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Filename: S:\Word\PERMITS\TSDs\SRP Copper Crossing\V20672.tsd.docx

From: Kale Walch

Date: October 6, 2017

Technical Support Document

Proposed PSD / Title V Permit

Salt River Project Copper Crossing Energy Center Permit # V20672.000

1. BACKGROUND ................................................................................................................................................ 4

1.1 APPLICANT/APPLICATION HISTORY ......................................................................................................................... 4 1.2 ATTAINMENT CLASSIFICATION ............................................................................................................................... 5 1.3 PERMITTING HISTORY .......................................................................................................................................... 5 1.4 COMPLIANCE/ENFORCEMENT HISTORY ................................................................................................................... 5

2. PROCESS DESCRIPTION................................................................................................................................... 5

2.1 GENERAL PROCESS .............................................................................................................................................. 5 2.2 CAPTURE AND CONTROL ...................................................................................................................................... 6 2.3 PROCESS CHANGES ............................................................................................................................................. 6

3. EMISSIONS ..................................................................................................................................................... 6

3.1 GENERAL METHODOLOGY .................................................................................................................................... 6 3.1.1 NSR Pollutants........................................................................................................................................ 7 3.1.2 Hazardous Air Pollutant (HAP) emissions .............................................................................................. 8 3.1.3 Greenhouse Gas Emissions .................................................................................................................... 9

3.2 POTENTIAL/ALLOWABLE EMISSIONS ....................................................................................................................... 9 3.3 CHANGES IN EMISSIONS ..................................................................................................................................... 11

4. REGULATORY REQUIREMENTS AND MONITORING ...................................................................................... 11

4.1 TITLE V/PSD/NNSR APPLICABILITY ................................................................................................................... 11 4.1.1 Title V ................................................................................................................................................... 11 4.1.2 PSD/NNSR ............................................................................................................................................ 11

4.2 NONATTAINMENT AREA REQUIREMENTS ............................................................................................................... 13 4.3 BEST AVAILABLE CONTROL TECHNOLOGY (BACT) ................................................................................................... 13

4.3.1 Combustion Turbine PM/PM2.5 BACT Analysis ................................................................................... 14 4.3.2 Combustion Turbine NOx BACT Analysis .............................................................................................. 14 4.3.3 Combustion Turbines CO and VOC BACT Analysis ................................................................................ 14 4.3.4 Combustion Turbine GHG BACT Analysis ............................................................................................. 14 4.3.5 Wet Surface Air Coolers (WASAC) and Cooling Tower PM/PM2.5 BACT Analysis ............................... 15 4.3.6 Cooling Tower VOC BACT Analysis ....................................................................................................... 15 4.3.7 Equipment Leaks VOC and GHC BACT Analysis .................................................................................... 15 4.3.8 Fire Pump Engine BACT Analysis .......................................................................................................... 15 4.3.9 Diesel Fuel Storage Tank VOC BACT Analysis ....................................................................................... 15 4.3.10 Circuit Breaker GHC BACT Analysis ...................................................................................................... 15

4.4 REGULATORY EMISSION LIMITATIONS AND COMPLIANCE/MONITORING ...................................................................... 16 4.4.1 Opacity ................................................................................................................................................. 18 4.4.2 Particulate Matter - Weight Rate Equation ......................................................................................... 18 4.4.3 Emission Caps and Recordkeeping ....................................................................................................... 19 4.4.4 Compliance Assurance Monitoring (CAM) ........................................................................................... 19 4.4.5 Testing Requirements .......................................................................................................................... 20

4.5 NAAQS AND CLASS II PSD INCREMENT CONSUMPTION ANALYSES ............................................................................ 20 4.6 CLASS I PSD INCREMENT CONSUMPTION ANALYSIS ................................................................................................. 22 4.7 NSPS/NESHAP APPLICABILITY .......................................................................................................................... 23

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4.8 NON-APPLICABLE REQUIREMENTS ....................................................................................................................... 24 4.8.1 SIP limitations ...................................................................................................................................... 24 4.8.2 HAP limitations .................................................................................................................................... 24

5. DISPERSION MODELING AND IMPACT ANALYSIS .......................................................................................... 24

5.1 AMBIENT AIR QUALITY ANALYSIS ......................................................................................................................... 24 5.2 OZONE IMPACT ANALYSIS ................................................................................................................................... 24 5.3 CLASS I AND CLASS II VISIBILITY IMPAIRMENT ANALYSIS ........................................................................................... 25 5.4 CLASS I DEPOSITION ANALYSIS ............................................................................................................................ 26 5.5 SOILS ANALYSIS ................................................................................................................................................ 26 5.6 VEGETATION ANALYSIS ...................................................................................................................................... 27 5.6 GROWTH IMPACT ANALYSIS ................................................................................................................................ 28

6. OTHER FEDERAL REQUIREMENTS ............................................................................................................. 28

6.1 ENDANGERED SPECIES ACT (ESA) ........................................................................................................................ 28 6.2 NATIONAL HISTORIC PRESERVATION ACT (NHPA) .................................................................................................. 29

7. LIST OF ABBREVIATIONS ............................................................................................................................... 30

APPENDIX A - BACT ANALYSIS .............................................................................................................................. 31

A.1 BACT APPLICABILITY ................................................................................................................................. 33 A.2 BACT GENERAL APPROACH ...................................................................................................................... 33

A.2.1 Best Available Control Technology Definition ......................................................................... 33 A.2.2 Methodology for the BACT Analysis .......................................................................................... 34 A.2.3 Basic Purpose and Design of the CCEC Project .................................................................... 35 A.2.4 BACT Baseline ................................................................................................................................. 35 A.2.5 Available Control Strategies ........................................................................................................ 36 A.2.6 BACT Technical Feasibility Criteria............................................................................................ 36

A.3 COMBUSTION TURBINES PM/PM2.5 BACT ANALYSES ............................................................................ 37 A.3.1 PM/PM2.5 BACT Baseline ............................................................................................................. 38 A.3.2 Step 1 – Identify Available Control Options ............................................................................. 38 A.3.3 Step 2 – Eliminate Technically Infeasible Options ................................................................. 38 A.3.4 Step 3 – Rank Control Options .................................................................................................... 38 A.3.5 Step 4 – Evaluate Feasible Control Options ............................................................................ 39 A.3.6 Step 5 – Establish BACT ............................................................................................................... 39

A.4 COMBUSTION TURBINES NOX BACT ANALYSES ...................................................................................... 40 A.4.1 NOx BACT Baseline ....................................................................................................................... 41 A.4.2 Step 1 – Identify Available Control Options ............................................................................. 41 A.4.3 Step 2 – Eliminate Technically Infeasible Options ................................................................. 47 A.4.4 Step 3 – Rank Control Options .................................................................................................... 47 A.4.5 Step 4 – Evaluate Feasible Control Options ............................................................................ 48 A.4.6 Step 5 – Establish BACT ............................................................................................................... 48

A.5 COMBUSTION TURBINES CO AND VOC BACT ANALYSIS ........................................................................ 49 A.5.1 CO and VOC BACT Baseline ........................................................................................................ 50 A.5.2 Step 1 – Identify Available Control Options ............................................................................. 50 A.5.3 Step 2 – Eliminate Technically Infeasible Options ................................................................. 51 A.5.4 Step 3 – Rank Control Options .................................................................................................... 51 A.5.5 Step 4 – Evaluate Feasible Control Options ............................................................................ 51 A.5.6 Step 5 – Establish BACT ............................................................................................................... 51

A.6 COMBUSTION TURBINES GHG BACT ANALYSIS ...................................................................................... 52 A.6.1 GHGs BACT Baseline .................................................................................................................... 53 A.6.2 Step 1 – Identify Available Control Options ............................................................................. 54 A.6.3 Step 2 – Eliminate Technically Infeasible Options ................................................................. 69

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A.6.4 Step 3 – Rank Control Options .................................................................................................... 72 A.6.5 Step 4 – Evaluate Feasible Control Options ............................................................................ 73 A.6.6 Step 5 – Establish BACT ............................................................................................................... 77

A.7 WET SURFACE AIR COOLERS AND COOLING TOWER PM/PM2.5 BACT ANALYSIS ............................... 80 A.7.1 PM/PM2.5 BACT Baseline ............................................................................................................. 80 A.7.2 Step 1 – Identify Available Control Options ............................................................................. 80 A.7.3 Step 2 – Eliminate Technically Infeasible Options ................................................................. 81 A.7.4 Step 3 – Rank Control Options .................................................................................................... 82 A.7.5 Step 4 – Evaluate Feasible Control Options ............................................................................ 82 A.7.6 Step 5 – Establish BACT ............................................................................................................... 83

A.8 COOLING TOWER VOC BACT ANALYSIS .................................................................................................. 83 A.8.1 VOC BACT Baseline ....................................................................................................................... 83 A.8.2 Steps 1 – 5 ........................................................................................................................................ 83

A.9 EQUIPMENT LEAKS VOC AND GHG BACT ANALYSIS.............................................................................. 84 A.9.1 VOC and GHG BACT Baseline ..................................................................................................... 84 A.9.2 Step 1 – Identify Available Control Options ............................................................................. 84 A.9.3 Step 2 – Eliminate Technically Infeasible Options ................................................................. 84 A.9.4 Step 3 – Rank Control Options .................................................................................................... 84 A.9.5 Step 4 – Evaluate Feasible Control Options ............................................................................ 85 A.9.6 Step 5 – Establish BACT ............................................................................................................... 85

A.10 FIRE PUMP ENGINE BACT ANALYSES ................................................................................................... 86 A.10.1 Fire Pump NOx and VOC BACT Analysis ............................................................................. 86 A.10.2 Fire Pump CO BACT Analysis ................................................................................................. 88 A.10.3 Fire Pump PM/PM2.5 BACT Analysis ..................................................................................... 89 A.10.4 Fire Pump GHG BACT Analysis .............................................................................................. 89

A.11 DIESEL FUEL STORAGE TANK VOC BACT ANALYSIS .......................................................................... 90 A.11.1 VOC BACT Baseline ....................................................................................................................... 90 A.11.2 Step 1 – Identify Available Control Options ............................................................................. 90 A.11.3 Step 2 – Eliminate Technically Infeasible Control Options .................................................. 91 A.11.4 Step 3 – Rank Feasible Control Options ................................................................................... 91 A.11.5 Step 4 – Evaluate Feasible Control Options ............................................................................ 91 A.11.6 Step 5 – Establish BACT ............................................................................................................... 91

A.12 CIRCUIT BREAKERS GHG BACT ANALYSIS ......................................................................................... 92 A.12.1 GHG BACT Baseline ................................................................................................................... 92 A.12.2 Step 1 – Identify Available Control Options ......................................................................... 92 A.12.3 Step 2 – Eliminate Technically Infeasible Control Options .............................................. 92 A.12.4 Step 3 – Rank Feasible Control Options ............................................................................... 93 A.12.5 Step 4 – Evaluate Feasible Control Options ........................................................................ 93 A.12.6 Step 5 – Establish BACT ........................................................................................................... 93

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1. Background

1.1 Applicant/Application History

This permit pertains to a new natural gas power plant, operated by Salt River Project Agricultural

Improvement and Power District (SRP). The SIC Code is 4911. The facility is located on Pinal

County parcel numbers 210-24-001J, 210-24-001M, 210-24-001R, in Florence, Arizona. The

permit is issued under the Pinal County Air Quality Control District (PCAQCD) State

Implementation Plan (SIP) approved authority and under a delegation agreement with the United

States Environmental Protection Agency (EPA). This permit is the initial unitary permit for the

facility and includes Prevention of Significant Deterioration (PSD) construction provisions, Clean

Air Act (CAA) Title IV Acid Rain provisions, CAA Title V operating provisions and CAA Title

VI Stratospheric Ozone Protection provisions. This permit also serves as a Greenhouse Gas

(GHG) PSD construction permit pursuant to a 40 CFR 52.21 delegation agreement with (EPA).

This analysis reflects consideration of (at least) the following:

A March 31, 2016 modeling protocol submitted by SRP.

A May 5, 2016 memo from Air Resource Specialist (ARS) to Pinal County Air Quality Control

District (PCAQCD) and sequentially sent to SRP commenting on the modeling protocol.

A May 12, 2016 memo from PCAQCD to SRP commenting on the modeling protocol.

A June 27, 2016 memo from RTP to PCAQCD responding to the modeling protocol comments.

A July 27, 2016 memo from RTP to PCAQCD concerning the use of off-site ambient monitoring

data.

An August 1, 2016 email from Kale Walch with PCAQCD to Barbara Cenalmor with SRP

commenting on the use of off-site ambient monitoring data.

An August 16, 2016 memo from RTP to PCAQCD responding to the off-site ambient monitoring

data comments.

An August 23, 2016 email from Kale Walch with PCAQCD to Barbara Cenalmor with SRP

commenting on the use of off-site ambient monitoring data.

A September 16, 2016 permit application and impact analysis signed by Kevin Nielsen, SRP

Senior Director Valley Generation.

An October 6, 2016 supplement to the application.

An October 10, 2016 memo from PCAQCD to SRP asking clarifying questions on the application

material.

An October 10, 2016 memo from SRP to PCAQCD supplying additional information on the

evaluation of impacts to ozone nonattainment areas.

An October 12, 2016 email from Barbara Cenalmor with SRP to Kale Walch with PCAQCD

clarifying the parcel numbers listed in the permit application.

An October 20, 2016 memo from SRP to PCAQCD responding to a portion of the 10/10/16

questions posed by PCAQCD.

A November 16, 2016 memo from ARS, a contractor for PCAQCD reviewing the modeling files,

asking clarifying questions on the dispersion modeling.

A November 22, 2016 memo from ARS asking clarifying questions on the CALPUFF modeling.

A December 2, 2016 memo from PCAQCD to SRP determining application completeness

occurred on 10/10/16.

A December 7, 2016 memo from ARS asking clarifying questions on the AERMOD modeling.

A December 7, 2016 memo from SRP to PCAQCD responding to the 11/16/16 and 11/22/16

questions.

A December 7, 2016 memo from SRP to PCAQCD responding to the 10/10/16 questions.

A January 12, 2017 memo from ARS asking clarifying questions on the VISCREEN modeling.

A January 20, 2017 memo from ARS providing recommendations concerning the VISCREEN

modeling.

A February 3, 2017 memo from SRP responding to the 1/20/17 VISCREEN recommendations.

A February 16, 2017 email from Kale Walch with PCAQCD to Kristin Watt with SRP asking

CAM and CEM questions.

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A February 16, 2017 email from Kristin Watt with SRP to Kale Walch with PCAQCD responding

to the CAM and CEM questions.

A March 1, 2017 CAM plan submittal from SRP.

A June 2, 2017 email and BACT addendum from Kristin Watt with SRP to Kale Walch with

PCAQCD responding to BACT analysis questions.

1.2 Attainment Classification

The source is situated in an area classified as moderate non-attainment for PM10 and attainment or

unclassifiable for all other pollutants.

1.3 Permitting History

This permit is the initial unitary permit for the facility and includes Prevention of Significant

Deterioration (PSD) construction provisions, Clean Air Act (CAA) Title IV Acid Rain provisions,

CAA Title V operating provisions and CAA Title VI Stratospheric Ozone Protection provisions.

The project is subject to PSD requirements for carbon monoxide (CO), particulate matter (PM),

particulate matter with aerodynamic diameter less than 2.5 micrometers (PM2.5), volatile organic

compounds (VOC), oxides of nitrogen (NOx), and greenhouse gases (GHGs). The facility will

control emissions using Best Available Control Technology (BACT) including requirements to

use a CO oxidation catalyst to control CO and VOC emissions, and Selective Catalytic Reduction

(SCR) to control NOx emissions from the combustion turbines.

1.4 Compliance/Enforcement History

None, since this is the initial permit.

2. Process Description

2.1 General Process

The facility has up to a nominal 1684 MW generating capacity, provided by two aeroderivative

simple cycle combustion turbine generators and up to six frame simple cycle combustion turbines

that utilize natural gas. The permit allows for construction of one of three potential combinations

of two aeroderivative simple cycle combustion turbine generators and either six GE frame simple

cycle combustion turbines, or six Siemens frame simple cycle combustion turbines, or five

Mitsubishi frame simple cycle combustion turbines.

Ancillary equipment includes three wet surface air coolers (WSAC), a cooling tower, a 220 hp

diesel-fired emergency fire pump, a 500 gallon diesel storage tank, and project associated valves,

pressure relief devices, connectors, and electric circuit breakers.

Heated water/fluid from the frame combustion turbine generators (CTGs) to be cooled flows

through tube bundles in a closed loop system. A large quantity of water from the WSAC basin is

sprayed downward over the tube surfaces. At the same time, fans induce air flow over the bundles

in a co-current direction. The saturated air stream leaving the tube bundles then makes two 90-

degree turns into the WSAC fan plenum. The reduction in air velocity returns most of the large

water droplets to the WSAC basin. The air is then exhausted through the WSAC fan stacks. A

small amount of the water is entrained in the induced air flow in the form of liquid phase droplets

or mist. Demisters are used at the outlet of the exhaust fans to reduce the amount of water droplets

entrained in the air. The water droplets that pass through the demisters and are emitted to the

atmosphere are called drift loss. When these droplets evaporate, the dissolved solids in the droplet

become particulate matter. Therefore, WSACs are sources of PM, PM10, and PM2.5 emissions.

The aeroderivative intercooling system uses a closed loop water system to cool compressed air to

optimal temperatures. The heated water is directed through a cooling tower where circulating

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cooling water, is introduced into the top of the mechanical draft cooling tower. As the water falls

through the tower and over the closed loop tubes, an air flow is induced in a countercurrent flow

using an induced draft fan. A portion of the circulating water evaporates, cooling the remaining

water. A small amount of the water is entrained in the induced air flow in the form of liquid phase

droplets or mist. Demisters are used at the outlet of cooling towers to reduce the amount of water

droplets entrained in the air (drift loss). Therefore, similar to the WSAC units, cooling towers are

sources of PM, PM10, and PM2.5 emissions.

The emergency fire pump will include a compression ignition, reciprocating internal combustion

engine (RICE) to drive the water pump to serve the plant fire emergency needs. The facility will

also include an associated 500 gallon diesel fuel oil storage tank.

A small amount of VOC and GHG emissions from natural gas leaks from piping may occur from

the valves, flanges and connectors. Some of the circuit breakers proposed as part of the project

contain SF6. Fugitive SF6 emissions may occur as a result of leaks from the circuit breakers.

2.2 Capture and Control

Each CTG is designed and operated to incorporate low-NOx combustion operation (water

injection for Aeroderivative units and low-NOx design for Frame units) along with a Selective

Catalytic Reduction (SCR) system utilizing ammonia as a reductant for control of NOx. An

oxidation catalyst is also incorporated into each CTG for the control of CO and VOCs.

The SCR and oxidation catalyst are not operational during startup and shutdown of the CTGs

since the exhaust gas temperatures are too low for these systems to function as designed. During

startup and shutdown water injection is used to reduce NOx emissions from the aeroderivative

units. The earlier that water injection can be initiated during the startup process, the lower NOx

emissions will be during startup. However, if injection is initiated at very low loads, it can impact

flame stability and combustion dynamics, and may increase CO emissions. These concerns must

be carefully balanced when determining when to initiate water injection. During startup and

shutdown a dry low NOx (DLN) combustion system is used for the frame units. The DLN system

is not operational in pre-mix mode and the operation occurs in diffusion flame mode. The earlier

the DLN combustor can achieve lean pre-mix mode during the startup process, the lower NOx

emissions will be during startup.

The normal startup time for the aeroderivative GE LMS100PA+ units is 30 minutes (10 minutes

for the aeroderivative CTG to achieve full capacity and 20 minutes for the SCR to warm up) and

the normal shutdown time is 13 minutes. The normal startup time for the frame GE 7F.05 units is

30 minutes and the normal shutdown time is 13 minutes. The normal startup time for the frame

Siemens SGT6-5000F units is 33 minutes and the normal shutdown time is 18 minutes. The

normal startup time for the frame Mitsubishi M501GAC units is 31 minutes and the normal

shutdown time is 20 minutes. The startup and shutdown potential to emit (PTE) values in the

application and the table below reflect these timelines.

All of the CTGs will include oxidation catalyst control for CO and VOCs. These controls will also

reduce organic HAPs from the CTGs. To be conservative, it was assumed that there will be no

control of HAPs during the CTG startup or shutdown.

2.3 Process Changes


3. Emissions

3.1 General Methodology

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3.1.1 NSR Pollutants

The regulated NSR pollutants emitted by the facility include oxides of nitrogen (NOx),

carbon monoxide (CO), volatile organic compounds (VOC), sulfur dioxide (SO2),

particulate matter (PM), particulate matter equal to or less than an aerodynamic diameter

of nominally 10 µm (PM10) and 2.5 µm (PM2.5), sulfuric acid mist (H2SO4), lead (Pb),

and greenhouse gases (GHGs) as carbon dioxide equivalent (CO2e).

The PTE of regulated NSR pollutants for each aeroderivative GE LMS100PA+ CTG are

based on the maximum rated heat input for the combustion turbines of 953 MMBtu per

hour (higher heating value or HHV) for the site conditions at 10 °F ambient temperature.

Maximum emission rates for NOx, CO, and VOC were obtained by the permittee from

GE for the 100% load condition, at site elevation, for 10 °F ambient temperature as noted

in the equipment specifications included in the application. Maximum annual average

sulfur concentration is from the historical fuel specifications for natural gas supply in the

project area. Particulate matter (PM/PM10/PM2.5) emission rate is based on the best

available control technology (BACT) emission limitations.1 Sulfuric acid mist (H2SO4)

emissions are estimated as 10% of the SO2 emissions. Other emission factors are from

U.S. EPA's Compilation of Air Pollutant Emission Factors, AP-42 and 40 CFR Part 98.

The PTE of regulated NSR pollutants for each frame GE 7F.05 CTG are based on the

maximum rated heat input for the combustion turbines of 2,177 MMBtu per hour (HHV)

for the site conditions at 10 °F ambient temperature. Maximum emission rates for NOx,

CO, VOC, and PM/PM10/PM2.5 were obtained from GE for the 100% load condition, at

site elevation, for 10 °F ambient temperature as noted in the equipment specifications

included in the application.

The PTE of regulated NSR pollutants for each frame Siemens SGT6-5000F CTG are

based on the maximum rated heat input for the combustion turbines of 2,386 MMBtu per

hour (HHV) for the site conditions at 10 °F ambient temperature. Maximum emission

rates for NOx, CO, VOC, PM/PM10/PM2.5 were obtained from Siemens for the 100%

load condition, at site elevation, for 59 °F ambient temperature, and for when the

combustion turbines are operating with inlet evaporative coolers as noted in the

equipment specifications included in the application.2

The PTE of regulated NSR pollutants for each frame Mitsubishi M501GAC CTG are

based on the maximum rated heat input for the combustion turbines of 2,788 MMBtu per

hour (HHV) for the site conditions at 10 °F ambient temperature. Maximum emission

rates for NOx, CO, VOC, and PM/PM10/PM2.5 were obtained from Mitsubishi for the

100% load condition, at site elevation, for 10 °F ambient temperature as noted in the

equipment specifications included in the application.

WSAC particulate matter emissions were calculated based on the circulating water flow

rate, the total dissolved solids (TDS) in the circulating water, and the design drift loss

according to the following AP-42 equation:

1 Under the PSD program “PM” indicator is regulated as EPA Method 5 (front half) filterable fraction (77 Fed. Reg.

65107, October 25, 2012). Since limited information is available regarding the filterable and condensable fractions

for various combustion units proposed under the Project, PM emissions rates for combustion units, conservatively,

include both filterable and condensable fractions. PM10 emissions are not subject to PSD BACT since the facility is

located in a PM10 nonattainment area and PM10 emissions are not subject to NNSR since PM10 emissions are

limited to less 100 tpy. 2 Unlike the other frame units, Siemens specifications note maximum mass emission rate occurs at 59 °F when the

turbines are operating with inlet evaporative coolers. However, the peak heat input at 2,386 MMBtu/hour occurs at

10 °F. See Appendix C of the application.

8

𝐸 = 𝑘 ∗ 𝑄 ∗ 60 [𝑚𝑖𝑛

ℎ𝑜𝑢𝑟] ∗ 8.345 [𝑙𝑏

𝐻2𝑂

𝑔𝑎𝑙𝑙𝑜𝑛] ∗ [

𝐶𝑇𝐷𝑆

106] ∗ [

𝐷𝐿

100]

Where, E = Particulate matter emissions, pounds per hour

Q = Circulating water flow rate, gallons per minute

CTDS = Circulating water total dissolved solids, ppm

DL = Drift loss, %

k = Particle size multiplier, PM=1, PM10=0.3150,

PM2.5=0.18903

Cooling tower particulate matter emissions were calculated based on the circulating water

flow rate, TDS in the circulating water, and the design drift loss according to the AP-42

equation described above for the WSAC emissions. The cooling tower will also emit a

small amount of VOCs, in the form of chloroform, from use of chlorine in the

recirculating water. Emission factors for VOC/chloroform were accounted for under the

HAPs calculations for the cooling processes.

The diesel emergency generator emissions calculations utilize vendor data for NOx, CO,

and VOC emissions. The vendor’s PM emissions rate was escalated from 0.12 g/kW-hour

to 0.2 g/kW-hour to account for condensable emissions. SO2 emissions were calculated

assuming 0.0015% sulfur in diesel fuel. Other emission factors are from AP-42 and 40

CFR Part 98. VOC Emissions from the associated 500 gallon diesel fuel oil storage tank

were based a maximum annual throughput of 6,000 gallons per year (based on the

generator being limited to 500 hours per year) and estimated utilizing the U.S. EPA’s

TANKS program, Version 4.0.9d (which is based on the equations from AP-42, Section

7.1, Organic Storage Tanks). For the TANKS run, the breather vent setting was set to

zero assuming no control for the tank.

Fugitive VOC and GHG emissions from valves in gas service, pressure relief valves, and

connectors were estimated using the EPA’s 1995 guidelines for estimating emissions

from equipment leaks.4 A VOC emissions factor was developed as the ratio of methane to

VOCs using EPA’s background document for the proposed standards for the oil and gas

sector.5

3.1.2 Hazardous Air Pollutant (HAP) emissions

Combustion of natural gas in CTGs generates relatively small amounts of HAP

emissions. CTG HAP emissions were calculated for the aeroderivative-frame

combination scenario with maximum annual heat input as worst case. The 6 Siemens

SGT6-5000F scenario represents the worst case heat input for HAPs calculations. For

normal operation heat input, a 70% control efficiency from the oxidation catalyst was

applied for organic HAPs emissions. To be conservative, it was assumed that there will

be no control of HAPs during the CTG startup or shutdown. The HAP emission factors

3 PM10 and PM2.5 emission factors from the TSD for APS Ocotillo Permit No.V95-007, PSD16-01, March 22,

2016, Maricopa County AQD. Maricopa County used the PM10 factor of 0.315 for the majority of power plants in

the County (this factor was developed based on the tests performed at the Gila Bend Power Plant). Maricopa County

used the PM2.5 factor as 0.6 of PM10 based on the PSD permitting for Hydrogen Energy California by San Joaquin

Valley Air Pollution Control District based on the data from the California Emission Inventory Development and

Reporting System database. 4 “Protocol for Equipment Leak Emission Estimates,” U.S. EPA, Emission Standards Division, Office of Air and

Radiation, Office of Air Quality Planning and Standards, Research Triangle Park, North Carolina 27711, November

1995, EPA‐453/R‐95‐017. 5 “Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission,

and Distribution,” U.S. EPA, Sector Policies and Programs Division, Office of Air Quality Planning and Standards,

Research Triangle Park, North Carolina 27711, July 2011, EPA‐453/R‐11‐0002.

9

are from the U.S. EPA's Compilation of Air Pollutant Emission Factors, AP-42, Volume

1: Stationary Point and Area Sources, Section 3.1, Stationary Combustion turbines for

Electricity Generation.

HAP emissions were calculated based on the WSAC and cooling tower drift rates and the

chemical composition of the cooling tower blowdown. It is conservatively assumed that

the entire quantity of each chemical in the blowdown would be emitted. The

concentration of HAPs in the blowdown for the system were provided by the project

engineering support. Chloroform emissions for the WSAC and cooling tower are based

on factors from EPA’s “Locating and Estimating Air Emissions from Sources of

Chloroform” (EPA 1984).6 HAPs emissions are calculated for the two GE LMS100PA+

and 6 Siemens SGT6-5000F CTGs scenario as this case represents the worst case water

recirculation rates resulting in maximum emissions from the cooling systems (WSAC and

Cooling Tower). Diesel fuel combustion in the RICE unit of the fire pump will result in HAP emissions.

These HAP emissions are based on emission factors from the U.S. EPA's Compilation of

Air Pollutant Emission Factors, AP-42, 5th Edition, Tables 3.4-3 and 3.4-4.

3.1.3 Greenhouse Gas Emissions

CO2e was calculated in accordance with 40 CFR §52.21(b)(49)(ii) using the mass

emission rates of six GHGs defined in 40 CFR §52.21(b)(49)(i) and their corresponding

global warming potential (GWP) published in 40 CFR 98, Subpart A, Table A-1. For this

application, Table A-1 GWPs from the July 1, 2015 version of 40 CFR Part 98 were

used.

Fugitive Sulfur Hexafluoride (SF6) emissions may occur as a result of leaks from the

circuit breakers. Circuit breaker SF6 emissions were calculated based on a leak rate of

0.1% per year.7

3.2 Potential/Allowable Emissions

The following tables summarize the controlled PTEs for each operating scenario and provide a

worst case scenario estimate for HAP emissions.

