PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

FOR GREENHOUSE GAS EMISSIONS 

ISSUED PURSUANT TO THE REQUIREMENTS AT 40 CFR § 52.21 

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION 6 

PSD PERMIT NUMBER: PSD-TX-979-GHG 

PERMITTEE: Calpine Corporation 

717 Texas, Suite 1000 

Houston, TX 77002 

FACILITY NAME: Calpine Corporation, 

Deer Park Energy Center (DPEC) LLC 

FACILITY LOCATION: 5665 Highway 225 

Deer Park, TX 77536 

Pursuant to the provisions of the Clean Air Act (CAA), Subchapter I, Part C (42 U.S.C. Section 7470, et. 

Seq.), and the Code of Federal Regulations (CFR) Title 40, Section 52.21 , and the Federal 

Implementation Plan at 40 CFR § 52.2305 (effective May I, 2011 as published at 76 FR 25178),the U.S. 

Environmental Protection Agency, Region 6 (EPA) is issuing a Prevention of Significant Deterioration 

(PSD) permit to the Calpine Corporation, Deer Park Energy Center (DPEC) LLC for Greenhouse Gas 

(GHG) emissions. The Permit applies to the two-phase construction of a new 180 megawatt (MW) 

natural gas-fired combined-cycle combustion turbine, identified as CTG5/HRSG5, to augment the 

existing power generation at the existing facility located in Deer Park, Texas. 

Calpine Corporation is authorized to construct at the Calpine Corporation, Deer Park Energy Center 

(DPEC) as described herein, in accordance with the permit application (and plans submitted with the 

permit application), the federal PSD regulations at 40 CFR § 52.21, and other terms and conditions set 

forth in trus PSD permit in eonjunction with the corresponding Texas Commission on Environmental 

Quality (TCEQ) PSD permit No. PSD-TX-979. Failure to comply with any condition or term set forth in 

tllis PSD Permit may result in enforcement action pursuant to Section 113 of the Clean Air Act (CAA). 

Trus PSD Permit does not relieve Calpine Corporation of the responsibility to comply with any other 

applicable provisions of the CAA (including applicable implementing regulations in 40 CFR Patts 51, 

52, 60, 61,72 through 75, and 98) or other federal and state requirements (including the state PSD 

program that remains under approval at 40 CFR § 52.2303). 

In accordance with 40 CFR § 124.15(b)(3), this PSD Permit becomes effective immediately upon 

issuance of trus final decision. 

Car~&-- l E. Edlund, P.E, Director Date 

Multimedia Plaruling and Pt~rm ittin g Division 
Calpine Corporation, Deer Park Energy Center (DPEC) LLC (PSD-TX-979-GHG) 

Prevention of Significant Deterioration Permit 

For Greenhouse Gas Emissions 

Final Permit Conditions 

PROJECT DESCRIPTION 

The proposed facility is a natural gas-fired combined-cycle electric generating unit at the Deer 

Park Energy Center (DPEC) LLC power plant in Harris County, Texas. With this construction 

permit, Calpine Corporation will construct a new natural gas-fired combined-cycle combustion 

turbine generator (CTG) unit, identified as CTGS/HRSGS, with a generating capacity of 

approximately 180 MW which is of the similar design and output as the other existing four ( 4) 

natural gas-fired combined-cycle combustion turbine units at the plant. Construction will be 

completed in two phases: in phase one, a new Siemens FD2-series turbine will be constructed; in 

the second phase, the FD2 turbine which will be modified and upgraded to the FD3-series within 

the statutory time lines as defined by this permit. The steam produced from the new combustion 

turbine will exhaust to a dedicated Heat Recovery Steam Generator (HRSG) to produce steam. 

The steam produced from the HRSG is routed to either the existing steam turbine unit to produce 

electricity for sale to the Electric Reliability Council of Texas (ERCOT) power grid or may be 

sold for use at an adjacent industrial facility. 

EQillPMENT LIST 

The following devices are subject to this GHG PSD permit. 

Emission Unit Id. Description 

No. 

CTG5/HRSG5 (FD2- Natural Gas-Fired Siemen FD2-Series 501 F Combustion Turbine Generator (CTG5) 

Series) rated at a maximum base-load electric output of approximately 168 MW and venting to 

(Initial Phase) a dedicated Heat Recovery Steam Generator (HRSGS) that is equipped with a Selective 

Catalytic Reduction (SCR). 

CTG5/HRSG5 (F03- Natural Gas-Fired Siemen FD3-Series 50 IF Combustion Turbine Generator (CTGS) 

Series) rated at a max imum base-load electric output of approximately 180 M W and venting to 

a dedicated Heat Recovery Steam Generator (HRSGS) that is equipped with a Selective 

(Final Phase) Catalytic Reduction (SCR). 

NG-FUG Fugitive Natural Gas emissions from piping components (inciuding valves and flanges) 

SF6-FUG SF6 Insulated Electrical Equipment (i.e., circuit breakers) consisting of one new 72 lb 

SF6 insulated generator circuit breaker, 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Hanis County) 

I. GENERAL PERMIT CONDITIONS 

A. PERMIT EXPIRATION 

Page 3 of21 

PSD-TX-979-GHG 

Pursuant to 40 CFR §52.21 (r), this PSD Permit shall become invalid if construction: 

1. is not commenced (as defined in 40 CFR §52.21(b)(9)) within eighteen (18) months after 

the approval takes effect; or 

2. is discontinued for a period of eighteen (18) months or more; or 

3. is not completed within a reasonable time; and, 

4. EPA may extend the eighteen (18) month period upon a satisfactory showing that an 

extension is justified. 

B. PERMIT NOTllFICATION REQUIREMENTS 

Permittee shall notify E.P A Region 6 in writing or by electroni·c mail of the: 

1. date construction is commenced, postmarked within thirty (30) calendar days of such 

date; 

2. actual date of initial strutup, as defined in 40 CFR §60.2, postmarked within fifteen (15) 

calendar days of suc:h date; 

3. date upon which initial performance tests will commence, in accordance with the 

provisions of Section V, postmarked not less than thirty (30) calendar days prior to such date. 

Notification may be provided with the submittal of the performance test protocol required 

pursuant to Section V.E; and 

4. date upon which initial certification tests of fuel flow meter and determination of the 

GCV (Gross Calorific Value) and associated data acquisition and handling system in 

accordance with 40 CFR 75, Appendix D. Additionally, the initial certification or 

recettification appliGation shall be submitted for the fuel flow meter as required by 40 CFR 

75, Appendix D. 

5. date upon which certification tests of the C02 CEMS will commence, if Calpine chooses 

to install a C02 continuous emission monitoring system (CEMS), in accordance with 40 CFR 

§ 75.61(a)(l)(i) and 40 CFR Part 60, Appendix B, Performance Specification 3. 

Additionally, the initial certification or recertification application shall be submitted for the 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Han-is County) 

C02 CEMS as required by 40 CFR 75.63 . 

Page 4 of 21 

PSD-TX-979-GHG 

6. date upon which the FD3-series combustion turbine generator is in commercial operation 

or date eighteen ( 18) months after the completion of initial. performance testing, or whichever 

comes first. 

C. FACILITY OPERATION 

At all times, including periods of startup, shutdown, and malfunction, Permittee shall, to the 

extent practicable, maintain and operate the facility including associated air pollution control 

equipment in a manner consistent with good air pollution control practice for minimizing 

emissions. Determination of whether acceptable operating andl maintenance procedures are being 

used will be based on infom1ation available to the EPA, which may include, but is not limited to, 

monitoring results, review of operating maintenance procedur1es and inspection of the facility. 

D. MALFUNCTION REPORTING 

1. Permittee shall notify EPA by mail within forty-eight (48) hours following the discovery 

of any failure of air pollution control equipment, process equipment, or of a process to 

operate in a normal manner, which results in an increase in C02 emissions above the 

allowable emission limits stated in Section II of this pennit. 

2. Within ten ( 1 0) days of the restoration of normal operations after any failure described in 

Section I.D.l , the Permittee shall provide a written supplement to the initial notification that 

includes a description of the malfunctioning equipment or abnormal operation, the date of the 

initial malfunction, the period oftime over which emissions were increased due to the failure, 

the cause of the failure, the estimated resultant emissions in excess of those allowed in 

Section II, and the methods utilized to mitigate emissions and restore normal operations. 

3. Compliance with this malfunction notification provision shall not excuse or otherwise 

constitute a defense: to any violation of this permit or any law or regulation such malfunction 

may cause. 

E. RIGHT OF ENTRY 

EPA authorized representatives, upon the presentation of credentials, shall be permitted: 

1. to enter the premises where the facility is located or where any records are required to be 

kept under the terms and conditions of this PSD Permit; 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Page 5 of21 

PSD-TX-979-GHG 

2. during normal business hours, to have access to and to copy any records required to be 

kept under the terms ar.'1d conditions of this PSD Pern1it; 

3. to inspect any equipment, operation, or method subject to requirements in this PSD 

Permit; and, 

4. to sample materi.als and emissions from the source(s). 

F. TRANSFER OlF OWNERSHIP 

In the event of any changes in control or ownership of the facilities to be constructed, this PSD 

Permit shall be binding on all subsequent owners and operators. Permittee shall notify the 

succeeding owner and operator of the existence of the PSD Permit and its conditions by letter; a 

copy of the letter shall be forwarded to EPA Region 6 within thirty (30) days of the letter 

signature. 

G. SEVERABILITY 

The provisions of this PSD Permit are severable, and, if any provision ofthe PSD Permit is held 

invalid by a court of competent jurisdiction, the remainder of this PSD Permit shall not be 

affected. 

H. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER 

ENVIRONMENTAL LAWS 

Permittee shall construct and operate this project in compliance with this PSD Permit, the 

application on which this permit is based, the TCEQ PSD Permit No. PSD-TX-979-GHG, as 

finalized and all other applicable federal, state, and local air quality regulations. This PSD permit 

does not release the Permittee from any liability for compliance with other applicable federal, 

state and local environmental laws and regulations, including the Clean Air Act. 

