golden spread electric coop - antelope station ......(psd) regulations in 40 cfr 52.21, antelope...

Application forPrevention of Significant Deterioration Permit

for Greenhouse Gases for Antelope StationGolden Spread Electric Cooperative, Inc.

Abernathy, Texas

Submitted to:

U.S. Environmental Protection Agency, Region 6Dallas, TX

January 2013

GSEC Antelope Station January 2013PSD Permit Application for Greenhouse Gases

1.0 INTRODUCTION AND ADMINISTRATIVE INFORMATION

Golden Spread Electric Cooperative, Inc. (GSEC) is a tax-exempt, consumer-owned public utility,organized in 1984 to provide low cost, reliable electric service for its rural distribution cooperativemembers. Its 16 member systems serve more than 199,000 retail consumers located in the OklahomaPanhandle and an area covering 24 percent of Texas including the Panhandle, South Plains and EdwardsPlateau Regions.

GSEC owns Mustang Station, a 480 MW, gas-fueled, combined cycle generating plant located nearDenver City, Texas, as well as Mustang Station Units 4, 5, and 6, three 168 MW combustion turbine-generators located at the Mustang Station site. GSEC also owns Antelope Station, a 168 MW generatingfacility made up of 18 quick start engines located near Abernathy, Texas, and Golden Spread PanhandleWind Ranch, a 78 MW wind facility made up of 34 wind turbines located near Amarillo, Texas. Throughits affiliate Fort Concho Gas Storage, Inc., GSEC also owns a gas storage facility near San Angelo, Texas,capable of storing more than two billion cubic feet of natural gas.

Due to concerns about the adequacy of future power reserve margins in West Texas and in other areas inTexas, GSEC is proposing to build a new combustion turbine-generator facility at Antelope Station nearAbernathy, Texas. GSEC expects the new facility to provide primarily peaking and intermediate powerneeds in a highly cyclical operation.

The new unit at Antelope Station will feature a new GE 7F 5-Series gas turbine in a simple cycleapplication.1 The 7F 5-Series turbine is the latest development of GE’s F-class turbine technology, whichis used in over 1100 gas turbines worldwide. The 7F 5-Series turbine features a 14-stage compressor withsuper-finish 3-dimensional airfoils for improved efficiency with less long-term degradation. The 3-stagecombustion turbine in the 5-Series features a hot gas path with advanced cooling and sealing technologiesto improve efficiency and lower lifecycle costs. A new model-based process control system alsoimproves performance efficiency. As a result, the 7F 5-Series turbine achieves an efficiency above 38.7%in a simple-cycle application2. The unit can produce up to 202 MW in cold weather conditions, andnominally 190.1 MW in peak summer operation. Compared to other 7F class turbines, the 5-Seriesturbine also has improvements in start-up and turndown capability, ramp-up rate, and lifecycle costs inpeaking, cyclic, and steady-state operation. During normal start-up, the 5-Series turbine will achieve 50%capacity load in 30 minutes, and thereafter operate at design emission limits. During “peaking start-up”, acombination of measures allow the unit to achieve 75% load in about 10 minutes, full load operation inabout 11.5 minutes, and to operate within design emission limits within 22 minutes. (Peaking start-upsincrease the rotor and hot gas maintenance costs relative to normal start-ups.) The turbine is equippedwith GE’s Dry Low NOx (DLN) 2.6 combustion system to achieve normal emission levels of 9 ppmvdnitrogen oxides (NOx) @15% O#"and 9 ppmvd carbon monoxide (CO) at operation from 100% load tonominally 50% load.

Exhaust emissions from the turbine comprise the majority of air emissions from the plant site, withsmaller emissions from the natural gas supply equipment, and electrical equipment.

Under the U.S. Environmental Protection Agency’s (EPA’s) Prevention of Significant Deterioration(PSD) regulations in 40 CFR 52.21, Antelope Station is currently a major source of greenhouse gas

1 These units were previously designated as 7FA.005 series turbines.2 This efficiency is equivalent to a heat rate of 8905 BTU (LHV)/kWh of gross power output, and is guaranteed at98!F ambient temperatures and 18% relative humidity and other specified operating conditions and parameters.

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(GHG) emissions because its potential emissions have global warming potential equivalent to more than100,000 tons per year of emissions of carbon dioxide (CO2). (The emissions equivalent to CO2 aredesignated as CO2-e.) The existing units at Antelope Station were not subject to PSD permitting foreither GHG or non-GHG pollutants. Under the PSD rules, the project to install a gas turbine at AntelopeStation is required to obtain a pre-construction air quality permit for the GHG emissions from the EPA.The proposed project is also subject to PSD review by the Texas Commission on Environmental Quality(TCEQ) for non-GHG emissions, since it will also be a major source of CO emissions, and emissions ofNOx and particulate matter less than 10 microns in diameter and less than 2.5 microns in diameter willexceed their PSD significant emission rates. These non-GHG emissions, and those with emission ratesbelow the respective PSD significant emission rates, are subject to the State of Texas pre-constructionauthorization requirements, and authorizations for those associated facilities and emissions will beobtained separately from the TCEQ.