Table 3-1 Controlled PTE for Scenario 1 – 2 GE LMS100PA+ and 6 GE 7F.05

Pollutants Potential to Emit (tons/year)

Simple Cycle Frame Simple Cycle Aero WSAC

*

Cooling

Tower

Fire

Pump

Tank Equip

ment

Leaks

Circu

it

Brea

kers

Total

Normal SU&SD Normal SU&SD

NOx 198.7 55.8 33.6 20.4 0.3 308.8

CO 193.9 593.1 32.5 20.2 0.1 839.8

VOC 27.6 108.0 9.3 4.7 0.03 0.03 0.02 0.0002 0.4 150.3

SO2 22.0 0.6 3.6 0.1 0.001 26.3

6 There is an error in the chloroform emission factor in the report. This noted in Appendix B of the “Bowie Power

Station, Class I Permit Application,” September 2013, as “Personal communication with EPA by Russ Henning,

Radian International. The chloroform emission factor for cooling towers from the L&E document should be 2.3/0.75

kg/E9 liters not E6 liters.” 7 From Electric Power Substation Engineering, 2nd Edition, 2007, Edited by John D. McDonald. "Field checks of

GIS [gas-insulated substations] in service after many years of service indicate that a leak rate objective lower than

0.1% per year is obtainable."

10

PM 68.2 6.8 19.7 2.9 0.3 0.3 0.02 98.2

PM10 68.2 6.8 19.7 2.9 0.1 0.1 0.02 97.7

PM2.5 68.2 6.8 19.7 2.9 0.1 0.1 0.02 97.6

H2SO4 2.20 0.06 0.36 0.01 0.000

1

2.63

Lead 0.01 2.89E-04 0.0018 6.78E-05 3.53E

-06

0.01

CO2 2,573,848 68,610 416,260 16,095 63 3,074,876

CO2e 2,576,575 68,683 416,701 16,112 63 400 48 3,078,582

*WSAC emissions represent worst case for Siemens turbines.

Table 3-2 Controlled PTE for Scenario 2 – 2 GE LMS100PA+ and 6 Siemens SGT6-5000F



* Cooling

Tower Fire

Pump Tank Equip

ment

Leaks

Circu

it

Brea

kers

Total

Normal SU&SD Normal SU&SD

NOx 217.0 96.9 33.6 20.4 0.3 368.2

CO 105.6 823.5 32.5 20.2 0.1 981.9

VOC 30.7 81.3 9.3 4.7 0.03 0.03 0.02 0.0002 0.4 126.6

SO2 22.9 0.7 3.6 0.1 0.001 27.3

PM 68.2 6.8 19.7 2.9 0.3 0.3 0.02 98.2

PM10 68.2 6.8 19.7 2.9 0.1 0.1 0.02 97.7

PM2.5 68.2 6.8 19.7 2.9 0.1 0.1 0.02 97.6

H2SO4 2.29 0.07 0.36 0.01 0.000

1

2.73

Lead 0.0113 0.0003 0.0018 6.78E-

05

3.53E

-06

0.01

CO2 2,680,530 82,686 416,260 16,095 63 3,195,634

CO2e 2,683,370 82,773 416,701 16,112 63 400 48 3,199,468

Table 3-3 Controlled PTE for Scenario 3 – 2 GE LMS100PA+ and 5 Mitsubishi M501GAC



*

Cooling

Tower

Fire

Pump

Tank Equip

ment

Leaks

Circu

it

Brea

kers

Total

Normal SU&S

D

Normal SU&S

D

NOx 219.2 39.4 33.6 20.4 0.3 312.9

CO 106.4 723.4 32.5 20.2 0.1 882.6

VOC 30.4 324.9 9.3 4.7 0.03 0.03 0.02 0.0002 0.4 369.9

SO2 22.3 0.9 3.6 0.1 0.001 26.9

PM 67.2 2.9 19.7 2.9 0.3 0.3 0.02 93.3

PM10 67.2 2.9 19.7 2.9 0.1 0.1 0.02 92.9

PM2.5 67.2 2.9 19.7 2.9 0.1 0.1 0.02 92.8

H2SO4 2.23 0.09 0.36 0.01 0.000

1

2.69

11

Lead 0.0110 0.0004 0.0018 6.78E-

05

3.53E

-06

0.01

CO2 2,609,034 106,564 416,260 16,095 63 3,148,016

CO2e 2,611,798 106,677 416,701 16,112 63 400 48 3,151,800

*WSAC emissions represent worst case for Siemens turbines.

Table 3-4 Uncontrolled and Controlled HAPs*

Pollutants CTGs Cooling System Fire Pump Total

Controlled

HAPs 8.73 0.60 1.5eE03 9.33

Formaldehyde

(max HAP)

6.21 4.56E-04 6.21

Uncontrolled

HAPs 27.12 0.60 1.5E-03 25.72

Formaldehyde

(max HAP)

19.30 4.56E-04 19.30

*Based on scenario #2, Siemens Turbines

3.3 Changes in Emissions


4. Regulatory Requirements and Monitoring

4.1 TITLE V/PSD/NNSR Applicability

4.1.1 Title V

For all three scenarios the PTE of NOx, CO and VOCs exceed the 100 ton per year Title

V trigger. The permit incorporates Title V operating provisions for these pollutants. As

summarized below PM10 emissions are limited to below 100 tons per year for all three

scenarios thus the permit incorporates federally enforceable operating limits for PM10 to

ensure actual PM10 emissions remain below 100 tons.

4.1.2 PSD/NNSR

The PTE of PM10 for the Copper Crossing Energy Center (CCEC) facility is limited to

less than 100 tons per year in all three scenarios via federally enforceable limits on hours

of operation and the number of startups and shutdowns. Therefore, the nonattainment

New Source Review (NNSR) requirements are not applicable to the proposed facility.

For all three scenarios, the PTE of NOx and CO from the project exceeds 250 tons per

year. (In the case of Scenario 3, VOC emissions also exceed that threshold, but this fact

does not affect applicability.) Therefore, the proposed Project is a new major source for

PSD. PSD requirements apply to emissions of NOx, CO, VOC, PM, and PM2.5 from the

project as the PTE of these regulated NSR pollutants exceed the significant emission

rates. As noted above since the facility is located in a PM10 nonattainment area and since

PM10 emissions are limited to less than 100 tons per year via federally enforceable

operating limits neither PSD nor NNSR provisions apply to PM10.8 The CO2e emissions

from the Project exceed the emission rate in 40 CFR §52.21(b)(49)(iv)(a) of 75,000 tons

8 See PCAQCD Code §§3-3-250.B and 3-3-203.2

12

per year. Since the project will be a new major stationary source for non-GHGs and the

PTE of GHG on a mass basis is greater than or equal to the significant level of “any

emissions rate,” GHGs will also be subject to BACT.

Tables 4-1 thru 4-3 summarize the PSD applicability of the facility.

Table 4-1 NNSR & PSD Applicability for Scenario 1 - 2 CT LMS100+6 GE 7F.05

Pollutant PTE

(tons/year)

Major Source

Threshold

(tons/year)

Whether

Major?

Significant

Emission Rate

(tons/year)

For PSD

Whether

Significant?

NOx 308.8 250 Yes 40 Yes

CO 839.8 250 Yes 100 Yes

VOC 150.3 250 No 40 Yes

SO2 26.3 250 No 40 No

PM 98.2 250 No 25 Yes

PM10 97.7 100 No NA NA

PM2.5 97.6 250 No 10 Yes

H2SO4 2.63 250 No 7 No

Lead 0.01 250 No 0.6 No

CO2e 3,078,582 -NA- -NA- 75,000 Yes*

*Determination whether GHGs are “subject to regulation.”

Table 4-2 NNSR & PSD Applicability for Scenario 2 - 2 CT LMS100+6 Siemens SGT6-5000F

Pollutant PTE

(tons/year)

Major Source

Threshold

(tons/year)

Whether

Major?

Significant

Emission Rate

(tons/year)

For PSD

Whether

Significant?

NOx 368.2 250 Yes 40 Yes

CO 981.9 250 Yes 100 Yes

VOC 126.6 250 No 40 Yes

SO2 27.3 250 No 40 No

PM 98.2 250 No 25 Yes

PM10 97.7 100 No NA NA

PM2.5 97.6 250 No 10 Yes

H2SO4 2.73 250 No 7 No

Lead 0.01 250 No 0.6 No

CO2e 3,199,468 -NA- -NA- 75,000 Yes*


Table 4-3 NNSR &PSD Applicability for Scenario 3 - 2 CT LMS100+5 Mitsubishi M501GAC

Pollutant PTE

(tons/year)

Major Source

Threshold

(tons/year)

Whether

Major?

Significant

Emission Rate

(tons/year)

For PSD

Whether

Significant?

NOx 312.9 250 Yes 40 Yes

CO 882.6 250 Yes 100 Yes

VOC 369.9 250 Yes 40 Yes

SO2 26.9 250 No 40 No

PM 93.3 250 No 25 Yes

PM10 92.9 100 No NA NA

PM2.5 92.8 250 No 10 Yes

H2SO4 2.69 250 No 7 No

Lead 0.01 250 No 0.6 No

13

Pollutant PTE

(tons/year)

Major Source

Threshold

(tons/year)

Whether

Major?

Significant

Emission Rate

(tons/year)

For PSD

Whether

Significant?

CO2e 3,151,800 -NA- -NA- 75,000 Yes**


4.2 Nonattainment Area Requirements

Since the facility is located in the West Pinal PM10 nonattainment area the permit incorporates the

open area / vacant lot stabilization requirements of PCAQCD Code Chapter 4, Article 1. A

January 9, 2017 Federal Register notice, 80 FR 2305, proposed to approve adoption of this rule

into the nonattainment area SIP and accept comments. EPA has not yet taken final action on the

proposal.

4.3 Best Available Control Technology (BACT)

The project is subject to PSD review, or major, for NOx, CO, VOC, PM, PM2.5, and GHGs. A

new major source must apply BACT for each conventional air pollutant for which the potential to

emit is significant. In this case, BACT is applicable to all of the newly constructed units that have

the potential to emit NOx, CO, VOC, PM/PM2.5, or GHGs in any amount. Table 4-4 summarizes

the units subject to BACT review on a pollutant basis.

Table 4-4 Unit-Pollutant Combinations Subject to BACT Review

Unit Description PM/PM2.5 NOx CO VOC GHGs

Simple Cycle Combustion turbines X X X X X

Wet Surface Air Coolers X X

Cooling Tower X X

Natural Gas Supply Equipment X X

Emergency Fire Pump Engine X X X X X

Diesel Fuel Storage Tank X

Circuit Breakers X

The purpose of the BACT analysis is to identify the best available technology for controlling

emissions that is achievable while taking into account energy, environmental, and economic

impacts and other costs. Below are the five basic steps of a top-down BACT review as identified

by the EPA:

Step 1. Identify all control technologies

Step 2. Eliminate technically infeasible options

Step 3. Rank remaining control technologies by control effectiveness

Step 4. Evaluate most effective controls and document results

Step 5. Select BACT

The minimum control to be considered BACT must not result in emissions of any pollutant in

excess of any emissions limit set forth in any applicable New Source Performance Standard

(NSPS). After determining whether any NSPS is applicable, the first step in this approach is to

determine, for the emission unit in question, the most stringent control available for a similar or

identical source or source category. If this level of control is determined by PCAQCD to be

technically infeasible for the unit in question, then the next most stringent level of control is

determined and similarly evaluated. This process continues until the BACT level under

consideration is not eliminated by PCAQCD based on consideration and weighing of energy,

environmental, and economic impacts and other costs.

14

Appendix A of this document provides the BACT analysis as proposed by the applicant. Tables 4-

5 and 4-7 identify the BACT limits that are incorporated into the permit based on the BACT

determinations made by PCAQCD. Under the top down approach the applicant must identify and

prioritize all available control strategies, ranking the most stringent or top control strategy first.

That alternative is established as BACT unless the applicant demonstrates and the permitting

authority in its informed judgment agrees that technical considerations, energy, environmental or

economic impacts justify a conclusion that the most stringent technology is not achievable in that

case. If the most stringent technology is eliminated in this fashion then the next most stringent

alternative is considered. The following sections constitutes a summary of PCAQCD’s review of

the applicant’s submitted BACT analysis.

4.3.1 Combustion Turbine PM/PM2.5 BACT Analysis

PCAQCD’s review of the applicant’s 5-step analysis, of the RACT/BACT/LAER

Clearing house database (RBLC) and of other recent combustion turbine permits supports

establishing the PM/PM2.5 BACT limits listed in Table 4-5 for normal operation and

start-up/shutdown. The listed pound/hour limits for normal operation and listed limits for

the annual number of start-up/shutdown events sufficiently demonstrates BACT.

4.3.2 Combustion Turbine NOx BACT Analysis

PCAQCD’s review of the applicant’s 5-step analysis, of the RBLC and of other recent

combustion turbine permits supports establishing the NOx BACT limits listed in Table 4-

5 for normal operation and start-up/shutdown. The listed ppmvd limit for normal

operation is below the applicable NSPS and is equivalent to the known most restrictive 1-

hour BACT limit for normal operations. The listed pound per event limits for startups and

shutdowns sufficiently demonstrates BACT.

The chosen control technology of Dry Low-NOx (DLN) combustors in combination with

Selective Catalytic Reduction (SCR) on the frame combustion turbines and water

injection in combination SCR on the aeroderivative combustion turbines represents the

most effective, demonstrated technically feasible control strategy for the proposed

turbines. The primary potential adverse environmental impact associated with SCR is

ammonia slip which could contribute to increased measured particulate mass emissions.

This is mitigated by a locally enforceable permit condition that limits ammonia emissions

during normal operations and is assessed via annual stack test.

4.3.3 Combustion Turbines CO and VOC BACT Analysis


combustion turbine permits supports establishing the CO and VOC BACT limits listed in

Table 4-5 for normal operation and start-up/shutdown. The listed ppmvd limits for

normal operation are equivalent to known most restrictive BACT limits established for

each type of combustion turbine. The listed limits for the annual number of start-

up/shutdown events sufficiently demonstrates BACT.

The chosen control technology of an oxidation catalyst in combination with DLN

combustors and good combustion practices for the frame turbines and an oxidation

catalyst in combination with good combustion practices for the aeroderivative turbines is

the top-performing feasible CO and VOC control strategy for each turbine type.

4.3.4 Combustion Turbine GHG BACT Analysis


combustion turbine permits supports establishing the GHG BACT limits listed in Table

4-5 for all load ranges of the CTGs.

15

The rolling 12-month average CO2e limits assessed on a unit specific basis via a

Continuous Emission Monitor (CEM) is consistent with the majority of recent turbine

GHG BACT emission limits, including one recently issued in a neighboring jurisdiction.

The CO2e emission rate limits are within the range of recent simple cycle GHG BACT

determinations. Given the purpose of the project is provide quick response peaking power

the analysis supports utilizing efficient simple cycle natural gas combustion turbines.

4.3.5 Wet Surface Air Coolers (WASAC) and Cooling Tower PM/PM2.5 BACT Analysis


combustion turbine permits supports establishing the design requirements listed in Table

4-5 for WASACs and the cooling tower.

Application of the chosen control technology, installation of drift eliminators with a

maximum drift rate specification of 0.0005 percent or less, is consistent with the most

stringent recently established PM/PM2.5 BACT limit identified. The choice to not also

limit Total Dissolved Solids (TDS) is supported since PM2.5 (and PM10) would not be

reduced in measurable amounts and a substantial water usage increase would result.

4.3.6 Cooling Tower VOC BACT Analysis


combustion turbine permits supports not establishing design requirements or a VOC

BACT limit for the cooling tower. Given the Cooling Tower’s VOC PTE of 0.06 tons per

year and the lack of known control strategies a technically nor economically feasible

alternative was identified.

4.3.7 Equipment Leaks VOC and GHC BACT Analysis

PCAQCD’s review of the applicant’s 5-step analysis and of other recent combustion

turbine permits supports not establishing design requirements, a VOC BACT limit or a

GHG BACT limit for equipment leaks. While a technically feasible option, a leak

detection and repair (LDAR) program, was identified, it was concluded that the

associated cost resulted in an unreasonable economic impact. Given the VOC PTE of

0.44 tons per year and the GHG PTE of 16.02 tons per year an economically feasible

alternative was not identified.

4.3.8 Fire Pump Engine BACT Analysis

PCAQCD’s review of the applicant’s 5-step analysis supports establishing the NOx,

VOC, CO, PM/PM2.5 and GHG BACT design requirements listed in Table 4-7. The

listed design requirements are equivalent to the applicable NSPS and no additional

economically feasible alternatives were identified.

4.3.9 Diesel Fuel Storage Tank VOC BACT Analysis

PCAQCD’s review of the applicant’s 5-step analysis supports establishing the VOC

BACT design requirements listed in Table 4-7. The listed design requirements

sufficiently demonstrates BACT and no additional economically feasible alternatives

were identified.

4.3.10 Circuit Breaker GHC BACT Analysis

PCAQCD’s review of the applicant’s 5-step analysis and of other recent combustion

turbine permits supports establishing the GHG BACT design requirements listed in Table

16

4-7. The proposed limit is consistent with recently established GHG BACT limits for

similar equipment.

4.4 Regulatory Emission Limitations and Compliance/Monitoring

Tables 4-5 and 4-7 summarize the facility wide limits (BACT, NSPS and permit imposed) and the

associated compliance methodologies. Limits that have been determined to demonstrate BACT are

noted as such. Table 4-6 summarizes performance indicators.

Table 4-5 Summary of CTG Limits

Pollutant Mode of

Operation

Limit Unit Timeframe Compliance Methodology

PM/PM10/PM

2.5

Normal 5.3 lb/hr

(BACT)

GE LMS100 PA 3-test average for the most

recent performance test

EPA Methods 5, 201A, 202

Normal 7.1 lb/hr

(BACT)

GE 7F.05 Frame 3-test average for the most



Normal 5.3 lb/hr

(BACT)

Siemens SGT6-

5000F

3-test average for the most



Normal 8.0 lb/hr

(BACT)

Mitsubishi

M501GAC1




PM/PM10/PM

2.5

Normal 3734 hours GE LMS100 PA Per calendar year Records

Normal 3200 hours GE 7F.05 Frame Per calendar year Records

Normal 3200 hours Siemens SGT6-

5000F

Per calendar year Records

Normal 3200 hours Mitsubishi

M501GAC1


NOx – BACT Normal 2.5 ppmvd

(BACT)

All CEMS 1-hour average RATA

Start-up 21.9 lbs

(BACT)

GE LMS100 PA CEMs per event RATA

Start-up 44.0 lbs

(BACT)

GE 7F.05 Frame CEMs per event RATA

Start-up 63.3 lbs

(BACT)

Siemens SGT6-

5000F

CEMs per event RATA

Start-up 28.7 lbs

(BACT)

Mitsubishi

M501GAC1

CEMs per event RATA

Shutdown 6.0 lbs

(BACT)

GE LMS100 PA CEMs per event RATA

Shutdown 18.0 lbs

(BACT)

GE 7F.05 Frame CEMs per event RATA

Shutdown 44.4 lbs

(BACT)

Siemens SGT6-

5000F

CEMs per event RATA

Shutdown 23.8 ppm

(BACT)

Mitsubishi

M501GAC1

CEMs per event RATA

NOx –NSPS Normal 15 ppmvd All CEMs 4-hour rolling

average

RATA

<75% load 96 ppm All CEMs 4-hour rolling

average

RATA

CO Normal 4.0 ppmvd

(BACT)

All 3-test average for the most


EPA Method 10

VOC Normal 2.0 ppmvd

(BACT)

GE LMS100 PA 3-test average for the most


EPA Method 25A

17

* Limit for each CTG calculated as the product of its “design efficiency” and “potential electric output” as those

terms are defined at 40 CFR § 60.5580.

Table 4-6 Summary of performance indicators

Table 4-7 Summary of Ancillary Equipment Limits and Design Requirements

Normal 1.2 ppmvd

(BACT)

GE 7F.05 Frame 3-test average for the most


EPA Method 25A

Normal 2.0 ppmvd

(BACT)

Siemens SGT6-

5000F



EPA Method 25A

Normal 1.2 ppmvd

(BACT)

Mitsubishi

M501GAC1



EPA Method 25A

CO2e All 1,434

lb/MWhgross

(BACT)

GE LMS100 PA CEMs 12-month rolling

average

RATA

All 1,317

lb/MWhgross

(BACT)

GE 7F.05 Frame CEMs 12-month rolling

average

RATA

All 1,434

lb/MWhgross

(BACT)

Siemens SGT6-

5000F

CEMs 12-month rolling

average

RATA

All 1,317

lb/MWhgross

(BACT)

Mitsubishi

M501GAC1

CEMs 12-month rolling

average

RATA

PM/PM10/PM

2.5, VOC, CO

Start-up &

Shutdown

730 cycles

(BACT)

GE LMS100 PA Per calendar year Records

300 cycles

(BACT)

GE 7F.05 Frame Per calendar year Records

300 cycles

(BACT)

Siemens SGT6-

5000F


300 cycles

(BACT)

Mitsubishi

M501GAC1


Ammonia Normal 10 ppmvd

All 3-test average for the most


EPA Method 320 or EPA

CTM-027 or Bay Area ST-

1B

Formaldehyde All <10 tons All Per year EPA Methods 320 or 323

Net Electric

Sales

All TBD* All 3 calendar year rolling

average

Records

Pollutant Mode of

Operation

Limit Unit Timeframe Compliance Methodology

Inlet

temperature

All TBD Oxidation Catalyst TBD Annual Calibration

Pollutant Limit Timeframe Compliance Methodology

Emergency Generator

NMHC+NOX 4.0 g/KW-hr (3.0 g/HP-hr)

(BACT)

N/A Manufacturer design parameter

CO 3.5 g/KW-hr (2.6 g/HP-hr)

(BACT)


18

4.4.1 Opacity

Any plume not subject to a NSPS or PCAQCD Code Chapter 5 standard is subject to a

20% opacity limit. The only items that are not subject to the 20% limit are stationary

rotating machinery, which shall not exceed 40% for longer than 10 consecutive seconds.

4.4.2 Particulate Matter - Weight Rate Equation

For each combustion turbine or fire pump with a heat input capacity of 4,200 million Btu

or less per hour, particulate emissions shall not exceed:

E = 1.02Q0.769, where E = maximum emissions in lbs/hr for each million BTU per hour

heat input, and Q = maximum heat input capacity in million BTU per hour.

Aeroderivative GE LMS100PA CTG

E = 199.3 lbs/hr = (1.02)953 MMBtu per hour0.769

The GE LMS100PA BACT limit and associated compliance demonstration of 5.3 lb/hr is

more restrictive

Frame GE 7F.05 CTG

E= 376.2 lbs /hr = (1.02)2,177 MMBtu per hour0.769

The GE 7F.05 BACT limit and associated compliance demonstration of 7.1 lb/hr is more

restrictive

Frame Siemens SGT6-5000F CTG


The Siemens SGT6-5000F BACT limit and associated compliance demonstration of 5.3

lb/hr is more restrictive

PM 0.2 g/KW-hr (0.15 g/HP-hr)

(BACT)


All 500 hours total

100 hours testing (BACT)

50 hours non-emergency


CO2e 163.6 lb/MMBtu

(BACT)

12-month rolling average Records

SO2 Diesel sulfur limits of ≤0.90 %

by weight and ≤15 ppm

and

a minimum cetane index of 40

or a maximum aromatic

content of 35 volume percent

N/A Fuel Supplier Certification

SO2 1.0 lb/MMBtu N/A Manufacturer design parameter

WSAC and Cooling Tower

PM/PM10/PM2.5 Drift eliminators with a

maximum drift loss of

0.0005% or less

(BACT)


Circuit Breakers

CO2e SF6 leak detection system and

Leak rate ≤0.5%

(BACT)

Per calendar year Manufacturer design parameter

and records

Diesel Storage Tank

VOC Fixed Roof

(BACT)


19

Frame Mitsubishi M501GAC CTG


The Mitsubishi M501GAC BACT limit and associated compliance demonstration of 8.0

lb/hr is more restrictive

Diesel Emergency Fire Pump

1.55 MMBtu per hour

E= 1.43 lbs /hr = (1.02)1.55 MMBtu per hour0.769

The emergency fire pump PM emission rate of 0.07 lb/hr (Table 3-18 of the application)

demonstrates compliance

4.4.3 Emission Caps and Recordkeeping

Table 4-7 summarizes the facility wide emission caps listed in the permit and the

associated compliance methodology.

Table 4-7 Facility Wide Emission Caps

4.4.4 Compliance Assurance Monitoring (CAM)

CAM applies to individual emission units located at a Title V source that have a pollutant

specific emission limit, utilize an add-on control device to meet the limit, and have a pre-

controlled PTE greater than 100 tpy on an emission unit basis.

Each CTG emission unit has the potential to be subject to CAM requirements for NOx,

CO and VOC since the units utilize add-on control devices for these pollutants and have

emission limits or standards for these pollutants. The NOx emission limitations imposed

by NSPS KKKK, by the Acid Rain Program, and as BACT are monitored by a CEMS

and are specifically exempted from CAM under 40 CFR 64.2(b).

As shown in Table 4-8, each CTG emission unit has a pre-controlled CO PTE over 100

tpy. Thus the CAM requirements apply to each CTG for CO. Only the Mitsubishi CTG

emission units have a pre-controlled VOC PTE over 100 tpy. Thus the CAM

requirements only apply to the Mitsubishi CTG units for VOC.

The permit requires a temperature monitoring system at the inlet of the oxidation catalyst

via 40 CFR Part 64. The oxidation catalyst inlet temperature monitoring system satisfies

the CAM requirements for CO and if needed VOCs. Since the oxidation catalyst reduces

both CO and VOCs monitoring the effectiveness of the CO control is a suitable surrogate

for also determining the effectiveness of VOC control.

Table 4-8 Uncontrolled CO and VOC PTE for CAM Applicability

Parameter GE

LMS100PA

GE 7F.05 Siemens

SGT6-5000F

Mitsubishi

M501GAC

Pollutant Limit Timeframe Compliance Methodology

PM10 99.9 tons Rolling 12-month total Monthly rolling 12-month

report

Individual

HAP

9.9 tons Per calendar year Semi-annual report

Cumulative

HAPs

24.9 tons Per calendar year Semi-annual report

20

GTG Operation (hours/year) 3734 3200 3200 3200

Oxidation Catalyst Control Efficiency 90% 90% 90% 90%

CO Max Rate (Controlled)(lb/hr) 8.7 20.7 11.0 13.3

CO Max Rate (Uncontrolled)(lb/hr) 87 207 110 133

CO Emissions SU&SD (tons/year) 10.1 98.9 137.3 144.7

CO PTE (Uncontrolled)(tons/year) 173 430 313 358

VOC Max Rate (Controlled)(lb/hr) 2.5 2.9 3.2 3.8

VOC Max Rate (Uncontrolled)(lb/hr) 25 29 32 38

VOC Emissions SU&SD (tons/year) 2.4 18 13.5 65

VOC PTE (Uncontrolled)(tons/year) 49 64 65 126

4.4.5 Testing Requirements

Table 4-9 summarizes the testing and quality assurance audits required by the permit.

Pollutants that are monitored by a CEMS, NOx and CO2, are required to perform relative

accuracy test audits in lieu of stack testing.

The PM, VOC, SO2 and formaldehyde testing regime is designed to confirm assertions

set forth in the initial application and to maintain updated emission factors moving

forward. Formaldehyde is the only HAP required to be quantified during testing since the

application demonstrates formaldehyde comprises approximately 71% of the HAPs

estimated for the facility. The periodic formaldehyde testing is sufficient to demonstrate

compliance with the cumulative and individual HAP caps.

The annual ammonia slip test is a measurement of compliance with the ammonia limit.

The design efficiency test is required by NSPS 40 CFR Part 60 Subpart TTTT.

Table 4-9 Performance Testing and Audits

4.5 NAAQS and Class II PSD Increment Consumption Analyses

Emissions from the proposed project were modeled in accordance with the modeling protocol. The

resulting ambient impacts were compared with the Class II significant impact levels (SILs). If the

maximum ambient impacts from the project was below the particular SIL, the project was

presumed to neither cause nor contribute to a violation of the NAAQS or PSD increment for that

Pollutant or

Parameter

Method Timeframe

NOx RATA Annually (see permit for

possible extension)

CO Method 10 Annually

CO2 RATA Annually (see permit for

possible extension)

PM/PM10/PM2.5 Method 5, 201A, 202 Initial and every 60 months

VOC Method 25A Initial and every 60 months

HAP (formaldehyde) Method 320 or 323 Initial and every 60 months

Opacity Method 9 Initial and every 60 months

Design Efficiency ASME PTC 22, ASME PTC 46 or ISO 2314 Initial

Ammonia Method CTM-027 or Bay Area Air Quality Management

District Source Test Procedure ST-1B or EPA Method 320

Every 12 months

SO2 (fuel sulfur) ASTM D1072-80, 90, D3246-81, 92, 96 or D6667-01 Annually

21

pollutant. Pollutants with impacts that exceeded the SIL, were analyzed further in both the

NAAQS and increment analyses.

The initial application as submitted on 9/16/16 showed the 1-hour NO2 and 24-hour PM2.5

modeled impacts to be above the SILs and also showed the 1-hour NO2 modeled impact to be

above the NAAQS. All other modeled concentrations demonstrated impacts less than the

applicable SILs.