I. ACRONYMS AND ABBREVIATIONS 

AVO 

~=tarT I...JJ\. ....... l 

Btu 

CAA 

CEMS 

CFR 

CH4 

co 

C02 

Audio, Visual, and Olfactory 

Best Available Control Technology 

British thermal unit 

Clean Air Act 

Continuous Emissions Monitoring System 

Code of Federal Regulations 

Methane 

Carbon Monoxide 

Carbon Dioxide 
Calpine Corporation, Oleer Park Energy Center 

Deer Park, TX (Harris County) 

C0 2e 

DCS 

OPEC 

dscf 

EPN 

ERCOT 

FR 

GHG 

gr 

GWP 

HHV 

hp 

Ill' 

HRSG 

KWh 

lb 

MMBtu 

MW 

MWh 

N20 

NSPS 

PSD 

QAIQC 

RATA 

SCFH 

SCR 

SF6 

TAC 

TCEQ 

tpy 

usc 

voc 

Carbon Dioxide Equivalent 

Distributed Control System 

Deer Park Energy Center 

Dry Standard Cubic Foot 

Emission Point Number 

Electric Reliability Council of Texas 

Federal Register 

Greenhouse Gas 

Grains 

G lobal Warming Potential 

High Heating Value 

Horsepower 

Hour 

Heat Recovery Steam Generator 

Ki lowatt-hour 

Pound 

Million British Thermal Units 

Megawatt 

Megawatt -hour 

Nitrous Ox ides 

New Source Performance Standards 

Prevention of Significant Deterioration 

Quality Assurance and/or Quality Control 

Re lative Accuracy Test Audit 

Standard Cubic Feet Per Hour 

Selective Catalytic Reduction 

Sulfur Hexafluoride 

Texas Administrative Code 

Texas Commission on Environmental Quality 

Tons Per Year 

United States Code 

Volatile Organic Compounds 

Page 6 of21 

PSD-TX -979-GH G 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

II. SPECIAL PERMfiT CONDITIONS 

A. Facility Emission Limits 

Page 7 of21 

PSD-TX-979-GHG 

The proposed BACT limits are in terms of efficiency measured in units of Btu of fuel energy 

consumed in order to generate a kilowatt of electric energy (Btu/kWh). The BACT limits for the 

heat rate in terms ofBtu/ kWh (HHV) on an annual basis will be the same for the FD2 

configuration as the FD3 configuration. The FD3 configuration provides greater electrical 

output at high ambient temperatures during base load periods. Therefore, for the FD3, the 

potential mmual electric generation (MWH) and fuel usage, as well as corresponding GHG 

emissions, will be higher on an annual basis. Consequently, the BACT limits, monitoring and 

recordkeeping requirements listed in tlus pernlit are identical for both the FD2- and FD3-series 

combined-cycle combustion turbine generators. Any output-based emissions, in tons of C02 per 

megawatt hour (tons/M\Vh) on a 30-day rolling average and armual emissions, in tons of C02e 

per year (TPY) on a 365-day rolling average basis shall not exceed the following: 

(NEXT PAGE) 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Table 1 Phase 1 Facilitv Emission Limits 

P hase I of Construction 

G HG Mass Basis 

Emission Description G HG Unit Potential O utpu t-based 

Emissio ns BACT COz 

(TPY)

2

.J Limie 

C02 1,044,629 C02 

0.460 

tons/MWh 

CT G5 CTG5/HRSG5 

(FD2) I Annual 

HRSG5 Emissions 7,730 

Cf!t 19.34 CH4 Btu/KWh 

N20 1.93 N20 

Fugitive Natural 

Gas emissions 

NG- from piping C02 0. 11 COz 

FUG components 

(including valves 

& flanges) CH4

4 2.84 CH44 

SF6- SF 6 Insulated 

FUG Electrical 

Equipment SF6 0.000 18 SF6 

Page 8 of21 

PSD-TX-979-GHG 

BACT 

Annual 

Tons pe r BACT 

yea r Limit 

C0 2e2

'

3 (TPY C0 1 e2

'

3

) 

1,044,629 

1,045,635 

406 

599 

0.11 60 

59.69 

4.3 

4.3 

I. Compliance wtth the output-based emtsston lnntts (on a per hour basts) ts based on a 30-day ro llmg 

average. 

2. Compliance with the annual emission limits (tons per year) is based on a 365-day rolling average. 

3. The tpy emission limits specified in this table are not to be exceeded for this facility and includes em.ission..s 

only from the facility during nom1al operations and startup and shutdown activities. 

4. Because the emissions from this unit are calculated to be 96% methane (CH4), the remaining pollutant 

emission (C02) is not presented in the table. 

5. Because the emissions from this unit are calculated to be over 99.9% carbon dioxide (C02), the remaining 

pollutant emissions (CH4 and N20) are not presented in the table. 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Table 2 Phase 2 Facilitv Emission Limits 

Phase 2 of Construction 

GHG Mass Basis 

Emission Description Unit GHG Potential Output-based 

Emissions BACT C02 

(TPYl'3 Limit1 

COz 1,062, 627 COz 

0.460 

CTGS CTG5/HRSG tons/MWh 

(FD3) I 5 Annual 

RRSGS Emissions 7,730 

CH4 19.67 CH4 Btu/KWh 

NzO 1.97 N20 

Fugitive 

Natural Gas 

emissions 

NG- from piping COz 0. 11 C02 

FUG components 

(including 

valves & 

flanges) Cl-Lt 4 2.84 CH4

4 

SF6- SF 6 insulated 

FUG Electrical 

Equipment SF6 0.000 18 SF6 

Page 9 of21 

PSD-TX-979-GHG 

BACT 

Annual 

Tons per BACT 

year Limit 

C01e1

'

3 (TPY C02e2

'

3

) 

1,062, 627 

1,063,650 

4 13 

6 10 

0. 11 60 

59.69 

4.3 

4.3 

I. Compliance with the output-based emission limits (on a per hour basis) is based on a 30-day rolling 

average. 

2. Compliance with the annual emission limits (tons per year) is based on a 365-day rolling average. 

3. The tpy emission limits specified in this table are not to be exceeded for this facility and includes emissions 

only from the facility during nom1al operations and startup and shutdown activities. 

4. Because the emissions from this unit are calculated to be 96% methane (CH4), the remaining pollutant 

emission (C02) is not presented in the table. 

5. Because the emissions from this unit are calculated to be over 99.9% carbon dioxide (C02), the remaining 

pollutant emissions (CH4 and N20) are not presented in the table. 
Calpine Corporation, neer Park Energy Center 

Deer Park, TX (Harris County) 

B. Requirements for Combustion Turbine 

Page 10 of21 

PSD-TX-979-GHG 

1. Combustion Turbine Generator (CTG) BACT Emission Limits 

a. Within 180 days of the date of initial startup of the FD2-series combustion turbine 

generator, the Permittee shall perform an initial emission test for C02 and use 

emission f.:tctors from 40 CFR Part 98. The Permittee shall ensure that GHG 

emissions from the Combustion Turbine Generator (CTG5) and heat recovery 

steam generator (HRSG5) into the atmosphere in excess of 0.460 tons C02/MWh 

(net), not including duct firing, during the test. To determine this BACT emission 

limit, Permittee shall calculate the limit based on the measured net hourly energy 

output (MWh (net)), the CTG is operating above 90% of its design capacity without 

duct burning firing and the results shall be corrected to ISO conditions (59°F, 14.7 

psia, and 67% humidity). If the CTG does not meet the design emissions limit, then 

the Permittee shall remedy the CTG's failure to meet the design emissions limit, 

and shall not combust any fuel in the CTG until the Permittee has shown 

complianoe with that limit during a subsequent emission test. 

b. Upon demonstration that the FD2-series combustion tmbine generator is in 

compliance with the design emissions limit via an emission test, the Permittee shall 

not discharge or cause the discharge of emissions: from the Combustion Turbine 

Generator (CTG5) and heat recovery steam generator (HRSG5) into the atmosphere 

in excess of 0.460 ton C02/MWh (net) on a 30-day rolling average and shall not 

discharge or cause the discharge of emissions into the atmosphere in excess 

1,045,635 tons of C02e on a 365-day rolling average. To determine this BACT 

emission Limits, the Permittee shall calculate the limit based on the measured net 

homly energy output (MWh (net)) and the tons of C02 calculated from the 

equations provided in 40 CFR 75, Appendix D and For the C02 emissions CEMS 

data. The calculated hourly rate is averaged daily. 

c. Within 180 days of the date of initial startup of the FD3-series combustion turbine 

generator, the Permittee shall perform an initial emission test for C02 and use 

emission factors from 40 CFR Part 98. The Pemlittee shall ensure that GHG 

emissions from the Combustion Turbine Generator (CTG5) and heat recovery 

steam generator (HRSG5) into the atmosphere in excess of 0.460 tons C0 ~.1\llh 

(net), not including duct burning firing, during the test. To determine this BACT 

emission limit, Permittee shall calculate the limi.t based on the measured net hourly 

energy output (MWh (net)), the CTG is operating above 90% of its design capacity 

without duct burning and the results shall be corrected to ISO conditions (59op, 14.7 

psia, and 67% humidity). If the CTG does not meet the design emissions limit, then 

the Permittee shall remedy the CTG's failure to meet the design emissions limit, 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Han-is County) 

Page 11 of21 

PSD-TX-979-GHG 

and shall not combust any fuel in the CTG until the Permittee has shown 

romn ~nf'l> u tith tl~at li.nit rlnri..,n .:1 S"bSPf"111Pnt Prl"' ;.,s;o,.., t<>st .... ...... l" .... ~..~.............. .... ....... .. ,.. _1 ... ...... ...... '""'""'"'"" .... 5 ..... "" \,.;'"t""'"''•"' ""11..11..:> , .11 """ \ . 

d. Upon demonstration that the FD3-series combustion turbine generator is in 

compliance with the design emissions limit via an emission test, the Permittee shall 

not discharge or cause the discharge of emissions from the Combustion Turbine 

Generator (CTG5) and heat recovery steam generator (HRSG5) into the atmosphere 

in excess of 0.460 ton C02/MWh (net) on a 30-day rolling average, and shall not 

discharge or cause the discharge of emissions into the atmosphere in excess 

1,063,650 tons ofC02e on a 365-day rolling average. To determine this BACT 

emission limits, the Permittee shall calculate the limit based on the measured net 

hourly ene1rgy output (MWh (net)) and the tons of C02 calculated from the 

equations provided in 40 CFR 75, Appendix D and For the C02 emissions CEMS 

data. The calculated hourly rate is averaged daily. 

e. Modification of the proposed FD2-series combustion turbine generator, identified 

as CTG5, to the FD3-series combustion turbine generator shall commence within 

eighteen (18) months of commencement of commercial operation of the initial 

project, or no later than eighteen (18) months after initial testing is completed. 