Sources and emissions subject to PSD permitting requirements because of their potential to release GHGemissions are only subject to some of the requirements of the PSD rules. The primary requirement of aPSD permit for GHG emissions is to require that the permitted facilities use the Best Available ControlTechnology (BACT) for controlling GHG emissions. The resulting PSD permit specifies emission levelsreflecting the use of BACT, including emissions monitoring and other requirements to ensure that theBACT emission levels are maintained during operations.

Administrative information for the owner and operator of the Antelope Station, and information on thesite itself, is provided in the TCEQ Core Data Form which follows this page. Additional information isprovided in the TCEQ Form PI-1, which also follows this page. The TCEQ Form PI-1 is a basic elementof the TCEQ permit process which will be used to authorize emissions and facilities other than thoserelated to GHG pollutants.

The start of construction of the new turbine at Antelope Station is projected for end of 2013. Initialoperation of the power plant is expected in 1st quarter 2015.

The remaining sections of this permit application are the following: Section 2.0 provides processinformation for the new turbine and Section 3.0 provides site information for Antelope Station. Section4.0 summarizes and describes the calculation of GHG emissions from the proposed turbine andsupporting equipment. Section 5.0 summarizes the applicability of PSD permit requirements. Section 6.0analyzes and selects the BACT, including proposed emission limits and monitoring and maintenancerequirements to achieve and maintain compliance with the BACT emission limits.

Affiliated with the Federal PSD permit process are requirements to consider the impacts of the proposedpower plant on cultural and historical resources in the area, and on biological resources includingthreatened and endangered species. These impacts will be addressed in studies separate from this PSDpermit application.

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TCEQ-10252 (Revised 10/12) PI-1 InstructionsThis form is for use by facilities subject to air quality requirements and may berevised periodically. (APDG 5171v19) Page_____ of _____

Texas Commission on Environmental QualityForm PI-1 General Application for

Air Preconstruction Permit and Amendment

Important Note: The agency requires that a Core Data Form be submitted on all incoming applications unlessa Regulated Entity and Customer Reference Number have been issued and no core data information haschanged. For more information regarding the Core Data Form, call (512) 239-5175 or go towww.tceq.texas.gov/permitting/central_registry/guidance.html.

I. Applicant Information

A. Company or Other Legal Name: Golden Spread Electric Cooperative Inc.

Texas Secretary of State Charter/Registration Number (if applicable): SOS Filing No. 68655501

B. Company Official Contact Name: Jeff Pippin

Title: Senior Asset Manager, Production

Mailing Address: P.O. Box 9898

City: Amarillo State: TX ZIP Code: 79105-5898

Telephone No.: 806/418-3010 Fax No.: 806/374-2922 E-mail Address: [email protected]

C. Technical Contact Name: Patrick Murin, P.E.

Title: Principal

Company Name: Murin Environmental Inc.

Mailing Address: 979 Via Puebla

City: Rio Rico State: AZ ZIP Code: 85648-1918

Telephone No.: 713/819-6115 Fax No.: 520/281-4359 E-mail Address: [email protected]

D. Site Name: Antelope Station

E. Area Name/Type of Facility: Turbine 1/Electrical Power Production Permanent Portable

F. Principal Company Product or Business: Electrical Power Production

Principal Standard Industrial Classification Code (SIC): 4911

Principal North American Industry Classification System (NAICS): 221112

G. Projected Start of Construction Date: 12/2013

Projected Start of Operation Date: 1st Q/2015

H. Facility and Site Location Information (If no street address, provide clear driving directions to the sitein writing.): Facility is north off County Road 315, east of I-27, and bounded on the east by CountyRoad P

Street Address: 1454 County Road 315

City/Town: Abernathy County: Hale ZIP Code: 79311

Latitude (nearest second): 33!51’56.5”N Longitude (nearest second): 101!50’37.6”W

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11


2.0 PROCESS DESCRIPTION AND PROCESS FLOW DIAGRAM

The process flow diagram illustrates the process steps in the proposed gas turbine system.

The proposed gas turbine will be a GE 7F 5-Series gas-fired combustion turbine. Supply air will becompressed by the integral 14-stage compressor. Natural gas fuel will be combusted in GE’s DLN 2.6combustion system and the combustion exhaust gases will power the 3-stage expansion turbine. Theturbine is air cooled, and an evaporative air cooler is also used for inlet air cooling during summer peakambient air temperatures.

The gas turbine will exhaust through stack Emission Point Number (EPN) TURB1 and will release bothGHG and non-GHG air pollutants. The GHG pollutant sulfur hexafluoride (SF6) will be released in low-volume leaks from circuit breakers as EPN SF6-FUG. Leaks from the natural gas supply equipment (EPNNG-FUG) will release mostly GHG emissions but a small amount of non-GHG emissions. Non-GHGemissions will not be covered in this permit.

13


3.0 SITE INFORMATION

As shown in the Area Map, Antelope Station is located north of County Road 315, east of I-27 andbounded on the east by County Road P in Hale County, Texas. The location is approximately 1.6 milesnorth of the City of Abernathy.