PCAQCD’s review of the NO2 modeling found that the 1-hour NO2 modeled concentration was

heavily influenced by an offsite emergency generator. PCAQCD requested that the NO2 impact be

modeled without the offsite emergency generator as allowed under EPA guidance and the

approved modeling protocol. The revised modeled NO2 impact as submitted on 12/7/16

demonstrated the 1-hour NO2 NAAQS was not exceeded. While the revised 1-hour NO2 modeled

impact was above the SIL there is no 1-hour NO2 increment so further analysis beyond the

NAAQS assessment was not required. The modeled annual NO2 concentration was below the SIL

thus no further analysis was required in relation to the annual NO2 NAAQS

The modeled 24-hour PM2.5 concentration was above the SIL for the GE 7F.05 and Mitsubishi

M501 scenarios.9 The Siemens STG6 scenario modeled 24-hour concentration demonstrated

impacts less than the SIL. Thus the 24-hour PM2.5 increment consumption was assessed through a

cumulative analysis for two of the three scenarios. The GE 7F.05 scenario consumes 11% of the

increment and the Mitsubishi M501 scenario consumes 12% of the increment.

This application triggered the PM2.5 minor source baseline date for the Central Arizona Intrastate

Air Quality Control Region, within the PM2.5 attainment areas of Pinal and Gila Counties10 since

it was the first PSD application received after the PM2.5 Trigger Date of 10/20/11 for construction

of a source in Pinal County.

Tables 4-10 thru 4-12 summarize the three step approach to the class II increment analysis. Table

4-10 takes into account emissions from the proposed project

Table 4-10 Class II Significant Impact Analysis

Pollutant Average Plant Configuration Model Conc.

(µg/m3)

SIL

(µg/m3)

% SIL

NO2

1-HR

GE 68.04 7.5 No increment, refer

to NAAQS analysis

Mitsubishi 44.23 7.5 No increment, refer

to NAAQS analysis

Siemens 65.50 7.5 No increment, refer

to NAAQS analysis

ANNUAL

GE 0.45 1.0 45%

Mitsubishi 0.45 1.0 45%

Siemens 0.43 1.0 43%

CO

1-HR

GE 519.25 2000 26%

Mitsubishi 682.06 2000 34%

Siemens 629.14 2000 31%

8-HR

GE 91.52 500 18%

Mitsubishi 139.90 500 28%

Siemens 114.15 500 23%

PM2.5

24-HR

GE 1.40 1.2 117%


Siemens 1.16 1.2 97%

ANNUAL GE 0.17 0.3 58%


9 The PM2.5 increment was assessed pursuant to Arizona Administrative Code (AAC) R18-2-218 and Delegation

Agreement #EV12-0061 between the Arizona Department of Environmental Quality (ADEQ) and Pinal County. 10 The baseline area is defined in PCAQCD Code §2-5-190 and 40 CFR §81.271 (as of 7/1/1993).

22

Siemens 0.15 0.3 49%

PM10

24-HR

GE 1.27 5 25%


Siemens 1.06 5 21%

ANNUAL

GE 0.16 1 16%


Siemens 0.13 1 13%

SO2

1-HR

GE 3.38 7.8 43%


Siemens 2.67 7.8 34%

3-HR

GE 1.13 25 5%


Siemens 0.89 25 4%

Table 4-11 takes into account all major and minor source of PM2.5 within 68.2 km of the site and

NO2 sources within 10 km of the site. Emergency generator emissions were excluded from the

NO2 1-hour analysis as allowed under EPA guidance and the approved modeling protocol. These

intermittent sources are limited in the number of hours they can operate and do not have the

potential to contribute significantly to the annual distribution of the daily maximum

concentrations.

Table 4-11 NAAQS Analysis

Pollutant Average Plant

Configuration

Model

Conc.

(µg/m3)

Background

(µg/m3)

Total

(µg/m3)

NAAQS (µg/m3) %NAAQS

NO2 1-hour

Siemens 32.34 112.8 145.14 188 77%

GE 31.65 112.8 144.45 188 77%

Mitsubishi 20.94 112.8 133.74 188 71%

PM2.5 24-hour GE

6.06 12.2 18.3 35 52%

Mitsubishi 6.06 12.2 18.3 35 52%

Table 4-12 summarizes the increment consumption for this facility.

Table 4-12 Class II PSD Increment Analysis


Configuration

Model Conc.

(µg/m3)

Class II

Increment

(µg/m3)

%

Increment

PM2.5 24-hour GE 1.00 9 11%


4.6 Class I PSD Increment Consumption Analysis

Portions of Superstition Wilderness are located both within and beyond 50 km from the proposed

facility. AERMOD and CALPUFF models were used to model impacts for nearfield and farfield

receptors in Class I areas respectively. Detailed Class I modeling information is presented in the

September 16, 2016 application.

For the nearfield modeling (within 50 km of the proposed site), the Project results in impacts

above the Class I SIL only for the 24-hour PM2.5 increment. Therefore a cumulative nearfield

PM2.5 Class I PSD increment evaluation was conducted. Based upon results of preliminary

modeling for the farfield analysis, SRP conservatively assumed project impacts to be significant

for both the 24-hour and annual PM2.5 Class I SILs.

23

Tables 4-13 thru 4-16 summarize the three step approach to the class I increment analysis. Both

nearfield and farfield, proposed project impacts do not cause or contribute to a violation of PSD

increments at any Class I areas.

Table4-13 presents impacts on Class I area within 50 km of the proposed CCEC site.

Table 4-13 Class I Significant Impact Analysis Result – Superstition <50 km


Configuration

Model Conc.

(µg/m3)

Class I SIL (µg/m3) % SIL

NO2 Annual

GE 0.04 0.1 42%


Siemens 0.04 0.1 42%

PM2.5

24-hour

GE 0.19 0.07 268%


Siemens 0.17 0.07 244%

Annual

GE 0.02 0.06 33%


Siemens 0.02 0.06 28%

Table4-14 presents modeled impacts for Class I areas located beyond 50 km from the site.

Table 4-14 Class I Significant Impact Analysis Result – for Areas >50 km

Pollutan

t

Averag

e

Meteorological Model

Year

Model Conc.

(µg/m3)

PSD Class I SIL

(µg/m3)

%

SIL

NO2 Annual

2001 0.027 0.10 27%

2002 0.033 0.10 33%

2003 0.026 0.10 26%

Table4-15 presents impacts on Class I area within 50 km of the proposed CCEC site.

Table 4-15 Class I PSD Increment Analysis Result – Superstition <50 km


Configuration

Model Conc.

(µg/m3)

Class I

Increment

(µg/m3)

% Increment

PM2.5 24-hour

GE 0.17 2 8%


Siemens 0.16 2 8%

Table4-16 presents modeled impacts for Class I areas located beyond 50 km from the site.

Table 4-16 Class I PSD Increment Analysis Result – for Areas >50 km

Pollutant Average Meteorological

Model Year

Model Conc.

(µg/m3)

Class I

Increment

(µg/m3)

% Increment

PM2.5 24-hour

2001 0.402 2 20%

2002 0.280 2 14%

2003 0.379 2 19%

PM2.5 Annual

2001 0.025 1 3%

2002 0.032 1 3%

2003 0.268 1 3%

4.7 NSPS/NESHAP Applicability

24

Applicable Federal standards include New Source Performance Standard (NSPS) 40 Code of

Federal Regulations (CFR) Part 60 Subpart KKKK, Subpart TTTT, and Subpart IIII. Provisions of

40 CFR Part 60 Subpart KKKK, Standards of Performance for Stationary Combustion Turbines,

apply to each combustion turbine since each unit is rated at more than 10 MMBtu/hr and will

commence construction after February 18, 2005. 40 CFR Part 60 Subpart TTTT, Standards of

Performance for Greenhouse Gas Emissions for Electric Generating Units, applies to each

combustion turbine since each unit is rated at more than 250 MMBtu/hr and capable of selling

more than 25 MW of electricity. 40 CFR Part 60 Subpart IIII, Standards of Performance for

Stationary Compression Ignition Internal Combustion Engines applies to the emergency fire pump

since the unit was manufactured after July 1, 2006.

4.8 Non-Applicable Requirements

4.8.1 SIP limitations

PGCAQCD Code 7-3-2.2, Fuel Burning Installations Sulfur Compounds, does not apply

since steam is not being used to generate power.

PGCAQCD Code 7-3-5.1, Fuel Burning Equipment Nitrogen Oxide Emissions, does not

apply since steam is not used to generate power.

4.8.2 HAP limitations

NESHAP YYYY, Stationary Combustion Turbines, does not apply since the facility is

not a major source for HAPs, as demonstrated in Table 3-4.

NESHAP ZZZZ, Stationary Reciprocating Internal Combustion Engines, does not apply

to the emergency fire pump since it is manufactured after 2006 and the unit is covered by

NSPS IIII, Stationary Compression Internal Combustion Engines.

5. Dispersion Modeling and Impact Analysis

Additional discussion, literature references and modeling files concerning the analysis summarized below

are included in the September 16, 2016 application materials, including but not limited to Section 6:

Ambient Air Quality Impact Analysis, Section 7: Site Air Quality Analysis, Section 8: Additional Impact

Analysis, Section 9: Class I Area Impacts Analysis and Appendix G: Class I and Class II Air Dispersion

Modeling and Visibility Analysis.

5.1 Ambient Air Quality Analysis

AERMOD and CALPUFF were used to conduct the load analysis, significant impact analysis,

NAAQS analysis, and increment analysis summarized in Section 4.5 and 4.6 of this document.

The September 16, 2016 application material provides modeling inputs and outputs.

5.2 Ozone Impact Analysis

PCAQCD Code §3-3-250.A.5.b requires than an applicant locating with 50 kilometers of a

nonattainment area for ozone submit a demonstration that emissions of NOx and VOC from the

new major source will not contribute to violations of the Arizona ambient air quality standards for

ozone. Since this facility is approximately 10 kilometers from the 2008 Phoenix-Mesa 8-hour

ozone nonattainment area SRP submitted an analysis of the NOx and VOC impacts from this

facility on the ozone nonattainment area.

AERMOD was used to estimate the NO2 concentration at the nearest point along the

Maricopa/Pinal County line which also represents the nearest point to the ozone nonattainment

25

area. The maximum annual NO2 concentration for the project at this point was estimated to be

0.053 µg/m3 compared to the Maricopa County annual NO2 concentration for 2015 of 41.5

µg/m3.11 The application also demonstrated that the project NOx emissions were approximately

0.4% of the NOx inventory of all NOx source in Maricopa and Pinal County. Given this relatively

small potential contribution the project NOx emissions were concluded to not affect the

neighboring ozone nonattainment area.

The project’s worst-case daily VOC emission rate will be 0.51 tons (for the Mitsubishi scenario).

The “2011 Periodic Emission Inventory for Ozone Precursors” prepared by the Maricopa County

Air Quality Department in February 2014 indicated that the ozone season-day daily emissions for

all sources, excluding biogenic, in the Maricopa County 8- hour ozone nonattainment area were

246 tons per day.12 Even if this facility were located in the nonattainment area, its VOC emissions

would be approximately 0.21% of the VOC emission inventory. Given this relatively small

potential contribution the project VOC emissions were concluded to not affect the neighboring

ozone nonattainment area.

5.3 Class I and Class II Visibility Impairment Analysis

The applicant utilized on-site meteorological data, VISCREEN modeling and the Iowa DNR’s

Level II VISCREEN tool to address the possibility of an observer seeing a plume at locations less

than 50 kilometers from the facility. The modeling analysis addressed two locations: Tonto

National Forest (Class II area, minimum distance approximately 23 kilometers) and Superstition

Wilderness (Class I area, minimum distance about 27 kilometers). The VISCREEN modeling

results for each location suggest there is a potential for a visible emission plume to exist at times

for each receptor location.

The output from the IDNR’s Level-2 screening tool for the Tonto National Forest (Class II area)

was provided in the February 3, 2017 SRP response to comments. Based upon the VISCREEN

modeling results, as provided in the September 16, 2016 application, SRP determined that the 4

m/sec and E stability class combination did not result in visibility threshold exceedances. Since in

this case there are no regulatory standards, PCAQCD presumes impacts are acceptable if they are

below the levels indicated in the FLAG guidance.

Using the on-site data it was determined that the wind blows towards the Tonto National Forest

for a total of 2.5% (0.59% for hours 1-6, 0.0% for hours 7-12, 0.05% for hours 13-18, and 1.86%

for hours 19-24) of the time. Only 0.64% of this time is during day light hours (hours 7-18). Given

the conservative nature of the Level-2 VISCREEN modeling analysis, the infrequency of the

modeled exceedances of the Class I visibility screening criteria, and the fact that most of the

adverse meteorological conditions occur when it is dark, when visibility is of less concern, SRP

concluded the potential for visibility impairment at Tonto is negligible.

The output from the IDNR’s Level-2 screening tool for the Superstition Wilderness Area (Class I

area) was provided in the February 3, 2017 SRP response to comments. Based upon the

VISCREEN modeling results, as provided in the September 2016 application, SRP determined

that the 5 m/sec and D stability class combination did not result in visibility threshold

exceedances.

Using the on-site data it was determined that the wind blows towards Superstition for a total of

11.8% (4.28% for hours 1-6, 0.96% for hours 7-12, 0.69% for hours 13-18, and 5.84% for hours

19-24) of the time. Only 1.65% of this time is during day light hours (hours 7-18). Given the

11 https://www.epa.gov/air-trends/air-quality-cities-and-counties - File “Air Quality Statistics by County, 2015”

(accessed on 10/6/2016). 12 http://www.maricopa.gov/aq/divisions/planning_analysis/docs/Reports/2011/11_O3_PEI_MainReport.pdf

(accessed on 10/5/2016). As of 4/4/2017, the document is available at

www.maricopa.gov/DocumentCenter/Home/View/4967

http://www.maricopa.gov/DocumentCenter/Home/View/4967

26

conservative nature of the Level-2 VISCREEN modeling analysis, the infrequency of the modeled

exceedances of the Class I visibility screening criteria, and the fact that most of the adverse

meteorological conditions occur when it is dark, when visibility is of less concern, SRP concluded

the potential for visibility impairment at Superstition is negligible.

Class I areas located beyond 50 kilometers from the site were modeled for visibility impacts using

the CALPUFF model. Model results were inputted into CALPOST to calculate the change in light

extinction for each day. The results were reviewed to determine the number of days where the

change in light extinction was at or above 5%. The CALPUFF results for Class I areas beyond 50

kilometers from the site show modeled visibility extinction below the 5% criteria. Therefore, the

project impacts meet the “presumptive no adverse impacts” criteria for visibility impacts.

5.4 Class I Deposition Analysis

Modeled deposition rates for total sulfur and nitrogen were calculated. These results were

reviewed for comparison to the Deposition Analysis Thresholds (DATs) of 0.005 for each Class I

area. The modeled deposition value for sulfur was 14% or less of the DAT threshold and the

modeled deposition value for nitrogen was 57% or less of the DAT threshold. No exceedances of

the DATs were identified. Since in this case there are no regulatory standards, PCAQCD presumes

impacts are acceptable if they are below the levels indicated in the FLAG guidance.

5.5 Soils Analysis

Since the project will emit NOx, CO, VOC, PM, and PM2.5 in excess of the PSD significant

emission rates these pollutants were considered in the required soil impairment analysis. Per the

USEPA’s guidance the additional impacts analyses requirements do not apply to the emissions of

GHGs from the project. 13 14

Over 90,000 acres (140 square miles) surrounding the proposed site were evaluated for the soils

analysis using the U.S. Department of Agriculture Natural Resource Conservation Service Web

Soil Survey application. The area evaluated encompasses Eastern Maricopa, Southern Gila and

Pinal Counties and Gila River Indian Reservation.15 The primary soil type in this area is some

variety of Mohall loam at over 32 percent of the total acreage in the study. Other types of soil in

significant quantities around the facility include Contine Clay loam, Gilman loam, and Laveen

loam. The pH of these soils ranged from 7.9 to 8.2.

The U.S. Department of Agriculture considers approximately 51 percent of this land to be prime

farmland if irrigated. Less than 1 percent is considered farmland of unique importance. All of

these soil types are identified as having somewhat or very limited use for recreational activities,

such as camping, paths and trails, picnic areas, and playgrounds. Less than 0.1 percent of the study

area is identified as having unlimited recreational value.

Current literature contains little information on impairment or other direct effects on soils due to

air pollution, and SRP did not identify as part of this analysis any studies in which potential

pollutant effects on the soils specific to the project area were evaluated.

13 75 Fed. Reg. 31514, June 3, 2010, page 31520. 14 In a March 2011 permitting guidance, the U.S.EPA observed that “…it is not necessary for applicants or

permitting authorities to assess impacts from GHGs in the context of the additional impacts analysis or Class I area

provisions of the PSD regulations… EPA believes that the most practical way to address the considerations reflected

in the Class I area and additional impacts analysis is to focus on reducing GHG emissions to the maximum extent.”

PSD and Title V Permitting Guidance for Greenhouse Gases, EPA-457/B-11-001, March 2011, at pages 47-48. 15 U.S. Department of Agriculture, Natural Resource Conservation Service, Custom Soil Resource Report for

Eastern Maricopa and Northern Pinal Counties Area, Arizona; Eastern Pinal and Southern Gila Counties, Arizona;

Gila River Indian Reservation, Arizona, Parts of Maricopa and Pinal Counties; and Pinal County, Arizona, Western

Part March 16, 2015.

27

Because deposition of NOx and other nitrogen compounds into soils in the survey area could

occur as a result of emissions from the construction and operation of the project, it is reasonable to

consider whether some marginal acidification of the soils might occur as a result of this project.

Since the soils in the survey area are alkaline (i.e., pH greater than 7.0) some degree of

acidification can be readily tolerated and may in fact be desirable. Based on this information, SRP

and PCAQCD have concluded that the proposed facility will not have an adverse impact on soils.

5.6 Vegetation Analysis

Since the project will emit NOx, CO, VOC, PM, and PM2.5 in excess of the PSD significant

emission rates these pollutants were considered in the required vegetation impairment analysis. This analysis was limited to vegetation having significant commercial or recreational value16 and

covered the entirety of the Arizona District 80 agricultural district which includes Cochise,

Graham, La Paz, Maricopa, Pima, Pinal, Yuma, Santa Cruz, and Greenlee Counties. This study

area exceeds the scope suggested by U.S. EPA guidance, which is limited to the area within the

impact area of the proposed facility (10 km).17

Approximately 3 percent of the land included in the study area is used for harvested crops. 85

percent of that area is used for alfalfa hay, upland cotton, pima cotton, durum wheat, barley,

lettuce and lemons. Other crops, each harvested from less than 1 percent of the area, include

cantaloupes, spinach, various nuts, and orchard fruits.18 19 Air pollutants can affect crops through

two principal means; direct phytotoxic effects from air concentrations of pollutants and indirect

phytotoxic effects due to deposition of pollutants in soils in which the crops are growing.

NOx includes both nitric oxide (NO) and nitrogen dioxide (NO2), and much of the scientific

literature treats these two gases separately. Based on the results of the air quality impacts analysis,

the maximum predicted ambient NOx concentrations due to emissions from the proposed facility

are 68 μg/m3 (1-hour average) and 0.45 μg/m3 (annual average). These values represent total NOx,

including both NO and NO2. These impacts are well below the secondary NAAQS of 100 μg/ m3

(annual average)20 and the minimum U.S. EPA screening values of 3,760 μg/ m3 (4-hr average) and 94 μg/ m3 (annual average).21 Both the secondary NAAQS and the screening value are

expressed in terms of NO2; there are no NAAQS or screening values for NO.

The agricultural crops for which the minimum U.S. EPA screening value is listed as being

protective include all of the primary crops identified above (i.e., alfalfa, cotton, wheat, barley,

lettuce, and citrus).22 The literature was reviewed to ascertain whether there exists, in the scientific

literature, any basis for concluding that: a) the secondary NAAQS and the minimum U.S. EPA

screening value are not protective of any of the crops identified herein; or b) the project’s NOx

emissions will have an unacceptable, adverse impact on agricultural crops in the study area.

16 Pinal County Air Quality Control District Code of Regulations, Chapter 3, Article 3, Section 3-3-260(J)(1) 17 See, e.g., Prevention of Significant Deterioration Workshop Manual (EPA-450/2-80-081), Oct. 1980, at page I-D-

6, expressly limiting the soils and vegetation impairment analysis to the “impact area”. See also the same document

at page I-C-12, defining the impact area as a “circular area whose radius is equal to the greatest distance from the

source to which approved dispersion modeling shows the proposed emissions will have a significant impact.” 18 2011 Arizona Agricultural Statistics Bulletin, Issued September 2012 19 2012 Census of Agriculture-County Data, USDA, National Agricultural Statistics Service, Arizona Volume 1,

Tables 24-34. 20 40 CFR § 50.11(c). 21 Smith, A.E., and J.B. Levenson. A Screening Procedure for the Impacts of Air Pollution Sources on Plants, Soils,

and Animals (EPA-450/2-81-078). U.S. EPA, Office of Air Quality Planning and Standards. Research Triangle

Park, NC. December 1980. p. 11. 22 Ibid at p. 68.

28

In April 2012, U.S. EPA issued a final rule retaining and affirming the secondary NO2 NAAQS of

100 μg/m3 (annual average).23 This action reflected both the U.S. EPA Administrator’s finding

that this standard is “adequate to protect against direct phytotoxic effects on vegetation”24 and her

judgment that an alternative standard to protect against deposition-related effects is not supported

by currently available data.25

In 2000, the World Health Organization (WHO) instituted a NOx guideline concentration value of

30 μg/m3 on an annual average (including both NO and NO2, expressed as NO2). The WHO

declined to institute a short-term value, saying “[t]here are insufficient data to provide these levels

with confidence at present,” but indicated that current evidence would suggest a guideline NOx

concentration value of about 75 μg/m3 on a daily average. The guideline concentration value is

intended to be protective of all classes of vegetation under all environmental conditions.26

Nothing in the scientific literature reviewed indicates that the secondary NAAQS and the

minimum annual U.S. EPA screening value are not protective of any of the crops identified in the

analysis. The maximum predicted NOx concentration is well below the secondary NAAQS, the minimum U.S. EPA screening value, guideline concentration values established by foreign

governmental agencies, and concentrations that are identified in the literature as being harmful to

commercially significant vegetation in the study area. SRP concluded that emissions from the

proposed project are not expected to result in adverse effects to soils, crops, or plant species of

concern, within the vicinity of the project site.

5.6 Growth Impact Analysis

The purpose of the growth analysis is to quantify the associated industrial, commercial, and

residential growth that will occur in the area due to the project. The associated growth is the

growth that occurs as a result of the construction or modification of the source, but which is not

part of the source. The emissions that result from this growth are then estimated and the effects of

these emissions on the surrounding environment are determined.

The growth analysis addresses only permanent economic growth attributable to the proposed

project. Short-term or temporary impacts, such as construction, are not considered permanent

growth and therefore are not addressed as an additional impact.

Given the large local population, the construction associated with the Project will not have a

significant impact to the local population. Construction of the project is expected to result in 15-20

new, permanent positions at the site, and approximately 130-200 temporary construction positions.

It is anticipated that the construction workforce will be drawn, largely from the surrounding

communities. Therefore, the effect on air quality from the incremental growth will be

insignificant.

6. Other Federal Requirements

6.1 Endangered Species Act (ESA)

Pursuant to Section 7 of the Endangered Species Act (ESA), 16 U.S.C. 1536, and its implementing

regulations at 50 CFR Part 402, EPA is required to ensure that any action authorized, funded, or

carried out by EPA is not likely to jeopardize the continued existence of any endangered or

threatened species or result in the destruction or adverse modification of such species’ designated

critical habitat. Most portions of the PSD program in Pinal County are implemented by the Pinal

23 See, generally, 77 Fed. Reg. 20218. April 3, 2012. 24 Ibid at p. 20241. 25 Ibid at pp. 20262-63. 26 Air Quality Guidelines for Europe, 2nd Ed. World Health Organization, Regional Office for Europe. Copenhagen,

Denmark. 2000. pp. 230-233.

29

County Air Quality Control District (PCAQCD) under state and local law, and would not be

considered federal actions for the purposes of ESA. However, a portion of the of the PSD

program in Pinal County addressing greenhouse gases (GHG) is a federal permitting program.27

This GHG-related portion of the PSD permitting program in Pinal County is implemented

pursuant to a federal delegation of authority from EPA whereby PCAQCD “stands in the shoes” of

EPA in issuing the federal, GHG-related elements of a PSD permit. As a result, the portion of the

PSD permit issued in Pinal County that is related to GHGs is being issued pursuant to 40 CFR

52.21, and is therefore a federal action that is subject to ESA Section 7 requirements.

SRP submitted a Biological Assessment (BA), developed by Jacobs Engineering Group, to

examine potential impacts from the construction of the proposed facility to listed species and

critical habitat. The draft BA is included in the administrative record for this action, and examined

potential effects on multiple bird, fish, mammal, plant, and reptile species. The draft BA

identified 14 species for which no effect finding was recommended, and an additional 2 species,

the lesser long-nosed bat (endangered), and the acuna cactus (endangered), for which a finding of

“may affect, not likely to adversely affect” was recommended. The primary impacts related to

these two species are the impact of soil acidification from additional nitrogen deposition on the

critical habitat of these two species. Modeling of potential project emissions indicate that

additional levels of nitrogen deposition are at such a low level that they are not significant.

As a result, in a letter dated February 28, 2017, EPA requested concurrence from the U.S. Fish and

Wildlife Service (USFWS) with a finding of “may affect, not likely to adversely affect” regarding

these species. On April 18, 2017, USFWS responded with a letter concurring with this finding.

These documents, as well as the Biological Assessment and other supporting information, are

included in the administrative record for this permitting action.

6.2 National Historic Preservation Act (NHPA)

Pursuant to Section 106 of the National Historic Preservation Act (NHPA), 6 U.S.C. § 470f, and

its implementing regulations at 36 CFR Part 800, prior to the approval of the expenditure of any

funds on or prior to the issuance of any license for an undertaking, EPA is required to account for

the effects of its undertakings on historic properties and afford the Advisory Council on Historic

Preservation (Council) a reasonable opportunity to comment upon such undertakings.

Consultation is generally conducted with relevant state and tribal historic preservation authorities

in the first instance, with opportunities for direct Council involvement in certain circumstances.

As discussed in the section above regarding the Endangered Species Act (ESA), while Pinal

County Air Quality Control District (PCAQCD) is the permit issuing authority for the Copper

Crossing Energy Center, this project is considered a federal action for which Section 106

consultation is required.

For purposes of NHPA review, a 3.5-mile buffer area around the 545-acre project area represents

the area of potential effects (APE) for impacts such as noise and ground disturbing effects, and

represents the direct area of potential effects. In addition, because emissions of NOX and SO2

from the proposed project have the potential to contribute to increased nitrogen and sulfur

deposition, we also examined a radius of 31 miles (50 km) around the project site for indirect

impacts related to air emissions. SRP prepared a Class I cultural resources inventory of the project

area and APE, which included a summary of previously conducted Class III surveys. The Class I

inventory indicated that 15 archaeological sites have been previously recorded within the 3.5-mile

buffer, two of which fall within the project area. On March 16, 2017, EPA forwarded this

information and initiated consultation with the Arizona State Historical Preservation Officer

(SHPO) and multiple tribal Chairpersons and Tribal Historic Preservation Officers (THPO).

Based on feedback from the Arizona SHPO, an additional Class III survey and certain additional

analysis was performed, indicating that no sites eligible for National Register of Historical Places

(NRHP) listing are located within the APE.

27 See 40 CFR 52.37

30

A copy of the initial Class I cultural resources inventory and supplemental analyses is included in

the administrative record for this permit. At this time, consultation is still ongoing with the

Arizona SHPO, as well as with several Arizona tribes.

7. List of Abbreviations

ADS .............................................................................................................. Agglomerative Dust Suppression

AP-42 ................................................................................................................................................................

“Compilation of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area Sources”, 5 th Edition

CAA ............................................................................................................................................ Clean Air Act

CAM .......................................................................................................... Compliance Assurance Monitoring

CFR ..................................................................................................................... Code of Federal Regulations

CO ........................................................................................................................................ Carbon Monoxide

GHG ........................................................................................................................................ Greenhouse Gas

hr ............................................................................................................................................................... Hour

lb .............................................................................................................................................................. Pound

MACT .......................................................................................... Maximum Achievable Control Technology

MMBTU ............................................................................................................ Million British Thermal Units

Mod. ............................................................................................................................................. Modification

MSDS ..................................................................................................................... Material Safety Data Sheet

NOX ....................................................................................................................................... Nitrogen Oxides

NSPS ......................................................................................................... New Source Performance Standard

NSR .................................................................................................................................. New Source Review

PCAQCD ......................................................................................... Pinal County Air Quality Control District

PGCAQCD ........................................................................... Pinal-Gila Counties Air Quality Control District

PM10 .......................................................................... Particulate Matter nominally less than 10 Micrometers

PSD ..................................................................................................... Prevention of Significant Deterioration

SIC ............................................................................................................................ Standard Industrial Code

SOX ........................................................................................................................................... Sulfur Dioxide

tpy ................................................................................................................................................. tons per year

TSD .................................................................................................................... Technical Support Document

VOC ..................................................................................................................... Volatile Organic Compound

yr ............................................................................................................................................................... Year

31

Appendix A - BACT analysis

This appendix provides the BACT analysis as proposed by the applicant in the September 16, 2016 permit

application and as amended on June 2, 2017.