Completion of the initial project will occur the date of the commercial operation of 

the FD2-series combustion turbine. 

f. Within 180 days of the date of initial strutup of for both the FD2 and FD3-series 

combustion turbine generator, the Permittee shall not exceed a Combustion Turbine: 

Generator average net heat rate of 7, 730 Btu/kWh (HHV), not including duct burner 

firing, during the test for combustion turbine unit. To determine this BACT 

emission limit, Permittee shall calculate the average net heat rate on a hourly basis 

consistent with equation F-20 and procedures provided in 40 CFR Part 75, 

Appendix F, § 5.5.2, the measured net hourly heat rate (kWh), that the CTG is 

operating above 90% of its design capacity without duct burning and the results 

shall be corrected to ISO conditions (59°F, 14.7 psia, and 67% humidity). If the 

CTG does not meet the emissions limit, then the Permittee shall remedy the CTG's 

failure to meet the emissions limit, and shall not combust any fuel in the CTG until 

the Permittee has shown compliance with that heat rate limit during a subsequent 

emission test. 

g. Upon initial demonstration that the FD2-series and FD3-series combustion turbine 

generator complies with the emissions limit via an emission test, the Permittee shall 

not exceed a Combustion Turbine Generator net heat rate of7,730 Btu/kWh (HHV) 

on a 30-day rolling average, for both the FD2- or FD3-series combustion turbine 

unit. To determine this limit, Permittee shall calculate the average net heat rate on a 
Calpine Corporation, D•~er Park Energy Center 

Deer Park, TX (Harris County) 

Page 12 of21 

PSD-TX-979-GHG 

hourly basis consistent with equation F-20 and procedure provided in 40 CFR Part 

"7C A --e-...1: .. C' 1: c c...., ~ •• A +t..~ -- e~~ .. -e...l -~• t.. ~ .. -1 .. o-~" ~ .. +-.. + / 1, \1 / 1.\ Tl,o I J , n.vp HUlA r , ':-J J .J ,.:., alJU lllv Ill a;:,uJ U llvl 11ULH lJ vllvl oJ UUlJ.lUL \1\. V> ll)• 111'-

Calculated hourly heat rate is averaged daily. 

h. Permittee shall determine the hourly C02 emission rate from 40 CFR Part 75, 

Appendix G, using Fe factors updated monthly from fuel analysis or, as an 

alternative, permittee may install and operate a volumetric stack gas flow monitor 

and associated data acquisition and handling syst,em in accordance with the C02 

CEMS system provided in 40 CFR § 75.10(a)(3) and (a)(5). 

2. Monitoring of C02 Emissions for CTG5/HRSG5 

a. The permittee shall determine the C02 hourly emission rate and C02 mass 

emissions for the combustion turbine generator and heat recovery steam generator, 

identified as CTG5/HRSG5, using an 0 2 monitor according to appendix F to 40 

CFR Subpart 75. In accordance to 40 CFR Subpart 75.20(c)(4), the permittee shall 

determine hourly C02 concentration and mass emissions with a flow monitoring 

system; a continuous 0 2concentration monitor; fuel F and Fe factors; and, where 0 2 

concentration is measured on a dry basis (or where Equation F- 14b in appendix F 

to 40 CFR Subpart 75 is used to determine C02concentration), either, a continuous 

moisture naonitoring system, as specified in §75.ll(b)(2), or a fuel-specific default 

moisture percentage (if applicable), as defined in §75.11(b)(l); and by using the 

methods and procedures specified in appendix F to 40 CFR Subpart 75. 

b. Permittee shall install, calibrate, and operate a fud flow meter and perform periodic 

scheduled GCV fuel sampling for the combustion turbine generator and heat 

recovery steam generator, identified as CTG511-fRSGS, and shall meet the 

applicable requirements, including certification t~~sting, of 40 CFR Part 75, 

Appendix D and 40 CFR Part 60 to be used in conjunction with the Fe factor based 

on the procedures to calculate the C02 emission rate in 40 CFR Part 75, Appendix 

F. 

c. Oxygen analyzers shall continuously monitor and record oxygen concentration in 

the combustion turbine generator and heat recovery steam generator identified as r""'T'~C TDCr!.t:. T .. ,...1-. .... 11 ........... ....l .... ,..,,... +1... ...... ,.....,,. ,,....,... ..... ..... .......... ..-1~ .... ,.,.. .... t ...... ,...._ ,...,. ,... ,..n,.~nrr ._t::~o ..... ; ...... ,-1 "+t:.. 

\...; 1 UJ lT~ . .::>UJ. H ;:,uaH JvUUvv w,.; vAy ~;;u u;;autu0 ;:, lUau avv1a0 1110 y,.;uuu u1 u 

minutes OJ! less and record it at that frequency. 

d. The oxygen analyzers shall be quality-assured at least quarterly using cylinder gas 

audits (CG-As) in accordance with 40 CFR Part 60, Appendix F, Procedure 1, § 

5.1 .2, with the following exception: a relative accuracy test audit is not required 

once every four quarters (i.e., two successive semiannual CGAs may be conducted). 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Page 13 of21 

PSD-TX-979-GHG 

e. ..A .. s a..r1 alter11ative to Special Condition II.B.2.a, the pertnittee n1ay L~ ta11 a r'Q2 

CEMS and volumetric stack gas flow monitoring system with an automated data 

acquisition and handling system for measuring and recording C02 emissions 

discharged to the atmosphere. 

f. ln accordance with 40 CFR Part 75, Appendix D and 40 CFR Part 60, the permittee 

shall ensure that all required fuel flow meter is installed, a periodic schedule for 

GCV fuel sampling is initiated and all certification tests are completed on or before 

the earlier of 90 unit operating days or 180 calendar days after the date the unit 

conunences conunercial operation (as defined in 40 CFR Part 75, Appendix D and 

G). 

g. Permittee shall ensure compliance with the specifications and test procedures for 

fuel flow meter and/or C02 emission monitoring system at stationary sources, 40 

CFR Part 75 and 40 CFR Part 60. 

h. Permittee shall meet the appropriate quality assurance requirements specified in 40 

CFR Part 7'5, Appendix D and F and 40 CFR Part: 60 for the fuel flow meter and/or 

C02 emission monitoring system. 

3. FD2/FD3 Combustion Turbine Work Practice and Operational Requirements 

a. Permittee shall calculate the amount of C02 emitted for both the FD2- and FD3-

series CTG from combustion in tons per hour (tonslhr) on a 365-day rolling 

average, and converted to tons per year (tpy) based on equation G-4 of 40 CFR Part 

75 and the average net heat rate on an hourly basis based on the heat input 

calculation procedures contained in 40 CFR Part 75, Appendix F, equation F-20. 

b. The calculated C02 emissions from Special Condition Il.B.3.a shall be compared to 

the measured C02 emissions from the 02 emission monitor, required in Special 

Condition II.B.2.a, and ifthe Permittee is using the C02 monitor (CEMS) 

methodology, then the calculated hourly stack gas volwnetric flow rate, required in 

Special Condition Il.B.l , on a daily basis. If the mean difference between the 

calculated and measured C~ emission monitor result is greater than 10% of 

measured C02 concentration, the permittee shali review the emission units and 

monitoring instrumentation operational perfmmance. From this review, any 

corrective measures taken are to be identified, rec:orded, including the reason for the 

C02 emissiions difference and corrective measures completed within 48 hours of the 

corrective measures being taken. lf the pe1mittee chooses to install and operate a 

C02 CEMS equipped with a volumetric stack gas monitoring system, then the C02 
Calpine Corporation, er Park Energy Center 

Deer Park, TX (Harris County) 

Page 14 of21 

PSD-TX-979-GHG 

emission calculation from Special Condition II.B.3 .a and the mean difference "'"'......,.-'""...,.;,..."_ ;l"' ....," l"'\.'t'\I'Y.0. 11 ~ n ..,.o,.,n~ ... .a...-o ...... + +h.a- t-1-,.a. -·a•.....-vt.;t+ao. ,... h,,....ll ... al, r """ +1"\ o rlf"ltf"' YVULpa.tJ.;)Vltl t.;) llV tVHOVJ a 1\,.;\..fUll\.;Jlt\...JtL, LLI\,..11 UL\,...1--'\,.;lUULL\,.;\... uau tt,.,l J v11 ut""" ualu. 

from the C02 CEMS for compliance purposes. 

c. Permittee shall calculate the CH4 and N20 emissions on a 365-day rolling average. 

Permittee shall determine compliance with the CH4 and N20 emissions limits 

contained iin this section using the default CH4 and N2 0 emission factors contained 

in Table C-2 of 40 CFR Part 98 and the measured actual hourly heat input (HriV). 

d. Permittee shall calculate the C02e emissions on a 365-day rolling average, based on 

the procedures and Global Warming Potentials (GWP) contained in Greenhouse 

Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1. 

e. Fuel for the FD2 or FD3 Combustion Turbines shall be limited to natural gas with a 

fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr 

S/ 1 00 dscf). The gross calorific value of the fuel shall be determined monthly by the 

procedures contained in 40 CFR Part 75, Appendix F, §5.5.2 and records shall be 

maintained of the monthly fuel gross calorific vallue for a period of five years. 

Upon request, Permittee shall provide a sample and/or analysis of the fuel-fired in 

the Combustion Turbines or shall allow a sample to be taken by EPA for analysis. 

f. The flow rate of the fuel combusted in combustion turbine emission unit, identified 

as CTG5, :shall be measured and recorded using an operational non-resettable 

elapsed flow meter. 

g. Permittee shall measure and record the new energy output (MWh (net)) on an 

hourly basis. 

h. On or before the date of initial performance test required by 40 CFR 60.8, and 

thereafter, Permittee shall install, and continuously operate, and maintain the 

HRSG5 equipped with a SCR so emissions are a1t or below the emissions limits 

specified in this permit and TCEQ permit No. 45642/PSD-TX-979M2/N036M2. 

1. On or after initial performance testing, permittee shall use the combustion turbine, 

Heat Recovery Steam Generator, Steam Turbine and Plant-wide energy efficiency 

processes, work practices and designs as represented in the permit application. 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Page 15 of21 

PSD-TX-979-GHG 

4. Requirements during FD2/FD3 Combustion Turbine (CTGS) Startup and 

Shutdown 

a. Permittee shall minimize emissions during start-Ulp and shutdown activities by 

operating and maintaining the faci lity and associated air pollution control 

equipment in accordance with good air pollution control practices, safe operating 

practices, and protection of the facility. 

b. Emissions during startup and shutdown activities shall be minimized by limiting the 

dw-ation of operation in startup and shutdown mode as follows: 

1. A startup of CTG5 is defined as the period that begins when there is 

measw-eable fuel flow to the CTG5 and ends when the CTG5 load reaches 60 

percent. A startup for each CTG5 is limited to 480 minutes. 

