaneg · 2.30 E-Ol C

VOCh 2.96 E-02 C

PMI0 (filterable)i,j 9.50 E-03 E

PM2~5 (filterable~ 9.50 E-03 E

. k .

PM Condensable 9.91 E-03 E·

Trace Organic Compounds

1,1,2,2-TetrachloroethaneI 2.53 E~05 C

1, 1,2-TrichloroethaneI <1.53 E-05 E

1, 1~Dichloroethane <1.13 E-05 E

1,2-Dichloroethane <1.13 E-05 E

1~2-.Dichloropropane <1.30 E-05 E

. . I

1,3-Butadiene 6.63 E-04 D

1,3-Diehlo.ropropeneI .<1.27 E-05 E

. . 1m Acetaldehyd~ , 2.79 E-03 C

.

Aero1·lmetn ' 2.63·E-03 C

I \

Benzene 1.58 E-03 B

Butyr/isobutyraldehyde 4.86 E-05 D

Carbon'TetrachlorideI <1.77 E-05 E
btu=>ppm

SELECTION -#

COAL (ANTHRACITE) 0

COAL (BITUMINOU'S) 1

COAL (LIGNITE) , 2

OIL (CRUDE, RESIDUAL', OR DISTILLATE) 3

GAS (NATURAL) 4

GAS (PROPANE) 5

GAS (BUTANE) 6

WOOD 7

WOOD BARK -8

MUNICIPAL SOLID_WASTE_ 9

STANDARD 02 CORRECTION FOR EXTERNAL COMBUSTION IS 3%

Type of fuel (usetable above) 4 GAS

02 correc~ion (i.e.~ 3%) 15·%

. Enter LB/MMBTUemission factor

NOx 0.847 LB/MMBTU

CO 0.130- LB/MMBTU

voe (as methane) , 0.000 LB/MMBTU

CALCULATED EQUIVALEN.T CONCENTRATIONS

NOx 229.94 ppmv,

CO 57.98· pp-mv

voe-(as methane) 0.00· ppmv

pV.= R*T

pressure (p) . 1 atm

universal gas con~tant (R*) 0.7302 atm-scf/lbmofe-oR

temperature.(of) 60 of

calculated

molar specific volume (V)- 379.5 scf/lbmole

-..

Molecular weights

NOx 46 Ibllb-mole

CO 28 Ib/lb-mole

,vac (as methane) 16 Ib/lb-mole

F FACTORS FROM J=PA METHOD 19 @ 68 F

COAL (ANTHRACITE)' ,

COAL (BITUMINOUS).

COAL (LIGNITE)

',' OIL{CRUDE,RESIDUAL, OR DISTILLATE)

GAS (~ATURAL).

GAS (PROPANE)

GAS (BUTANl=) .

WOOD

WOOD BARK

MUNICIPAL SOLID WA~TE

F FACTOR USED IN CALCU-LATIONS

----.---------------,- --- .--6/-2--3t2008

101000'SCP/MMBTU

9780- DSCF/MMBTU

9860 DSCF/MMBTU

9160 OSCF/MMBTU

8710 DSCF/MMBTU

8710 PSCF/MMBTU

871-0 DSCF/NlMBTU

9240 DSCF/MMBTU

9600 DSCF/MMBTU

9570 DSCF/MMBTU

8710 DSCF/MMBTU

COAL"

C:OAL

COAL

OIL

GAS

GAS

GAS

WOOD

,WOOD BARK

.SOLID WASTE

GAS
Varia.blas:

'860lhp

230lppmv

Olppmv

aIPpmv '(as CH4)

15,1 0/0

351 % (Assumed)

85781 dscf/MMBtu

Fuel Type I 1

Oil (CRUDE. RESiDUAL, OR DISTillATE)

GAS (NATURAL) .

GAS (PROPANE)

GAS (BUTANE)

o

2

3

Conversion #1 :

··Conversion·#2:

Conversion·#3:

iVIVV (NOX).

dscf/lb-mol

bhp...hr/MMBtu

glib

ppmv F-factor MWpoUutant 1 1 Con~ersion #3 1

1 1 1 Conversion #1 ' Conversion #2 1 Engine Eff.