32

A. Best Available Control Technology

This section presents the required BACT reviews for the planned CCEC. It includes a general

discussion of the BACT analysis procedure employed. This general discussion is followed by a

site-specific case-by-case BACT analysis for the new emissions units to be constructed as part of

the Project. The results of the BACT analyses for the proposed CTGs are summarized in Table A-1 below:

Table A-1. Summary of BACT Determinations for the Proposed CTGs

Unit Description Mode Pollutant Proposed BACT

GE 7F.05 Frame Simple Cycle Normal PM/PM2.5 7.1 lb/hr (3-test average)

Siemens SGT6-5000F Frame Simple

Cycle

Normal PM/PM2.5 7.1 lb/hr (3-test average)

Mitsubishi M501GAC1 Frame Simple

Cycle

Normal PM/PM2.5 8.4 lb/hr (3-test average)

GE LMS100 PA Aero Simple Cycle Normal PM/PM2.5 5.3 lb/hr (3-test average)

Aeroderivative Turbines SU/SD PM/PM2.5

CO/VOC

Work practice – limit startups to

730/yr

Frame Turbines SU/SD PM/PM2.5

CO/VOC

Work practice – limit startups to

300/yr

All Turbines Normal NOx 2.5 ppmvd (15% O2, 1-hr avg)

GE 7F.05 Frame Simple Cycle SU NOx 44.0 lb/event


Cycle

SU NOx 63.3 lb/event


Cycle

SU NOx 28.7 lb/event

GE LMS100 PA Aero Simple Cycle SU NOx 21.9 lb/event

GE 7F.05 Frame Simple Cycle SD NOx 18.0 lb/event


Cycle

SD NOx 44.4 lb/event


Cycle

SD NOx 23.8 lb/event

GE LMS100 PA Aero Simple Cycle SD NOx 6.0 lb/event

All Turbines Normal CO 4.0 ppmvd (15% O2, 3-test average)

Aeroderivative Turbines Normal VOC 2.0 ppmvd (15% O2, 3-test average)

Frame Turbines Normal VOC 1.2 ppmvd (15% O2, 3-test average)

GE 7F.05 Frame Simple Cycle All CO2e 1,317 lb/MWh (gross - annual

average)


Cycle

All CO2e 1,428 lb/MWh (gross - annual

average)


Cycle

All CO2e 1,376 lb/MWh (gross - annual

average)

GE LMS100 PA Aero Simple Cycle All CO2e 1,434 lb/MWh (gross - annual

average)

33

A.1 BACT Applicability

The Project involves constructing a new peaking generating station consisting of five or six

simple cycle frame combustion turbine generators and two simple cycle aeroderivative

combustion turbine generators and the necessary support facilities such as cooling processes,

circuit breakers, and an emergency fire pump engine. As described in section 4.1.2 of the

application, the project is subject to PSD review for NOx, CO, VOC, PM/PM2.5, and GHGs. For

the Project, applicability of BACT is required pursuant to Code §3-3-250(A)(1) as follows:

A new major source shall apply best available control technology (BACT) for each conventional

air pollutant for which the potential to emit is significant. 28

In the case of the proposed CCEC Project, BACT is applicable to all of the newly constructed

units that have the potential to emit NOx, CO, VOC, PM/PM2.5, or GHGs in any amount. Table A-2 lists each unit-pollutant combination subject to BACT review.

Table A-2. Unit-Pollutant Combinations Subject to BACT Review

Unit Description PM/PM2.5 NOx CO VOC GHGs

Simple Cycle Combustion turbines X X X X X

Wet Surface Air Coolers X X

Cooling Tower X X

Natural Gas Supply Equipment X X

Emergency Fire Pump Engine X X X X X

Diesel Fuel Storage Tank X

Circuit Breakers X

A.2 BACT General Approach

This section presents an outline of BACT approach for the proposed CCEC Project units for regulated

NSR pollutants subject to PSD review.

A.2.1 Best Available Control Technology Definition

The definition of BACT at Code §1-3-140.20 is as follows:

An emissions limitation (including a visible emission standard), based on the maximum degree of

reduction for each pollutant subject to regulation under the Clean Air Act (1990) which would

be emitted from any proposed major stationary source or major modification which the Control

Officer, on a case-by-case basis, taking into account energy, environmental, economic impacts

and other costs, determines is achievable for such source or modification through application of

28 Pinal County implements 40 CFR §52.21 for GHGs permitting under delegation from the U.S. EPA. Pinal

County’s requirements for PSD review mirror the requirements under 40 CFR §52.21. Therefore, citations to 40

CFR §52.21 are omitted here.

34

production processes or available methods, systems, and techniques, including fuel cleaning or

treatment or innovative fuel combustion techniques, for control of such pollutant. Under no

circumstances shall BACT be determined to be less stringent than the emission control required

by the most restrictive applicable provision of District, State or federal laws or regulations. If

the Control Officer determines that technological or economic limitations on the application of

measurement methodology to a particular emissions unit would make the imposition of an

emissions standard infeasible, a design, equipment, work practice, operational standard or

combination thereof may be prescribed instead to satisfy the requirement for the application of

BACT. Such standard shall, to the degree possible, set forth the emissions reduction achievable

by implementation of such design, equipment, work practice or operation, and shall provide for

compliance by means which achieve equivalent results.

This definition of BACT is generally consistent with that in the federal Clean Air Act as

amended in 1977.29 The Clean Air Act Amendments of 1990 added the phrase “clean fuels” to

the list of candidate methods, systems, and techniques.30 The PCAQCD has not revised its rules

to reflect this change to the federal statute.

A.2.2 Methodology for the BACT Analysis

PCAQCD’s air quality regulations do not prescribe a procedure for conducting a case-by-case

BACT analysis but, by convention, BACT determinations are typically made following the top-

down approach. Accordingly, the BACT analyses presented in this application utilize the top-

down approach.

Under the “top-down” approach, progressively less stringent control technologies are analyzed

until a level of control considered BACT is determined, based on the most effective control

option that is determined to result in acceptable environmental, energy, and economic impacts.

More specifically, the top-down BACT analysis methodology consists of five steps as follows:

1. Identify all “available” control options that might be utilized to reduce emissions of the subject

pollutant for the type of unit subject to BACT.

2. Eliminate those available options that are technically infeasible to apply to the specific unit

under consideration.

3. Rank the remaining feasible control options by control effectiveness.

4. Evaluate economic, energy and/or environmental impacts of the each control option as applied

to the subject units, rejecting those options for which the adverse impacts are inappropriate.

5. Based on the most effective control option not rejected in Step 4, select an emission limit or

work practice standard as BACT, reflecting the level of control continuously achievable with

the selected control option.

29 P.L. 95-95, § 127(a). 30 P.L. 101-549, § 403(d). See, also, current 42 U.S.C. § 7479(3).

35

A.2.3 Basic Purpose and Design of the CCEC Project

To determine whether a particular technology or technique is “available” for consideration in the

BACT analysis, or would fundamentally redefine the proposed source, and must therefore be

omitted from consideration in the BACT analysis “a permitting authority should look first at the

administrative record to see how the applicant defined its goal, objectives, purpose or basic

design.”31 The permitting authority must take a “hard look” and determine “which design

elements are inherent to [the] purpose [of the facility], articulated for reasons independent of air

quality permitting, and which design elements may be changed to achieve pollutant emission

reductions.”32

SRP’s basic purpose and fundamental objective for the CCEC Project is to construct a natural

gas-fueled electric generating station on the proposed 161 acre site in Pinal County, Arizona.

This facility is designed to produce up to 1,684 MW.33 The facility will provide fast starts, high

availability and cycling capability without maintenance impact. These characteristics are

essential in realizing the project objectives of meeting customer peak demand, integration of

intermittent renewable energy sources, and supplying peak capacity as needed to offset potential

generation loss as a result of pending environmental regulations

To provide system regulating support and to optimize utilization of renewable sources, the

CCEC aeroderivatives are designed to idle at loads as low as 25% and to ramp and down quickly

(e.g,, from 50% to 100% load in less than one minute). Idling these units at a partial load allows

an almost instantaneous response to system fluctuations while the simple cycle frame

combustion turbines will provide the necessary maximum peaking capacity with acceptable cold-

start ramp rates.

A.2.4 BACT Baseline

As used in the BACT analyses presented herein, the term “BACT baseline” refers to the

following requirement in the definition of BACT:

Under no circumstances shall BACT be determined to be less stringent than the emission control

required by the most restrictive applicable provision of District, State or federal laws or

regulations.

Thus, any applicable PCAQCD, State or federal limit on emissions of a BACT-subject pollutant

from a given unit serves as a baseline for purposes of the BACT evaluations. As an example,

NSPS subpart KKKK limits NOx emissions from the proposed CTs to 15 ppm at 15 percent O2

or 0.43 lb/MWh. This limit serves as the BACT baseline for the turbine NOx BACT analysis and

represents the least restrictive NOx emission limit that can be considered as BACT for the

proposed CTs.

31 PSD and Title V Permitting Guidance for Greenhouse Gases, EPA-457/B-11-001, March 2011, at p. 26. 32 In re Prairie State, 13 E.A.D. at 23, 26-27 (EAB 2006). 33 ISO conditions.

36

A.2.5 Available Control Strategies

In the first step of the BACT analysis, all potentially “available” control strategies are identified

for further consideration. In the context of the first step of a top-down BACT analysis, U.S.

EPA’s guidance describes “available” control strategies as:

[T]hose air pollution control technologies or techniques with a practical potential for

application to the emissions unit and the regulated pollutant under evaluation.34[emphasis

added]

In the BACT analyses herein, the term “available” is used, consistent with U.S. EPA guidance, to

refer to any control strategy that is potentially applicable to the source type in question (i.e., a

technology or control option that has a practical potential for application to the source category

in general). These may include fuel cleaning or treatment, inherently lower polluting processes,

and end of pipe control devices. All identified control strategies that are not inconsistent with the

fundamental purpose and basic design of the proposed facility are listed in this step.

As discussed in subsection 0 below, the second step of the BACT analysis addresses site-specific

or design-specific criteria that would prevent an otherwise available technology from being

applied in the particular case of the proposed project. This “technical feasibility” question is

separate and distinct from the criteria used to determine whether a control option is considered to

be “available” for purposes of determining BACT.

A.2.6 BACT Technical Feasibility Criteria

In the second step of a top-down BACT analysis, potentially available control strategies are

evaluated for technical feasibility. A technically feasible control strategy is one that has been

demonstrated to function efficiently on an emissions unit that is identical or similar to the

emissions unit under review.35 For the purposes of assessing technical feasibility of an add-on

control technology, the determination of whether an emissions unit should be considered to be

identical or similar is usually based on the physical and chemical characteristics of the gas

stream to be controlled. An add-on control technology applicable to one emissions unit may not

be technically feasible for application to an apparently similar unit depending on differences in

physical and chemical gas stream characteristics, and rejection of a control option based on

technical infeasibility for BACT purposes is appropriate if “it is uncertain the control device will

work in the situation currently undergoing review.”36

For control strategies that are not demonstrated, the analysis of technical feasibility is somewhat

more involved. Two key concepts are important in determining whether an undemonstrated

technology is feasible: “availability37” and “applicability.” A technology is considered

“available” if it can be obtained by the applicant through commercial channels or is otherwise

available within the common sense meaning of the term. An available technology is “applicable”

34 See: 1990 New Source Review Workshop Manual, DRAFT, at page B.5. 35 See, Prevention of Significant Deterioration Workshop Manual, EPA-450/2-80-081, October 1980, at pp. I-B-6

through I-B-7. 36 See, PSD and Title V Permitting Guidance for Greenhouse Gases, EPA-457/B-11-001, March 2011, at p. 34. 37 In Step 2 of a top-down BACT analysis, the term “availability” has a different meaning than the term “available”

in Step 1. Control strategies that are not “available” in Step 1 are not considered in Step 2.

37

if it can reasonably be installed and operated on the source type under consideration. A

technology that is both available and applicable is technically feasible.

A.3 Combustion Turbines PM/PM2.5 BACT Analyses

This section presents the required PM/PM2.5 BACT analysis for the proposed CTs. Combustion

turbine PM2.5 emissions consist mainly of condensable particulates with a minor percentage of

emissions being filterable particulate matter (i.e., PM). Particulate matter emissions from natural

gas fired combustion turbines equipped with an SCR system, an oxidation catalyst and an inlet

air humidification system consist of:

Inert contaminants in natural gas;

Sulfates from oxidation of fuel sulfur and odorants;

Ammonia from the SCR system;

Dust in the ambient air used for combustion;

Suspended and dissolved solids in the water used for humidification; and

Compounds resulting from incomplete combustion of the natural gas fuel.

As a general matter, the combined impact of all of these factors on total particulate matter

emission rates is such that only trace levels of particulate matter are present in a natural gas

fueled combustion turbine’s exhaust stream making it difficult even to measure emissions with a

reasonable degree of accuracy.38

Virtually all of a combustion turbine’s particulate emissions are PM2.5 and strategies that reduce

filterable PM2.5 will reduce PM emissions as well. Thus, these pollutants are appropriately

considered together in this BACT analysis.

Based on the emission factors in AP-42, about 70% of combustion turbine particulate emissions

are condensable with the remainder being filterable.39 Using the AP-42 filterable PM emission

factor for combustion turbines fueled with natural gas, the expected filterable dust loading in the

exhaust gas will be on the order of 0.0001 grain/scf, a value that is small fraction of that typically

found at the exit of a fabric filter or electrostatic precipitator (ESP) control device applied to

other source types.

38 For example, one analysis of 38 stack tests on similar turbines showed PM test results having a relative standard

deviation of 59% on a lb/MMBtu basis – see: https://www.regulations.gov/#!documentDetail;D=EPA-R09-OAR-

2011-0978-0020 [2_1_PPEC_PSD_Permit_Application_PM_BACT_Determination.pdf]. Other studies have shown

that measurement error (e.g., blank correction issues) can represent a significant fraction of the measured emissions

(see for example: Evaluation of the Performance of EPA Methods 201A and 202 on a Natural Gas-Fired Boiler,

Ashok Jain and Lee Carlson, NCASI, Conference on the Environment Minneapolis, MN November 12, 2013).

Further, PM/PM10/PM2.5 test results are subject to inherent bias due to artifact formation of condensable particulate

in the sampling system. And finally, sampling times for particulate matter on natural gas fired combustion turbines

are typically six hours in duration which is up to six times longer than typical for many other source types. This

extended test duration is needed to collect sufficient amounts of actual particulates to reduce the impacts of

measurement error on the final results but it does add to the potential for artifact formation of condensable

PM10/PM2.5 in the sampling system. 39 See: AP-42, Table 3.1-2a, April 2000.

https://www.regulations.gov/#!documentDetail;D=EPA-R09-OAR-2011-0978-0020

https://www.regulations.gov/#!documentDetail;D=EPA-R09-OAR-2011-0978-0020

38

A.3.1 PM/PM2.5 BACT Baseline

As discussed in Section 4 of the application, the proposed CTs are subject to various emission

limits. However, none of the applicable rules impose specific limits on emissions of PM2.5 from

the CTs. Code §5-23-990 establishes allowable PM emissions for stationary combustion turbines

from an equation that uses the heat input for the unit. Since the allowable rates calculated using

the equation are significantly larger than the PTE of PM from the CTs, this BACT baseline value

is irrelevant to the BACT analysis (i.e., the potential emissions of PM are far below this baseline

value making any PM BACT limit more restrictive than the applicable PM standard).

A.3.2 Step 1 – Identify Available Control Options

Based on a review of available information and in particular recent combustion turbine BACT

determinations,40 the control strategies that may be considered to be “available” for limiting PM/

PM2.5 emissions from a combustion turbine include:

Good combustion practices;

Combustion air filtration; and

Use of clean fuels such as natural gas.

Other alternative control technologies that have been used to limit particulate emissions from

external combustion sources firing liquid and solid fuels such as fabric filters and ESPs have

never been applied to natural gas-fired combustion sources. These add-on technologies are not

considered to be available control options in the context of this BACT analysis because they do

not have a practical potential for application to control particulate emissions from the planned

gas-fired combustion turbines (where the filterable fraction of the particulate matter emissions is

very small). There are no known applications of such controls to any similar source. Further, the

general gas fueled combustion turbine source category characteristics (i.e., high exhaust flows

per unit of energy produced, sensitivity to back-pressure, and the ultra-low concentration of

filterable particulate emission in the exhaust) make application of such add-on technologies

impractical if not infeasible.

A.3.3 Step 2 – Eliminate Technically Infeasible Options

Each of the available control strategies identified in Section 0 is considered to be a technically

feasible basis for establishing the PM/PM2.5 BACT limits for the proposed combustion turbines.

A.3.4 Step 3 – Rank Control Options

The PM/PM2.5 control strategy selected for the proposed combustion turbines involves the use

of natural gas as a fuel, combustion air filtration, and the use of good combustion practices. This

control strategy is the top-performing feasible option for limiting PM/PM2.5 emissions from the

combustion turbines.

40 Table D-1 in Appendix D summarizes the control methods identified in recent natural gas fueled simple cycle

combustion turbine PM/PM2.5 BACT determinations.

39

A.3.5 Step 4 – Evaluate Feasible Control Options

The selected PM/PM2.5 control strategy will not have any material adverse energy,

environmental or economic impacts, and therefore it is appropriate that this strategy serve as the

basis for establishing the PM/PM2.5 BACT limits for the combustion turbines.

A.3.6 Step 5 – Establish BACT

The use of natural gas as a fuel combined with combustion air filtration and good combustion

practices represents the most effective basis for establishing the PM/PM2.5 BACT limits from

the proposed combustion turbines. As discussed in sub-section 0, equipment design or work

practice requirements are acceptable under the definition of BACT only when technological or

economic limitations on the application of measurement methodology would make the

imposition of an emissions standard infeasible. That criterion is not met with respect to

PM/PM2.5 emissions from the proposed combustion turbines during periods of normal

operation.41 However, that criterion is met during periods of startup and shutdown which are too

transient and brief to allow measurement of particulate matter emissions using available

performance testing methodologies.

To establish the appropriate BACT limit for the CTs, an analysis of recently established limits in

the RBLC and other recent combustion turbine permits was performed and the results of that

analysis are summarized in Table A-3. The data indicate that approximately three-fourths of

recently established simple cycle combustion turbine PM/PM2.5 BACT limits are expressed in

pounds per hour while only one-sixth of the limits are expressed in pounds per million Btu. A

pound per hour limit is the most appropriate form of PM/PM2.5 BACT limit for the CTs because

several of the factors that contribute to particulate matter emissions from the turbines are not

dependent on firing rates or turbine load. First, the impact of measurement bias and error are

load-independent. Also, the impact of sulfate formation due to oxidation of SO2 across the

proposed catalytic emissions control systems may be an inverse function of load (i.e., the SO2

oxidation fraction may increase as load decreases).42

Table A-3. Recent PM/PM2.5 BACT Limit Characteristics for Combustion Turbines43

PM/PM2.5 BACT Limit Form Number of Permits % of Total

lb/hour 26 79%

lb/MMBtu 4 12%

Grains S/100 SCF 3 9%

Each of SRP’s prospective CTG vendors has guaranteed different particulate emission rates, in

pounds per hour, based on the size and unique features of their designs. Each of these guarantee 41 There are numerous issues with the current PM2.5 measurement method which make this point debatable, but for

purposes of this analysis, SRP has assumed that the use of current U.S. EPA reference methods does allow an

emissions standard to be imposed. Nevertheless, sufficient compliance margin must be incorporated into the

emissions limit to account for the shortcomings of the current measurement methods. 42 Because exhaust gas flow decreases with decreasing load, residence time in the catalyst beds will increase and the

load-normalized sulfate production rates (i.e., SO2 oxidation fraction) could increase as firing rates decrease. 43 Derived from data in the RBLC Database: Simple cycle turbines permitted since 2006. See Table D-2 in

Appendix D for details.

40

values is consistent with the underlying control strategies identified as the most effective basis

for establishing PM/PM2.5 BACT limits for the combustion turbines. For normal operations,

these values are listed as proposed BACT limits in Table A-4.

Table A-4. Proposed Combustion Turbine PM/PM2.5 BACT Limits - Normal Operation

Turbine Model

Proposed

PM/PM2.5

BACT Limit

(lb/hr) †

Normalized PM/PM2.5

BACT Emission Rate

(lb/MWhgross*)

GE 7F.05 Frame Simple Cycle 7.1 0.031

Siemens SGT6-5000F Frame Simple Cycle 7.1 0.030

Mitsubishi M501GAC1 Frame Simple Cycle 8.4 0.033

GE LMS100 PA Aero Simple Cycle 5.3 0.051

† Proposed limit is based on a 3-run compliance test using U.S. EPA test methods.

*MWh values represent base load gross generation at 59 °F at site condition with no inlet cooling.

For each proposed PM/PM2.5 BACT limit, Table A-4 also lists the capacity-normalized

PM/PM2.5 emission rates (in lb/MWhgross) for each combustion turbine at full load. These

capacity-normalized rates compare favorably with the most restrictive rates identified in the

RBLC search for recently permitted simple cycle combustion turbines which range from a low of

0.043 lb/MWh to a high of 0.390 lb/MWh.44 Because SRP’s vendor guarantee values are at the

low end of recent BACT limits for apparently comparable simple cycle combustion turbines,

SRP proposes that the PM/PM2.5 BACT limits for normal operations be established at the pound

per hour values listed in Table A-4. SRP further proposes that compliance with the proposed

PM/PM2.5 BACT limits for the combustion turbines be demonstrated by conducting a

representative stack test (i.e., three test runs) on one of each turbine type installed (i.e., testing on

one frame and one aeroderivative unit), using approved U.S. EPA test methods.

Since compliance with numeric particulate matter emissions limits cannot be determined during

periods of startup and shutdown, a work practice is proposed as BACT. Specifically, SRP

proposes to operate and maintain the CTs, air pollution control equipment and monitoring

equipment in a manner consistent with good air pollution control practices. Additionally, SRP

proposes to limit the total number of frame CTs startup and shutdowns to 300 per year,

aeroderivative CTs startup and shutdowns to 730 per year and to follow the turbine

manufacturers’ recommended startup and shutdown procedures.

A.4 Combustion Turbines NOx BACT Analyses

This section presents the required NOx BACT analysis for the proposed combustion turbines.

NOx emissions from natural gas-fired combustion turbines result primarily from oxidation of

atmospheric nitrogen during the combustion of natural gas. NOx formation is favored when both

44 Ibid.

41

high combustion temperatures and high excess O2 levels are present. Thermal NOx formation

increases exponentially as a function of temperature with the rate of formation rising very rapidly

at temperatures above about 2,400 °F.

A.4.1 NOx BACT Baseline


limits. In the case of NOx emissions, the standards of performance for stationary combustion

turbines under 40 CFR Part 60, Subpart KKKK regulate NOx emissions from the proposed

combustion turbines. Each of the proposed new natural gas-fired simple cycle combustion

turbines has a maximum heat input capacity in excess of 850 MMBtu/hr. The applicable

standards in 40 CFR Part 60, subpart KKKK are summarized in Table A-5.

Table A-5. NSPS KKKK NOx Emission Limits for New Stationary Combustion Turbines

Combustion turbine Type Combustion Turbine Heat Input

at peak load (HHV) NOx Emission Standard45

New, modified, or reconstructed

turbine firing natural gas. > 850 MMBtu/hr

15 ppmvd at 15 percent O2

or

0.43 lb/MWh


Based on a review of recent simple cycle combustion turbine BACT determinations in the RBLC

database,46 the control strategies (individually and in certain combinations) that are being used to

limit NOx emissions from natural gas fired simple cycle combustion turbines include:

Lean Premix or Dry Low-NOx (DLN) combustors;

Water or steam injection; and

Selective catalytic reduction (SCR).

A review of other available information such as vendor presentations, recent air permit

applications, EPA and state agency reports, etc. identified certain additional NOx control

strategies that are potentially available for application to the proposed CTs including:

EMx™ (a.k.a. SCONOx);

K-LEAN™ (a.k.a. XONON™);

Selective non-catalytic reduction (SNCR); and

Non-selective catalytic reduction (NSCR).

Each of these control strategies and their “availability” are reviewed in the following

subsections.

45 Standard is based on a 4-hour rolling average for simple cycle turbines. 46 U.S. EPA’s RACT/BACT/LAER Clearinghouse database accessible at http://cfpub.epa.gov/rblc/. Table D-3 in

Appendix D summarizes the control methods identified in recent NOx BACT determinations.

http://cfpub.epa.gov/rblc/

42

A.4.2.1 Lean Premix or DLN Combustors

Lean-premix combustion, often referred to as DLN combustion, is a proven NOx control option

for gas-fired combustion turbines and is therefore considered an “available” control technology

for the proposed CCEC combustion turbines. DLN combustion limits NOx formation by

minimizing combustion temperatures and equalizing the temperature variation within the

combustor. These low-NOx combustion conditions are achieved by premixing fuel with air to

create a fuel-lean mixture (i.e., an air-fuel mix that contains more air than is required for

complete combustion) prior to injection of the fuel into the combustor itself. Turbines available

for purchase in the size-range of the proposed combustion turbines are usually equipped with a

DLN combustion system. At loads between 50% and 100%, current generation DLN systems

installed on frame simple cycle natural gas-fueled turbines are capable of meeting a NOx

emissions limit of 9 ppmv (at 15% O2, dry basis). For aeroderivative gas-fueled turbines, DLN

combustors can meet an emission limit of 25 ppmv (15% O2, dry basis) over the same load

range. Note that these levels of NOx emissions from the CTs cannot be maintained during startup

or shutdown conditions because optimal firing conditions in the DLN combustors cannot be

maintained because it is necessary to augment combustor flame stability to prevent flameout

under these conditions. Flame stability is typically augmented through a fuel distribution

adjustment, which in turn results in increased NOx, CO, and VOC emissions.47

A.4.2.2 Water or Steam Injection

Water or steam injection is an alternative to DLN combustors as a means of limiting combustion

temperatures and therefore NOx emissions. In the case of frame turbines, DLN combustors are

capable of achieving lower combustion NOx emissions than can be achieved with water or steam

injection and thus, DLN technology is generally preferred for the frame combustion turbine

applications. In the case of the aeroderivative combustion turbines, water or steam injection and

DLN combustors result in similar combustion NOx emissions. However, in an aeroderivative

combustion turbine, the use of water or steam injection allows the combustion turbine to operate

at loads as low as 25% while maintaining combustion NOx emissions at target design levels.

Aeroderivative DLN combustors cannot function as effectively below about 50% load.

A.4.2.3 Selective Catalytic Reduction (SCR)

SCR is a post-combustion control technology that, for combustion turbine applications, typically

employs ammonia (NH3) in the presence of a catalyst to convert NOx to nitrogen and water

according to the following overall reactions:

4NH3 + 4NO + O2 4N2 + 6H2O

4NH3 + 2NO2 + O2 3N2 + 6H2O

An SCR system typically utilizes an injection grid to evenly disperse the NH3 into the turbine

exhaust gas upstream of a catalyst. The function of the catalyst is to lower the activation energy

of the NH3-NOx reduction reactions. Technical factors related to this technology include the

catalyst reactor design, optimum operating temperature, sulfur content of the fuel, catalyst

47 See for example,

https://www.netl.doe.gov/File%20Library/Research/Coal/energy%20systems/turbines/handbook/3-2-1-2.pdf, p. 221.

https://www.netl.doe.gov/File%20Library/Research/Coal/energy%20systems/turbines/handbook/3-2-1-2.pdf

43

deactivation due to aging, ammonia slip (i.e., unreacted NH3 emissions), and the design of the

ammonia injection system.

The simple-cycle combustion turbines under consideration for this project operate with

untampered combustion turbine exhaust reaching temperatures up to about 1,100 °F which is

above the optimum operating range for most SCR catalysts as shown in Figure A-1. To install

an SCR system for the proposed application, an air injection system is employed in the

combustion turbine exhaust to reduce the gas temperature at the catalyst inlet to around 900 °F.

At this temperature, high-temperature SCR catalysts are reasonably effective in controlling NOx

emissions as shown in Figure A-1.

Figure A-1. Operating Temperature Ranges for SCR Catalysts48

When SCR is used in combination with DLN combustors and/or water injection, the planned

simple-cycle combustion turbines can achieve a NOx emissions level of 2.5 ppmv (15% O2, dry

basis) during normal operations. This level is not as low as the 2.0 ppmv level that can be

achieved for combined-cycle combustion turbine applications due to the more effective catalysts

that can be employed at the lower exhaust temperatures found in combined cycle combustion

turbine exhaust systems and due to the impact of dilution air on the reactor inlet NOx

concentrations and distributions for simple cycle combustion turbine operations.

A side-effect of using SCR systems on natural gas fired combustion turbines is that the SCR

catalyst can contribute to condensable particulate matter emissions to the extent the catalyst

48 Source: Independent Evaluation of SCR Systems for Frame-Type Combustion Turbines, The Brattle Group, Nov.

2013.

44

promotes oxidation of SO2 across the catalyst, thereby producing SO3, which is a condensable

particulate. In addition, NH3 slip from the SCR reactor can contribute to the measured mass of

particulate matter emissions due to potential for NH3-based reactions to occur in the sampling

systems that are typically used to measure condensable particulate matter emissions.

The application of high-temperature SCR catalysts using a dilution air for temperature control is

now a demonstrated technology for simple cycle combustion turbines. This type of NOx control

system is commercially available for the combustion turbine types being considered for the

CCEC Project. It is important to note, however, that SCR cannot function effectively during

startup and shutdown periods when turbine exhaust temperatures are outside the optimum

operating window of the catalyst. NH3 is not injected during startup and shutdown conditions to

prevent excess NH3 emissions and to avoid potential for damage to the SCR catalyst.