11. A shutdown of each CTG5 is defined as the period that begins when CTG5 

load falls below 60 percent and ends when there is no longer measureable fuel 

flow to CTG5. A shutdown for CTG5 is limited to 180 minutes. 

c. Permittee must record the time, date, fue l heat input (HHV) in mmBtu/hr and 

duration of each startup and shutdown event in order to calculate total C02e 

emissions. The records must include hourly C02 emission levels as measured by 

the fuel flow meter and/or 0 2 emission monitor (or C02 CEMS with volumetric 

stack gas fllowrate) and the calculations based on the actual heat input for the C02, 

C02e, 0 2, l~'hO, and CH4 emissions during each startup and shutdown event based 

on the equations represented in the permit application. These records must be kept 

for five (5) years following the date of such event. 

d. During sta11up and shutdown, CTGS and HRSGS emissions shall comply with all 

provisions of BACT emission limitations in Special Condition II.B.l . 

C. Fugitive Emission Sources 

1. Fugitive Emission Sources Emission Limits 

At all times, including equipment startup and shutdown, Permittee shall not discharge, or cause 

the discharge of emissions from each unit into the atmosphere, in excess of the following: 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Page 16 of21 

PSD-TX-979-GHG 

Tabie 3 Fugitive Emission Sources Emission Limits 

ID No. 

NG-FUG 

SF6-FUG 

I. 

GHG Polluta nts Fugitive Sources Emissions 

Description Limit 

Pollutant 

Mass Basis C02e Basis C02e TPY Total C02e 

TPY TPY TPY 

Fugitive Natural Gas CH41 

emissions from 

2.84 59.69 59.69 

piping compone-nts 

(inc luding valv~: s & 

flanges) coz 0. 11 0.1 J 0.11 

SF6 lnsulated 

Electrical SF6 0.000 18 4.30 4.30 

Equipment 

Because the emiSSIOns from this umt are calculated to be 94.44% methane (CH4) from natural gas 

analysis, the remaining pollutant emissions are not presented in the table. 

2. Fugitive Emission Sources Work Practice and Operational Requirements 

60 

4.30 

a. For emission unit NG-FUG, CH4 emissions shall be calculated annually (calendar 

year). Permittee shall not exceed 2.84 tons per year of methane (equivalent to 

59.69 tons of C02) from all piping components including valves and flanges and 

an overall emissions limit of 60 tons per year of C02e. Emissions shall be 

calculated annually based on the emission factors from Table W -1 A of 40 CFR 

Part 98, Subpart W, Petroleum and Natural Gas Systems using the reduction credit 

from 28LAER and calculations given in the TCEQ Technical Guidance Document 

for Equipment Leak Fugitives, dated October 2000. 

b. The permittee shall implement an as-observed auditory, visual and olfactory 

(AVO) method for detecting leaking from natural gas piping components 

c. For emission unit SF6-FUG, SF6emissions shall be calculated annually (calendar 

year) in accordance with the mass balance approach provided in equation DD-1 of 

the Mandatory Greenhouse Gas Reporting rules for Electrical Transmission and 

Distribution Equipment Use, 40 CFR Part 98, Subpart DD. Permittee shall not 

exceed one (1) 72 lb SF6 circuit breakers with leak detection. 

d. Permittee shall maintain a file of all records, data measurements, reports and 

documents related to the fugitive emission sources including, but not Limited to, 

the following: all records or reports pertaining to maintenance performed, all 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Page 17 of21 

PSD-TX-979-GHG 

records relating to compliance with the Monitoring and Quality Assurance and nn<:~ \1 {'nt1trr.J rn f'1 fnr'\ n rt"\f'Prl11l'PC l"\11tJinP rl ;1"1 LJ.() rJ:;""Q QQ 1()LJ. '<\.A.II..4-..&.I.\.) '-J \J.I.J.\..LVI \'<_-' )J '<.'-"} 1-'.I.UV'VUU.J.VU V \AL...l.l.l.lV'-4 l.ll '-'~""-'- ./ Uo ...J V I • 

III. Recordkeeping Requirements 

A. In order to demonstrate compliance with the GHG emission rates for both the FD2- and 

FD3-series CTG, the permittee will monitor the following parameters and summarize the 

data on a calendar month basis. 

a. Operating hours for all air emission sources; 

b. The natural gas fuel usage for all combustion sources, using continuous fuel flow 

monitors (a group of equipment can utilize a common fuel flow meter, as long as 

actual fuel usage is allocated to the individual equipment based upon actual 

operating hours and maximum firing rate); 

c. Record the number and duration of start-ups for each engine; and 

d. Record the number and duration of shutdowns for each engine. 

B. Petmittee will maintain site-specific procedures for best/optimum maintenance practices 

and vendor-recommended operating procedures and O&M manuals. These manuals must 

be maintained with the permit and located onsite. 

C. Permittee shall maintain records that include the following: the occunence and duration 

of any startup, shutdown, or malfunction, performance testing, calibrations, checks, GHG 

emission units and C0 2 emission CEMS maintenance (if a C02 CEMS is present), 

duration of any periods during which a monitoring device is inoperative, and 

corresponding emission measurements. 

D. Permittee shall r:naintain records for five (5) years from the date of any ofthe following: 

the duration of startup, shutdown, the initial stmtup period as defined in Section IV for 

the emission units, pollution control units and CEMS (if a C0 2 CEMS is present), 

malfunctions, performance testing, calibrations, checks, maintenance and duration of an 

inoperative monitoring device and emission units with the required conesponding 

emission data. 

E. Permittee shall maintain records of all GHG emission units and C02 emission CEMS 

certification tests (if a C02 CEMS is present) and monitoring and compiiance information 

required by this permit. 

F. Permittee will implement the AVO program and keep 1records of the monitoring results, 

as well as the repair and maintenance records. 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Page18of21 

PSD-TX -979-GHG 

G. At least once per year, the permittee will obtain an updated analysis of the inlet gas to 

docutne11t the C<)2 and metl1ane content of the gas strea..'Tis. 

H. Permittee shall maintain records and submit a written neport of all excess emissions to 

EPA semi-rumually, except when: more frequent reporting is specifically required by an 

applicable subpart; or the Administrator or authorized representative, on a case-by-case 

basis, determines that more frequent reporting is necessary to accurately assess the 

compliance status of the source. The report is due on the thirtieth (30111

) day following the 

end of each semi-annual period and shall include the following: 

1. Time intervals, data and magnitude of the excess emissions, the nature and cause 

(if known), corrective actions taken and preventive measures adopted; 

2. Applicable time and date of each period during which the monitoring equipment 

was inoperative (monitoring down-time); 

3. A statement in the report of a negative declaration; that is; a statement when no 

excess emissions occurred or when the monitoring equipment has not been 

inoperative, repaired or adjusted; 

4. Any failure to conduct any required source testing, monitoring, or other 

compliance activities; and 

5. Any violation of limitations on operation, including but not limited to restrictions 

on hours of operation of the emergency generator or fire pump. 

I. Excess emissions shall be defined as any period in which the facility emissions exceed a 

maximum emission limit set forth in this permit. 

J. Excess emissions indicated by GHG emission source certification testing or compliance 

monitoring shall be considered violations of the applicable emission limit for the purpose 

of this permit. 

K. All records required by this PSD Permit shall be retained for not less thru1 5 years 

following the date of such measurements, maintenance, and reports. 

IV. Shakedown Periods 

The combustion turbine emission limits and requirements in conditions II.A and II.B shall not 

apply during combustion shakedown periods. Shakedown is defined as the period beginning with 

initial startup and ending no later than initial performance testing, during which the Permittee 
Calpine Corporation, D<;:er Park Energy Center 

Deer Park, TX (HarTis County) 

Page 19 of21 

PSD-TX-979-GHG 

conducts operational ar1d contractual testing and tuning to ensure the safe, efficient and reliable 

operation of the plant. The shakedown period shall not exceed the time period for performar1ce 

testing as specified in 40 CFR § 60.8. The requirements of Special Condition I.C of this permit 

shall apply at all times. 

V. Performance Testing Requirements: 

A. Upon completion of the first phase of construction, the holder of this permit shall perform an 

initial stack test for the FD2-series combustion turbine to establish the actual quantities of air 

contaminants being emitted into the atmosphere from emission unit CTG5/HRSG5 and to 

determine the initial compliance with the C02 emission limits established in this permit. 

Sampling shall be conducted in accordar1ce with 40 CFR § 60.8 and EPA Method 3a or 3b 

for the concentration of C02 for the CTGs. 

B. Upon completion of the second phase of construction, the holder of this permit shall perform 

an initial stack test for the FD3 series combustion turbine to establish the actual quantities of 

air contaminants being emitted into the atmosphere from emission unit CTG5/HRSG5 and to 

determine the initial compliance with the C02 emission limits established in this permit. 

Sampling shall be conducted in accordance with 40 CFR § 60.8 and EPA Method 3a or 3b 

for the concentration of C02 for the CTGs. 

C. Within sixty (60) days after achieving the maximum production rate at which the F2-series 

CTG will be operated, but not later than one hundred and eighty (180) days after initial 

startup of the facility, perfonnance tests(s) must be conducted and a written report of the 

performance testing results furnished to the EPA. Additional sampling may be required by 

TCEQ or EPA. 

D. Within sixty (60) days after achieving the maximum produ,ction rate at which the FD-3 series 

CTG will be operated, but not later than one hundred and eighty (180) days after initial 

startup of the facility, performance tests(s) must be conducted and a written report of the 

performance testing results furnished to the EPA. Additional sampling may be required by 

TCEQ or EPA. 

E. Permittee shall submit a performance test protocol to EPA no later than thirty (30) days prior 

to the test to allow review of the test plan and to arrange for an observer to be present at the 

test for both the FD2- and FD3-series combustion turbine generator. The perfom1ance test 

shall be conducted in accordance with the submitted protocol, and any changes required by 

EPA. 

F. The holder of this permit shall perform stack sampling and other testing as required to 

establish the actual quantities of C02 emissions being emitted into the atmosphere from 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Page 20 of21 

PSD-TX-979-GHG 

emission unit CTG5/HRSG5 and to determine the initial compliance with aJJ emission limits ~nf.n l-.l: hed ; .. ;.1-.:n .. ,.~.~: .. ~,... .. h nf.h tho "Cn'l a'"'d Fn~ sor;os f"Tr. <;: <>.,.., nlincr ch<>ll h P ~;::)laUll 111 UUI:> jJ'woliJ.llL .lUl UVU.l \..11\.o 1 J....Jk -. .JI JJJ • "-'lJ."" '-' ..l '-...lo U U...lU.jJ1.,LU,6 ... HU.4U V V 

conducted in accordance with EPA Methods l-4 and 3 b for the concentration of C02 for the 

CTGs. 