46·t9 20.9 11bmql MMBtu 453.59 9 1 C::> 1 Ib mol 20.9 - 15 379.5 GSGf 393'~24 bhp-hr lb 35%

c=::> o~

10 W ft8-Ft-s

o~

1a ft8-Ft-s

8578 GsGf

MMStY

MM24J 453.59g

453.59 9

35%

350/0
btu=>ppm

SELECTION #

COAL (ANTHRACITE) 0

COAL (BITUMINOUS) 1

COAL (LIGNITE) 2

OIL (CRUDE, R"ESIDUAL, OR DISTILLATE) 3

GAS (NATURAL) 4

GAS (PROPA~E) 5

GAS (SUTANE) 6

WOOD 7

WOOD BARK 8

MUNICIPAL· SOLID WASTE 9

STANDARD 02 CORRECTION FOR EXTERNAL CO.MBUSTION IS 3%

Type of fuel (use tabl.e above) 4 GAS

02 correction (Le.; 3%) 15 %

Enter LB/MMBTU emission factor ./

NOx' . 2.270 LB/MMBTU

CO 0.130 LB/MMBTU

vae (as methane) 0.000 LB/MMS'TU

~CALCULATED EQUIVALENT CQ:NCENTRATIONS

NOx 616.25 ppmv

GO 57.98 ppmv

vac (as methane) 0.00 .ppmv

pV =R*T

pressure (p) 1 atm

universal gas constant-(R*) 0.7302 atm-scf/lbmole-oR

temperature (oF) 60 of

calculated

molar specific volume (V) ~79.5 scfllbmole

'.,

Molecular weights

N"Ox 46 Jb/lb-mofe

CO 28 Ib/lb-mote

.vae (as methane) 16 Ib/lb,..mole

F FACTORS FROM EPA METHOD 19 @ 68 F

COAL (ANTHRACITE)

. COAL (BITUMINOUS)

COAL'(LIGNITE) .

'. OIL (CRUDE, RESIDUAL, O'R DISTILLATE)

GAS(NATURAL)

GAS (PROPAN·E)

GAS (BUTANE)

. WOOD .

WOOD BARK

MUNICIPAL SOLID WASTE

F FACTOR USED IN CALCULATIONS

10100 DSCF/MMBTU

9780 DSCF/MMSTU

9860 DSCF'IMMBTU

'9160 DSCF/MMBTU

8710 DSCF/MMBTU

87100'SCF/MMBTU

87'10 DSCF/MMBTU

9240 DSCF/MMBTU

9600' DSCF/MMBTU

9570 DSCF/MMBTU

8710 DSCF/MMBTU

COAL

. COAL

COAL

OIL

GAS'

GAS

GAS

WOOD

WOOD BARK

SOLID WASTE

GAS
IV·arlaQles:

Engine. Size: 8.60 hp

NUx: 616 ppmv

CO: o ppmv

vac: o ppmv (as CH4)

U2level: 15 0/0

Engine Efficiency: 35_ 0/0 (ASsumed)

F-factor: .8578. dscf/MMBtu·

Fuel Type 1

OIL (CRUDE, RESIDUAL, OR DISTILLAT~) . 0

GAS (NATURAL) 1

GAS (PROPANE) . 2

GAS (BUTANE) 3

Conversion #1.:

Conversion #2:

.. Conversion #3:

Ivl vv-(NOx).

dscfllb-mol

bhp-hr/MMBtu

glib

35%

I 35%

1 I Engine Eff.

U3 I 35%

453,'59 9 I 1

453.59 9

453.59 g I 1

Conversion #3 I 1

MMStY

1

Conversion #2

1 .

11bmol

379.5 00sf

Conversion #1

tlb mol.

1 I 1

~4M8tu. I 1 Ib mol

F-factor I MWpol1utant

8578 GsGfI 28 fu

8578 GsGf I ·46 U3

ppmv

1

o~

o~

10V~

10V:~

10-~

616~
Avenal Power 'Center, LLC

500 Dallas Street, Level 31

Houston, TX· 77002'

RECEIVED

JUl 0 j 2008

Pe·rmlts:Srvc ~.l\I.A-rj·nD

July.1, 2008 COpy

RE: Certification of Avenal Energy, owned by Avenal Power Center, LLC

I, Stuart Zisman, on behalf of Avenal Power C~nter, LLC, hereby certify under penalty of

·perjury.as follows:

1. I am authorized to make this certification on behalf of Avenal Power Center, LLC.

2..This certification is made pursuant to Section 4.15.2 ofRule 2201 ofthe Rules and

Regulations of the SanJo'aquin Valley Unified Air Pollution Control District. ,

.3. To the best ofthe undersignedfs knowledge, relative· to Section 4.15.2 of District Rule

·2201-, Avenal Po'wer Center, LLC.do"es not currently own, operate or control any

Major Stationary Source or feder~l -major modification in the State ofCalifornia other

than the proposed Avenal Energy Project.