A.4.2.4 EMx™ (SCONOX)

The EMx™ system is an add-on control device that catalytically oxidizes NO to NO2 and then

adsorbs the NO2 onto a potassium carbonate-coated catalyst surface. The overall chemical

reaction between NO2 and the potassium carbonate catalyst is as follows:

2 NO2 + K2CO3 → CO2 + KNO2 + KNO3

The EMx™ process does not require injection of a reactant, such as ammonia, into the gas

stream being treated. EMx™ catalyst is reported to perform acceptably in the operating

temperature range of 425 °F to 750 °F with the best economy and lowest pressure drop achieved

in the temperature range of 550 °F to 650 °F where the catalyst activity is highest and the

catalyst volume is minimized.49 Based on this claimed operating range, it is not feasible to install

an EMx™ system on a simple cycle combustion turbine without a massive dilution air system.50

The EMx™ catalyst has a finite capacity to react with NO2 because potassium carbonate is

“consumed” by NO2 as shown above. Thus, in order to maintain the required NOx removal rate,

the catalyst must be periodically regenerated. Regeneration is accomplished by passing a

reducing gas containing hydrogen in dilute concentration (i.e., about 2 to 4 percent H2) across the

surface of the catalyst in the absence of oxygen. Hydrogen in the regeneration gas reacts with the

nitrites and nitrates to form water and molecular nitrogen. Carbon dioxide in the regeneration gas

reacts with the potassium nitrite and nitrates to regenerate potassium carbonate, which is the

original chemical in the catalyst coating. The overall chemical reaction during catalyst

regeneration is as follows:

KNO2 + KNO3 + 4 H2 + CO2 → K2CO3 + 4 H2O + N2

49 See: http://docketpublic.energy.ca.gov/PublicDocuments/Regulatory/Non%20Active%20AFC's/07-AFC-

9%20Canyon/2009/January/TN%2049920%2001-28-09%20ECM%20Technology%20White%20Paper.pdf at page

38 of the PDF file. 50 Depending on CTG load and ambient temperatures, the amount of dilution air needed for EMx™ at 700 °F would

be two to three times the amount of dilution air needed for SCR at 900 °F. Under some operating conditions,

dilution to accommodate EMx™ could nearly double the gas flow through the combustion turbine stack.

http://docketpublic.energy.ca.gov/PublicDocuments/Regulatory/Non%20Active%20AFC's/07-AFC-9%20Canyon/2009/January/TN%2049920%2001-28-09%20ECM%20Technology%20White%20Paper.pdf

http://docketpublic.energy.ca.gov/PublicDocuments/Regulatory/Non%20Active%20AFC's/07-AFC-9%20Canyon/2009/January/TN%2049920%2001-28-09%20ECM%20Technology%20White%20Paper.pdf

45

The regeneration gas is produced in a gas generator using a two-stage process to produce

molecular hydrogen and carbon dioxide. In the first stage, natural gas and air are reacted across a

partial oxidation catalyst to form carbon monoxide and hydrogen. Steam is then added to the

mixture and passed across a low temperature shift catalyst, forming carbon dioxide and more

hydrogen. The regeneration gas mixture is diluted to less than four percent hydrogen using

steam.

In order to regenerate its catalyst, the EMx™ system is constructed in parallel modules so that a

module can be isolated from the combustion turbine exhaust gas stream using inlet and outlet

dampers. The isolated module is then regenerated while other modules remain open to flow for

treatment of the combustion turbine exhaust gas stream.

Sulfur compounds (e.g., SO2, SO3) in the gas quickly inactivate the EMx™ catalyst requiring the

catalyst to be removed from the reactor for regeneration. To avoid this problem, EMx™ systems

on natural gas fueled combustion turbines include an upstream ESx™ catalyst module that

removes the sulfur compounds before they reach the EMx™ catalyst beds. The ESx™ catalyst is

regenerated at the same time as the EMx™ catalyst by the same regeneration gas. This releases

collected SOx as SO2 into the regeneration off-gas stream.

EMx™ is demonstrated for use on relatively small combined-cycle natural gas fueled

combustion turbines. The largest application is the 50 MW Unit 6 combined cycle combustion

turbine at the Redding, California municipal power plant. EMx™ has not been demonstrated on

a large combined cycle combustion turbine or on any simple-cycle combustion turbine. The La

Paloma Generating Project in California initially proposed to demonstrate EMx™ on a 150 MW

turbine, but ultimately an SCR system was installed instead. This was also the case with the Otay

Mesa project located in California.

Some of the issues identified with applying EMx™ are51:

The catalyst is very sensitive to sulfur in the exhaust gas;

The reliability of the system’s moving parts over time is an operational and maintenance

concern;

The use of hydrogen for regeneration could be a serious safety concern;

The potential exists for scale-up issues for larger combustion turbines (such as the ones

planned for the CCEC);

An EMx™ system has about twice the pressure drop of a comparable SCR system,

presenting design challenges not currently addressed in the installed simple cycle

combustion turbine population; and

The initial capital cost is about three times the cost of SCR.

A.4.2.5 K-LEAN™

Catalytic combustion is a NOx control strategy for combustion turbines that reduces the

temperature in the combustor thereby limiting NOx formation. The only identified available

51 See: http://www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/nitrogen-oxides (last accessed

6/2/2016).

http://www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/nitrogen-oxides

46

catalytic combustion system for combustion turbines is K-LEAN™ (formerly XONON™),

available for small combustion turbines (< 20 MWe).

The use of K-LEAN™ technology on a 750 MW combustion turbine project south of

Bakersfield, California called the Pastoria Energy Facility was to have demonstrated the

technology on large combustion turbines. Instead, the project was ultimately constructed using

DLN combustion turbines equipped with SCR. Catalytic combustion technology has yet to be

demonstrated on large combustion turbines and is therefore not an “available” technology for

application to the combustion turbines that are planned as part of the proposed CCEC Project.

For this reason, catalytic combustion is not considered further in this BACT analysis.

A.4.2.6 Selective Non-Catalytic Reduction (SNCR)

SNCR involves injection of a reducing agent (ammonia or urea) into a gas stream at a

temperature window between 1,600 °F and 2,000 °F.52 The reducing agent reacts with NOx to

form nitrogen and water without the use of a catalyst. Successful application of SNCR requires

an injection system capable of mixing the reagent and exhaust gas within the appropriate

temperature window and providing sufficient residence time after mixing for the ammonia to

react with the NOx. NOx reduction efficiencies achievable with SNCR are lower than those

achievable with SCR, typically ranging from 30 to 50 percent for applications with suitable

temperature-residence time windows.53

Undiluted, the exhaust gas temperature of the planned simple cycle combustion turbines will be

less than 1,200 °F which is below the low-end of the temperature window for SNCR

applications. In addition, for the frame simple cycle combustion turbines at full firing rate, the

NOx emissions from the DLN combustors are expected to be on the order of 9 ppmv, leaving

little residual NOx for potential reaction with the injected reducing agent. Finally, SNCR has

never been applied to a simple-cycle combustion turbine for NOx control.

A.4.2.7 Non-Selective Catalytic Reduction (NSCR)

NSCR is the exhaust gas treatment technology that is used to control NOx emissions from

automobile engines and other reciprocating engines which are operated in a “rich-burn” mode.

This technology uses precious metal catalysts, such as platinum, to promote reactions between

free radical hydrocarbons, produced by fuel-rich combustion, and NOx. The reaction products

are molecular nitrogen (N2) and water.

In a hypothetical application of NSCR, the catalyst modules would have be located in the

exhaust gas path downstream of the combustors where temperatures are sufficiently high for

reaction. The major products of the reactions are molecular nitrogen, carbon dioxide, and water.

Application of this technology also requires the installation of downstream oxidation catalysts to

remove any unreacted products of the fuel-rich combustion.

52 SNCR is used in this NOx BACT analysis as a generic term that includes specific technologies such as

NOXOUT® and Thermal DeNOx™. 53 See for example, Air Pollution Control Technology Fact Sheet: Selective Non-Catalytic Reduction, U.S. EPA,

EPA-452/F-03-031.

47

Operating conditions for NSCR require rich-burn fuel to air ratios with less than about 4%

oxygen present. As a result, NSCR is only applicable to combustion systems like reciprocating

engines, where the combustion process can be tightly controlled in a fuel-rich firing zone.

Consequently, NSCR is not applicable to combustion turbines which operate with oxygen levels

on the order of 15% in the exhaust stream. There are no known applications of NSCR to

combustion turbines and there are no suppliers offering this technology for this application.

Thus, NSCR is not an “available” technology for reducing NOx emissions from natural gas

fueled combustion turbines and is therefore not considered further in this BACT analysis.


Of the potentially available NOx control options identified in Step 1, EMx™ and SNCR are

considered to be technically infeasible as discussed below.

A.4.3.1 EMx™ is Technically Infeasible

EMx™ is infeasible because it has not been demonstrated on any combustion turbine larger than

50 MW. Size is an important issue for the EMx™ process as it is more suited to small-scale

applications and it has been rejected due to size/scale-up considerations in other situations.54

More significantly, EMx™ has not been demonstrated on any simple cycle combustion turbine.

The exhaust temperature from the proposed simple cycle combustion turbines is too high for

application of EMx™ technology. And while it is theoretically possible to consider an air

dilution cooling system similar to those used for simple cycle combustion turbine SCR

applications, the volume of dilution air needed to achieve an EMx™-compatible exhaust

temperature exceeds any previous application of this technology by nearly a factor of two.

A.4.3.2 SNCR is Technically Infeasible

Because the exhaust temperatures from the proposed combustion turbines will not approach the

appropriate operating temperature window for SNCR, this technology is not technically feasible

for application to the proposed units. The maximum combustion turbine exhaust temperatures

are expected to be less than 1,200 °F which is well below the range at which SNCR is effective.


Table A-6 lists the feasible NOx control options in descending order of effectiveness. The top

performing feasible control options are either a combination of a DLN combustor and SCR or

water/steam injection and SCR. Both of these options provide an equivalent level of NOx control

as they are capable of complying with a NOx emissions limit of 2.5 ppmvd (15% O2). DLN or

water/steam injection alone are less effective options with DLN being preferred for the frame

turbines because of the low NOx levels that can be achieved. Water injection is preferred for the

aeroderivative turbines because it provides an equivalent level of emissions to DLN combustors

but can operate effectively down to loads of 25% as compared to minimum loads of about 50%

for DLN combustors.

54 See for example, In Matter of Consolidated Edison Company of New York, 2001 N.Y. ENV LEXIS 36 (NYSDEC,

Aug. 16, 2001).

48

Table A-6. NOx BACT Control Technology Ranking55

Control Strategy Frame Turbines

NOx BACT Level

Aeroderivative Turbines

NOx BACT Level

SCR + DLN/Water 2.5 ppmvd 2.5 ppmvd

DLN Combustion 9 ppmvd 25 ppmvd

Water Injection 15 ppmvd 25 ppmvd


SRP proposes to install DLN combustors in combination with SCR on the frame combustion

turbines and water injection in combination with SCR on the aeroderivative combustion turbines.

These combinations represent the most effective, demonstrated technically feasible control

strategies for the proposed combustion turbines. They have no unusual adverse energy,

environmental, or economic impacts as applied to natural gas-fired simple cycle combustion

turbines.


As discussed in subsection 0, equipment design or work practice requirements are acceptable

under the definition of BACT only when technological or economic limitations on the

application of measurement methodology would make the imposition of an emissions standard

infeasible. That criterion is not met with respect to NOx emissions from the proposed

combustion turbines as emissions will be monitored using CEMS. The use of DLN combustors

(frame units) or water injection (aeroderivative units) in combination with SCR represents the

appropriate basis for establishing the NOx BACT limits from the proposed combustion turbines.

A.4.6.1 Normal Operations

To establish the appropriate BACT limit for the combustion turbines, a review of recently

established limits in the RBLC and other recent combustion turbine permits was performed.56

This review shows that the most restrictive simple cycle combustion turbine NOx BACT limit

for normal operations has been set at 2.5 ppmvd (15% O2) with a 1-hour averaging period. SRP

has received preliminary vendor guarantees at this level of performance and therefore proposes

that the NOx BACT limit for normal operations be set at 2.5 ppmv at 15% O2, 1-hour average for

all of the proposed combustion turbines. This limit shall not apply during the combustion turbine

startup or shutdown operations.

A.4.6.2 Start-up and Shutdown Operations

The proposed NOx BACT emission limit for normal operation of the combustion turbines cannot

be met during periods of startup and shutdown. One of the reasons that normal operation

emission limits cannot be met during startup and shutdown is that the emission reduction systems

cannot operate effectively at very low loads or when the turbines are undergoing a cold startup.

55 All values are at 15% O2. 56 See Table D-3 in Appendix D for details.

49

In the case of the DLN combustors, to ensure proper function at normal operating loads, the

injector nozzles connecting the premixing chamber to the combustion chamber must be large

enough to ensure that the fuel-air mixture flows into the combustion chamber at the proper rate.

During startup and shutdown when the combustion turbine is not at an operational load, the low

fuel flow from the nozzles is insufficient to prevent the flame wall in the combustion chamber

from backing up into the premixing chamber. To avoid the risk of fuel blowback, which could

cause the premixing chamber to overheat, the premixing chamber must be bypassed when the

combustion turbine is in startup and shutdown mode. When the premixing chamber is bypassed,

the combustion turbine operates like a standard single-stage diffusion flame combustion turbine.

In the case of the water injection system, if injection is initiated at very low loads, it can impact

flame stability and combustion dynamics, and thus can increase CO emissions.

In addition to the startup requirements of the combustors, a high-temperature SCR system cannot

provide NOx control, or provides only minimal control, when the combustion turbine exhaust

temperatures are not at optimum levels. Until the optimal exhaust temperature range for the SCR

catalyst is reached and the catalysts are at operating temperature, the control devices do not

operate at design levels. As such, during startup and shutdown periods, the combustors are not

operating to minimize emissions and the SCR system is not capable of efficiently controlling the

emissions that are generated.

As these conditions are part of the expected operation of the turbines, the requirement to meet

BACT still applies. To meet this requirement, SRP proposes specific startup and shutdown NOx

BACT limits as listed in Table A-7.

Table A-7. Proposed Turbine Startup and Shutdown NOx BACT Limits

Operating Mode

NOx Emissions Limit (lb/event)

GE LMS100 GE 7F.05 Siemens

SGT6-5000F

Mitsubishi

M501GAC

Startup 21.9 44 63.3 28.7

Shutdown 6 18 44.4 23.8

These periods are defined as follows:

Startup – Length of time from initial firing of fuel in the unit to achieving minimum

emissions compliance load (MECL).

Shutdown – Length of time from MECL to unit flame out.

A.5 Combustion Turbines CO and VOC BACT Analysis

This section presents the required CO and VOC BACT analysis for the proposed combustion

turbines. CO and VOC are emitted from simple cycle combustion turbines as a result of

incomplete combustion of fuel. Therefore, the most direct approach for reducing these emissions

50

is to maximize combustion efficiency. CO and VOC emissions can also be controlled by a post-

combustion oxidation catalyst.

A.5.1 CO and VOC BACT Baseline

There are no state, local or federal regulations applicable to CO or VOC emissions from the

proposed combustion turbines. Therefore there is no “BACT baseline” for these pollutants.


Based on a review of recent simple cycle combustion turbine BACT determinations in U.S.

EPA’s RBLC database,57 the control strategies (individually and in certain combinations) that are

being used to limit CO and VOC emissions from natural gas fired simple cycle combustion

turbines include:

Dry Low-NOx (DLN) combustors;

Good Combustion Practices; and

Oxidation Catalysts.

Other potential control strategies identified include EMx™ (CO emissions only) and K-LEAN™

(CO and VOC emissions). However, as discussed in sub-section 0, K-LEAN™ is not an

available technology for purposes of establishing BACT for the proposed combustion turbines

while EMx™ is technically infeasible for application to the proposed simple cycle combustion

turbines. Thus, DLN combustors, good combustion practices, and oxidation catalysts are the only

three available control strategies for controlling CO and VOC emission from the proposed

combustion turbines.

DLN combustors are discussed in sub-section 0 while good combustion practices are discussed

in sub-section 0.

To further reduce CO and VOC emissions, an oxidation catalyst can also be used. For natural gas

fueled turbines, the typical oxidation catalyst is a rhodium or platinum (noble metal) catalyst on

an alumina support material. This catalyst is typically installed in a reactor with exhaust gas inlet

and outlet distribution plates. CO and VOC react with oxygen (O2) in the presence of the catalyst

to form carbon dioxide (CO2) and water (H2O) according to the following general equations:

2CO + O2 → 2CO2

2CnH2n+2 + (3n + 1)O2 → 2nCO2 + (2n+2)H2O

Acceptable catalyst operating temperatures range from 400 – 1,250 °F, with the optimum

temperature range of 850 - 1,100 °F. No chemical reagent addition is required for a typical

oxidation catalyst. Below approximately 400 °F, catalyst activity (and oxidation potential) is

negligible. This temperature range is generally achievable with simple cycle combustion turbines

57 U.S. EPA’s RACT/BACT/LAER Clearinghouse database accessible at http://cfpub.epa.gov/rblc/. Table D-4 in

Appendix D summarizes both the control methods and emissions limits identified in recent CO and VOC BACT

determinations.

http://cfpub.epa.gov/rblc/

51

except at low load startup and shutdown conditions. Oxidation catalysts have the potential to

achieve approximately 90% reductions in CO and VOC emissions at steady state operation.


Each of the available control strategies for limiting CO and VOC emissions is technically

feasible for the proposed frame CTs, but the use of DLN combustion is infeasible for the

aeroderivative combustion turbines planned for the CCEC due to the low loads at which the

aeroderivative combustion turbines will be required to operate (see Section 0 for details). Thus,

the proposed aeroderivative combustion turbines will use an oxidation catalyst, good combustion

practices, and water injection.

For the frame CTs, the available control strategies can be used individually or in certain

combinations and SRP plans to use all three to limit CO and VOC emissions from the CCEC

frame turbines.


The top performing feasible CO and VOC control strategy for the frame CTs is to utilize an

oxidation catalyst in combination with DLN combustors and good combustion practices to limit

CO and VOC emissions from these turbines. SRP is proposing to utilize this strategy on the

CCEC frame turbines.

Since the use of DLN is infeasible due to the low loads at which the aeroderivative CTs are

expected to operate for extended periods, the top performing feasible CO and VOC control

strategy for the aeroderivative CTs is to utilize an oxidation catalyst in combination with good

combustion practices to limit CO and VOC emissions from these turbines. SRP is proposing to

utilize this strategy on the CCEC aeroderivative turbines only.


Because SRP is proposing to utilize the top-performing feasible CO and VOC control strategy

for each planned turbine type, there is no need to evaluate impacts. Nevertheless, this strategy

has no unusual adverse energy, environmental, or economic impacts and it is therefore

appropriate that it serve as the basis for establishing the CO and VOC BACT limits for the

proposed combustion turbines.


As discussed in Section 0, equipment design or work practice requirements are acceptable under

the definition of BACT only when technological or economic limitations on the application of

measurement methodology would make the imposition of an emissions standard infeasible. That

criterion is not met with respect to CO and VOC emissions from the proposed combustion

turbines during periods of normal operation. However, that criterion is met during periods of

startup and shutdown which are too transient and brief to allow measurement of CO and VOC

emissions using standard stack testing methodologies.

52

As with NOx, the selected BACT control strategy for CO and VOC is most effective during

normal operations and less so during startup and shutdown periods. The following discussion

identifies appropriate BACT limits for each mode of turbine operation.

A.5.6.1 Normal Operations

SRP proposes that the CCEC CO BACT limit for normal operations of both the frame and

aeroderivative combustion turbines be established at 4 ppmvd (15% O2) on a 3-test average

basis. Based on a review of the RBLC and recent permit records, this proposed limit is consistent

with the lowest current CO BACT limit established for a simple cycle natural gas fired

combustion turbine. This limit has been imposed in just a few recent PSD permits (e.g., Florida

Power & Light’s Lauderdale Plant and Indeck Wharton, LLC’s Wharton Energy Center).58

According to the preliminary vendor data SRP has received, this limit can be achieved over the

expected normal operating load range of the proposed combustion turbines, but it cannot be met

during periods of startup and shutdown.

SRP proposes that the CCEC frame combustion turbines VOC BACT limit for normal operations

be established at 1.2 ppmvd (15% O2) on a 3-hour average basis. Based on a review of the RBLC

and recent permit records, this proposed limit is consistent with the lowest known current VOC

BACT limits established for a this type of combustion turbine.59 The proposed VOC BACT limit

for the aeroderivative combustion turbines is 2 ppmvd (15% O2) on a 3-test average basis. Again,

this limit is consistent with the lowest known current VOC BACT limits established for this type

of combustion turbine. The proposed VOC BACT limits can be achieved over the expected

normal operating load range of the planned turbines, but cannot be met during periods of startup

and shutdown due to the temperatures at which the oxidation catalyst is effective.

A.5.6.2 Startup and Shutdown Operations

For periods of startup and shutdown, a work practice is proposed as CO and VOC BACT due to

the inability to accurately measure emissions during these periods. Specifically, SRP proposes to

limit the total number of startup and shutdowns for the frame combustion turbines to 300 per

year, aeroderivative combustion turbines to 730 per year, to follow manufacturer recommended

startup and shutdown procedures, and to operate and maintain the CTs, air pollution control

equipment and monitoring equipment in a manner consistent with good air pollution control

practices.

A.6 Combustion Turbines GHG BACT Analysis

GHG emissions from natural gas-fired combustion turbines include carbon dioxide (CO2),

methane (CH4), and nitrous oxide (N2O). Combustion turbine CO2 emissions result from

complete combustion while CH4 emissions result from incomplete combustion of the natural gas

fuel. Methane emissions may also result from natural gas fuel leaks which may occur from

valves and piping, and during maintenance activities. Nitrous oxide (N2O) emissions from

combustion turbines result primarily from low temperature combustion.

58 Note that neither of these projects has actually commenced operation so these BACT limits have not yet been

demonstrated. 59 See: RBLC ID FL-0285. BACT limit is for a simple cycle F-Class natural gas fueled turbine.

53

Under PSD applicability, GHGs emissions are addressed as carbon dioxide equivalent (“CO2e”)

emissions that are calculated using the global warming potentials (GWP) for the various GHGs.

The GWP of CO2 is set at 1, CH4 at 25, and N2O at 298. CO2e emissions are calculated by

multiplying the emission rates of each of the GHGs with its GWP which are then summed to

compute the total GHG emissions for a unit.

Based on the emission factors and considering the proposed operating limits in this permit

application, the potential GHG emissions for the proposed combustion turbines are summarized

in Table A-8. As illustrated by the values in this table, CO2 emissions account for 99.9% of the

total GHG emissions. Because CO2 emissions account for the vast majority of GHG emissions

from the planned combustion turbines, this BACT analysis focuses primarily on control

strategies that limit CO2 emissions.

Table A-8. CO2 and CO2e PTE from the Proposed Combustion Turbines60

Turbine Make – Model CO2 PTE

(tons/year)

CO2e PTE

(tons/year)

GHGs from CO2

(wt. %)

General Electric - LMS100PA+ 432,355 432,813 99.9%

General Electric - 7F.05 2,642,458 2,645,257 99.9%

Siemens - SGT6-5000F 2,763,216 2,766,143 99.9%

Mitsubishi - M501GAC 2,715,598 2,718,475 99.9%

A.6.1 GHGs BACT Baseline


limits. In the case of CO2 emissions, the standards of performance for stationary combustion

turbines under 40 CFR Part 60, Subpart TTTT regulate CO2 emissions from the proposed

combustion turbines. Each of the proposed new natural gas-fired simple cycle combustion

turbines will be a non-baseload unit, with limits on net sales of power generated (capacity factor)

to less than the design efficiency for the unit. Therefore, the applicable standard in 40 CFR Part

60, subpart TTTT, Table 2 are summarized in Table A-9. The proposed GHG BACT limit for

the CCEC turbines cannot be any less stringent than this nominal standard.

Table A-9. NSPS TTTT CO2 Emission Limits for New Stationary Combustion Turbines

Affected EGU CO2 Emission Standard

Newly constructed or reconstructed stationary

combustion turbine that supplies its design efficiency or

50 percent, whichever is less, times its potential electric

output or less as net-electric sales on either a 12-

operating month or a 3-year rolling average basis and

combusts more than 90% natural gas on a heat input

basis on a 12-operating-month rolling average basis

50 kg CO2 per gigajoule (GJ) of heat

input (120 lb CO2/MMBtu). (Nominal

standard only.) For units burning only

natural gas, compliance is assumed, with

no requirements for emissions

monitoring or analysis of fuel carbon

intensity.

60 Values shown include startup and shutdown emissions and are totals for the project.

54


Based on a review of available information, the control strategies that may be considered to be

potentially available for reducing GHG emissions associated with the proposed combustion

turbines include:

Efficient combustion and combustion controls;

Use of lower carbon fuels;

Energy efficient generating technologies;

Use of an oxidation catalyst (to reduce CH4 emissions); and

Carbon Capture and Storage (“CCS”).

Each of these options is reviewed below.

A.6.2.1 Efficient Combustion and Combustion Controls

Efficient combustion is one means of minimizing GHG emissions from combustion sources. In

the case of the proposed combustion turbines, efficient combustion means minimizing the energy

input (i.e., the quantity of natural gas fired) per unit of energy output consistent with the intended

purpose of the facility.

Modern combustion turbines, including the ones identified as candidates for the CCEC Project,

have sophisticated instrumentation and controls to automatically control the operation of the

combustion turbine. These systems monitor the operation of the combustion turbine and

modulate the fuel and air flows, water injection rates (if applicable) and other aspects of

combustion turbine operation to achieve optimal high-efficiency low-emission performance for

full-load and part-load conditions. Thus, the selected combustion turbines and combustor designs

and the combustion turbine control systems will function to optimize combustion efficiency

while minimizing emissions of combustion-related pollutants including GHGs.

A.6.2.2 Use of Lower Carbon Fuels

As shown in Table A-10, relative to other types of fuels, the use of natural gas yields lower

combustion emissions of GHGs collectively and each greenhouse gas individually when

compared to other types of generally available fuels. Thus, combustion GHG emissions are

minimized by maximizing the combustion of natural gas. This GHG reduction measure is

inherent in the design of the proposed Project because natural gas is the only fuel that will be

used in the proposed combustion turbines.

55

Table A-10. GHG Emission Factors for Various Fuels

Fuel Emission Factor (lb/MMBtu)a

CH4 CO2 N2O CO2e

Petroleum Coke 0.0243 225.8 0.0035 227.4 Subbituminous Coal 0.0243 214.2 0.0035 215.9 Residual Oil (No. 6) 0.0066 165.6 0.0013 166.1 Crude Oil 0.0066 164.3 0.0013 164.9 Distillate Oil (No. 2) 0.0066 163.1 0.0013 163.6 Fuel Gas 0.0066 130.1 0.0013 130.6 Natural Gas 0.0022 117.0 0.0002 117.1 a Individual GHG emissions factors are from Tables C-1 and C-2 of 40 CFR 98, subpart C.

The CO2e factor is computed using the GWP of individual GHGs.

A.6.2.3 Energy Efficient Design

Certain energy efficient processes and technologies are potentially available as CO2 control

strategies for the proposed Project. As a general matter, the most cost-effective means of

reducing the amount of CO2 generated by a fuel-burning power plant is to generate as much

electric power as possible from fuel combustion, thereby reducing the amount of fuel needed to

meet the plant’s power output design targets. Potentially available energy efficient processes and

technologies include:

Efficient simple cycle combustion turbines;

Inlet air cooling;

Combined cycle combustion turbines;

Reciprocating internal combustion engines (RICE);

Renewable energy technologies such as wind or solar power generation; and

Energy storage.

Each of these concepts is discussed further in the following subsections.

A.6.2.3.1 Efficient Simple Cycle combustion turbines

As discussed in subsection 2.1 of the application, the fundamental purpose of the CCEC is to

provide peaking power to meet growing customer demand, support grid stability by quick

response to fluctuations inherent to renewable power resources, and as needed to offset

generation that cannot meet more stringent environmental regulations. The planned CCEC

configuration includes five or six frame combustion turbines complimented by two

aeroderivative units. This combination of generating units was selected as the most effective

means of providing the needed quick startup times, rapid ramp rates, wide turndown capability

and peak load capacity necessary to meet the project objectives.

For the aeroderivative turbines, SRP is proposing to install two General Electric (GE) Model

LMS100PA+ simple cycle combustion turbines for the Project. The LMS100 turbines are among

the most efficient, and therefore the lowest CO2 emitting aeroderivative simple cycle combustion

turbines commercially available at this time at 44.0% efficiency.61 The frame-style turbines

61 Efficiency at ISO, base load without ancillary equipment.

56

being considered for the CCEC Project each represent state of the art energy efficient designs

available from their respective manufacturers. The proposed frame combustion turbines achieve

39.0%+ efficiency.62 While there are some variations between the different manufacturers’

design efficiencies, these differences are all consistent with the underlying premise of an energy

efficient combustion turbine system design.

A.6.2.3.2 Inlet Air Cooling

An energy efficient design element that is potentially applicable to the proposed combustion

turbines is the use of an inlet air cooler. This type of device is typically used to enhance power

output during periods of higher ambient temperatures, but certain air cooler designs can also

provide a marginal improvement in heat rate at constant power output rates, thereby reducing the

output-normalized GHG emissions rates from the combustion turbines. The plant’s geographic

location and local climate make inlet air cooling for combustion turbines effective during those

periods when plant operations are likely to be the highest (i.e., when ambient temperatures are

elevated). Thus, the use of inlet air cooling is considered an available technology for possible

application to each of the proposed combustion turbines.