The preliminary plot plan shows the location of the proposed unit at Antelope.

15

GSEC Antelope Station January, 2013PSD Permit Application for Greenhouse Gases

4.0 GHG EMISSIONS

As noted in the Process Description, the new sources of GHG emissions on the site will include thefollowing:

" The combustion turbine" Natural gas line equipment fugitive releases" SF6 leaks from circuit breakers

GHG emissions from these sources are summarized in Table 1. The bases for and calculations of theseemissions are further discussed below and in Tables 2 through 4. The new turbine at Antelope Stationwill not emit two of the six pollutant categories which comprise GHG pollutants, namelyhydrofluorocarbons or perfluorocarbons. The plant will emit some amount of each of the remaining fourcategories of GHG pollutants (CO2, CH4, N2O, and SF6), but emissions of CO2 comprise 98.7% of thetotal annual tons of GHG pollutants as CO2-e, and 99.97% of the mass emissions of GHG pollutants.

4.1 Gas Turbine

GHG emissions from the combustion turbine comprise CO2, CH4, and N2O. Emissions of CO2 and CH4

during normal operations are those estimated from turbine manufacturer data. Emissions of N2O areestimated from the EPA’s Compilation of Air Pollutant Emission Factors (AP-42, 5th Edition) and themaximum fuel usage rates. GHG emissions of CO2 and N2O during startup and shutdown operations wereconservatively estimated to be the same as those in normal operations. CH4 emissions during startup andshutdown operations were estimated from turbine manufacturer data. Actual GHG emissions in theseoperations will be less, based on the lower firing rate of natural gas. Table 2 provides the emissioncalculation bases and example calculations.

4.2 Natural Gas Line Fugitives

Natural gas line fugitive emissions are determined from the number of pipeline components such ascontrol and relief valves, flanges, and sampling connections, and emission factors in 40 CFR 98 Table W-1A. The speciation of the fugitive releases uses data on the maximum composition of GHG componentsin the natural gas supply. Table 3 provides the emission calculation bases and example calculations.

4.3 SF6 Leaks from Circuit Breakers

Leaks of SF6 are based on the amount of SF6 in circuit breakers at the power plant and a standard leak rateof 0.5% per year, which corresponds to the use of modern design circuit breakers and a comprehensiveleak monitoring program. Table 4 provides the emission calculation bases and example calculations.

18

Golden Spread Electric Cooperative Table 1: Summary of Emissions 1/9/2013

SF6 Fug TOTAL

Normal,lb/hr

SSM,lb/hr

Total,tons/yr lb/hr tons/yr tons/yr tons/yr

PSDSignificantIncreaseLevels,tons/yr

CO" 232,749 232,749 532,007 0.018 0.079 532,007 N/ACH# 12.00 153.00 124.97 0.93 4.07 129.04 N/AN"O 5.82 5.82 13.3 13.3 N/A

SF6 0.0073 0.0073 N/A

GHG 232,767 232,908 532,145 0.95 4.15 0.0073 532,149 100,000

CO2-e 234,806 237,767 538,754 19.5 85.55 174.47 539,014 100,000

Turbine 1 NG-Fugitives

19

Golden Spread Electric Cooperative Table 2. GE 7F 5-Series Turbine Emission Calculations 12/14/2012

Bases for Calculations- Total Annual Operating Hours, Normal Maximum Operation 4000- Total Number of 30-min Startups Per Year 635

- Maximum Duration of Startup (to 50% load), min 30

- Maximum Annual Startup Hours 317.5- Total Number of Shutdowns Per Year 635

- Maximum Duration of Shutdown (from 50% load), min 24

- Normal Operating Hours, % of Total 87.5%- Startup, Shutdown, or Maintenance (SSM) Hours, % of Total 12.5%

- Maximum Annual Shutdown Hours 254

1941

Maximum Emission Rates

Normal,lb/hr

Startup,

lbs/start-up

Startup,

lbs/hr (incl.

normaloperation)

Shutdown,lbs/shutdown

Shutdown,

lbs/hr (incl.

normaloperation)

Annual,tons/yr

CO" 232,749 N/A 232,749 N/A 232,749 532,007

CH# 12 147 153 171 178.2 124.97N"O 5.82 N/A 5.82 N/A 5.82 13.3

CO2!" 234,806 N/A 237,767 N/A 238,296 538,754

Example Calculation of Annual EmissionsAnnual CH4 Emissions from Turbine 1:

[(4000 hours X 12 lb/hr) + (635 startups X 147 lbs/startup) + (635 shutdowns X 178.2 lbs/shutdown)] X (1 ton / 2000 lbs) = 124.97 tons/yr

Tabulation of HAPs and N"O Emission Factors from AP-42, Tables 3.1-2a and 3.1-3HAPs (Total) 0.00103 lbs/MM Btu

N"O 0.003 lbs/MM Btu

Tabulation of GHG Warming Potential Equivalency Factors (40 CFR Part 98 Subpart A, Table A-1)CO" 1 kg CO2-e/kg CO"

CH# 21 kg CO2-e/kg CH#

N"O 310 kg CO2-e/kg N"O

Calculation of Normal CO2-e Hourly Emissions

(232,749 lb CO2/hr) X (1lb CO2-e/lb CO2) + (12 lbs CH4/hr) X (21 lb CO2-e/lb CH4) + (5.82 lbs N2O/hr) X (310 lb CO2-e/lb N2O) =

234,806 lbs CO2-e/hr

Note: AP-42 is the U.S. EPA's Compilation of Air Pollutant Emission Factors , 5th Edition.