G. Fuel sampling for emission unit CTG5/HRSG5 shall be conducted in accordance with 40 

CFR Part 75 and Pa1t 98. 

H. The turbine shall be tested at or above ninety percent (90%) of maximum load operations for 

the atmospheric conditions which exist during testing. The duct burners shall be tested at its 

maximum firing rate while the turbine is operating as close to base load as possible. The 

tested turbine load shall be identified in the sampling rep01t. The permit holder shall present 

at the pretest meeting the manner in which stack sampling will be executed in order to 

demonstrate compliance with the emissions limits contained in Section II and the emission 

standards found in NSPS, Subpart K.KKK. 

I. Air emissions from each HRSG exhaust stack shall be tested while firing at the minimum 

load in the normal operating range. The normal operating range consistent with emission 

limits is to be determined during stack testing. Air emissions will be sampled and analyzed 

while at a the minimum load include (but not limited to) VOC and 0 2. 

J. Performance tests must be conducted under such conditions to ensure representative 

performance of the affected facility. The owner or operator must make available to the EPA 

such records as may be necessary to determine the conditions of the performance tests. 

K. The owner or operator must provide the EPA at least thirty (30) days' prior notice of any 

performance test, except as specified under other subparts. to afford the EPA the opportunity 

to have an observer present and/or to attend a pre-test meeting. If there is a delay in the 

original test date, the faci lity must provide at least seven (7) days prior notice of the 

rescheduled date of the performance test. 

L. The owner or operator shall provide, or cause to be provided, performance testing facilities as 

follows: 

1. Sampling p011s adequate for test methods applicable to this facility, 

2. Safe sampling platform(s), 

3. Safe access to sampling platform(s), and 

4. Utilities fo:r sampling and testing equipment. 

M. Unless otherwise specified, each performance test shall consist of three separate runs using 

the applicable test method. Each run shall be conducted for the time and under the conditions 
Calpine Corporation, Deer Park Energy Center 

Deer Park, TX (Harris County) 

Page 2 1 of2 1 

PSD-TX-979-GHG 

specified in the applicable standard. For purposes of determining compliance with an 

applicable standard. the arithmetic mean of the results of the three runs shall apply. 

VI. Agency Notifications 

Permittee shall submit GHG permit applications, permit amendments, and other applicable 

permit information to: 

Multi Media Planning and Permitting Division 

EPA Region 6 

1445 Ross Avenue (6 PD-R) 

Dallas, TX 75202 

Email: Group R6AirPermits@EP A.gov 

Permittee shall submit a copy of all compliance and enforcement correspondence as required by 

this Approval to Construct to: 

Compliance and Enforcement Division 

EPA Region 6 

1445 Ross Avenue (6EN) 

DalJas, TX 75202 
Statement of Basis

Greenhouse Gas Prevention of Significant Deterioration Preconstruction Permit

for the Calpine Corporation, Deer Park Energy Center (DPEC), LLC

Permit Number: PSD-TX-979-GHG

August 2012 

This document serves as the Statement of Basis required by 40 CFR 124.7. This document sets 

forth the legal and factual basis for the draft permit conditions and provides references to the 

statutory or regulatory provisions, including provisions under 40 CFR 52.21, that would apply if 

the permit is finalized. This document is intended for use by all parties interested in the permit. 

I. Executive Summary

On September 1, 2011, the Calpine Corporation, Deer Park Energy Center (DPEC), LLC, 

submitted to EPA Region 6 a Prevention of Significant Deterioration (PSD) permit 

application for Greenhouse Gas (GHG) emissions from proposed construction of a natural 

gas-fired combined-cycle combustion turbine generator (CTG) at the existing DPEC facility. 

In connection with the same proposed project, Calpine Corporation submitted a PSD permit 

application for non-GHG pollutants to the Texas Commission on Environmental Quality 

(TCEQ) on September 1, 2011. On December 11, 2011, February 7, 2012, April 2, 2012, 

April 30, 2012 and June 22, 2012, Calpine submitted additional information to amend their 

permit applications to both EPA and TCEQ, revising the permit applications to incorporate a

multiphase construction of the proposed CTG. The revised project at the DPEC plant 

proposes phased construction of the natural gas-fired combined-cycle CTG with a 

generating capacity of approximately 180 megawatts that will be completed in two stages of 

construction. In the initial phase, Calpine intends to construct a Siemens Model FD2 

combustion turbine that will be subsequently be upgraded in performance as a FD3-series

combustion turbine in the second stage of construction. Modification of the FD2 combustion 

turbine to the FD3-series would commence within eighteen (18) months of completion of 

construction or beginning of commercial operation of the initial project. After reviewing the 

application, EPA Region 6 has prepared the following Statement of Basis (SOB) and draft 

air permit to authorize phased construction of air emission sources at DPEC. 

This SOB documents the information and analysis EPA used to support the decisions EPA 

made in drafting the air permit. It includes a description of the proposed facility, the 

applicable air permit requirements, and an analysis showing how the applicant complied 

with the requirements.

EPA Region 6 concludes that Calpine’s application is complete and provides the necessary 

information to demonstrate that the proposed project meets the applicable air permit regulations. 

EPA's conclusions rely upon information provided in the permit application, supplemental 

information EPA requested and provided by Calpine Corporation, and EPA's own technical 

analysis. EPA is making all this information available as part of the public record. 
Calpine Corporation, Deer Park Energy Center Page 2 of 38

Deer Park, Texas (Harris County)

II. Applicant

Calpine Corporation 

717 Texas, Suite 1000 

Houston, TX 77002 

 

Physical Address:

5665 Highway 225 

Deer Park, TX 77536 

Contact: 

Patrick Blanchard 

Director of Environmental, Health and Services

Deer Park Energy Center LLC 

717 Texas, Suite 1000 

Houston, TX 77002 

III.Permitting Authority

On May 3, 2011, EPA published a federal implementation plan that makes EPA Region 6 the 

PSD permitting authority for the pollutant GHGs. 75 FR 25178 (promulgating 40 CFR § 

52.2305). Texas still retains approval of its plan and PSD program for pollutants that were 

subject to regulation before January 2, 2011, i.e., regulated NSR pollutants other than GHGs. 

The GHG PSD Permitting Authority for the State of Texas is: 

EPA, Region 6 

1445 Ross Avenue 

Dallas, TX 75202 

The EPA, Region 6 Permit Writer is:

Alfred C. Dumaual, Ph.D. 

Air Permitting Section (6PD-R)

(214) 665-6613 

The Non-GHG PSD Permitting Authority for the State of Texas is:

Air Permits Division (MC-163) 

TCEQ 

P.O. Box 13087 

Austin, TX 78711-3087 
Calpine Corporation, Deer Park Energy Center Page 3 of 38

Deer Park, Texas (Harris County)

IV. Facility Location 

The Calpine Corporation, DPEC plant is located in Harris County, Texas, and this area is 

currently considered to be in attainment for all NAAQS with the exception of the 8 hour Ozone 

standard, for which it is classified as a marginal non-attainment area as of April 2012. The 

geographic coordinates for this facility are as follows: 

Latitude: 29o 42’ 43.6” North (29.712111) 

Longitude: 95o 08’ 7.8” West (-95.135511) 

The figures below illustrate the facility location for this draft permit in city of Deer Park, Harris 

County, Texas. 
Calpine Corporation, Deer Park Energy Center Page 4 of 38

Deer Park, Texas (Harris County)

V. Applicability of Prevention of Significant Deterioration (PSD) Regulations 

EPA concludes Calpine’s proposed modification is subject to PSD review for the pollutant GHG, 

because the project would lead to an emissions increase of GHGs for a facility as described at 40 

CFR §§ 52.21(b)(23) and (49)(iv). Under the project, GHG emissions are calculated to increase 

over zero tons per year (tpy) on a mass basis and well exceed the applicability threshold of 

75,000 tpy CO2e. (EPA calculates CO2e emissions of 1,045,635 tpy in the initial phase of 

construction which is increased to 1,060,783 tpy after the final phase of construction). EPA 

Region 6 implements a GHG PSD FIP for Texas under the provisions of 40 CFR § 52.21 (except 

paragraph (a)(1)). See 40 CFR § 52.2305. 

As the permitting authority for regulated NSR pollutants other than GHGs, TCEQ has 

determined the modification is subject to PSD review for non-GHG pollutants. Accordingly, 

under the circumstances of this project, the State will issue the non-GHG portion of the permit 

and EPA will issue the GHG portion.1 

EPA Region 6 applies the policies and practices reflected in the EPA document entitled “PSD 

and Title V Permitting Guidance for Greenhouse Gases” (March 2011). Consistent with that

guidance, we have not required the applicant to model or conduct ambient monitoring for GHGs, 

and EPA Region 6 has not required any assessment of impacts of GHGs in the context of the 

additional impacts analysis or Class I area provisions. Instead, EPA has determined that 

compliance with the BACT analysis is the best technique that can be employed at present to 

satisfy the additional impacts analysis and Class I area requirements of the rules related to 

GHGs. We note again, however, that the project has triggered review for regulated NSR 

pollutants that are non-GHG pollutants under the PSD permit sought from TCEQ. 

VI. Project Description

The proposed GHG PSD permit, if finalized, will allow DPEC to initiate a multiphase 

construction of a new 180 MW natural gas-fired Siemens 501 F-series combined-cycle

combustion turbine generator, identified as CTG5, with a plant-wide generating capacity of 

1230-1300 MW, depending on ambient conditions. The phased construction for this project will 

be carried out in two stages. In the initial stage, Calpine proposes to construct a 168 MW natural 

gas-fired Siemens Model 501 FD2 combined-cycle combustion turbine as described above upon 

issuance of the PSD GHG permit. In the final stage, the FD2 combustion turbine will be 

upgraded to a 180 MW FD3 combustion turbine, this involves replacement of a limited number 

of internal components of the turbine which will be accomplished in the timeframe of a routine 

outage. The modification includes improvements to the turbine blades, vanes and improved 

compressors seals that allow the turbine to regain generation capacity that is lost in the summer 

months due to hot ambient conditions. Calpine plans to install the turbine using the FD2 

configuration to ensure the project is online and available to supply needed power to the Electric 

Reliability Council of Texas (ERCOT) grid for the summer of 2014 peak season. Additional 

time may be required to install the parts required for an FD3 configuration, and hence a two-

 

1 U.S. Environmental Protection Agency, Question and Answer Document: Issuing Permits for Sources with Dual PSD 

Permitting Authorities, April 19, 2011,< http://www.epa.gov/nsr/ghgdocs/ghgissuedualpermitting.pdf> (April 2011). 
Calpine Corporation, Deer Park Energy Center Page 5 of 38

Deer Park, Texas (Harris County)

phased construction period is required to avoid compromising the scheduled construction and 

installation of the combustion turbine.