A.6.2.3.3 Combined-Cycle Combustion Turbines

Combined cycle combustion turbines are more efficient than simple cycle combustion turbines.

However, the purpose of the Project is to construct a peaking power generating station that has

certain characteristics. CCEC’s specific characteristics support the Facility objectives of meeting

customers’ growing demand, renewable resource integration support, and peak capacity

replacement. By definition, a peaking facility’s primary objective is to provide energy during the

relatively short time period when customer demand is the highest, afterwhich the units are

typically shutdown. This cycling capability, being able to startup and shut down multiple times

per day, allows the facility to follow customer load without maintenance impact. The simple

cycle frame units economically meet this criteria. Additionally, the aeroderivatives provide grid

stability by responding immediately to load variability inherent to renewable resources or other

system events. Hence, to satisfy the basic purpose of the facility, the peaking units must be able

to start quickly (even under “cold” start conditions), the units must be able to repeatedly start and

stop as needed, and the units must be able to reduce output to provide spinning reserve when

necessary.

Combined-cycle combustion turbines cannot meet the above requirements of the proposed

CCEC Project. The start-up of a combined cycle turbine system is normally conducted in three

steps:

Purging of the heat recovery steam generator (HRSG);

Combustion turbine startup, synchronization, and loading; and

Steam turbine speed-up, synchronization, and loading.

The startup process is dependent on the amount of time that the unit has been shut down prior to

being restarted. As a result, startups of a combined cycle combustion turbine generator systems

62 Ibid.

57

are often classified as “cold” starts, “warm” starts, and “hot” starts depending on the length of

time the system has been off-line. The HRSG and steam turbine must be started gradually to

avoid severe thermal stresses which can cause damage to the equipment and unsafe operating

conditions for plant personnel. For this reason, the startup time for a combined cycle combustion

turbine generator system is often much longer than that of a similarly-sized simple cycle

combustion turbine.

Even with fast-start technology, new combined cycle units can require more than three hours to

achieve full load from a cold-start, as compared to approximately 30-35 minutes to full electric

output for the simple cycle frame combustion turbines proposed as part of the CCEC Project.

The long startup time for combined cycle combustion turbines is incompatible with the purpose

of the CCEC which is to provide quick response to changes in the supply and demand of

electricity in which these combustion turbines may be required to startup, ramp quickly, and then

shutdown multiple times per day.

For the above reasons, the use of combined cycle combustion turbines would fundamentally

redefine the proposed source to such an extent that combined cycle combustion turbine systems

do not constitute an available GHG control strategy for purposes of this BACT analysis.

A.6.2.3.4 Reciprocating Internal Combustion Engines

RICE are well-suited for peaking applications and are technically feasible for the proposed

CCEC Project. However, the use of RICE would change the project in such a way that the

requirement to use RICE would fundamentally redefine the source. The capacity of largest

available RICE-powered generators that SRP has identified is on the order of 20 MW. If these

units were used for this project, this power plant would need to construct and operate 70 to 80 of

these units which would be nearly 10 times the size of the largest identified application of RICE

for a peaking power station.63 This would be a much more complex power plant to construct,

operate and maintain, and 70 or 80 generating units might not actually physically fit on the

CCEC site. Despite these fundamental differences between a RICE-powered peaking plant and

the planned CCEC simple cycle combustion turbine power plant, for the sake of completeness

RICE is evaluated further in this BACT analysis as a potentially available GHG control strategy.

A.6.2.3.5 Renewable Energy Generation Technologies

As discussed above, energy efficient generation is the key to reducing GHG emissions from

fossil fueled power plants. At the macro level, renewable energy generation technologies such as

wind or solar represent an alternative for reducing GHG emissions from power generation.

However, changing the applicant’s proposed primary fuel and process for the proposed facility

would redefine the source and is not required to be considered in the BACT analysis. Renewable

energy sources are incapable of meeting the purposes of the proposed CCEC Project because

they do not provide firm peaking power, especially as the planned peak timing shifts into later

evening hours. While renewable energy generation reduces system demand during selected

hours, the proposed CCEC Project is capable of controlled output after sunset and is also capable

of firming intermittent renewable generation. As one of the purposes of the proposed Project is to

63 See for example: http://www.pge.com/en/about/environment/pge/minimpact/humboldtbay/index.page

58

firm renewable resources, that need would be increased, not met, by the use of these alternative

generating technologies.

Renewable energy facilities require significantly more land to construct and they need to be

located in areas with very specific characteristics. Further, wind and solar facilities have power

generation profiles that cannot be readily matched to electric demand. Thus, conventional

peaking plants such as the proposed CCEC Project are needed to respond to the demand peaks

and valleys that are being exacerbated by the use of renewable energy technologies. Finally, the

capital costs for wind or solar facilities are substantially higher than for a comparable

conventional facility, making financing of such a project significantly different.

In short, the use of alternative renewable energy technologies would fundamentally redefine the

proposed source to such an extent that these technologies do not constitute an available GHG

control strategy for purposes of this BACT analysis for the CCEC.

A.6.2.3.6 Energy Storage

Energy storage options include battery storage, compressed air energy storage (CAES), and

pumped hydro storage. One control strategy that has been advocated for reducing GHG

emissions from peaking power plants is pairing energy storage with combustion turbine

generator systems. The underlying premise of this “hybrid” type of power plant configuration is

to use electricity from energy storage to serve short-term peak demands allowing more efficient

usage of fossil fueled generating equipment. For example, some groups have theorized that the

peaking function served by a simple cycle combustion turbine generator could be replicated by

an energy storage device (e.g., a battery) coupled with a more energy efficient combined cycle

combustion turbine generator system. Under this theory, the energy storage device would be

sized to handle short-term peak demands that could not be accommodated by the relatively slow

ramp rate of the combined cycle combustion turbine generator system. However, this theoretical

power plant configuration does not match the reality of available technologies needed to meet the

fundamental objectives of the CCEC Project as discussed below.

CAES involves compression of air to pressures of approximately 1,000 psi using electricity

produced during periods of low demand. The compressed air is then stored in a large

underground chamber (i.e., a salt dome) and is used to power a turbine generator during periods

of peak demand. CAES has been demonstrated in a few select locations but it is not an available

option for the CCEC Project because this storage option relies on storage of large volumes of

compressed air in underground salt domes and there are no salt domes in the vicinity of the

proposed CCEC site.

Pumped hydro storage involves pumping water from a lower to a higher elevation using

electricity produced during periods of low demand and then using the elevated water to generate

hydropower during periods of peak demand. As with CAES, there is no suitable location for

pumped hydro storage in the vicinity of the proposed CCEC site.

Battery storage involves charging batteries during periods of low demand and then drawing on

that stored energy during peak demand periods. Replacing some or all of the Project’s simple

cycle combustion turbine generating capacity with a some alternative combination of energy

59

storage and combustion turbines would not meet the design goals of the CCEC Project as this

hybrid storage-generation alternative is not capable of providing the required peak capacity

needed to meet the power demand cycles that are intended to be served by the CCEC as

described in Sections 2.1 and 5.2.3 of the application. Most of the battery installations that are

currently in operation are for voltage support and frequency regulation, and are short duration

batteries (<1hour). The largest known battery storage project proposed to date is 40 MW.64 At

this level of supply, a battery storage bank could not replace even a single aeroderivative turbine

proposed for the CCEC Project. Additionally, battery storage is typically only capable of

providing power for 4 hours – a time period that is insufficient to meet the forecast needs of the

project. Thus, the use of energy storage as a strategy for reducing facility GHG emissions would

fundamentally redefine the project and it is therefore not an available control strategy for

reducing GHG emissions from the planned CCEC.

A.6.2.4 Oxidation Catalysts

Although good combustion practices minimize CH4 emissions through optimized combustion

efficiency, a small amount of the CH4 present in the fuel inevitably remains un-combusted. To

reduce CH4 emissions even further, an oxidation catalyst can be used to convert residual CH4 in

the turbine exhaust to CO2 and H2O, thereby achieving a small reduction in GHG emissions (i.e.,

less than 0.1 percent on a CO2e basis). With an oxidation catalyst, turbine exhaust gases pass

through a catalyst bed installed in the exhaust gas path at a location where the gas temperature is

in a range between 850 °F and 1,100 °F. The oxidation of CH4 to CO2 and H2O utilizes the

oxygen present in the turbine exhaust. The presence of the catalyst lowers the activation energy

required for the CH4 oxidation reaction to proceed thereby reducing residual CH4 in the turbine

exhaust.

A.6.2.5 Carbon Capture and Storage

The final control strategy that is potentially available for reducing GHG emissions from the

combustion turbine involves capturing CO2 and “permanently” storing it. While the CCS concept

is currently receiving significant attention as a GHG control strategy, it is clearly still in the

R&D (research and development) phase and not truly an available technology. Nevertheless, for

purposes of completeness, this BACT analysis addresses the CCS process in Steps 2 through 4.

The CCS process involves three main steps:

Capturing and concentrating CO2 at its source by separating it from other constituents in

the combustion turbine exhaust gas stream;

Transporting the captured CO2 to a suitable storage location, typically in

compressed/liquid form; and

Storing the CO2 away from the atmosphere for a long period of time, for instance in

underground geological formations or in the deep ocean.

In a conventional combustion turbine design, the oxygen required for combustion of fuel is

provided by air. Because air contains about 79 percent nitrogen, the CO2 concentration in the

64 See: http://www.greentechmedia.com/articles/read/a-look-at-the-biggest-energy-storage-projects-built-around-the-

world-in-the

60

exhaust gas stream from the combustion turbines is necessarily diluted by the inert nitrogen and

excess oxygen along with other products of combustion. Further, to allow for implementation of

SCR for NOx control, dilution air is added to the turbine exhaust to cool the exhaust gases to

around 900 °F. As a result, the average CO2 concentration in the exhaust gas from the CCEC

turbines will be on the order of 3 volume percent. Therefore, capture and concentration of CO2 is

an important element of any CCS strategy that would be applied to the proposed combustion

turbines.

Capture and/or concentration of CO2 from a combustion source can theoretically be achieved

either through pre-combustion methods or through post-combustion methods. The availability of

each of these techniques for application to the proposed Project is discussed below.

A.6.2.5.1 Pre-Combustion CO2 Concentration

For some combustion sources, one option that can be used to increase the CO2 concentration in

the exhaust gas stream is to use oxygen instead of air to combust the fuel (i.e., oxy-combustion).

This technique results in a more concentrated CO2 exhaust gas stream with the combustion

exhaust gases containing primarily CO2, H2O and O2. This stream would still need to be further

processed to produce a relatively pure stream suitable for transportation and storage, but the size,

costs and complexity of downstream processing equipment are significantly reduced relative to

the equipment required if air is used in the combustion step.

Direct use of oxygen for combustion is not an available option for increasing the exhaust gas

CO2 concentration in the combustion turbines planned for the CCEC Project. Because a

combustion turbine relies on the mass flow of gasses through the turbine itself to generate power,

use of oxygen-only combustion would significantly reduce the gas mass flow through the

turbine, and thus would significantly reduce the turbine’s power output. Oxy-combustion

technology is currently under development using modified combustion turbines coupled with a

combustion system developed by Clean Energy Systems, Inc. At last report, a proof-of-concept

test on a 20 MW thermal combustion turbine has been completed and research and development

work is on-going on large scale applications of this technology. Because application of oxy-

combustion technology to combustion turbines is in the R&D stage at this time, the technology

does not meet the definition of “available” and therefore, it is not appropriate to consider it

further in this BACT analysis.

A.6.2.5.2 CO2 Capture Using Post-Combustion Techniques

Post-combustion CO2 capture methods can, in theory, be applied to conventional combustion

systems that use air and carbon-containing fuels in the combustion process. Technologies that

might be applied for post-combustion CO2 capture are described below.

Absorption of the CO2 with chemical solvents such as amines: This is currently the most

common method being evaluated for CO2 capture from combustion stack gases. This process is

illustrated in Figure A-2. Monoethanolamine (MEA) solvent has the advantage of fast reaction

with CO2 at the relatively low partial pressures found in most combustion exhaust gases. Some

of the main concerns with MEA and other amine solvents are: corrosion due to the presence of

O2 and other impurities in the exhaust gas, high solvent degradation rates because of solvent

irreversible reactions with SO2 and NOx, and the large amount of energy required for solvent

regeneration. Although this technology has not been commercially demonstrated with gas-fired

61

combustion sources similar to the proposed CCEC combustion turbines, it is conservatively

assumed to be an “available technology” for the purposes of this GHG BACT analysis because it

can theoretically be applied to a combustion turbine without affecting the turbine’s design.

One notable aspect of the capture and concentration process illustrated in Figure A-2 is that

significant amounts of steam are required by the process in the solvent regeneration step. For the

proposed Project, this increased steam demand would require the construction of a new steam

generator (e.g., a new gas-fired boiler) as part of the CCEC specifically for the purpose of

regenerating the spent MEA solvent. Generation of this steam will result in additional emissions

including a considerable quantity of GHGs as well as lesser amounts of NOx, CO, particulate

matter, and other pollutants.

Calcium cycle separation: In theory, quicklime (i.e., CaO) can be used to capture CO2 yielding

limestone, which can then be heated, releasing the captured CO2 in a concentrated stream and

regenerating the quicklime for reuse. R&D work is still required to obtain adequate sorbent

stability after regeneration. As such, this technique is not considered an “available” CO2 capture

and concentration technology for purposes of this BACT analysis.

Figure A-2. Simplified PFD of a Combustion CO2 Capture and Concentration

System

Cryogenic separation: This technique is based on solidifying CO2 by frosting it to separate it

from other gaseous components in the exhaust gas stream. However, the low concentration of

62

CO2 in the exhaust gas from conventional air-based combustion processes renders this

technology impractical. As such, this technique is not considered an “available technology” for

purposes of this BACT analysis.

Membrane separation: This technique is commonly used for CO2 removal from natural gas at

high pressure and relatively high CO2 concentrations. The low CO2 concentration expected in the

combustion turbine exhaust gas means that R&D is required to develop membranes suitable for

such an application, including the need to optimize the technology for large-scale CO2 recovery

and to minimize the energy required for separation. As such, this technique is not considered an

“available” CO2 capture and concentration technology for purposes of this BACT analysis.

Adsorption: With this technique, a combustion exhaust gas stream would be fed through a bed of

solid material with high surface area, such as a Zeolite or activated carbon. These solid materials

can preferentially adsorb CO2 while allowing other gases (e.g., nitrogen) to pass through. The

saturated adsorption bed could be regenerated by either pressure swing (low pressure),

temperature swing (high temperature), or electric swing (low voltage) desorption. Application of

adsorption to a turbine exhaust gas stream would require either a high degree of compression or

multiple separation steps to produce a high CO2 concentration from the dilute CO2

concentrations found in combustion turbine exhaust gases. This technique has not been used in

this type of application and is not suited for this type of application. As such, adsorption is not

considered an “available technology” for purposes of this BACT analysis.

Other options: There are additional potential CO2 capture/concentration measures that are still in

laboratory or conceptual stages of development, but are not discussed here because they have not

approached commercial demonstration status and therefore, they are clearly not “available”

control options for purposes of this BACT analysis.

A.6.2.5.3 CO2 Capture and Concentration Summary

Currently, the most advanced technique for capturing CO2 from combustion exhaust gases is

treatment of those gases to recover CO2 by chemical absorption using a regenerable amine

solvent. This technique has been demonstrated with combustion exhaust gas compositions that

are somewhat similar to the proposed combustion turbines.65 The most notable project is a

recently operational full-scale demonstration of an amine-based CCS system on a 139 MW coal-

fired unit at SaskPower’s Boundary Dam Power Station near Estevan, Saskatchewan, Canada.66

Thus, for the purposes of Step 2 in this BACT analysis, it is conservatively assumed that post-

combustion capture using chemical absorption can serve as a technically feasible component of a

control strategy involving CCS.

A.6.2.5.4 CO2 Storage in Geologic Formations

There are several options currently being evaluated for permanent storage of CO2. These options

include storage in various geological formations (including saline formations, exhausted oil and

65 Note that the CO2 concentration in coal-fired flue gases is dilute at about 12 volume percent, but generally higher

than the CO2 concentrations found in the stack gases exiting the planned CCEC combustion turbines which will be

on the order of 3.5 volume percent. 66 IEAGHG, Integrated Carbon Capture and Storage Project at SaskPower’s Boundary Dam Power Station,

2015/06, August 2015 (found at http://ieaghg.org/docs/General_Docs/Reports/2015-06.pdf).

http://ieaghg.org/docs/General_Docs/Reports/2015-06.pdf

63

gas fields/enhanced oil recovery, and un-mineable coal seams). Each of these options is

discussed in more detail below.

In general, the geologic formations that may be appropriate for CO2 storage consist of layers of

porous rock deep underground that are “capped” by a layer or multiple layers of non-porous rock

above them. In geologic storage, a well is drilled down into the porous rock and pressurized CO2

is injected into it. Under high pressure, CO2 turns to liquid and can move through a formation as

a fluid. Once injected, the liquid CO2 tends to be buoyant and will flow upward until it

encounters a barrier of non-porous rock, which can trap the CO2 and prevent further upward

migration.

There are other mechanisms for CO2 trapping as well. CO2 molecules can dissolve in brine, react

with minerals to form solid carbonates, or adsorb in the pores of porous rock. The degree to

which a specific underground formation is amenable to CO2 storage can be difficult to

determine. Ongoing research is aimed at developing the ability to characterize a formation before

CO2 injection in order to predict its CO2 storage capacity. Another area of research is the

development of CO2 injection techniques that achieve broad dispersion of CO2 throughout a

formation, overcome low diffusion rates, and avoid fracturing the cap rock.

Figure A-3 illustrates the status of Arizona’s CO2 storage resources. As shown, virtually all of

the potential CO2 storage capacity in Arizona is in a saline formation. Figure A-4 shows the

location of this formation, which is located just to the north of I-40 to the East of Flagstaff. The

closest distance from the CCEC to this formation is approximately 140 miles.

Figure A-3 also illustrates the degree of uncertainty presently surrounding the potential for

geologic storage of captured CO2 in Arizona. The data show the wide range of estimates of CO2

storage capacity in various geologic formations. As an example, the storage capacity estimates

for saline formations in Arizona range from a low of about 100 million metric tons to a high of

over a billion metric tons.

Some of the major unresolved issues with respect to CO2 sequestration in geologic formations

pertain to the legal framework for closing and remediating geologic storage sites, including

liability for accidental releases from these sites. In December 2010, U.S. EPA promulgated a

final rule establishing minimum Federal requirements under the Safe Drinking Water Act for

underground injection of CO2 for the purpose of geologic sequestration.67 This rule set minimum

technical criteria for the permitting, geologic site characterization, area of review and corrective

action, financial responsibility, well construction, operation, mechanical integrity testing,

monitoring, well plugging, post-injection site care, and site closure of wells for the purposes of

protecting underground sources of drinking water. In September 2011, U.S. EPA promulgated a

final rule making U.S. EPA the permitting authority for this program nationwide.68

67 75 Fed. Reg. 77230. December 10, 2010. 68 76 Fed. Reg. 56982. September 15, 2011.

64

Figure A-3. Estimate of Geologic CO2 Storage Capacity in Arizona69

There are several types of geologic formations in which CO2 can be stored, and each has

different opportunities and challenges as briefly described below.

Depleted Oil and Gas Reservoirs: These are formations that held crude oil and natural gas at

some time. In general, they are characterized by a layer of porous rock with a layer of non-

porous rock which forms a dome. This dome offers the potential to trap CO2 making this type of

formation potentially suited to GHG sequestration. As a side benefit of this type of sequestration,

CO2 injected into a depleting oil reservoir may enable recovery of additional oil and gas. When

injected into a depleting oil-bearing formation, the CO2 dissolves in the trapped oil and reduces

its viscosity. This process “frees” more of the oil by improving its ability to move through the

pores in the rock and flow with a pressure differential toward a recovery well. A CO2 flood

typically enables recovery of an additional 10 to 15 percent of the original oil in place. CO2

injection is currently being used for the purpose of EOR, but in general, the CO2 being used is

not being recovered from combustion exhaust gases.70

69 Source: http://www.natcarbviewer.com (last accessed June 8, 2016). 70 One notable exception is SaskPower’s Boundary Dam CCS demonstration project in Canada.

0

200

400

600

800

1,000

1,200

1,400

Saline Coal Oil/Gas Total

Mil

lio

n M

etr

ic T

on

ns

Arizona CO2 Storage Resource

Low Est. Mid Est. High Est.

http://www.natcarbviewer.com/

65

Figure A-4. Arizona’s Saline Formation Location

The EOR CO2 pipeline nearest to the proposed CCEC Project site is located in southwestern

Colorado as illustrated in Figure A-5. Thus, the use of CO2 captured and concentrated from the

planned CCEC turbines for enhanced oil recovery would require construction of a new pipeline

that would be on the order of 300 miles in length to connect to the existing CO2 EOR pipeline

network. Alternatively, the CO2 could be liquefied and shipped via rail or truck to a point where

it could be fed into an existing pipeline system.

Approximate

CCEC

Location

Saline

Formation

with CO2

Sequestration

Potential

66

Figure A-5. Current CO2-EOR operations and infrastructure in the U.S.71

Unmineable Coal Seams: Unmineable coal seams are seams that are too deep or too thin to be

mined economically. All coals have varying amounts of methane adsorbed onto pore surfaces,

and wells can be drilled into unmineable coal beds to recover this coal bed methane (“CBM”).

Initial CBM recovery methods (i.e., dewatering and depressurization) leave a fair amount of

CBM in the reservoir. Additional CBM recovery can be achieved by sweeping the coal bed with

nitrogen or CO2. Injected CO2 preferentially adsorbs onto the surface of the coal, releasing the

methane. Because two or three molecules of CO2 are adsorbed for each molecule of methane

released, unmineable coals seams provide a good storage sink for CO2. Like depleting oil

reservoirs, unmineable coal beds appear to be a good early opportunity for CO2 storage.

However, one potential barrier to injecting CO2 into unmineable coal seams is swelling. When

coal adsorbs CO2, it swells in volume. In an underground formation, swelling can cause a sharp

drop in permeability, which not only restricts the flow of CO2 into the formation but also

impedes the recovery of displaced CBM. Two possible solutions to this challenge include angled

drilling techniques and fracturing. Research in this area is ongoing. As shown in Figure A-3,

there are virtually no coal bed CO2 storage resources in Arizona.

Saline Formations: Saline formations are layers of porous rock that are saturated with brine.

They are much more commonplace than coal seams or oil and gas bearing rock, and saline

formations may have a significant potential for CO2 storage capacity (as illustrated in Figure

A-3). However, much less is known about saline formations than is known about crude oil

reservoirs and coal seams, and there is a greater degree of uncertainty associated with their 71 A Review of the CO2 Pipeline Infrastructure in the U.S., U.S. Department of Energy, DOE/NETL-2014/1681,

April, 2015 (available at: http://energy.gov/sites/prod/files/2015/04/f22/QER%20Analysis%20-

%20A%20Review%20of%20the%20CO2%20Pipeline%20Infrastructure%20in%20the%20U.S_0.pdf).

http://energy.gov/sites/prod/files/2015/04/f22/QER%20Analysis%20-%20A%20Review%20of%20the%20CO2%20Pipeline%20Infrastructure%20in%20the%20U.S_0.pdf

http://energy.gov/sites/prod/files/2015/04/f22/QER%20Analysis%20-%20A%20Review%20of%20the%20CO2%20Pipeline%20Infrastructure%20in%20the%20U.S_0.pdf

67

ability to store CO2. Saline formations contain minerals that could react with injected CO2 to

form solid carbonates and the carbonate reactions have the potential to be both a positive and a

negative. They can increase storage permanence but they also may plug up the formation in the

immediate vicinity of an injection well.

Saline formation CO2 storage is an area that has significant ongoing research. One of the most

advanced projects in the U.S. is a large-scale research effort aimed at evaluating the technical

and commercial feasibility of storing CO2 in the Mt. Simon sandstone saline formation which

lies more than a mile below the surface in Illinois. In the ongoing demonstration project, current

plans call for injection of approximately five million tons of CO2 into this formation through two

injection wells over a period of approximately five years. This R&D work involves

comprehensive testing and monitoring elements aimed at furthering the present understanding of

CO2 sequestration. As such, it is not appropriate to consider this geologic sequestration option an

“available technology” for purposes of this BACT analysis.72

Basalt and Organic Rich Shale Formations: Two additional geological environments being

investigated for long-term CO2 storage are basalt formations and organic shale formations.

Basalt formations are geological formations of solidified lava. These formations have a unique

chemical makeup that could potentially convert injected CO2 into a solid mineral form, thus

isolating it from the atmosphere permanently. Some key factors affecting the capacity and

injectivity of CO2 into basalt formations are effective porosity and interconnectivity. Current

efforts are focused on enhancing and utilizing the mineralization reactions and increasing CO2

flow within basalt formations.

Organic-rich shale formations are another potential geological storage option. Shale is formed

from silicate minerals, which are degraded into clay particles that accumulate over millions of

years. The plate-like structure of these clay particles causes them to accumulate in a flat manner,

resulting in rock layers with extremely low permeability in a vertical direction.

At this time, long-term CO2 storage in basalt formations and organic-rich shale basins has not

been demonstrated. Further, there are no such storage resources in the vicinity of the planned

CCEC.

A.6.3.5.4.1 Addendum to the BACT Analysis for Copper Crossing Energy Center Application for Class I Air Permit73

The greenhouse gases (GHGs) Best Available Control Technology (BACT) analysis presented in

the Sept. 2016 permit application includes, at subsection A.6.2.5.4, a general discussion of CO2

storage in geologic formations. Among the types of geologic formations discussed is saline

formations. As discussed in subsection A.6.3.5, saline formations were dismissed from further

consideration in the BACT analysis because Carbon Capture and Storage based on use of saline

72 According to U.S. EPA’s top-down BACT guidance, technologies “which have not yet been applied to (or

permitted for) full scale operations need not be considered available; an applicant should be able to purchase or

construct a process or control device that has already been demonstrated in practice.” This is not the case with

saline storage which is currently the subject of on-going R&D in an effort to commercialize this storage option. 73 Submitted to PCAQCD on June 2, 2017

68

formations is undemonstrated and not technically feasible. The discussion of CO2 storage in

saline formations in subsection A.6.2.5.4 of the permit application, and specifically Figure A-4,

implies that a saline formation in northern Arizona, located approximately 140 miles from the

Copper Crossing site, is the saline formation nearest the site.

Subsequent to filing the permit application, we became aware of a report published by the

Arizona Geologic Survey regarding the potential for CO2 sequestration in a saline formation in

the Picacho area, approximately 30 miles south of the Copper Crossing site.74 The purpose of

this addendum to the BACT analysis is to address this report and this resource.

The referenced report includes the following conclusion regarding potential for CO2

sequestration.

It is recommended that additional well log data of high quality and geophysical log suites

would be needed to adequately characterize basin-fill sediment, stratigraphy and

structure. As additional InSAR data become available, analysis may elucidate subsurface

structures in basin-fill sediment, such as bedrock topography and faults. Acquisition and

analysis of additional existing seismic data, coupled with well data, would be a valuable

and practical tool for furthering research of deep basin-fill stratigraphy and structure in

the Picacho basin for the purposes of evaluating CO2 storage potential. Additionally,

dipmeter data from new boreholes would help to validate the orientation of basin-fill

strata, and underlying mid-Tertiary units (if present). Mapping the distribution and

composition of basalt flows in further detail would to help resolve age and stratigraphic

correlation as driller-log data becomes available.

This conclusion is consistent with that presented in the permit application: Carbon Capture and

Storage using saline formations as the storage resource is not a demonstrated or technically

feasible control strategy for purposes of a GHG BACT determination, regardless of the

proximity of the saline formation to the proposed stationary source. The existence of a saline

formation in southern Arizona does not materially affect the BACT analysis.

A.6.2.5.5 CO2 Storage in the Deep Ocean

It is theorized that the oceans will eventually absorb 80 to 90 percent of the CO2 in the

atmosphere and transfer it to the deep ocean.75 Although the ocean has huge potential as a carbon

storage sink, the scientific understanding to enable ocean sequestration to be considered as a real

option is not yet available. Funding is being provided to researchers in this area to develop the

necessary scientific understanding of the feasibility of ocean sequestration. Some of this research

work is focused on understanding the mechanisms of CO2 uptake in the ocean and assessing the

environmental impacts of CO2 storage. Laboratory studies of the behavior of CO2 droplets and

CO2-H2O hydrate structures in simulated ocean environments are being conducted. Due to the

lack of commercial demonstration, this sequestration option is not considered an “available

technology” for purposes of this BACT analysis. 74 See “An Evaluation of Carbon Dioxide Sequestration Potential in Picacho Basin, Southeastern Arizona,” Arizona

Geologic Survey, OFR 15-09, November 2015. 75 See, for example, Free Ocean CO2 Enrichment (FOCE) System: Technology for Chemical and Biological Studies

of a High CO2 Ocean, Kirkwood, W. J., and Brewer, P. G., IEEE Forth International Workshop on Scientific Use

of Submarine Cables and Related Technologies 2006, February 2006.