- Basis of Turbine Emission Rates

- Maximum Turbine Firing Duty, MM Btu/hr (HHV)

Turbine 1

Vendor data except as noted

20

Golden SpreadElectric Cooperative

Table 3. Natural Gas Fugitive Emission Calculations 1/9/2013

Emission Bases and Calculations

Emission Source Characteristics- No. of Gas Valves: 120- No. of Gas Flanges: 300- No. of Gas Relief Valves: 8- No. of Sampling Connections: 18

Emission Factor, scf/hr/component- Gas Valve: 0.123- Gas Flange: 0.017- Gas Relief Valve: 0.196

- Gas Sampling Connection*: 0.123*Used factor for gas valves since no factor is provided in Table W-1A of 40 CFR 98.

Source of Emission Factors: Table W-1A of 40 CFR 98Annual Hours of Operation: 8760Maximum Component Compositon, % Vol

- CH4: 93.1548

- CO2: 0.6728

Molecular Weights

- CH4: 16.04

- CO2: 44.01

Calculated Fugitive Release, scf/hr = 7"#12&"2-"+20321,165$")"#,0/55/21"-*+624%"5+-'.4'+20321,16$"(

23.642 scf/hr

GHG Equivalency Factors, lb CO2-e/lb:

- CH4: 21

- CO2: 1

Calculated Emission Rateslbs/hr tons/yr

CH4 0.93 4.07

CO2 0.018 0.079

CO2-e 19.548 85.55

Example Calculation of Hourly Emissions (CH4):(23.642 scf/hr) * (93.1548 scf CH4/100 scf gas) X (1-lb-mol/379 scf) X (16.04 lbs CH4/lb-mol) =

0.93 lbs CH4/hr

Example Calculation of Annual Emissions (CH4)(0.93 lbs/hr) X (8760 hrs/yr) X (1 ton/2000 lbs) = 4.07 tons CH4/yr

Example Calculation of CO2-e Hourly Emissions(0.018 lb CO2/hr) X (1lb CO2-e/lb CO2) + (0.93 lbs CH4/hr) X (21 lb CO2-e/lb CH4) =

19.55 lbs CO2-e/hr

21

Golden SpreadElectric Cooperative

Table 4. Calculations for SF6 Fugitive EmissionsReleased from Electrical Equipment

1/9/2013

Emission Bases and Calculations

No. of Circuit Breakers: 8

Amount of SF6 in each Circuit Breaker, lbs: 365

Estimated annual leak rate, wt. %: 0.5

Estimated annual SF6 emissions = (8 breakers) X (365 lbs/breaker) X (0.5 % lost/yr) X (1 ton/2000 lbs) =

0.0073 tons SF6/yr

GHG Equivalency Factor, ton CO2-e/ton SF6: 23900

Estimated annual CO2-e emissions = (0.0073 tons SF6/yr) X (23900 tons CO2-e/ton SF6) =

174.47 tons CO2-e/yr

22


5.0 PSD APPLICABILITY SUMMARY

As shown in Table 1, the proposed gas turbine will emit 532,149 tons/yr of GHG pollutants and 539,014tons/yr of CO2-e. Because these emissions exceed the GHG major modification definition of 75,000

tons/yr, GSEC is required to obtain a pre-construction air quality permit for the GHG emissions from theproposed turbine under the PSD rules from the EPA. The proposed gas turbine is also subject to PSDreview by the Texas Commission on Environmental Quality (TCEQ) for non-GHG emissions, since, asshown in Table 1F, it will also be a major source of CO emissions, and emissions of NOx and particulatematter less than 10 microns in diameter and less than 2.5 microns in diameter will exceed their PSDsignificant emission rates. These non-GHG emissions, and those with emission rates below therespective PSD significant emission rates, are subject to the State of Texas pre-construction authorizationrequirements, and authorizations for those associated facilities and emissions will be obtained separatelyfrom the TCEQ.

Sources and emissions subject to PSD permitting requirements because of their potential to release GHGemissions are subject only to some of the requirements of the PSD rules. The primary requirement of aPSD permit for GHG emissions is to require that the permitted facilities use the Best Available ControlTechnology (BACT) for controlling GHG emissions. The resulting PSD permit specifies emission levelsreflecting the use of BACT, including emissions monitoring and other requirements to ensure that theBACT emission levels are maintained during operations. An analysis of and rationale for BACT for theGHG emissions from the new gas turbine facility at Antelope Station are provided in Section 6.0.