'Each ofthe'statements herein is made in good faith. Accordingly, it is Avenal' Power Center,

LLC'sunderstanding in submitting this certification that the SJVUAPCD shall take no action

against Avenal Power Center, LLC or a~y of its employees based on any st~tement made.in

.this certificatiou.

J e Forbes

Senior Lawyer

. Stuart Zisman

Vice President

Avenal Power C~nter, LLC

~JIO~ Dated
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

ATTACHMENT J'

CEC Comments and Districts R(3sponses

----------.. -~--~----------.-.------ .... -- --- --- ----..--.--.-.--------------.. ------Atta-cb-me-nt~j-----
Public Comments I District Respon.se

The comments from the California Energy Commission (Keith Golden) regarding

. the proposed Title V Operating Permit for Aven.al Power Genter LLC(District

facility Co-3953) are encapsulated below followed by the District's response.

CEC Comments _0 Letter Dated August 12, 2008

CEC Comment #1 :

Energy Commission staff is concerned that the integrity of the proposed

mitigation may be adversely affected by the annual equivalency demonstration

required by SJVAPGD Rule 2201, Section 7. This rule requires the District to

demonstrate that emission reduction credits (ERGs) used by th~ project 'as

offsets are surplus at the time of use.

Please describe whether District compliance with Rule 2201, Section 7 would

require any of the offsets to be subject to discounting.. Please also confirm

.whether the offsets identified for the project·(on PDOCp. 47) are representative

. of real and surplus reductions, taking into account possible discounting under

Rule 2201, Section 7. Additionally, please identify the original emission reduction

site and date, and the method of reduction, for the ERGs that would be used to

offset this project.

Districts Response:

Provided the FDOCis issued prior to a finding of failure of the equivalency

system, the "at time of use" requirements don't apply. ° In addition, the-District has

not failed the equivalency demonstration, and does not· expect to fail the

demonstration this year. Finally, "at time of use" means at the time of the

issuance of the permit (which the District considers to be the FOOG, in this case).

Therefore, if a permit is issued without requiring "surplus at time of use credits",

as the District subsequently fails ° to demonstrate equivalency with federal

offsetting requirements, there is no affect··on the permit. The "surplus at time· of

use" requirements would only kick in on permits issued after that date.

CEC Comment #2:

Staff would like to verify that using offsets would not disrupt regional progress in

attaining PM10 or PM2.5 standards. The SJVAPCD, in Attachment H of the

PDOC incorrectly states that the applicant proposed a one-to-one .ratio. Please

provide the District analysis in "Appendix A" with the Attachment H of the PDOC

that supports compliance with Rule 2201, Section 4.13.3.
Districts Response:

The Districts PM10 and PM2.5 plans both account for the growth in permitted

sources in the air district. This growth is compared to the amount of offsets

available in the Districts ERG bank to assure that the increase'in emissions will

not invalidate the Districts PM10 and PM2.5 plans. Since the growth in permitted

sources in the air district and the air districts available offsets have been taken

into account when determining both the 'PM10 and PM2.5 attainment plans, the

use of offsets in this project will not result in th~ disruption of the attainment

plans.

The interpollutant offset ratio for sax reductions for PM10 increases will remain

the same as stated in the PDOC.The Districts analysis of the interpollutant

offset ratio has can be seen in Appendix A, which has been included· in

Attachment H of the POOG.

CEC Comment #3: .