69

A.6.2.5.6 CO2 Transportation

“Permanent” carbon storage is possible in a limited number of sites. Sequestration of CO2 from

the CCEC Project would require either transporting the CO2 to an existing CO2 pipeline for use

in enhanced oil recovery or transporting the CO2 to northern Arizona for sequestration in a saline

formation. Note that this storage option would require development and permitting of a number

of injection wells in the Arizona saline formation.

Figure A-5 shows the current state of CO2-EOR operations and infrastructure in the U.S. As

illustrated, the CO2 pipeline nearest the planned CCEC is located in southeastern Colorado.

Connecting to this pipeline would require the construction of a new pipeline approximately 300

miles long.

Given the distance to the nearest EOR pipeline, an alternative option for transportation of the

CO2 is by rail. Assuming that 90% of the CO2 from the proposed combustion turbines is captured

and converted to a liquid, its transportation would require about 5 unit trains (i.e., about 500 train

cars) a week.76 While this level of transportation is theoretically feasible, it is impractical and

thus, construction of a pipeline is the preferred solution for transportation of captured CO2.


Some of the available control strategies identified in sub-section 0 must be eliminated from

further consideration as the basis for establishing the GHG BACT limit on the proposed Project

based on technical infeasibility. The following discussion describes why, on the basis of site-

specific factors, certain available GHG control options are considered infeasible.

A.6.3.1 Efficient Combustion and Combustion Controls

The use of good combustion practices is inherent in the design of proposed combustion turbine

combustors and the combustion controls that are part of the turbine systems. Therefore good

combustion practices are a feasible GHG emissions control option for the proposed combustion

turbines.

A.6.3.2 Use of Low Carbon Fuels

The proposed combustion turbines in the Project will be fired with natural gas, which is the

lowest CO2e emitting fuel source available for use in the planned turbines. This option is

considered to be technically feasible and available. It is not currently feasible to utilize a lower

emitting fuel in the proposed combustion turbines.

A.6.3.3 Energy Efficient Design

Certain energy efficient processes and technologies are technically feasible CO2 control

strategies for the proposed CCEC Project while others are not. The following discussion reviews

the various potentially available control strategies and identifies those that are infeasible.

76 It is estimated that a single unit train would transport approximately 9,500 m3 or approximately 8,000 tons of

liquid CO2.

70

A.6.3.3.1 Efficient Simple Cycle Combustion Turbines

SRP is proposing to install a total of 7 or 8 simple cycle combustion turbines at the CCEC. Two

of these will be aeroderivative LMS100PA+ combustion turbines manufactured by General

Electric. The remaining five to six turbines will be frame-type combustion turbine generators

from one of three manufacturers. Each of the combustion turbines under consideration for this

project represents the respective manufacturers’ current state of the art design in terms of

efficiency. It is therefore technically feasible to utilize these energy efficient designs for the

CCEC Project. The planned configuration of five to six frame-type combustion turbines paired

with two aeroderivative combustion turbines was selected to fulfill the basic purpose of the

CCEC Project which is to provide between 11 MW and 1,684 MW (ISO) of nominal rapid

response peaking power to ensure reliable generation during summer conditions.

A.6.3.3.2 Inlet Air Cooling

An inlet air cooler can provide a small boost in energy efficiency as illustrated in Figure A-6.

The figure illustrates the impact of inlet air cooling on a GE combustion turbine in Houston,

Texas. This strategy would be beneficial in Arizona as well. Figure A-6 also illustrates the fact

that the use of an inlet air chiller (as opposed to an air humidification cooler or “fogging”) does

not provide any GHG emissions reduction because the parasitic load of the chiller system would

exceed the gross combustion turbine heat rate improvement resulting in a net increase in heat

rate. Thus, although available, inlet air cooling using a chiller system is not a technically feasible

GHG control strategy for the Project.

71

Figure A-6. Effect of Inlet Air Cooling on Turbine Heat Rate77

A.6.3.3.3 Reciprocating Internal Combustion Engines

The use of 70 to 80 RICE in lieu of the seven or eight planned simple cycle combustion turbines

is a theoretically feasible but impractical means of generating peaking power in an energy

efficient manner.

A.6.3.4 Oxidation Catalyst

Oxidation catalysts are commonly installed in the exhaust gas path of simple cycle natural gas-

fired combustion turbines to control emissions of CO and VOC. This same technology will

reduce CH4 emissions slightly by converting it to CO2. Because of the higher global warming

potential of CH4 compared to CO2, this oxidation reduces GHG emissions from the combustion

turbine. Thus, an oxidation catalyst is a technically feasible GHG control option for the CCEC

Project.

A.6.3.5 Carbon Capture and Sequestration

As discussed in carbon capture and storage sub-section, permanent CO2 concentration, capture

and sequestration has not been commercially demonstrated as a GHG control technique and

significant technical and legal uncertainties remain before this control option can be considered

commercially available in the context of a GHG BACT analysis. Further, this option should not

be considered a technically feasible GHG control option in the context of determining BACT for

77 Source: GT Inlet-air Cooling Boosts Output on Warm Days to Increase Revenue, Punwani, D.V. and Pasteris, R.,

Combined Cycle Journal, Q4 2003.

72

the CCEC Project because it is unclear that an acceptable long-term storage option can be

identified. Nonetheless, in order to ensure that this BACT analysis is conservative, it is assumed

that CCS is feasible. The assumption of feasibility incorporates the assumption that the captured

CO2 would be liquefied and transported to the existing CO2 pipeline in southwestern Colorado

for use in enhanced oil recovery. All other CCS sequestration options are considered infeasible

for purposes of this BACT analysis based on the development status and/or uncertainties

surrounding the use of other carbon sequestration alternatives.


The baseline GHG control strategy for the Project involves the use of natural gas as a fuel, the

use of good combustion practices, the use of an energy efficient design that incorporates an inlet

air cooler, and the use of an oxidation catalyst. All of these control techniques are inherent in the

design and intended operation of the proposed combustion turbines. Thus, this equipment

configuration serves to define the baseline GHG emissions rate for the GHG BACT analysis.

Because it involves the combustion of natural gas, this baseline case is at least as stringent as the

nominal emission standard for CO2 in the applicable NSPS (40 CFR Part 60 Subpart TTTT).

Potential GHG emissions from the proposed Project with this control strategy total

approximately 3.2 million tons per year on a CO2e basis.78

The top-ranked GHG control strategy, which is assumed to be technically feasible for purposes

of this BACT analysis, involves the application of CCS to the baseline emissions from the

combustion turbines. Assuming 90 percent capture efficiency of CO2, this control strategy would

reduce GHG emissions from the combustion turbines to approximately 320,000 tons per year.79,

80 For purposes of this BACT analysis, it is assumed that 100 percent of the captured CO2 would

be permanently sequestered although actual sequestration efficiency is likely to be less than 100

percent.

The second-ranked GHG control strategy, which is assumed to be technically feasible for

purposes of this analysis involves the use of between 80 and 90 natural gas fueled RICE

generator sets in lieu of the planned seven or eight simple cycle combustion turbine generator

sets. This option might be expected to reduce GHG emissions by up to 15 percent.81 Thus, this

control strategy would reduce potential GHG emissions during normal operations from about 3.1

to 2.6 million tons per year.

78 This value is for Scenario 2 which has the highest CO2e emissions PTE. 79 A capture efficiency of 90% is typical of the efficiencies that have been used in studies of CO2 capture systems

installed on natural gas combustion sources. See, for example, Cost and Performance Baseline for Fossil Energy

Plants Volume 1: Bituminous Coal and Natural Gas to Electricity Revision 2, DOE/NETL-2010/1397,

November, 2010. Virtually all of the GHG emissions from the combustion turbine are in the form of CO2. 80 This value does not include the additional GHGs that would be emitted due to operating the CCS equipment (i.e.,

about 500,000 T/yr additional GHG emissions). Net GHG reductions from application of CCS are shown in

Table 5-10. 81 CO2 emissions for 100% load normal operation of large RICE-generator sets (e.g., Wartsila’s 18V50SG with a

nominal rating of 18.7 MWgross) are estimated at 957 lb/MWh (gross output, base load) while the CO2 emissions

from the planned CCEC turbines are estimated at 1,130 lb/MWh (gross output, base load, ISO conditions) based on

the planned combination of frame and aeroderivative simple cycle units (Scenario 2).

73


For the purposes of the following evaluation of the impacts of applying CCS to the Project,

chemical absorption using an amine-based solvent is assumed to represent the best CO2 capture

option available and disposition of the captured CO2 in an EOR CO2 pipeline is assumed to

represent the best option for long-term storage. Under this GHG control scenario, the combustion

exhaust gases from the turbines would be ducted from turbine outlet to an absorption system

where the gases would be quenched and then the CO2 would be captured in an amine solution.

The amine solution would be regenerated to release the CO2 as a concentrated stream which

would then be dehydrated and compressed into a liquid. The liquid CO2 would be transported to

the EOR pipeline end-user via a new 300-mile pipeline running from the CCEC site to

southwestern Colorado.

As discussed previously, permanent CO2 capture from a combustion turbine exhaust gas has not

been commercially demonstrated as a GHG control technique and significant technical

uncertainties remain. In addition, as shown by the following discussion, the adverse economic,

energy, and environmental impacts of CCS as applied to the Project are significant and beyond

those that should be considered acceptable in establishing a BACT limit for GHG emissions

from the proposed combustion turbines.

For the GHG control strategy based on substituting RICE for simple cycle combustion turbines,

it is assumed that a total of ninety 18.7 MWgross engine-generator sets would be required and that

the BACT limits established for a recent large-scale RICE installation in Kansas are

representative of the BACT limits for this type of installation elsewhere.

A.6.5.1 Economic Impacts Evaluation

The top-performing GHG emissions control option is the application of CCS to the proposed

combustion turbines. To implement CCS, the exhaust gases from the combustion turbines would

be routed to an amine absorption unit to concentrate the CO2 from around 3% to approximately

90%. This concentrated CO2 stream would then need to be dehydrated and compressed from

ambient pressure to about 2,200 pounds per square inch. The costs of CCS including

concentration, dehydration, compression, and transportation are substantial as shown in Table

A-11 and as summarized below.

74

Table A-11. Summary of CCS Impacts Analysis for the Project82

Parameter Value

Economic Impacts

CCS+Pipeline: Total Installed Cost 2,282,410,874 $

Annualized Costs 383,272,171 $/year

Net GHG Reduced 2,790,325 ton/year

Control Cost-Effectiveness 137 $/ton

Environmental Impacts (CCS Steam & Power Related Emissions)

Increased NOx Emissions 81 T/year

Energy Impacts

Increased CCS Power Demand 458,585 MWh/year

Increased CCS Natural Gas Demand 14,301 MMSCF/year

As shown in Table A-11, the estimated capital cost for the equipment and infrastructure needed

for concentration and compression of CO2 from planned CCEC Project is in approximately $2.3

billion which is approximately two times the cost of the Project itself. The annualized cost of

implementing CCS, including operating and maintenance costs and the costs of CO2

transportation, is estimated to be in excess of $380 million per year. The resulting control cost-

effectiveness of CCS is approximately $137 per ton of CO2 sequestered.

The next best performing GHG control strategy is to utilize RICE generator sets in lieu of the

simple cycle combustion turbines. The estimated installed cost for this control strategy is on the

order of $1,000/kW vs. an installed cost for advance simple cycle combustion turbines on the

order of $700/kW. 83, 84 This difference translates to an increase in project costs on the order of

$500 million or about a 40% increase in the cost of the proposed Project. Assuming a 20-year

capital recovery period and further conservatively assuming that operating and maintenance

costs are approximately equivalent for the two plant designs, this installed cost difference

equates to a GHG control cost of approximately $100 per ton.85

The estimated control cost for the application of CCS to the CCEC Project is approximately

$137 per ton of CO2 reduced while the control COST of RICE is estimated at about $100 per ton.

82 See Appendix E for details of how the values in this table are determined. 83 See: Catalog of CHP Technologies - Section 2. Technology Characterization – Reciprocating Internal

Combustion Engines, U.S. EPA Combined Heat and Power Partnership, March 2015, Table 2-4.

(https://www.epa.gov/sites/production/files/2015-

07/documents/catalog_of_chp_technologies_section_2._technology_characterization_-_reciprocating_internal_com

bustion_engines.pdf). 84 See: Updated Capital Cost Estimates for Utility Scale Electricity Generating Plants, Energy Information Agency,

April 2013, Table 9-1. (http://www.eia.gov/forecasts/capitalcost/pdf/updated_capcost.pdf) 85 See Appendix E for details of how this value is determined. It is assumed that the fuel savings realized for a

RICE-powered peaking station would be offset by increased O&M costs due to the fact that ten times as many

generators would have to be operated and maintained at a RICE-powered generating station.

75

These costs are well above the range of cost effectiveness values considered to be reasonable or

acceptable in BACT determinations for control of GHG emissions. For example:

In making the GHG BACT determination for Copano Processing, U.S. EPA determined

that control of GHG emissions at a cost-effectiveness of $54/ton is not BACT because it

is “economically prohibitive.”86

In making the GHG BACT determination for the City of Palmdale, U.S. EPA determined

that control of GHG emissions at a cost-effectiveness of $45/ton is not BACT because it

is “economically infeasible.”87

In making the GHG BACT determination for Valero’s McKee Refinery, U.S. EPA

determined that control of GHG emissions at a cost-effectiveness of $134/ton is not

BACT.88

In making the GHG BACT determination for Freeport LNG Development, L.P.’s

Freeport LNG Liquefaction Project, U.S. EPA determined that control of GHG emissions

from the amine treatment units was cost prohibitive. The cost effectiveness of this control

option was estimated at approximately $14/ton of CO2 sequestered.89

As another benchmark, California Carbon Allowances for December 2016 delivery are currently

quoted at less than $13 per ton.90

Pursuant to a long-standing policy of U.S. EPA, cost effectiveness as described above, is an

appropriate metric for evaluating economic impacts in Step 4 of a top-down BACT analysis.

Based on these values and the impact that CCS would have on the required capital investment

(i.e., increasing the project capital costs by nearly $2.3 billion which would nearly triple the cost

of the CCEC), the cost of applying CCS to the combustion turbines proposed under the CCEC

Project of approximately $137 per ton of CO2 sequestered is unreasonable. In conjunction with

the significant adverse energy and environmental impacts of CCS for this application, even if

assumed to be technically feasible, this control option does not represent an appropriate basis for

establishing a BACT limit for the CCEC Project.

86 Statement of Basis: Draft Greenhouse Gas Prevention of Significant Deterioration Preconstruction Permit for the

Copano Processing, L.P., Houston Central Gas Plant, Permit Number: PSD-TX-104949-GHG. U.S. EPA Region

6, December 2012. (Cost effectiveness calculated based on listed cost of $10.9 million/yr for annual emission

reduction of 202,000 tons per year.) 87 Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Palmdale

Hybrid Power Project. U.S. EPA Region 9, October 2011. (Cost effectiveness calculated based on listed cost of

$78 million/yr for annual emission reduction of 1.7 million tons per year.) 88 Statement of Basis: Draft Greenhouse Gas Prevention of Significant Deterioration Preconstruction Permit for the

Diamond Shamrock Refining Company, L.P., Valero McKee Refinery Permit Number: PSD-TX-861-GHG,

July 2013, p. 7; and Diamond Shamrock Refining Company, L.P., a Valero Company Greenhouse Gas Prevention

of Significant Deterioration Permit Application for Crude Expansion Project Valero McKee Refinery Sunray,

Texas, Updated December 2012, p. 4-15. 89 Statement of Basis: Draft Greenhouse Gas Prevention of Significant Deterioration Preconstruction Permit for the

Freeport LNG Development, L.P., Freeport LNG Liquefaction Project, Permit Number: PSD-TX-1302-GHG,

December 2013, p. 31; and Greenhouse Gas PSD Application, Freeport LNG Development, L.P., December 2011,

p. 10-21. 90 See: BGC California Monthly Market Report, June 1, 2016.

76

Similarly, the use of RICE in lieu of simple cycle combustion turbines, even if assumed to be

technically feasible, is both economically unreasonable and has even greater adverse

environmental impacts which are off-set by a modest decrease in energy use. A RICE-based

project would increase the Project costs by about 40% resulting in GHG control costs of

approximately $100 per ton while increasing other criteria pollutant emissions by significant

amounts.

A.6.5.2 Energy Impacts Evaluation

The electric power that would be required to compress captured CO2 from the CCEC Project is

approximately 460,000 MWh/year, which is a significant, adverse energy impact associated with

the CCS control strategy. This is approximately 3% of the maximum potential power output of

the CCEC and it represents enough electricity to power about 42,000 average American homes.91

In addition, more than 16 billion cubic feet of natural gas would be consumed annually in

generating the steam needed to operate the CO2 capture and concentration system. This is

enough natural gas to heat about 220,000 average U.S. homes during a winter.92

The use of RICE generator sets in lieu of the proposed simple cycle combustion turbines would

save an estimated 15% of the natural gas fuel consumed by the proposed Project. At the

maximum potential fuel consumption rate for the Project, this is equivalent to about 8 billion

cubic feet of natural gas annually or enough to heat about 120,000 homes during the winter.

A.6.5.3 Environmental Impacts Evaluation

The adverse environmental impacts of implementing CCS for controlling CO2 emissions from

the proposed Project are those associated with the collateral increase in pollutants emitted from

steam and electrical generation required to meet the CCS system’s steam and power demands

described above. These emissions include more than 100 tons of NOX per year which would

increase the project’s NOx emissions by one-third. There would also be lesser increases in

emissions of other pollutants such as PM10, PM2.5, CO, VOC, SO2, and HAP.93 The Project site

is located in PM10 nonattainment area where additional PM10 emissions could make the Project

a major source of PM10 and may further exacerbate the ambient air quality.

Significant adverse environmental impacts would result from using RICE generator sets in lieu

of simple cycle combustion turbines for the proposed Project. These impacts occur due to the

higher emission rates of NOx, PM10/PM2.5, CO, and VOC from RICE as compared to simple

cycle combustion turbines (when compared at BACT levels for each technology). For periods of

normal operation, these increases are summarized in Table A-12 below. As shown, powering

the CCEC with RICE in lieu of simple cycle combustion turbines would cause NOx and

PM10/PM2.5 emissions to more than double, CO emissions would increase by a factor of four,

and VOC emissions would increase by a factor of 40.

91 Source: based on the 2014 U.S. average annual consumption rate of 10,935 kWh per year:

http://www.eia.gov/tools/faqs/faq.cfm?id=97&t=3 (last accessed July 8, 2016). 92 Based on March 2015 EIA estimates that an average home heating with gas consumed 64,800 cubic feet of natural

gas during the winter of 2014/15 (see: http://www.eia.gov/tools/faqs/faq.cfm?id=867&t=8 Table WF01 - last

accessed July 8, 2016). 93 Note that the increase in GHG emissions resulting from steam generation are already accounted for in determining

the “net” GHG reductions shown in Table A-11.

http://www.eia.gov/tools/faqs/faq.cfm?id=97&t=3

http://www.eia.gov/tools/faqs/faq.cfm?id=867&t=8

77

Table A-12. Comparison of RICE and CCEC Turbine Emissions94

Pollutant

[A]

RICE PTE

(tons/year)

[B]

CCEC Turbine PTE

(tons/year)

[A – B]

RICE Increase

(tons/year)

NOx 606 219 387

PM10/PM2.5 373 68 305

CO 1,098 194 904

VOC 1,656 31 1,625


Based on the significant costs and other adverse impacts of the potentially more effective control

strategies, SRP concludes that the GHG BACT limit for the Project should be based on the

following: the use of natural gas as a fuel, modern energy efficient simple cycle combustion

turbine designs, the use of good combustion practices through proper operation and maintenance

of the combustion turbine combustor systems, and the use of an oxidation catalyst.

As discussed in section A.2.2, equipment design or work practice requirements are acceptable

under the definition of BACT only when technological or economic limitations on the

application of measurement methodology would make the imposition of an emissions standard

infeasible. That criterion is not met with respect to GHG emissions from the proposed

combustion turbines. Thus, the combustion turbine GHG BACT limits must be emission limits

rather than design or work practice standards.

Combustion turbine BACT emission limits must be achievable at all times and across all load

ranges for which the turbines are designed to operate. As described earlier in this application, the

CCEC combustion turbines must have the ability to start quickly, ramp load quickly, and idle at

low loads. To meet these requirements, the aeroderivative combustion turbines are designed to

operate at loads as low as 25% of their maximum output capability while the frame combustion

turbines are designed to operate at loads as low as 50%. Thus, the GHG BACT limits must be

established such that the limits are consistent with the expected combustion turbine emissions

while operating at such loads.

In general, the CO2 emission rate per unit of output of a combustion turbine increases as the load

is decreased. In addition, the CO2 emission rate may vary between individual combustion

turbines of the same model due to normal variations in the manufacturing process. And even

with proper operation and maintenance, the constant-load production-normalized CO2 emission

rate is expected to rise over time due to the normal operation and wear of a combustion turbine’s

components which cause a slight decrease in efficiency. The effect of these factors is that the 94 Values shown are for normal operation (i.e., they do not include startup and shutdown period emissions) and are

based on 5.55 million MWh/yr of generation. For the CCEC, values are the maximum from any of the three possible

frame turbine suppliers. The RICE emissions are based on BACT limits from KDHE Permit No. 0670173 C-10021

(see: http://www.kdheks.gov/bar/midkanec/0670173_MKEC_Rubart_PSS_Final_1_28_13.pdf). See Appendix E for

additional details.

78

constant-load production-normalized CO2 emission rate can be up to 6% above the “as-new”

turbine design values even with proper operation and maintenance of a highly efficient

combustion turbine.

Table A-13 lists the expected long-term average combustion turbine CO2e emission rates and

proposed BACT limits, expressed in pounds of CO2e per megawatt hour of gross electric output

(lb CO2e/MWhgross) at the expected combustion turbine operating loads and temperatures. The

values in Table A-13 include both startup and shutdown emissions and a 6% increase above the

“as-new” design values to account for variability and degradation.95

Table A-13. Proposed CO2 Emission Rates for CCEC Combustion Turbines96

Turbine Make - Model CO2e Emission Rate

(lb/MWhgross)

General Electric - LMS100 1,425

General Electric - 7F.05 1,313

Siemens - SGT6-5000F 1,417

Mitsubishi - M501GAC1 1,335

The values in Table A-13 are generally consistent with recent simple cycle turbine GHG BACT

determinations which average 1,362 lb/MWh and range from 1,138 to 1,707 lb/MWh.97 It is

appropriate that the proposed site-specific turbine GHG limits differ from the lowest (and

highest) of these recent BACT limits given the fact that the proposed limits are based on the

unique site conditions at the CCEC, the specific turbine generators being considered for this

project, and the projected operating load profiles for those turbines. The discussion below

provides further support for this conclusion.

U.S. EPA provided a framework for addressing the variation of combustion turbine efficiency

and resulting GHG emission rates as a function of load in a PSD permit action in 2012.98

Because it is not possible to predict the extent of part-load operation over the life of the

generating facility and because peaking plants are designed to meet a range of operating levels,

EPA stated that “it would be inappropriate to establish a permit limit that prevents the facility

from generating electricity as intended.”99 EPA determined that the appropriate methodology for

95 This allowance for degradation is consistent with previous GHG BACT determinations. See for examples:

Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Pio Pico

Energy Center, U.S. EPA, November 2012. 96 See Appendix E for the underlying basis for the values in this table. 97 See Table D-5 in Appendix D for details. 98 See: Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Pio

Pico Energy Center, November 2012, p. 7. Available at:

http://docketpublic.energy.ca.gov/PublicDocuments/Regulatory/11-AFC-

1%20Pio%20Pico/2012/November/TN%2068643%2011-19-

12%20US%20EPA%20Responses%20to%20Public%20Comments%20on%20Proposed%20PSD%20Permit.pdf

And Title V Operating Permit Revision and Prevention of Significant Deterioration Air Pollution Control Permit

Application Ocotillo Power Plant Modernization Project, September 30 2015, p. 62. Available at:

https://yosemite.epa.gov/OA/EAB_WEB_Docket.nsf/Filings%20By%20Appeal%20Number/FC8890EB564F2E6A

85257F9D00635EE7?OpenDocument (Attachment 5). 99 Ibid., p. 15.

https://yosemite.epa.gov/OA/EAB_WEB_Docket.nsf/Filings%20By%20Appeal%20Number/FC8890EB564F2E6A85257F9D00635EE7?OpenDocument

https://yosemite.epa.gov/OA/EAB_WEB_Docket.nsf/Filings%20By%20Appeal%20Number/FC8890EB564F2E6A85257F9D00635EE7?OpenDocument

79

setting the GHG BACT emission limit was to set the final BACT limit “at a level achievable

during the ‘worst-case’ (i.e., lowest load) of normal operating conditions.” This same

methodology has been used to develop the GHG BACT limits for the proposed combustion

turbines.

Because the BACT emission limit must be achievable across all load ranges for which the

combustion turbines are designed and intended to operate, and because the CCEC Project

turbines are intended to operate continuously at loads as low as 25% for the aeroderivative

turbines and 50% for the frame turbines, the lowest achievable BACT emission limit for these

turbines are the values shown in Table A-13.

Because combustion turbine’s output-normalized GHG emission rate varies with ambient air

temperatures, and because the operating load will vary not only with the time of day but also the

time of year, the averaging period for the proposed GHG BACT emission limit must be 12

months to appropriately encompass the expected variability in operation. A 12-month rolling

average basis is consistent with the majority of recent turbine CO2 BACT emission limits, and is

also consistent with the CO2 emission standards under 40 CFR 60, subpart TTTT.

In the preamble to the proposed NSPS 40 CFR Part 60 Subpart TTTT, EPA stated “This 12-

operating-month period is important due the inherent variability in power plant GHG emissions

rates.”100 EPA went on to say “a 12-operating-month rolling average explicitly accounts for

variable operating conditions, allows for a more protective standard and decreased compliance

burden, allows EGUs to have and use a consistent basis for calculating compliance (i.e., ensuring

that 12 operating months of data would be used to calculate compliance irrespective of the

number of long-term outages), and simplifies compliance for state permitting authorities.”101

Further, EPA has stated that “annual averaging periods are appropriate for GHG limits in PSD

permits because climate change occurs over a period of decades or longer, and because such

averaging periods allow facilities some degree of flexibility while still being practically

enforceable”.102 For these reasons, SRP proposes that the CCEC turbine GHG BACT limits be

based on a 12-month rolling average, and should include all periods of operation including

startup and shutdown.

SRP proposes to demonstrate compliance with the proposed GHG BACT limits on a monthly

basis by using CO2 CEMS as a surrogate for all GHGs with the appropriate adjustment factor to

account for CH4 and N2O emissions based on the emissions factors in 40 CFR Part 98, Tables

C-1 and C-2.

100 79 Fed. Reg. 1430, January 8, 2014. See 1481 101 Ibid. 102 Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Pio Pico

Energy Center, November 2012, p. 33.

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A.7 Wet Surface Air Coolers and Cooling Tower PM/PM2.5 BACT Analysis

The CCEC Project will employ two types of cooling processes. There will be a single

mechanical draft direct contact cooling tower for the aeroderivative combustion turbines and

there will be three wet surface air coolers for the frame combustion turbines. This section

presents the required PM/PM2.5 BACT analysis for the four cooling processes. In both

mechanical cooling tower and WSACs, cooling is provided by evaporation of recirculating water

into a stream of flowing air. A small amount of this water is entrained in the air stream in the

form of liquid droplets or mist. Demisters (i.e., drift eliminators) are used at the air discharge

point of cooling towers and WSACs to reduce the quantity of water droplets entrained in the air.

The water droplets that pass through the demisters and are emitted to the atmosphere are known

as drift. As these droplets drift from the cooling processes, they tend to evaporate and the solids

in the droplet become particulate matter emissions. Therefore, the proposed cooling tower and

WSACs emit PM, PM10, and PM2.5.

The size distribution of the particulates emitted from a particular cooling process is a function of

two main factors – the size distribution of the wet droplets emitted and the solids content of the

droplets. A well-established model of droplet drying is that a droplet dries to form a single

particle.103 Thus, for any given wet particle size, larger wet droplet diameters and higher droplet

the solids contents form larger dry particles. The converse is true in that smaller wet droplets and

lower solids contents produce finer particles.

The maximum target total dissolved solids (TDS) level in the CCEC cooling water is

5,000 ppmw. This level provides an appropriate balance between water usage, equipment

reliability, and particulate emissions.

A.7.1 PM/PM2.5 BACT Baseline

There are no state, local or federal regulations applicable to the PM/PM2.5 emissions from the

proposed CCEC cooling processes. Therefore there is no “BACT baseline” for this unit-pollutant

group.


Two control strategies were identified for limiting particulate matter emissions from the

proposed cooling tower and WSACs:

Use of high-efficiency drift eliminators; and

Reducing the TDS content of cooling water.

Each of these techniques is discussed further below.

103 See for example, Modeling of Particle Formation During Spray Drying, Haung, D. European Drying Conference

– EuroDrying’ 2011, October 2011 (available at http://www.uibcongres.org/imgdb/archivo_dpo10983.pdf).

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A.7.2.1 High-Efficiency Drift Eliminators

High-efficiency drift eliminators (also known as mist eliminators or demisters) reduce cooling

water drift by collecting entrained droplets at the point of air discharge from the cooling tower

and WSACs. These drift eliminators function by forcing the airstream leaving a cooling unit to

make changes in direction. When the air is forced to change direction, the inertia of any

entrained drift droplets keeps them moving in a straight line, causing them to impact the wall of

the drift eliminator where they coalesce and then drain back into the wet section of the cooling

unit. A simplified illustration of this process is shown in Figure A-7 below.