 

Calpine intends to begin the upgrade of the Siemens 501 FD2-series engine to the FD3-series

within an eighteen (18) month period following commercial operation of the FD2 series unit. 

Completion of construction of the initial project will occur the date that commercial operation of 

the FD2 phase of the project begins, or no later than eighteen (18) months after initial testing is 

completed in order to account for any additional work that may take place during the 

“shakedown period” that immediately follows first fire of the proposed turbine. The increased 

changes in CO2 emissions due to this modification are presented in the calculations of the 

original application as submitted on September 1, 2011. It is calculated that the proposed 

combustion turbine is an FD3-series engine will generate more CO2 emissions than the FD2-

series; however, the heat rate (in Btu/kWh) for the combined cycle process is about the same for 

both configurations. Some or all of the steam produced from the new combustion turbine will 

either exhaust to a dedicated Heat Recovery Steam Generator (HRSG) to produce steam or be 

sold to a neighboring facility. The steam produced from the HRSG is then routed to an existing 

shared 200 MW steam turbine unit to produce electricity for sale to the ERCOT power grid. 

Listed in the table below is a summary of the emissions for this project, a detailed analysis of the 

calculations can be found in the Appendix, Tables 1 through 8: 

Total GHG Potential Emissions – Phase 1 of Construction (FD2)

Potential Emissions

(Mass Basis)

TPY

CO2e Potential 

Emissions

TPY

CO2 1,044,629 CO2 1,044,629

CH4 19.34 CH4 406

N2O 1.93 N2O 599

SF6 0.00018 SF6 4.3

Total Potential 

Emissions

(Mass Basis) 1,044,651 Total CO2e 1,045,635

Total GHG Potential Emissions – Phase 2 of Construction (FD3)

Potential Emissions

(Mass Basis)

TPY

CO2e Potential 

Emissions

TPY

CO2 1,062,627 CO2 1,062,627

CH4 19.67 CH4 413

N2O 1.97 N2O 610

SF6 0.00018 SF6 4.3

Total Potential 

Emissions

(Mass Basis) 1,062,652 Total CO2e 1,063,650
Calpine Corporation, Deer Park Energy Center Page 6 of 38

Deer Park, Texas (Harris County)

VII. General Format of the BACT Analysis

The BACT analyses was conducted in accordance with the “Top-Down” Best Available Control 

Technology Guidance Document outlined in the 1990 draft U.S. EPA New Source Review 

Workshop Manual, which outlines the steps for conducting a top-down BACT analysis. Those 

steps are listed below.

(1) Identify all potentially available control options;

(2) Eliminate technically infeasible control options;

(3) Rank remaining control technologies; 

(4) Evaluate the most effective controls and document the results; and 

(5) Select BACT.

Also in accordance with the top-down BACT guidance, the BACT analyses also takes into 

account the energy, environmental, and economic impacts of the control options during step 4. 

Emission reductions may be determined through the application of available control techniques, 

process design, and/or operational limitations. Such reductions are necessary to demonstrate that 

the emissions remaining after application of BACT will not cause adverse environmental effects 

to public health and the environment. 

Each of the emission unit submitted in the PSD GHG application was evaluated separately in the 

top-down 5-step BACT analysis.

VIII. Applicable Emission Units Subject to BACT

The following devices are subject to this GHG PSD permit:

• Natural Gas-Fired Combined-cycle Combustion Turbine Generator (CTG5) and Heat 

Recovery Steam Generator (HRSG5)

• Fugitive Natural Gas emissions from piping components (NG-FUG) 

• SF6 Insulated Electrical Equipment (SF6-FUG) 
Calpine Corporation, Deer Park Energy Center Page 7 of 38

Deer Park, Texas (Harris County)

IX. GHG BACT for the Natural-Gas Fired Combined-Cycle Combustion Turbine 

Generator (CTG5) and Heat Recovery System Generator (HRG5)

The new combined-cycle combustion turbine generator (CTG) is proposed to be as efficient, but 

with improved environmental controls compared to the other four existing CTG at the site. If 

approved, initially, a Siemens 501 FD2-series combined-cycle combustion generator with a 

electrical generating capacity of approximately 168 MW will be constructed and will be 

upgraded to a FD3-series with a electrical generating capacity of 180 MW within an 18-month 

period under terms of conditions of the permit. The FD3 upgrade includes improvements to the 

turbine blades and vanes and improved compressor seals to allow the turbine to regain generation 

capacity that is lost during the summer months due to hot ambient conditions. The FD3-series

combustion turbine will generate more CO2 emissions than the FD2-series; however the 

efficiency, in terms of heat rate (in Btu/kWh), is the same for both on a combined cycle basis. 

The CTG/HRSG unit will be fired exclusively with pipeline-quality natural gas with a fuel sulfur 

content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). For purposes 

of BACT, CTG5 and HRSG5 are treated as one emission unit. 

EPA has reviewed Calpine’s BACT analysis for the two-phase construction of a natural gas-fired 

combined-cycle combustion turbine generator and finds it sufficient in setting forth this proposed 

permit, as summarized below. 

Step One: Identify All Potentially Available Control Technologies

As part of the PSD review, Calpine provides in the GHG permit application a 5-step top-down 

BACT analysis for the new combustion turbine emission unit. In this analysis, the following 

technologies are identified in the BACT analysis:

(A)the use of carbon capture and storage (CCS) including CO2 capture/compression, CO2

transport and CO2 storage; 

(B) Inherently lower-emitting processes, practices, and designs which are further subdivided 

into: 

(1) Combustion turbine energy efficiency processes, practices and designs;

(2) Heat recovery steam generator energy efficiency process, practices and designs; and 

(3) Plant-wide energy efficiency processes, practices, and designs; 

(A) Carbon Capture and Storage 

For purposes of the BACT analysis, CCS is classified as an add-on pollution control 

technology for “facilities emitting CO2 in large concentrations, including fossil fuel-fired 

power plants, and for industrial facilities with high-purity CO2 streams (e.g., hydrogen 

production, ammonia production, natural gas processing, ethanol production, ethylene oxide 

production, cement production, and iron and steel manufacturing).”2

 CCS involves the 

separation and capture of CO2 from the combustion process flue gas, the pressurizing of the 

captured CO2 and then the transportation of the compressed CO2 by pipeline or other means 

of transportation, if necessary, where it is injected into a long-term geological location. 

 

2

U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, PSD and Title V Permitting Guidance for 

Greenhouse Gases, March 2011, <http:/www.epa.gov/nsr/ghgdocs/ghgpermittingguidance.pdf> (March 2011)
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Several technologies are in various stages of development and are being considered for CO2

separation and capture. 

As it stands currently, CCS technology and its components can be summarized in the table3

below adopted from IPCC’s Carbon Dioxide Capture and Storage report: 

CCS Component CCS Technology

Capture

Post-combustion

Pre-combustion

Oxy-fuel combustion

Industrial separation (natural gas processing, 

ammonia production)

Transportation Pipeline

Shipping

Geological Storage

Enhanced Oil Recovery (EOR)

Gas or oil fields

Saline formations

Enhanced Coal Bed Methane Recovery (ECBM)

Ocean Storage Direct injection (dissolution type)

Direct injection (lake type)

Mineral carbonation Natural silicate minerals

Waste minerals

CO2 Utilization/Application Industrial Uses of CO2 (e.g. carbonated products)

For large, point sources, there are three types of capture configurations – pre-combustion 

capture, post-combustion capture, and oxy-combustion capture: 

1) Pre-combustion capture implies as named, the capture of CO2 prior to combustion. It 

is a technological option available to integrated coal gasification combined-cycle

(IGCC) plants. In these plants, coal is gasified to form synthesis gas (syngas with key 

components of carbon monoxide and hydrogen). Carbon monoxide (CO) is reacted 

with steam to form CO2 which is then removed and the hydrogen is then diluted with 

nitrogen and fed into the gas turbine combined-cycle. 

2) Post-combustion capture involves extracting CO2 in a purified form from the flue gas 

following combustion of the fuel. Primarily for coal-fired power plants and electric 

generating units (EGU), other industries can benefit. Currently, all commercial postcombustion capture is via chemical absorption process using monoethanolamine 

(MEA)-based solvents.4

 

3 Intergovernmental Panel on Climate Change (IPCC) Special Report, Bert Metz, Ogunlade Davidson, Heleen de Coninck, 

Manuela Loos and Leo Meyer (Eds.), Carbon Dioxide Capture and Storage (New York: Cambridge University Press, 2005), 

Table SPM.2, 8. <http://www.ipcc.ch/pdf/special-reports/srccs/srccs_wholereport.pdf> 4 Wes Hermann et al. An Assessment of Carbon Capture Technology and Research Opportunities - GCEP Energy Assessment 

Analysis, Spring 2005. <http://gcep.stanford.edu/pdfs/assessments/carbon_capture_assessment.pdf> 
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3) Oxy-combustion technology is primarily applied to coal-burning power plants where 

the capture of CO2 is obtained from a pulverized coal oxy-fuel combustion in which 

fossil fuels are burned in a mixture of recirculated flue gas and oxygen rather than air. 

The remainder of the flue gas, that is not recirculated, is rich in carbon dioxide and 

water vapor, which is treated by condensation of the water vapor to capture the CO2.

5

When combusting coal with air (which is done in nearly all existing coal-burning 

power plants), nitrogen is formed as byproduct of the combustion and is present in 

high concentrations in the flue gas. Post-combustion capture of CO2 is essentially the 

separation of nitrogen and carbon dioxide, which can be done but at a high cost. 

However if there were no nitrogen present as in the case of oxy-combustion, then 

CO2 capture from flue gas would be greatly simplified6

. It is implied that an 

optimized oxy-combustion power plant will have ultra-low CO2 emissions as a result.

Once CO2 is captured from the flue gas, CO2 is compressed to 100 atmospheres (atm) or 

higher for ease of transport (usually by pipeline) into a storage area, in most cases, a 

geological storage area. It is also possible that CO2 can be stored and shipped via all 

different modes of transportation via land, air and sea. 