'Energy Commission staff concurs with the District that th,e NOx emission limits

for the combustion turbines and duct burners 'should apply on one-hour rolling

averages during all operating conditions, except startup and shutdown periods

(as described in PDOC p. 64 and POOC Condition. 26). However, the one-hour

NOx emission limit is not consistently described in the POOC. Please confirm

that the value calculated by the District is 17.20 Ib/hr (POOC Condition 26), not

17.44 Ib/hr (as shown onp.64).

D'istricts Response:

The hourly NOx emission limit is 17.20 Iblhr. The condition on page 64 of the

PDOC has been corrected to be consistent with condition 126 of the PDOC~

CEC Comment #4:

Energy Commission staff recommends limiting ammonia, slip to the extent

feasible. Although ammonia slip is intr.insic to operation of the selective catalytic

reduction system, staff suggests that the District set a performance. standard for

ammonia slip. Guidance from CARB (Guidance for Power Plant Siting and Best

Available Control Technology, September 1999) indicates that an ammonia slip

limit of 5 parts per million by volume dry basis (ppmvd) should be achievable.

Please consider revising th.e ammonia slip limits for the combustion turbines.
Districts Response:

Ammonia is an integral part of the NOx emissions control system when using

SCR. The District has no regulatory basis for restricting ammonia slip to 5 ppmv.

Ammonia is not a criteria air contaminant or a "pre,cursor" as defined in District

Rule 2201. The District's BACT Clearinghouse does not specify an ammonia slip

rate for combustion turbines using SCR. Whi/~ ammonia emissions' may be

restricted as part of a he~/th risk evaluation that determines an unacceptable

health risk from the ammonia to exposed populations, this is not the case with

Avenal Power Center. The risk due to all toxic air contaminant emissions,

including 10 ppmv ammonia, was found to be not significant.

A high ammonia slip from the turbin,e will not lead to increased PM10 formation in'

the atmosphere. The air basin currently has an excess of ammonia emissions;

therefore lowering ammonia' emissions will not reduce PM· formation. This is

demonstrated in the Districts PM2.S plan which does not not rely on ammonia

reductions to' reduce PM2.S, but rather relies largely on ,NOx reductions.

Generally, increased ammonia injection rates, and therefore increased ammonia

slip rates, are required to maintain NOx BACT performance levels (2.0 ppmv) as

the catalyst ages. Allowances for operation 'at the end of the economic life of a

control te'chnology and for periods of non-steady state operation (including

startup and shutdown which can result in ammonia slip higher than 5 ppmv) are

part of a BACT determination.

CEC Comment #5:

The New Source Performance Standard (NSPS) Subpart KKKK applies to stationary

combustion turbines and emissions from any associated duct burners, and it replaces

earlier requirem.ents in NSPS Subpart Db and Subpart GG. The PDOC (p. 55) shows

requirements from NSPS Subpart Db, although the project appears to be exempt.

Similarly, the PDOC (p. 63) states that the turbines meet the applicability requirements

of Subpart GG when the project appears to be exempt. Please clarify whether' the

project is indeed exempt from NSPS Subparts Db and GG.

Districts Response:

The stationary combustion turbines and duct burners in this project are subject to

Subpart KKKK and are therefore exempt from Subparts Db and GG. An

additional compliance section was added to state that the duct bu.rners are

"exempt from Subpart Db. The compliance section for SubpartGG already states

that the turbines are exempt from its requirements.
Avenal Power Center, LLC (08-AFC-01)

SJVACPO Determination of Compliance, C-1080386

ATTACHMENT K

EPA Comments and District Responses
EPA Comments I District Response

The comments (from Shirley Rivera) regarding the proposed Title V Operating

Permit fo'r Avenal Power Center LLC(District facility C-3953)~s encapsulated

below followed by the District's response.

EPA Comments - Email Dated August 15,2008

EPA Comment #1:

For the purposes of EPA's review of the PDOC evaluation and PDOC, although

n'ot required as part of· our PSD permit application review/permit development

process, we are in the process of identifying whether information provided by the

Applicant ·through the PSD permit application process is consistent with the

·information in the District's evaluation. (Note: The Applicant provided sections

from its CEC AFC that includes the Air Quality and Public Health sections, which

presumably is information that the District evaluation also is based. PSD review

has been triggered for NOx, CO, and P'M.)

We would like to ensure' that, at a minimum, those data sets and assumptions

shared between the PSD' and PDOC processes 'that contribute. to' the

determination of the potential-to-emit, BACT, and assumptions for the air quality

ana'lysis/modeling are consistent.. At this time, we simply would like to make the

District aware that th'is evaluation is in process. To the extent that we identify

inconsistencies during our review, we will address them as part of our PSD

permit process..

Districts Response:

Thank you for (h.enotification.