Figure A-7. Typical Cooling Tower Drift Eliminator Process

High-efficiency drift eliminators reduce emissions of particulate matter of all sizes, regardless of

TDS level. They are most effective at reducing emissions of larger droplets because the larger

droplets are more susceptible to collection via inertial impaction. The most effective,

commercially available drift eliminators for cooling processes in the size ranges required for the

CCEC Project have a vendor-specified maximum total liquid drift of 0.0005 percent of the

circulating water flow rate. This value is consistent with the lowest cooling tower BACT limits

identified in the RBLC.104

A.7.2.2 Circulating Water TDS Reduction

The reduction in cooling tower and WSACs particulate matter emissions achievable through

reductions in TDS content is complex. Any reduction in TDS content will achieve a

proportionate decrease in total PM emissions (i.e., all emissions of finely divided solid or liquid

material, other than uncombined water, with an aerodynamic diameter less than 100 μm).

However, the particle size of a dried drift droplet is dependent upon TDS since higher TDS

levels result in larger dried particle sizes and lower TDS levels result in smaller dried particle

sizes. As a result, under certain circumstances, a reduction in TDS can actually cause an increase

in PM10 and/or PM2.5 emissions.


Both of the identified control options are technically feasible and are therefore considered further

in this BACT analysis.

104 See Table D-6 Appendix D for details.

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The most effective control strategy for limiting PM and PM2.5 emissions is the use of a high

efficiency drift eliminator. Using such a drift eliminator in combination with reduced TDS levels

is also effective in reducing PM emissions, but less so in reducing PM2.5 emissions as illustrated

below.

Using a generally accepted model to determine cooling tower particulate matter size distributions

from a hypothetical cooling tower equipped with a high-efficiency drift eliminator, the effect of

TDS can be assessed.105 Assuming a circulation rate of 50,000 gpm, a drift rate of 0.0005 percent

(the most effective level identified in recent BACT determinations) and a cooling water TDS

content of 5,000 ppmv, particulate matter emissions from this cooling tower are estimated as

follows:

PM: 0.63lb/hour

PM10: 0.19 lb/hour

PM2.5: 0.001 lb/hour

The following emissions model results show the effect of reducing the TDS content in this

hypothetical cooling tower on particulate matter emissions using a 20 percent reduction in TDS

for illustration purposes (i.e., an assumed TDS content of 4,000 ppmv):

PM: 0.50 lb/hour

PM10: 0.19 lb/hour

PM2.5: 0.001 lb/hour

These results show that although reducing TDS content of the recirculating water in the cooling

tower by 20% would achieve a 20% reduction in total PM emissions, there would be no material

change in either PM10 or PM2.5 emissions. Based on the above assessment, moderate reductions

in the cooling water TDS level would be expected to have little effect on PM2.5 emissions in the

specific case of the planned CCEC cooling processes.


For new construction, the use of a high-efficiency drift eliminator that is capable of achieving a

drift loss rate of 0.0005 % has no material adverse energy, environmental, or economic impacts

while providing material reductions in PM and PM2.5 emissions. Combining this control

strategy with lower cooling water TDS levels can result in further modest reductions in PM

emissions but it would be expected to have minimal impact on PM2.5 emissions from the

proposed CCEC cooling tower and WSACs. However, any reduction in TDS content would

result in increased water usage. For example, assuming that a TDS level of 5,000 ppmw

represents 10 cycles of concentration (i.e., assuming the influent water has 500 ppmw of TDS), a

reduction of the circulating water TDS level to 4,000 ppmw would increase the cooling tower

105 See Calculating Realistic PM10 Emissions from Cooling Towers, Reisman, J and Frisbie, G., July 2002. See

Appendix Efor additional details. Note that the measured drift rate that underlies the droplet size distribution used in

the cited study is similar to the proposed drift rate which means the “Resiman and Frisbie” analysis methodology is

appropriate for the planned CCEC cooling towers.

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makeup water rate by approximately 25%. Given the desirability of minimizing water

consumption at the CCEC and the trivial particulate matter decreases that may be achieved,

reductions in TDS content below 5,000 ppmw do not represent the appropriate basis for

establishing the cooling tower and WSACs PM/PM2.5 BACT limits.


As discussed in sub-section 0, equipment design or work practice requirements are acceptable

under the definition of BACT when technological or economic limitations on the application of

measurement methodology would make the imposition of an emissions standard infeasible. That

criterion is met with respect to particulate matter emissions from the cooling tower and WSACs

due to their physical configuration. Therefore, SRP proposes that a design standard – installation

of drift eliminators with a maximum drift rate specification of 0.0005 percent or less – be

established as BACT for PM/PM2.5 emissions from the cooling tower and each of the WSACs.

This design standard is consistent with the most stringent recently established PM/PM2.5 BACT

limits identified.

A.8 Cooling Tower VOC BACT Analysis

This section presents the required VOC BACT analysis for the four planned CCEC cooling

processes. Inorganic chlorine compounds will be added to the circulating cooling water to inhibit

bacterial growth in the cooling water systems. It is theorized that a small amount of chloroform

(a VOC) may be produced in the cooling water due to reaction of chlorine with organic matter

which, if accurate, would result in a trace amount of chloroform emissions from the cooling

processes. The estimated total VOC PTE of the four CCEC cooling processes is 0.06 tons per

year. At this rate, the concentration of VOC in the cooling tower exhaust air stream will be less

than 1 ppbv which is near the detection limit of EPA Method TO-14.

A.8.1 VOC BACT Baseline

There are no state, local or federal regulations applicable to the VOC emissions from the planned

CCEC cooling processes. Therefore there is no “BACT baseline” for this unit-pollutant group.

A.8.2 Steps 1 – 5

A review of the RBLC and other information sources did not identify any VOC control strategies

for EGU cooling processes similar to those planned for the CCEC. VOC BACT requirements for

cooling towers in petroleum refineries and similar sources are based on addressing leaks of

volatile organic compounds from process streams into cooling water streams. These VOC

control methodologies are not applicable to addressing trace VOC emissions that result from

reactions of inorganic chlorinating compounds that may occur in the circulating cooling water.

Given the extremely low concentration of VOC in the cooling tower air exhaust stream (i.e., less

than 1 ppbv) and the trivial rate of VOC emissions from the cooling processes (i.e., less than 0.1

tons per year), there are no known control strategies or technologies that could feasibly be

applied to reduce these emissions. Given these facts, SRP concludes that it is inappropriate to

establish a VOC BACT limit or work practice standard for the planned CCEC cooling processes.

84

A.9 Equipment Leaks VOC and GHG BACT Analysis

The CCEC Project will involve installation of a number of equipment components such as valves

and flanges that supply natural gas to the turbines. Some of the components have the potential to

leak, resulting in fugitive emissions of VOC and of CH4 which is a GHG with a global warming

potential of 25. This section presents the required VOC and GHG BACT analysis for equipment

leaks associated with the combustion turbines’ natural gas supply system piping.

Table A-14 presents a preliminary estimate of the number of equipment components that have

the potential to emit fugitive natural gas along with an estimate of the uncontrolled VOC and

methane emissions from these components.

Table A-14. PTE of CH4 from the CCEC Project Equipment Components

Component Type Quantity VOC PTE

(tons/year)

CH4 PTE

(tons/year)

Valves – Gas Service 80 0.12 4.49

Pressure Relief Valves – Gas Service 8 0.22 7.82

Connectors 216 0.10 3.71

Total Emissions = 0.44 16.02

A.9.1 VOC and GHG BACT Baseline

There are no state, local or federal regulations applicable to the VOC and GHG emissions from

the natural gas supply piping in the proposed CCEC Project. Therefore, there is no “BACT

baseline” for this unit-pollutant group.


The only potentially available control strategy identified to reduce fugitive emissions from

equipment leaks is a leak detection and repair (LDAR) program. LDAR is a work practice that is

commonly used in the petroleum refining and synthetic organic chemical manufacturing industry

to reduce VOC emissions from equipment leaks. Such a program involves periodic monitoring to

identify components with leak rates above a set threshold, and when such components are

identified, efforts are made to repair the component and thereby reduce or eliminate leaks. There

are no other available control options for reducing fugitive emissions from equipment leaks.


The use of an LDAR program is a feasible means of reducing fugitive VOC and CH4 emissions

from leaking components.


The costs and effectiveness of LDAR programs vary according to the leak repair threshold

selected. For purposes of this BACT analysis, it is assumed that leak repair thresholds equivalent

to those required 40 CFR 63, subpart H would be utilized. On average, these thresholds are

estimated to reduce emissions by 91% relative to the uncontrolled fugitive emissions from

85

leaking components. This is the most effective feasible control option available to reduce

fugitive VOC and CH4 emissions from the natural gas piping.


Table A-15 summarizes the costs and benefits of implementing an LDAR program on the

planned CCEC Project to reduce fugitive VOC and CH4 emissions from natural gas piping leaks.

As shown in the table, the costs of implementing such a program are excessive relative to the

emissions reductions that would result. This table is based on the premise that a VOC control

cost threshold of $20,000/T is excessive. Crediting this cost threshold to the LDAR VOC

emissions reductions results in a GHG emissions control cost (on a CO2e basis) of $141/T.

Table A-15. Control Costs for Natural Gas LDAR Program106

Cost Category / Element Value

Annualized Capital Costs - $/year

(Annualized cost of capital required to establish LDAR program) $11,789

Annual O&M Costs - $/year

(Annual direct and indirect costs to operate LDAR program) $52,905

Gross Annualized Costs - $/year $64,694

Amount of NG recovered (ton/year) 15.65

Amount of CH4 Controlled (T/yr) 15.23

Amount of VOC Controlled (T/yr) 0.42

Value of NG “recovered” $2,550

Credit for VOC @ $20,000 T $8,436

Total Net Annualized Costs $53,708

Cost Effectiveness ($/ton CO2e) $141


As discussed in Section 0, a cost effectiveness of $141 per ton results in unreasonable economic

impacts. Thus, based on the excessive costs and limited benefits of implementing an LDAR

program to reduce fugitive VOC and CH4 emissions from leaking components, SRP concludes

that it is unreasonable to require such a program as BACT for reducing fugitive emissions from

the CCEC turbines’ natural gas supply systems. SRP further concludes that BACT for fugitive

VOC and CH4 emissions from leaking components is good industrial design coupled with

routine operation and maintenance of the equipment consistent with the all applicable safety

standards.

106 LDAR costs and benefits estimated based on data in: Hazardous Air Pollutant Emissions from Process

Units in the Synthetic Organic Chemical Manufacturing Industry-Background Information for Proposed Standards

- Volume 1C: Model Emission Sources, Emission Standards Division, U.S. Environmental Protection Agency,

Office of Air and Radiation, Office of Air Quality Planning and standards, Research Triangle Park, North

Carolina 27711, November 1992; EPA-453/D-92-016c. See Appendix E for additional details.

86

A.10 Fire Pump Engine BACT Analyses

The CCEC will include one emergency fire water pump. This emergency pump will be powered

by a reciprocating compression-ignition engine (i.e., a diesel fueled RICE) with a rated output of

220 brake horsepower (“bhp”). This engine is generally similar to engines that are regulated as

non-road mobile sources under 40 CFR parts 89 and 1039. This engine is subject to BACT

review for NOx, VOC, CO, and PM/PM2.5 emissions.

A.10.1 Fire Pump NOx and VOC BACT Analysis

A.10.1.1 NOx and VOC BACT Baseline

As discussed in Section 4 of the application, the emergency fire pump engine will be an affected

facility subject to the standards for emergency engines under 40 CFR Part 60 Subpart IIII. The

minimum standards that would meet BACT requirements for NOX and VOC emissions from this

engine are as follows:

The fire water pump engine, pursuant to 40 CFR §§ 60.4205(c), will be required to meet

the combined NOx and non-methane hydrocarbons emission standard established for

nonroad engines of the same model year pursuant to Table 4 of subpart IIII. The emission

standard is a specification of 3.0 g/bhp-hr, as determined by the engine manufacturer

using the nonroad engine testing procedures set forth at 40 CFR §§ 89.401 to 89.424 and

at Table 4 of subpart IIII.

A.10.1.2 Step 1 – Identify Available Control Options

Identified control technologies and techniques for NOX and VOC emissions from compression-

ignition RICE include the following:

Injection timing retard, also called ignition timing retard, which involves delaying the

fuel injection point in each engine cycle such that the heat release from fuel combustion

occurs during the cylinder expansion. Lower NOX emissions are achieved by reducing the

peak combustion temperature;

Exhaust gas recirculation, which involves retaining or re-introducing a fraction of the

exhaust gases. Lower NOX emissions are achieved by reducing the peak combustion

temperature and by reducing the amount of available molecular oxygen;

NOX adsorber technology, which typically utilizes alkali or alkaline earth metal catalysts

to adsorb NOX on the catalyst surface under the fuel-lean and oxygen-rich conditions

typical of diesel engine exhaust. Periodically, the catalyst bed is subjected to fuel-rich

exhaust in order to desorb the NOX and regenerate the catalyst. The desorbed NOX is

catalytically reduced over a second catalyst, typically platinum and rhodium;

SCR for NOX reduction;

An oxidation catalyst for VOC control, similar to the catalyst described in sub-section 0;

and

Catalyzed diesel particulate filters, which control emissions by capturing particulate

matter in a filter media, typically a ceramic wall flow substrate, and then by oxidizing it

87

in the oxygen-rich atmosphere of diesel exhaust. The particulate matter emitted by diesel

engines includes semi-volatile organic compounds that are regulated as VOC.

A.10.1.3 Step 2 – Eliminate Technically Infeasible Options

All of the identified control options are assumed to be technically feasible.

A.10.1.4 Step 3 – Rank Feasible Control Options

The third-ranked control option for NOX and VOC emissions comprises the use of internal

combustion engines certified by the engine manufacturer to meet the applicable NSPS emission

standards for non-road, compression-ignition engines. Engines meeting these standards may use

multiple in-engine control technologies including injection timing retard and exhaust gas

recirculation. This control option would result in a PTE of NOX plus VOC emissions of 0.34

tons per year from the fire pump engine based on an assumed 500 hours per year of operation.

The second-ranked control option for NOX and VOC emissions involves the use of SCR and

oxidation catalyst in conjunction with the third-ranked control option. For the purposes of this

BACT analysis, it is assumed that an 80 percent reduction in NOX and VOC emissions, down to

a total annual emission level of 0.07 tons per year, is achievable with this control option. This

likely overstates the achievable emission reduction by a significant amount, as the engine will

have very little time operating under the steady-state conditions favorable for SCR and oxidation

catalyst system performance.

The highest-ranked control option for NOX and VOC emissions involves the use of catalyzed

diesel particulate filters and NOX adsorber technology in conjunction with the third-ranked

control option. For the purposes of this BACT analysis, it is assumed that 90 percent emission

reduction is achievable down to an emission rate of 0.04 T/yr.

A.10.1.5 Step 4 – Evaluate Feasible Control Options

Third-ranked control option will not cause any adverse energy, environmental, or economic

impacts. The higher-ranked control options will cause adverse impacts that warrant their

exclusion as the basis for establishing VOC and NOx BACT limits from the fire pump engine.

The adverse impacts include energy impacts, due to reduced energy efficiency attributable to

increased pressure drop, and environmental impacts associated with catalyst disposal. These

adverse energy and environmental impacts are minimal.

The adverse economic impacts that would result from requiring catalytic add-on controls for an

emergency use, internal combustion engine would be significant. Economic analyses prepared by

U.S. EPA in its rulemaking for NSPS subpart IIII showed that, for emergency use engines, the

cost effectiveness of SCR is more than $100,000 per ton of NOX reduction, and the cost of

catalyzed diesel particulate filters and NOX adsorbers are more than $20,000 per ton of total NOX

and VOC emission reduction. Considering the minimal environmental benefit that would result,

and the adverse energy, economic and environmental impacts described above, these controls are

rejected as BACT.

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A.10.1.6 Step 5 – Establish BACT

The fire pump engine to be installed at the CCEC will be certified by the equipment

manufacturer to meet the applicable emission standards for nonroad, compression-ignition

engines, as codified in 40 CFR Part 60 Subpart IIII and at 40 CFR § 89.112. Supbart IIII also

limits the operation of the fire pump engine for non-emergencies to less than 100 hours per year.

Due to the very low emissions from this engine, the fact that it will operate only intermittently,

and the availability of engines that are certified to achieve this emission level, and considering

the nature of the certification test procedure for the nonroad engine emission standards, SRP

proposes that an equipment design standard rather than an emission rate limit is an appropriate

form of expression for the NOX and VOC BACT requirements for the fire pump engine.

A.10.2 Fire Pump CO BACT Analysis

A.10.2.1 CO BACT Baseline

As discussed in Section 4 of the application, emergency fire pump engine will be an affected

facility subject to the standards for emergency engines under 40 CFR Part 60 Subpart IIII. The

minimum standards that would meet BACT requirements for CO emissions from these engines

are as follows:


the CO emission standard established for nonroad engines of the same model year

pursuant to Table 4 of subpart IIII. The emission standard is a specification of 2.6

g/bhp-hr, as determined by the engine manufacturer using the nonroad engine testing

procedures set forth at 40 CFR §§ 89.401 to 89.424 and at Table 4 of subpart IIII.

A.10.2.2 Steps 1 – 4

Potentially available control technologies and techniques for CO emissions include the

combustion controls identified as options for VOC control in sub-section 0. All of these

technologies are assumed to be technically feasible. The baseline control option, using an

internal combustion engine certified by the engine manufacturer to meet the applicable NSPS

emission standards for non-road, compression-ignition engines, will result in potential CO

emissions of 0.1 tons per year from the fire pump engine. The top-ranked control option -

addition of an oxidation catalyst - may be able to achieve a CO emission rate on the order of 0.05

tons per year, but is rejected as BACT due to its adverse energy, environmental, and economic

impacts and its minimal environmental benefit, as discussed in the engine VOC BACT analysis.




engines, as codified in 40 CFR Part 60 Subpart IIII and at 40 CFR § 89.112. Due to the very low

emissions from this unit, the fact that it will operate only intermittently, that non-emergency use

operation is limited to 100 hours per year, and the availability of engines that are certified to

achieve this emission level, and considering the nature of the certification test procedure for the

nonroad engine emission standards, SRP proposes that an equipment design standard rather than

89

an emission rate limit is an appropriate form of expression for the CO BACT requirements for

the fire pump engine.

A.10.3 Fire Pump PM/PM2.5 BACT Analysis

A.10.3.1 PM/PM2.5 BACT Baseline

As discussed in Section 4 of the application, the fire pump engines will be affected facilities

subject to the standards for emergency engines under subpart IIII of 40 CFR part 60. The

minimum standards that would meet BACT requirements for particulate matter emissions from

this engine is as follows:


the PM emission standard established for nonroad engines of the same model year

pursuant to Table 4 of subpart IIII. The emission standard is a specification of 0.15

g/bhp-hr, as determined by the engine manufacturer using the nonroad engine testing

procedures set forth at 40 CFR §§ 89.401 to 89.424 and at Table 4 of subpart IIII.

A.10.3.2 Steps 1 – 4

Identified control technologies and techniques for particulate matter emissions are the same

technologies identified for VOC emissions in subsection 0. Each of these technologies is

assumed to be technically feasible. The baseline control option, using an internal combustion

engine certified by the engine manufacturer to meet the applicable NSPS emission standards for

non-road, compression-ignition engines, will result in potential PM/PM2.5 emissions less than

0.02 tons per year. The top-ranked control option - use of catalyst diesel particulate filters - could

achieve some level of particulate matter emission reduction, but is rejected as BACT due to its

adverse energy, environmental, and economic impacts and its minimal environmental benefit, as

discussed in the VOC BACT analysis in sub-section 0.




engines, as codified in 40 CFR Part 60 Subpart IIII and at 40 CFR § 89.112. Due to the very low

emissions from this engine, the fact that it will operate only intermittently, that non-emergency

use operation is limited to 100 hours per year, and the availability of engines that are certified to

achieve this emission level, and considering the nature of the certification test procedure for the

nonroad engine emission standards, SRP proposes that an equipment design standard rather than

an emission rate limit is an appropriate form of expression for the PM/PM2.5 BACT

requirements for the fire pump engine.

A.10.4 Fire Pump GHG BACT Analysis

The fire pump engine will be a trivial source of GHG emissions that result from the combustion

of diesel fuel by the engine during those brief periods when it will operate. The GHG PTE,

assuming 500 hours of operation per year, is 63 tons of CO2e per year or about 0.002 % of the

source-wide GHG PTE. The baseline emission level for this engine, representing proper

equipment design and operation and the use of diesel fuel, is a GHG emission factor of 163.6

90

lb/MMBtu of fuel burned. On a mass basis, emissions of CH4 and N2O comprise 0.005 percent

of total GHG emissions from the engine, with the remainder being CO2.

A.10.4.1 GHG BACT Baseline

There are no applicable NSPS or NESHAP rules that would establish a baseline emission rate for

GHG emissions from the fire pump emergency engine at the planned CCEC.

A.10.4.2 Steps 1 – 4

The only identified control technologies for GHG emissions from the emergency diesel engine

are oxidation catalyst (for control of CH4 emissions)107 and CCS (for control of CO2 emissions).

Each of these technologies is assumed to be technically feasible. The use of oxidation catalyst

could achieve some level of CH4 emission reduction, but is rejected as BACT due to its adverse

energy, environmental, and economic impacts and its minimal environmental benefit, as

discussed in the VOC BACT analysis above. Similarly, CCS is rejected as BACT because it is

infeasible, and even if feasible, would not be cost effective, as discussed further in Section 0.


No available control strategy more effective than the inherent engine design has been identified

as BACT for GHG emissions from the emergency fire pump engine at the CCEC. Therefore,

SRP proposes that an emission limit of 163.6 lb/MMBtu of fuel burned be established for GHG

emissions from the engine, on a CO2e basis, with compliance to be demonstrated using the

procedures of 40 CFR § 98.33.

A.11 Diesel Fuel Storage Tank VOC BACT Analysis

The CCEC Project will include a single 500 gallon fixed-roof storage tank to support operation

of the emergency fire pump engine. This tank has the potential to emit a small amount of VOC.

The baseline emission levels from this tank, representing proper equipment design and operation,

is estimated to be less than 0.001 tons per year. VOC emissions from this tank will occur as the

result of working and breathing losses. The diesel fuel stored will have a maximum true vapor

pressure of less than 3.5 kPa.

A.11.1 VOC BACT Baseline

There are no applicable state, local or federal rules that would establish baseline emission rates

for VOC emissions from the diesel fuel storage tank.


The identified control options for VOC emissions for an organic liquid storage tanks can be

divided into two general categories: Design and/or work practice standards and add-on controls.

The specific control options in these categories include:

Fixed roof storage tanks;

Fixed roof tanks equipped with conservation (pressure/vacuum) vents;

107 Oxidation catalyst will increase GHG emissions on a mass basis but due to the differing global warming

potentials of CH4 and CO2, oxidation of CH4 is nonetheless considered a GHG control option.

91

Floating roof tanks (internal or external);

Fixed roof tanks equipped with vapor collection, recovery, and/or control equipment.

A.11.3 Step 2 – Eliminate Technically Infeasible Control Options

All of the options identified for controlling VOC emissions from the tank vents are technically

feasible for some storage tanks. However, floating roof tanks are not considered feasible for

application to small storage tanks such as the 500 gallon diesel storage tank planned for the

CCEC.

A.11.4 Step 3 – Rank Feasible Control Options

The most effective option for controlling VOC emissions from this tank is controlling emissions

using vapor collection and control equipment. This option is estimated to provide 95 percent

control. The specific control technique applicable to this type of small, low emissions application

is the use of a fixed bed carbon canister which can be installed with minimal capital costs. Costs

would primarily be incurred for periodic replacement of the carbon canister. The next most

effective control option is the use of a conservation vent. In the case of the small diesel fuel

storage tank, this option is estimated to provide minimal emissions reductions.108


The economic impacts of using a carbon canister system or a conservation vent to reduce VOC

emissions from the diesel storage tank were evaluated. The results of this analysis are

summarized in Table A-16. As this table shows, neither of these options represent cost-effective

control strategies with costs in excess of $2 million per ton for either of the options. Due to the

low level of emissions from the other organic liquid storage tanks, these control options are

projected to be much more expensive (on a dollar per ton basis) than the costs for controlling the

gasoline tank.

Table A-16. Summary of VOC Control Cost Analysis for the Diesel Storage Tank109

Control Option Capital Costs Annualized

Costs

Emission

Reductions

(tons/year)

Cost-

Effectiveness

Carbon Canister $1,501 $214 0.0002 >$1.0x106

Conservation Vent $1,725 $349 <1x10-5 >$30x106

Because the cost of controlling VOC emissions from the diesel storage tank at CCEC facility is

excessive relative to the trivial reduction in emissions that could be achieved, the use of fixed

roof storage tank represents BACT for VOC emissions from this tank.


Equipment design or work practice requirements are acceptable under the definition of BACT

when technological or economic limitations on the application of measurement methodology

108 Based on a TANKS 4.09d analysis of the diesel storage tank which was evaluated with and without a

conservation vent. This analysis showed about 0.00004 T/yr difference in emissions between the two designs. See

Appendix E for TANKS 4.09d output reports. 109 See Appendix E for details.

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would make the imposition of an emissions standard infeasible. That criterion is met with respect

to emissions from the diesel fuel storage tank due to its physical configuration and the trivial

amount of emissions from this tank. Therefore, SRP proposes that a fixed-roof design be

established as BACT for VOC emissions from this tank.

A.12 Circuit Breakers GHG BACT Analysis

There will be an electrical switchyard within the CCEC boundary. The switchyard will include

26 circuit breakers each containing 360 lbs of sulfur hexafluoride (SF6), a GHG. SF6 is a highly

effective dielectric used for interrupting arcs and is the universally accepted medium for high-

voltage circuit breakers. The circuit breakers located on the CCEC site will have the potential for

fugitive emissions of SF6 as a result of equipment leaks with an estimated GHG PTE of 48 tons

(CO2e) per year. The BACT analysis for GHG emissions from the circuit breakers is presented

below.

A.12.1 GHG BACT Baseline

There are no State, local or federal regulations applicable to the GHG emissions from the circuit

breakers to be installed as part of the CCEC Project. Therefore there is no “BACT baseline” for

this unit-pollutant group.


Three control options have been identified for the SF6 emissions from the circuit breakers:

Use of another type of circuit breaker such as oil circuit breakers, air blast breakers, or

vacuum breakers;

Use of a different dielectric material in the circuit breakers; or

Use of low-leak design coupled with a leak detection system to minimize fugitive

emissions.

Air-blast, oil, and vacuum circuit breakers are three alternative circuit breaker types. However,

SF6 circuit breakers provide superior performance to these alternatives. For example, SF6 is

about 100 times better than air for interrupting arcs. Further, oil and air-blast circuit breakers are

not an available option for high-voltage applications because they are no longer being offered by

manufacturers. For this reason, these circuit breaker types are not “available” and therefore not

considered further in this BACT analysis.

Another alternative for reducing circuit breaker GHG emissions is to utilize other dielectric gases

or mixtures of SF6 with other gases as replacements for SF6 alone. Finally, leak detection

monitoring can be used to minimize emissions by identifying and repairing leaks as soon as

possible.

A.12.3 Step 2 – Eliminate Technically Infeasible Control Options

Use of vacuum circuit breakers is not a technically feasible option for application to the CCEC

medium to high voltage (i.e., 18 to 230 kV) circuit breakers. In the case of the medium voltage

breakers, the required maximum amperage rating of 8,446 exceeds the ratings of available

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vacuum circuit breakers. And, in the case of the high voltage breakers, some prototype higher-

voltage vacuum circuit breakers are being developed but these are not yet commercially

available and are therefore not a feasible GHG control strategy for the circuit breakers to be

located on the CCEC site.

Use of an alternative dielectric is not a feasible option as there are no replacement gases that

have been commercially developed. Decades of investigation have found alternatives for

medium voltage electric power equipment, but there is no viable alternative to SF6 for high-

voltage equipment. The 2014 annual report (the most recent available) for U.S. EPA’s SF6

Emission Reduction Partnership for Electric Power Systems states, “Because there is no clear

alternative to SF6, Partners reduce their greenhouse gas emissions through implementing

emission reduction strategies such as detecting, repairing, and/or replacing problem equipment

…”110

A.12.4 Step 3 – Rank Feasible Control Options

The only feasible control strategy for limiting SF6 emissions from the CCEC high-voltage circuit

breakers is the use of a low-leak design coupled with a leak detection system.


The use of a low-leak design coupled with a leak detection system for the CCEC high-voltage

circuit breakers has no material adverse energy, environmental, or economic impacts. Therefore,

this control strategy is the basis for the GHG BACT limit on this emissions unit-pollutant group.


Equipment design or work practice requirements are acceptable under the definition of BACT

when technological or economic limitations on the application of measurement methodology

would make the imposition of an emissions standard infeasible. That criterion is met with respect

to emissions of SF6 from the proposed CCEC high-voltage circuit breakers. Therefore, SRP

proposes a design and work practice standard requiring a manufacturer-guaranteed SF6 leak rate

of no more than 0.5% per year coupled with leakage detection systems and alarms on the circuit

breakers. This proposed limit is consistent with recently established GHG BACT limits for

similar equipment.

110 Emission Reduction Partnership for Electric Power Systems, 2014 Annual Report, U.S. EPA, March 2015

(available at: https://www.epa.gov/sites/production/files/2016-02/documents/sf6_annrep_2015_v9.pdf).