GHG emissions from the proposed gas turbine facility are not subject to other PSD permit requirements.The facility is not subject to an analysis of ambient air impacts because there are no National Ambient AirQuality Standards or PSD Ambient Air Increments for GHG emissions. It is not subject topreconstruction ambient air monitoring because of the nature of GHG emissions and their potential globalimpact; there is no benefit for the gathering of local ambient air monitoring data on GHG pollutants.EPA’s permitting guidance for GHG also indicates there is no need to conduct analyses of additionalimpacts on Class I areas, soils and vegetation because quantifying the impacts attributable to a singlesource is not feasible with current climate change models.3

3 U.S. EPA, PSD and Title V Permitting Guidance for Greenhouse Gases, EPA-457/B-11-001, March 2011.

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6.0 BEST AVAILABLE CONTROL TECHNOLOGY (BACT)

EPA’s PSD rules require that any emissions emitted above the significant increase level, and thus subjectto the PSD permitting process, be subject to the BACT analysis. Title 40 CFR 52.21(b)(12) reads in part:

Best available control technology means an emissions limitation (including a visible emissionstandard) based on the maximum degree of reduction for each pollutant subject to regulation under[this] Act which would be emitted from any proposed major stationary source or majormodification which the Administrator, on a case-by-case basis, taking into account energy,environmental, and economic impacts and other costs, determines is achievable for such source ormodification through application of production processes or available methods, systems, andtechniques, including fuel cleaning or treatment or innovative fuel combustion techniques forcontrol of such pollutant. In no event shall application of best available control technology result inemissions of any pollutant which would exceed the emissions allowed by any applicable standardunder 40 CFR parts 60 and 61.

BACT is established in a top-down analysis where the most effective control technology is selected if it istechnically feasible and has “reasonable” energy, environmental, and economic/cost impacts. Asdescribed in EPA’s PSD and Title V Permitting Guidance for Greenhouse Gases (EPA, 2011) the steps tobe followed in establishing BACT are the following:

1) Identify all available control technologies2) Eliminate technically infeasible options3) Rank remaining control technologies4) Evaluate most effective controls and document results5) Select the BACT

These steps are used below to evaluate and select BACT for the proposed turbine facility at AntelopeStation.

6.1 Gas Turbine

6.1.1 Step 1 - Identify all available control technologies.

There are two fundamental control technology options for the gas turbine. The first is carbon capture andstorage (CCS). CCS is an add-on technology that captures GHG emissions resulting from natural gascombustion before they enter the atmosphere. In this instance the captured CO2 would be compressedand transported via pipeline to a site where the CO2 could either be stored or used (for example, forenhanced oil recovery). The second option is the baseline option of using an efficient gas turbinetechnology and maintaining and operating each turbine train component properly.

6.1.2 Step 2 - Eliminate technically infeasible options.

According to EPA GHG Permitting Guidance document a technology is technically feasible if it (1) hasbeen demonstrated and operated successfully on the same type of source under review or, (2) is availableand applicable to the type of source under review.4 In the United States, there are presently no existingdemonstrations of CCS systems used in the removal of CO2 from natural-gas turbines, from turbines fired

4 Ibid, page 33.

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with other fuels, or from gas-fired, liquid-fired, or solid-fired boilers and furnaces.5 One project, theKemper County Integrated Gasification Combined Cycle Project, is under construction in Mississippi.6

This project features the removal of CO# from a syngas produced from coal gasification; the syngas isthen used in a conventional combined cycle power unit. A similar demonstration project, the Texas CleanEnergy IGC project, has been planned for Penwell, Texas but construction has not begun.7 Both of theseprojects will use technology in a pre-combustion application similar to gas processing conducted inpetroleum refineries and natural gas treatment facilities, and do not demonstrate CCS on post-combustionequipment exhausts. Combustion exhausts are at low pressure while gasifier streams are at medium tohigh pressure: the low pressure in turbine exhausts limits the availability, viability, and practicability oftechnologies for the removal of CO2 since some technologies are viable only at medium or high pressure.In addition, the concentration of CO# in combustion exhausts is much lower than in gasifier streams.Overall, the lack of utilization of the CO2 capture/compression/transport/storage as BACT reflects theemerging nature of the CCS technology and the fact that it is not deployed even in demonstration projectson combustion sources.

Just two years ago, the President’s Interagency Task Force on Carbon Capture and Storage 2010 reportfound,

Current technologies …are not ready for widespread implementation primarily becausethey have not been demonstrated at the scale necessary to establish confidence for powerplant application. Since the CO2 capture capacities used in current industrial processesare generally much smaller than the capacity required for the purposes of GHG emissionsat a typical power plant, there is considerable uncertainty associated with capacities atvolumes necessary for commercial deployment.8

CCS systems comprise three key systems: capture, transport and storage.