EPA Comment #2:

The emission limits proposed for each combustion turbine generator (CTG),

Units C-3953-10-0 and C-3953-11-0, are 4.0 ppmvd @ 15% 02. EPA is· aware

of CTGs achieving CO emissions less than 4.0 ppmvd @. 15% 02. Therefore,.

please provide' confirmation whether the District's evaluation considered

achieved in practice CO ppm levels less than 4.0 ppmvd @ 15% 02. If s'o,

please provide reasons why a 'Iower level was eliminated from consi.deration.

Districts Response:

The facility has proposed to lower their CO emission limit to 2.0 ppmvd @ 15%

- 02.
Avenal Power Center, LLC(OB-AFC-01)

SJVACPO Determination of Compliance,C-1080386

ATTACHMENT L

CURE Comments and District Responses

Attachment - 1
Public Com'm'ents I District Response

The comments from California Unions for Reliable Energy· (Loulena Miles,

attorney at Ad.am Broadwell Joseph & Cardozo) regarding the proposed Title V

Operating Permit for Avenal Power Center LLC (District facility C-3953) is

encapsulated below followed by the District's response.

Public Comments - Email Dated August 18, 2008

Public Comment #1 :

THE SJVAPCD MUST SET LIMITS FOR GREENHOUSE GAS EMISSIONS

The law is now settled that greenhouse gases are pollutants subject to regulation

under the Clean Air Act (CAA). Therefore,Air District permits must include a

Best Available Control Technology (BACT) analysis and a permit limit for

greenho.use gas emissions. The PDOC contains' neither. Accordingly, the

PDOC is deficient and must be revised to require BACT· for greenhouse gas

emissions.

Districts Response:

According to the Advanced Notice of Proposed Rulemaking for Regulating

Greenhouse Gas Emissions under: the Clean Air Act, Federal" Register Vol. 73,

No. 147, pg. 44420 (July 30, 2008),

"The Supreme' Court's con.clusion that GHGs are "air pollutants" under the CAA

did not automatically make these pollutants subject to the PSD program. A

subst~nce may be an "air pollutant" under the Act without·being regulated under

the Act. The Supreme Court directed the EPA Administrator to determine

whether GHG emissions from motor vehicles meet the endangerment test of

CAA section 202(a). A positive finding of endangerment would require the

Administrator to then set" standa'rds applicable to GHG emissions from motor

vehicles under the Act. The positive finding itself would not constitute a regulation

requiring actual control of emissions. GHGs would become regulated pollutants

under the Act if and when EPA subjects GHGs to control requirements under a

CAA· provision other than sections 112 and 211(0)."

EPA has not added control requirements for GHG's in the CAA, therefore GHG's

are not regulated air pollutants and are not subject to the PSD program. In

addition, the District has no~ been delegated the PSD program by EPA.

Therefore, even if GHGs do become regulated pollutants, the District will .

continue to have no jurisdiction to regulate them until the EPA- decides to

delegate the PSD program to the District. . -

Based on the information discussed in ·the paragraphs above, an evaluation of

GHG's is not necessary to determine if this project is apprqvable.
Public Comment #2:

The PDOC limits CO emiss'ions from the combustio'n turbine generators (CTGs)

. to 4.0 ppm at 15% 02 regardless of whether the duct burners are firing based on

the use of an oxidation catalyst. 1 The PDOC',s determination that 4.0 ppm CO

emissions are 'BACT is incorrect a.nd fails to recog'nize th'at a number of power

pl,ants in the same category and class of source have achieved lower CO

emission rates than proposed by'the Applicant.

Districts Response:

The facility has proposed to lower their CO emission limit to 2.0 ppmvd @ 15%

O2.

Public Comment #3:

THE PM10 BACT DETERMINATION ,FOR CTGs IS DEFICIENT

The PDOC limitsPM10 emissions 'from the combustion turbine generators (CTGs)

to 9.0 Ibs/hr without duct firing and 11.8 Ibs/hr with duct firing, using natural gas

fuel. The PDOC determined that BACT for PM10 emis.sions from this Project's

two 'G,eneral Electric (GE) 7FACTGs wou.ldbe the use of natural gas'fuel with an

LPG backup.' This determination is incorrect and fails to recognize that a number

of power plants in the same category and class of source that have ach·ieved

lower PM10 emission rates than proposed by the Applicant.