Geological storage of CO2 involves the injection of compressed CO2 into deep geologic 

formations (injection zones) overlain by competent sealing formations and geologic traps that 

will prevent the CO2 from escaping, there are five types of geologic formations that are 

considered: clastic formations; carbonate formations; deep, unmineable coal seams; organicrich shales; and basalt interflow zones. There is a large body of ongoing research and field 

studies focused on developing better understanding of the science and technologies for CO2

storage.7

(B) Inherently lower-emitting processes, practices, and designs 

Methods techniques and systems to increase energy efficiency is the key GHG reducing 

direction that falls under “lower polluting processes/practices.” Use of inherently loweremitting technologies, including energy efficiency measures, represents an opportunity for 

GHG reductions in these types of BACT reviews. In some cases, a more energy efficient 

process or project design may be used effectively alone; where in other cases, energy 

efficient measure may be used effectively in tandem with end-of-stack controls to achieve 

additional control criteria pollutants. Applying the most energy efficient technologies at a 

source should in most cases translate into fewer overall emissions of all air pollutants per unit 

of energy produced. Selecting technologies, measures and options that are energy efficient 

translates not only in the reduction of emissions of the particular regulated NSR air pollutant 

undergoing BACT review, but it also may achieve collateral reductions of emissions of other 

pollutants, as well as GHGs. 

 

5 U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory, “Oxy-Fuel 

Combustion”, August 2008. < http://www.netl.doe.gov/publications/factsheets/rd/R&D127.pdf> 

6 Herzog et al., page 4-5 7 U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory Carbon Sequestration Program: 

Technology Program Plan, , February 2011

<http://www.netl.doe.gov/technologies/carbon_seq/refshelf/2011_Sequestration_Program_Plan.pdf> 
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Inherently lowering emitting processes, practices, and designs is divided into two basic 

categories. The first category of energy efficient improvement options includes improvement 

options or processes that maximize the energy efficiency of the individual emissions unit. 

The second category of energy efficiency improvements includes options that could reduce 

emissions is more appropriate for new Greenfield facilities that includes equipment or 

processes that have the effect of lowering emissions by improving the utilization of thermal 

energy and electricity that is generated and used on the site. 

(1) In the case of combustion turbine energy efficiency processes, practices and designs, 

one of the current efficient ways of generating electricity from a natural gas fuel 

source is through a combined-cycle design. For fossil fuel technologies, efficiency 

ranges from 30 to 50 percent higher heating value (HHV). A typical coal-fired 

Rankine cycle power plant has a base load efficiency of approximately 30% HHV 

while a modern F-Class natural gas fired combined-cycle turbine generator operating 

under optimal conditions has a baseload efficiency of approximately 50% HHV. 

The combined-cycle unit operates based on a combination of two thermodynamic 

cycles: the Brayton and Rankine cycles. The combustion turbine operates on the 

Brayton cycle while the HRSG and steam turbine operate on the Rankine cycle. The 

combination of both of these cycles contributes to the higher efficiency of the 

combined-cycle power plants.

While there are number of modifications to a combustion turbine generator that exist, 

Calpine has identified the following additional processes, practices and designs that 

are applicable for the combined combustion turbine generator: 

(a) Periodic Burner Tuning: The modern F-Class combustion turbines have a 

regularly scheduled maintenance program for optimal efficiency of the 

turbine. Three basic maintenance levels exist: combustion inspections, hot 

gas path inspections, and major overhauls with combustion inspections being 

the most common. As a part of the maintenance activity, combustors are 

tuned to restore the highly efficient low-emission operation. 

(b) Reduction in Heat Loss: Use of insulation blankets help minimize heat loss at 

cooler temperatures, as well as protect personnel and nearby auxiliary 

equipment, insulation blankets will be deployed around the combustion 

turbine casing. Uses of the blankets immediately minimize any heat loss from 

the combustion turbine shell and increase the overall efficiency of the 

machine.

(c) Instrumentation and Controls: Operation of the combustion turbine is all 

under automatic control via the distributed control system (DCS). DCS

oversees all aspects of the operation including fuel feed and burner operations 

to achieve efficient low-NOx combustion. The control system monitors the 

operational parameters of the unit and modulates the fuel flow and turbine 
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Deer Park, Texas (Harris County)

operations to achieve optimal high-efficiency low-emission performance for 

full-load and part-load conditions. 

Calpine proposed the use of a new combined-cycle combustion turbine, which is 

more energy efficient compared with the emissions from a simple-cycle gas turbine in 

table below. 

GHG Control Technologies Emission Rate

(lb CO2/MWh)

New combined-cycle gas CTG 774

Existing combined-cycle CTG 824-996

Simple cycle CT ~1,319

Calpine has elected to construct the Siemens 501F CTG/HRSG with a CTG rated at 

180 MW nominal and a duct burner-fired heat recovery steam generator (HRSG). 

The maximum design rated capacity of the duct burners will be 725 million British 

thermal units per hour (MMBtu/hr). The CTG will be fired exclusively with pipelinequality natural gas. The Siemens 501F turbine was chosen for DPEC because it has 

the appropriate size needed for this facility, DPEC is already equipped with four (4) 

operating Siemens 501F turbines, and several Siemens 501F turbines are ready for 

use in Calpine’s fleet. In comparison with other turbines, EPA has identified the 

several high energy efficient models commercially available around the 180 MW 

range. For a CTG, efficiency can be determined by the heat rate, which can be 

expressed as Btu of the fuel combusted divided by kWh of electricity produced 

(Btu/kWh). The lower the overall numbers, the less heat needed to produce a unit of 

electricity. Using data provided by the manufacturer for CTG under ISO test 

conditions, EPA identified the following models: 

Manufacturer Model

Net Plant 

Output 

(kW)8

LHV9 ISO Heat 

Rate (Btu/kWh)

%Net ISO 

Plant 

Efficiency 

(ISO)

Rolls-Royce 2 x Trent 60 DLE 149 7,129 45.5

Rolls-Royce 2 x Trent 60 WLE ISI 153 7,281 44.5

Mitsubishi MPCP1 (M501) 167 7,000 46.3

Siemens SCC6-2000F 1x1 

(FD2/FD3) 171 7,007 46.2

Hitachi 206FA 215 6,800 47.7

As listed in the table above, the Siemens 501F-series turbine has a calculated 

efficiency of 46.2% which is as efficient as or more efficient than the other listed

natural gas-fired combined-cycle combustion turbines (efficiencies tend to range from 

40% to 60% with larger kW-producing turbines typically having the highest 

 

8 Net plant output is calculated using specific design (i.e., ISO) test criteria 9 Lower heat rate is determined by subtracting the heat of vaporization of water from the higher heating value.
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efficiencies)10. Since age and ambient and operating conditions will affect efficiency, 

the heat rate numbers presented above are used to compare efficiency between turbine 

models and do not translate directly into permit limitations. 

(2) For the heat recovery steam generator, energy efficient processes, practices and 

design include: 

a. Heat Exchanger Design: Heat exchanger design is optimized to provide 

maximum heat exchange transfer from the waste heat of the combustion 

turbine exhaust using multiple thin-walled tubes filled with fluid and at the 

same time minimizing the overall size of the HRSG. 

b. Insulation: Similar to the combustion turbine practice, use of insulation to 

minimize heat loss to the surroundings is used to help improve the overall 

efficiency of the HRSG. Insulation is applied to the HRSG panels that make 

up the shell of the unit, to the high-temperature steam and water lines, and 

typically to the bottom portion of the stack. 

c. Minimizing Fouling of Heat Exchange Surfaces: Since HRSGs are made up of 

numerous tubes within the shell of the unit are used to generate steam from 

the combustion turbine, the tubes and their extended surfaces must be kept as 

clean as possible to maximize heat transfer. Fouling occurs from the 

constituents within the exhaust gas stream. To minimize fouling, filtration of 

the inlet air to the combustion turbine is performed. Additionally, cleaning of 

the tubes is performed during periodic outages. 

d. Minimized Vented Steam and Repair of Steam Leaks: Routine maintenance 

checks will include inspection of valves and pipes for steam leaks and reducting steam escaping which would result in large losses in efficiency in 

power generation. 

(3) Plant-wide energy efficient processes include fuel gas preheating, drain operation, 

multiple combustion/HRSG trains and boiler feed pump fluid drivers. 

a. Fuel gas preheating: The overall efficiency is increased with increased fuel 

inlet temperatures. For the F-class combustion turbine, the fuel gas is heated 

with high temperature water from the HRSG.

b. Drain operation: Drains are required to allow for draining the equipment for 

maintenance (maintenance drains) and allow condensate to be removed from 

the steam piping and drains for operation (operation drains) and prevent loss 

of energy from the cycle. 

 

10 United States Environmental Protection Agency, Combined Heat and Power Partnership, Technology 

Characterization: Steam Turbines, December 2008, p.8-9 

<http://www.epa.gov/chp/documents/catalog_chptech_steam_turbines.pdf> 
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c. Multiple combustion turbine/HRSG trains: Multiple combustion 

turbine/HRSG trains help with part-load operation and allow for higher 

overall plant part-load efficiency by shutting down trains operating at less 

efficiency part-load conditions and ramping up the remaining train(s) to highefficiency full-load operations. 

d. Boiler feed pump fluid drivers: Boiler feed pumps are used as a means to 

impart high pressure on the working fluid. The pumps require considerable 

power and to minimize the power consumption at part-loads, fluid drives are 

being used to minimize power consumption at part-load at part-load, 

improving the facility’s overall efficiency.

Step Two: Eliminate Technically Infeasible Control Options

 Based on the information reviewed for this BACT analysis, while there are some portions of 

CCS that are technically infeasible, EPA has determined that overall Carbon Capture and Storage 

(CCS) technology is technologically feasible at this source. Listed below is a summary of those 

CCS components that are technically feasible and those CCS components that are not technically 

feasible for DPEC. 

Step Two Summary for CCS for Calpine DPEC

CCS Component CCS Technology Technical Feasibility

Capture 

Post-combustion Y

Pre-combustion N

Oxy-fuel combustion N

Industrial separation (natural 

gas processing, ammonia 

production)

N

Transportation Pipeline Y

Shipping Y

Geological Storage

Enhanced Oil Recovery 

(EOR)

Y

Gas or oil fields N*

Saline formations N*

Enhanced Coal Bed Methane 

Recovery (ECBM)

N*

Ocean Storage 

Direct injection (dissolution 

type)

N*

Direct injection (lake type) N*

Mineral carbonation Natural silicate minerals N*

Waste minerals N*

Large scale CO2 

Utilization/Application

N*
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Deer Park, Texas (Harris County)

* Both geologic storage and large scale CO2 utilization technologies are in the research and development phase

in the United States and currently commercially unavailable.11

Step Three: Rank Remaining Control Technologies by Control Effectiveness

The remaining technically feasible options for controlling CO2 emissions from the combustion 

turbine operation are as follows (listed in descending order of the most technically feasible): 

1) Carbon Capture and Storage (CCS) 

CCS could enable large (> 85%) reduction of CO2 emissions from fossil fuel combustion in 

power generation, industrial processes and synthetic fuel production12 and is the best known 

method of reducing CO2e emissions into the atmosphere. 