Capture

The CO# capture system uses one of several absorption processes to absorb CO# from the combustionexhaust gas into a liquid such as monoethanolamine. The absorbed CO2 is then released by changing thetemperature and/or pressure of the absorbing liquid. The enriched CO# stream must then be compressedfor transport to storage or an end-use. The absorption and compression processes increase the internalenergy use for the power plant by 10-40%.9

Transport

The availability of transportation to move the captured CO2 presents a second critical issue to thetechnical viability of the CCS option.

5 Search of EPA’s RACT/BACT/LAER Clearinghouse, EPA Clean Air Technology Center, 10/8/2012, and literature survey.6 Whether Mississippi Power can recover the costs of building the Kemper facility is currently pending before the Sixth ChanceryCourt District of Mississippi.7 According to the Penwell project website, as of September 14, 2012 construction of this project had not begun.http://www.texascleanenergyproject.com/news-room/8 Report of the Interagency Task Force on Carbon Capture and Storage, August 2010.9 Intergovernmental Panel on Climate Change, Special Report on Carbon Dioxide Capture and Storage, (Bert Metz et al. eds.,2005)

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CO2 pipelines in the Permian Basin are shown in the figure below. There are presently no existingpipelines that could transport the CO2 stream from Antelope Station to a storage facility or an enhancedoil recovery (“EOR”) field. The closest existing CO2 pipeline – the Anton-Irish Pipeline - is located

CO2 Pipelines in the Permian Basin10

about twenty miles west of Antelope Station. The Anton-Irish Pipeline is an 8” pipeline that is privatelyowned by Oxy Permian and the line’s capacity is dedicated to Oxy’s operations.11 Because this is aprivate line, GSEC cannot demand access to the line and even if Oxy were amenable to GSEC using itsline, whether the pipeline or the site it delivers to have any available capacity is unknown to GSEC. Inaddition the Anton-Irish line may not be suitable for the transportation of anthropogenic CO2. In its 2012report The Global CCS Institute noted:

[T]here are significant differences between the US experience with CO2 EOR pipelines(mainly dealing with naturally occurring CO2), and the expertise needed to designtransport systems for anthropogenic CO2. The composition of CO2 that is captured from

10 Advanced Resources International, Basin-Oriented Strategies for CO2 EOR: Permian Basin, prepared for U.S. Department ofEnergy, February 2006.11 A Policy, Legal and Regulatory Evaluation of the Feasibility of a National Pipeline Infrastructure for the Transport and Storageof Carbon Dioxide, page 38 (September 2010).

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power plants, for instance, will influence the hydraulics calculations that are needed todesign these pipelines. Impurities or by-products such as nitrogen, argon, methane, andhydrogen lower the density of a CO2 stream, resulting in a higher pressuredrop…Moreover, combinations of impurities (e.g. from different sources) could togetherraise the critical pressure more than that from one component in isolation. Thecharacteristics of CO2 with impurities are therefore vitally important to know in order toproperly engineer a CO2 transport system. Detailed thermodynamics of CO2 withimpurities has been modeled, but the available models need to be further validated.12

Aside from the costs related to the building of a new CO2 line, there are other adverse factors. Privateright of way would need to be obtained from likely hundreds of landowners. The sensitivity of andimpact on wildlife of such a pipeline would need to considered along with the time delays inherent inobtaining all of the required permits and approvals from State and possibly Federal agencies.

Storage

Finally, the availability of a geologic storage site for the storage of the captured CO2 or for use in EORoperations presents many technical challenges. After a search of publicly available information, GSECwas unable to find any geologic sites in the immediate vicinity of Antelope Station that are viable forlarge-scale, long-term CO2 storage. Even if there were a storage site with available capacity, anygeologic site to be used for CO2 injection and storage would need to be extensively characterized andstudied which would take several years and would cost several million dollars.13 The viability of apotential storage site depends on the trapping mechanisms and capacity of the geological formations, andthe risks for environmental effects on subsurface and surface waters resulting from pipeline and storagefacility leaks. In addition the quality of the CO2 produced from the Antelope Station would impact thesuite of storage options available to it. While EOR sites exist in the Permian Basin, Antelope Station isapproximately 20 miles away from the nearest possible pipeline terminus and the transportationchallenges noted above would apply. In addition, whether the captured CO2 would be suitable forinjection as part of an EOR operation is unknown.

Because of the lack of demonstration of CCS on gas turbine power plants, and other power plantapplications, lack of commercial deployment, lack of a transport pipeline, and uncertainties on thepossible use of the CO2 for EOR or for storage in geologic storage sites, CCS is not considered to be atechnically viable option.

Gas turbo machinery such as that proposed for use at Antelope Station are readily commercially availableand demonstrated in practice, and are considered to be technically viable. The new turbine proposed forAntelope Station has a low heat rate (conversely, a high energy efficiency) due to the use of advanced gasturbine technology. By minimizing fuel usage, these techniques also minimize the release of GHG. Thisis discussed further below.

6.1.3 Step 3 - Rank remaining control technologies.

CCS technology has the potential to remove between 85 to 90% of the CO2 from the turbine train exhaust,and this potential capability gives it the first rank for control effectiveness. The baseline option to useefficient gas turbine technology does not reduce CO2 further than by the innate efficiency of the gasturbine production technology.