Districts Response:

The' District Top-Down BACT Analysis did not consiqer any PM10 emissions

contr()1 other than the use of an air inlet filter, lube oil vent coalescer and natural

gas fuel.

District BACT Policy, Section. IX. 0, states that a cost effective analysis is not

necess,ary for a 'project in which the most effective control alternative is selected.

BACT Guideline 3.4.2 identifies BACT for PM10 as the use of an air inlet filter,

lube air vent coalescer and natural' gas fuel. Since the applicant proposed the

most effective BACT control alternative, no evaluation of ·other control

t~chnologies were 'performed.

1 SJVAPCD PDOC Attachment F-5.
Furthermore, District BACT Policy, Section IV, states that BACT Determinations

are to be based upon the control technologies and methods for the same·or similar

source categories, listed in the District's BACT Cle'aringhouse for the calendar

, quarter during which the' application is, de~med complete. This application was

deemed complete in the 1

st quarter of 2008, therefore it 1s $ubject to the BACT

Guideline for the source categories contained in the BACT Clearinghouse at that

time. 'Based on the completion date of this application, the BACT requirements for

,the units in this project would not change even if the BACT Guidelines were

changed in subsequent quarters.

The permitted PM10 emissions limit for each CTG in this project is 11. 78 Ib/hr.

This emission limit is lower other GE Frame 7A, combined cycle, turbines with

duct burners at power plants which have recently been approve(j by the GEC.

The Victo/Ville 2 Hybrid Power Plant (approved 7/16/08) was permitted with a

PM10 emission limit of 18.0 Ib-PM101hr. The Colusa Generating Station (approved

4/23/08) was permitted with a PM10 emission limit of 20. 1 Ib-PM101hr. The Los

Medanos Energy Center referenced in yoiJr comment has a permitted PM10

emission limit of 16.2 Ib-PM101hr. In addition, the PM10 emission limits for the two

turbin~s, at the Cosumne,s Power Plant are not comparable since they are not

equipped with duct burners.

Public Comment #4:

SJVAPCD's LIMITS ON AMMONIA SLIP ARE NOT BACT

The PDOC and attached permit conditions ,propose an unreasonably high

ammonia slip limit of 10 ,ppm @ 15°1'<> O2.

2 This' ammonia slip rate was selected

by the Applicant i'n the Application for Certification' (AFC).3 The, PDOC

incorporates this rate without any BACT analysis. The PDOC dismisses the nee'd,

to do a BACT analysis on the basis that "the, ammonia emissions are intrinsic to

the operation of the SCR system, which is BACT for NOX. The emissions from a

control device th~t is determined by the District to be BACT are not subject to

BACT'."

Districts Response:

Ammonia is an integral part of the NOx emissions control system when using

SCR. The District has no regulatoryba$is for restricting ammonia slip to 5 ppmv.

Ammonia is not a criteria air contaminant or a ''precLirsor'' as defined in District

" Rule 2201. The ,District's BACT Clearinghouse does not specify an ammonia slip

rate for combustion turbines using S'CR. While ammonia emis$ions may be

restricted as part of a health risk evaluation that determines an unacceptable

health risk from the ammonia to exposed populations, this is ~ot the case with

2 SJVACPD Avenal PDOC p. 7 and PDOC Attachment A.

,3 Avenal Energy AFC, p. '6.2-41.
Avenal Power Center. ·The risk due to ·all· toxic air contaminant emissions,

including 10 ppmv ammonia, ¥Vas found to be not significant.

A high ammonia slip from the turbine wil' not lead to increased PM10 formation in

the atmosphere. The air basin· currently has an excess of ammonia emissions;

therefore lowering ammonia· emissions will not reduce PM formation. This is

demonstrated in the Districts PM2.S plan which does not not rely on ammonia

reductions to reduce PM2.S, but.~ather relies largely on NOx reductions.

You commented that initial ammonia slip rates below 5 ppmv have been

observed on some combustion turbines using SCR. Generally, increased

ammonia injection. rates, and therefore increased ammonia slip rates, are

required to maintain NOx BACT performance levels (2.5 ppmv) as the catalyst

ages. Allowances for operation at the end of the economic life of a control

. technology and for periods of non-steady state operation (including startup and

shutdown which can result in ammonia slip higher than 5 ppmv) are part of a

BACT determination.