12 Global CCS Institute, The Global Status of CCS: 2012, Canberra Australia, 123-124 (emphasis added).12 Ibid. at 129.

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6.1.4 Step 4 - Evaluate the most effective controls and document results.

Post-combustion capture of CO2 could potentially remove 90%, or 485,296 tons per year of CO2-e fromthe turbine exhaust.

Costs for CCS applied to natural gas-fired gas turbines, primarily in combined cycle applications, havebeen widely examined in studies conducted by the U.S. Department of Energy, the Interagency TaskForce on Carbon Capture and Storage, the Electric Power Research Institute, and others. Results of themost recent of these have been presented in the “The Cost of Carbon Capture and Storage for Natural GasCombined Cycle Power Plants”14 along with additional estimates generated from Carnegie MellonUniversity’s Integrated Environmental Control Model. These cost estimates can be readily extrapolatedto the Antelope turbine exhaust because the exhausts from both simple-cycle turbines and combined cyclepower plants have similar characteristics, including similar levels of impurities and carbon dioxide (3-5%by volume). One difference is the scale of the production facility. The studied combined cycle powerplants have all featured two F Class gas turbines with a total power output approximately 2.5 times that ofthe turbine proposed for Antelope Station. This difference in scale results in a higher capital cost per unitof power produced or carbon dioxide removed for the Antelope turbine. While GSEC has considered thateffect in the calculation of capital cost below, we have not escalated the annualized costs to consider thehigher relative capital cost for a CCS system used with a single simple cycle turbine. The annualizedcosts for a CCS facility can thus be expected to be even higher than the estimates provided below. Costsare presented in 2011 dollars.

Cost Component CCS Cost for Antelope Station

Total Capital Cost $196 million

Total Annualized Cost $29-50 million

Cost Effectiveness $61-104/ton CO# removed

The capital costs include the CO# absorption train, CO# compression train, CO# pipeline costs, and costsfor the injection of CO# into storage sites or EOR sites. The total annualized costs included annualizedcapital costs and all fixed and variable operating and maintenance costs. These costs can be expected toreasonably represent the minimum costs of CCS for the turbine at Antelope Station. The cost of CCSwould increase the cost of electricity produced at the plant by $0.03-0.05/kWh. Included in these costsare the cost of the higher energy demands at the plant due to the use of CCS, with an expected increase inenergy usage (or a reduction in the net power from the plant) of about 15%. The costs estimates weredeveloped with data from the paper cited above and from the Global CCS Institute’s 2012 Status Report.15

CCS may also have adverse environmental impacts on subsurface and surface water qualities, but likemany aspects of CCS, the extent of these and other environmental effects is uncertain.

Finally, it is worth noting that anthropogenic CO2 used and trapped within an EOR reservoir may notserve the goal of reducing overall GHG emissions. The objective of using CO2 in EOR operations is to

14 E.S. Rubin and Haibo Zhai (Carnegie Mellon University), “The Cost of Carbon Capture and Storage for Natural Gas CombinedCycle Power Plants”, Environmental Science and Technology, 2012, 46, 3076-3084.15Global CCS Institute, The Global Status of CCS: 2012, Canberra Australia, 145.

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produce oil which will be combusted and emit GHG gasses. Consequently, the net result of a CCSsystem that is used for EOR could ultimately result in zero GHG savings.16

The base case option of the advanced F class turbine system will not entail the CCS costs or energyimpacts.

6.1.5 Step 5 - Select the BACT.

Economic, energy, and environmental impacts all argue against the selection of CCS as BACT. Thehigher annual costs, and the resulting impact on the costs of produced electricity, would in fact result inthe cancellation of the turbine project for Antelope Station project, if CCS were required as BACT. CCSis also not considered technically viable. BACT for GHG emissions is the use of the efficient gas turbinetechnology proposed for the Antelope Station, with the turbine facility operated and maintained properlyaccording to the manufacturer recommendations.

6.2 Natural Gas Line Fugitives

Fugitive emissions from the natural gas supply lines amount to 85.55 tons/yr of CO2-e emissions, and4.15 tons/yr of GHG emissions on a mass basis.

6.2.1 Identify all available control technologies.

Piping fugitive leaks can be controlled by three basic approaches:

1) Use of leak-less and/or seal-less equipment,2) Use of a leak detection and repair program using either periodic leak inspection by instrument or

remote sensing of leaks by infrared camera,3) Use of audio/visual/olfactory (AVO) observations of leaks in periodic walkthroughs as part of normal

operations. (This method of control results in the base emissions of fugitive leaks.)

6.2.2 Eliminate technically infeasible options.

Leak-less piping equipment has been used in the chemical process industry when toxic or hazardousmaterials are used. They have not been used in natural gas supply lines, and operating/maintenanceproblems with their operation would require line shutdowns to effect repairs. Because of the safety riskand increased GHG emissions of line shutdowns to repair leak-less equipment, and because the naturalgas fuel lines do not contain toxic or hazardous materials, the use of leak-less piping components isinfeasible and impracticable. The other options to control fugitive leaks are technically feasible.

6.2.3 Rank remaining control technologies.

Both instrument detection of leaks and remote sensing of leaks have been determined to be equivalentcontrol methods by EPA.17 These methods are ranked as most effective, with an estimated effectivenessof 75-95%. AVO methods are less effective since their observations are not conducted at specifiedintervals. However, because of the presence of natural gas odorants and the high pressure of the naturalgas, AVO is moderately effective. We have not attributed a control efficiency to the AVO monitoring byperiodic walk-around inspections because this technique is very likely included with the emission factorused to estimate GHG emissions.

16Global CCS Institute, The Global Status of CCS: 2012, Canberra Australia, 153.17 73 FR 78199-78219, December 22, 2008.

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6.2.4 Evaluate the most effective controls and document results.

Leak monitoring quarterly using instrument monitoring would cost approximately $1,500 per quarter or$6,000 annually. Leak monitoring using camera/remote sensing would cost approximately $4,000 perquarter or $16,000 annually. Leak repair costs are estimated to be approximately $5,000 per year. Costsfor instrumental or remote monitoring of leaks, and their repair, would thus cost $11,000 to $21,000annually. For an overall reduction of 85% of the CO2-e emissions from equipment leaks, this wouldresult in a cost effectiveness of $150-290/ton CO2-e. Periodic AVO monitoring, as a base option, wouldhave no costs other than those included in normal plant operation and maintenance expense. None ofthese options have significant adverse environmental or energy impacts.

6.2.5 Select the BACT.

Due to the high cost of instrument monitoring or remote monitoring of leaks, with a cost effectiveness of$150-290/ton CO2-e, neither of these options are BACT for fugitive leaks from the natural gas supplysystem. BACT is the periodic AVO observation of piping equipment.

6.3 SF6 Leaks from Circuit Breakers

SF6 leaks from circuit breakers will amount to 174.47 tons/yr of CO2-e emissions, and 0.0073tons/yr of GHG emissions on a mass basis.

6.3.1 Identify all available control technologies.

There are two technology options. The first is to replace SF6 with an alternate dielectric material oralternative type of circuit breaker. The second is to use comprehensive leak detection with modern SF6

circuit breaker technology.

6.3.2 Eliminate technically infeasible options.

Although the development of alternative dielectric materials and types of circuit breakers is underway, noalternative or option has been found to be superior to SF6 based circuit breakers for high voltageapplications. SF6 provides better electrical insulation, and quenches electric arcs more effectively.Circuit-breakers using SF6 as the insulating and quenching medium are smaller, safer, and have longeruseable lifetimes than alternatives. As such, the use of alternate dielectric materials or types of circuitbreaker is not technically feasible.

The use of leak detection and modern SF6 circuit breaker technology is feasible.

6.3.3 Rank remaining control technologies.

The use of modern circuit breaker technology and comprehensive leak detection methods will allowAntelope Station to achieve a leak rate of 0.5%/year.

6.3.4 Evaluate the most effective controls and document results.

The use of modern circuit breaker technology and comprehensive leak detection methods will not causeany significant adverse economic, environmental, or energy effects.

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6.3.5 Select the BACT.

Use of modern circuit breaker technology and a comprehensive leak detection and disposition programconstitutes BACT. The comprehensive program will involve inventory and use tracking, leak detectionby hand-held halogen detectors, and low-gas density alarms. It will also include a recycling program sothat SF6 is evacuated into portable cylinders rather than vented to atmosphere.

6.4 Proposed Emission and Production Limits, Monitoring, and Maintenance Requirements

Table 5 shows the emission and production limits, monitoring, and maintenance requirements proposed tosupport BACT.

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Emission SourceEmission and ProductionLimits

Monitoring Requirements MaintenanceRequirements

Gas turbine " 538,754 tons/yr CO2-e" 237,767 lbs/h CO2-e" 923,443 MWh (gross)/yr" 1217 lbs CO2-e/MWh

(gross) @ max. load" 1514 lbs CO2-e/MWh

(gross) @ any load from50% to 100% load

" Determine hourly andannual GHG emissionsusing 40 CFR 98.43

" Determine and recordannual GHG emissionson a rolling 12-monthbasis

" Determine and record lbsCO2/MWh (gross) as arolling 30-day average

" Record gross electricityoutput in MWh/yr on arolling 12-month basis

" Operate andmaintain allequipment accordingto manufacturerrecommendations

Natural GasPiping FugitiveLeaks

" 85.55 tons/yr CO2-e " Record leak observationsreporting by operatingand maintenance staff


SF6 FugitiveLeaks

" 174 tons/yr CO2-e " Use inventory records todetermine SF6 and CO2-eemissions on a calendaryear basis

" Monitor for leaks usinghalogen detector on amonthly basis

" Implement arecycling programso that SF6 isevacuated intoportable cylindersrather than vented toatmosphere.


Table 5. Proposed Emission and Production Limits, Monitoring, and Maintenance Requirements

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golden spread electric coop - antelope station ......(psd) regulations in 40 cfr 52.21, antelope...

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