2) Inherently lower-emitting processes, practices, and designs which are further 

subdivided into:

a. Combustion turbine energy efficiency processes, practices and designs;

b. Heat recovery steam generator energy efficiency process, practices and 

designs; and

c. Plant-wide energy efficiency processes, practices, and designs;

To date, other similar facilities with a GHG BACT limit are summarized in the table below: 

Company / 

Location

Process 

Description Control Device

BACT Emission 

Limit / 

Requirements

Year 

Issued Reference

Lower 

Colorado 

River 

Authority 

(LCRA), 

Thomas C. 

Ferguson 

Plant

Horseshoe 

Bay, TX

combinedcycle

combustion 

turbine and 

heat 

recovery 

steam 

generator

Energy 

Efficiency/ Good 

Design & 

Combustion 

Practices

Combustion turbine 

annual net heat rate 

limited to 7,720 

Btu/kWh (HHV)

GHG BACT limit of 

0.459 tons 

CO2/MWh (net) 

365-day average, 

rolling daily for the 

combustion turbine 

unit

Fugitive methane 

emissions and SF6 

emissions are 

monitored and 

maintained using 

2011

PSD-TX-1244-

GHG

 

11 U.S. Department of Energy, Carbon Sequestration Program: Technology Program Plan, page 20-23 12 IEA Energy Technology Essentials, “CO2 Capture and Storage,” December 2006 <http://www.iea.org/techno/essentials1.pdf> 

(December 2006)
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best practice 

standards.

Palmdale 

Hybrid 

Power Plant 

Project

Palmdale, 

CA

combinedcycle

combustion 

turbine and 

heat 

recovery 

steam 

generator, 

plus a 50 

MW solar 

array*

Energy 

Efficiency/ Good 

Design & 

Combustion 

Practices, and 

use of the solar 

array

Combustion turbine 

annual net heat rate 

limited to 7,319 

Btu/kWh (HHV)

GHG BACT limit of 

0.387 tons 

CO2/MWh (net) 

365-day average, 

rolling daily for the 

combustion turbine 

unit

Auxiliary boiler and 

heater heat input 

limit of 110 

MMBtu/hr and 500 

hours operation on 

365-day rolling total

SF6 Circuit Breakers 

BACT limit of 9.56 

tpy CO2e

2011 SE 09-01

Calpine

Russell City 

Energy

Hayward, 

CA

600 MW 

combinedcycle power 

plant

Energy 

Efficiency/ Good 

Design & 

Combustion 

Practices

Combustion turbine 

Operational limit of 

2,038.6 

MMBtu/kWh

Fire Pump Diesel 

Engine GHG BACT 

limit of 7.6 tpy CO2e

SF6 Circuit Breaker 

annual limit of 39.3 

tpy CO2e

2011 15487

PacifiCorp 

Energy

Lakeside, UT

combinedcycle turbine

Energy 

Efficiency/ Good 

Design & 

Combustion 

Practices

Combustion turbine 

BACT limit of 950 lb 

CO2e/MWh

2011 DAQEIN0130310010-11
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Kennecott 

Utah CopperRepowering

South Jordan, 

UT

275 MW

combined 

combustion 

Energy 

Efficiency/ Good 

Design & 

Combustion 

Practices

Combustion turbine 

BACT limit of 

1,162,552 tpy CO2e 

rolling 12-month 

period

2011 DAQEIN105720026-11 

*Palmdale is unique as the applicant proposed to include, and thus the BACT analysis and eventual limit included, 

use of a solar component that includes up to 50 MW of potential solar thermal power generation, which represents 

an inherently lower-emitting technology for that proposed facility.

Step Four: Evaluate Top Control Alternatives - Economic, Energy, and Environmental Impacts

EPA Region 6 reviewed Calpine’s CCS cost estimate and believes the overall cost estimation is 

financially prohibitive due to the overall cost of GHG control strategies. CCS costs include 

installation and operation of carbon capture controls and construction of a new pipeline to 

transport the CO2 approximately 15 miles13 (24 kilometers) to the closest site with recognized 

potential for geological storage of CO2, which is the enhanced oil recovery (EOR) operations 

located at the Hastings oil field, southwest of Houston, Texas. 

The bulk of the cost for CCS is attributable to the post-combustion capture and compression 

system, and the additional operating cost estimates are listed in detail in Table 9 of the Appendix. 

As it stands, the estimated cost to construct and install a CCS system to the turbine is

approximately $113 million14, around 50% of the cost of the of a typical gas-fired combined 

cycle turbine without CCS. Additionally Calpine, using EPA guidance documents, has provided 

an estimation that the overall average operating costs for the entire CCS system could add 

approximately $80 million annually (See Appendix, Table 9). While Calpine has provided 

information suggesting that annual operating costs for CCS could increase overall costs by as 

little as 20%15, EPA notes that Calpine arrives at this figure by including the lowest estimated 

cost for each and every step of the CCS process. Calpine’s analysis also included an estimate of 

the annual operating costs for CCS if the highest costs were needed for each and every step of 

the CCS process, and estimated the annual operating cost increase to be approximately 58%. 

Since it is unlikely that either the lowest costs or the highest costs could be achieved for each and 

every step of the process, EPA has instead relied upon the average costs and determined that the 

average combined costs of installation and operation of a CCS system still makes CCS 

economically infeasible for this project. 

In addition, EPA notes that implementing CCS would result in energy penalty simply because 

the CCS process will use energy produced by the plant. This may, in turn, potentially increases 

the natural gas fuel use of the plant, with resulting increases in emissions of non-GHG pollutants, 

to overcome these efficiency losses, or would result in less energy being produced for use on the 

 

13University of Texas at Austin, Bureau of Economic Geology, Gulf Coast Carbon Center, 

<http://www.beg.utexas.edu/gccc/miocene/> 14 Natural Gas Combined-Cycle Plants With and Without Carbon Capture & Sequestration, DOE 

<http://www.netl.doe.gov/energy-analyses/pubs/deskreference/B_NGCC_051507.pdf> 15 The minimum cost factor found for implementation/operation of the CO2 capture systems within the cost-related 

information reviewed for CCS technology was found from the “Properties” section of the Greenhouse Gas 

Mitigation Strategies Database ( last accessed April 2010) (<http:/ghg.ie.unc.edu:8080/GHGMDB/#data>), which 

was obtained through the EPA GHG web site (<http://www.epa.gov/nsr/ghgpermitting.html>).
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grid. The Report of the Interagency Task Force on Carbon Capture and Storage has estimated 

that an energy penalty of as much as 15% would result from inclusion of CO2 capture (Reference 

4, page A-14) and an overall loss of energy efficiency of approximately 7%16. It was concluded 

in the same report17 that while CCS is technically feasible at this time, the costs for the capture 

and compression of CO2 remains the biggest barrier to widespread commercialization of CCS.

Therefore, CCS has been eliminated as BACT for this particular project based upon research and 

analysis showing that there is a significant negative economic impact due to the additional 

projected capital costs of implementing and operating CCS as the control technology at the 

proposed combustion turbine. In addition, the potential negative environmental and energy 

impacts of increased non-GHG pollutant emissions, the overall loss in energy efficiency, and/or 

decreased energy produced for use on the grid also provide a basis for excluding CCS as BACT 

for this facility.

Step Five: Select BACT

Calpine intends to initially construct and install an FD2-series combustion turbine with plans to 

modify it within an eighteen (18) month period to the FD3-series combustion turbine. The 

proposed BACT limits are in terms of efficiency measured in units of Btu of fuel energy 

consumed in order to generate a kilowatt of electric energy (Btu/kWh). Since CCS has been 

eliminated as BACT for CTG5, then BACT for the new combined-cycle combustion turbine is

the high efficiency processes, practices and designs which are made enforceable by output-based

and annual BACT limits. The average heat rate in terms of Btu/kWh (HHV) will be the same for 

the FD2 configuration as the FD3 configuration when in continuous operation, since the FD2-

series and FD3-series combustion turbines have the same efficiency. However, the FD3 

configuration provides greater output at high ambient temperatures during base load periods. 

Therefore, for the FD3, the potential annual electric generation (MWh) and fuel usage, as well as 

corresponding GHG emissions, will be higher on an annual basis, maximum CO2e potential 

emissions will increase by only two percent (2%) from 1,045,635 tons for the FD2-series to 

1,063,650 tons of CO2e for the FD3-series combustion turbine (see Appendix Calculations, 

Tables 1 and 2). 

a) Degradation Consideration for combined-cycle combustion turbine generator efficiency

To establish an enforceable BACT condition that can be achieved over the life of the facility, it is 

important that the permit limit accounts for the anticipated degradation of the equipment over 

time between regular maintenance cycles. A 48,000-operating-hour degradation curve provided 

by the manufacturer, Siemens, reflects anticipated recoverable and non-recoverable degradation 

in heat rate between major maintenance overhauls of approximately five percent (5%). The 

results of the degradation curves differentiate between “recoverable” and “non-recoverable” 

degradation. Components of the turbine and combustion system subject to high thermal and 

mechanical stress are designed for periodic refurbishment or replacement. The turbine 

components most affected by the combustion process include combustion liners, fuel nozzle 

assemblies, transition pieces, turbine nozzles, stationary shrouds, and turbine buckets. These 

components are often referred to as “hot gas path” components. “Recoverable” degradation is 

 

16 IPCC Special Report of the Interagency Task Force on Carbon Capture and Storage (August 2010) 17 Ibid., p. 33-51
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mostly attributable to turbine blade fouling due to impurities in intake air and fuel. This type of 

degradation can be mitigated through inspection programs, on-line turbine water washes, 

instrument calibration, and other maintenance activities. “Non-recoverable” degradation is 

mainly attributed to blade surface roughness, erosion and blade tip rubs and cannot be restored 

upon a maintenance overhaul. 

The manufacturer’s degradation results only account for the anticipated degradation within the 

first 48,000 hours of the gas turbine’s useful life; they do not reflect any potential increase in this 

rate of degradation which might be expected after the first major overhaul and/or as the 

equipment approaches the end of its useful life. Further, the projected 5% degradation rate 

represents the average, and not the maximum or guaranteed rate of degradation for the turbines. 

Therefore, Calpine DPEC proposes that, for the purposes of deriving an enforceable BACT limit 

on the proposed facility’s heat rate, gas turbine degradation may be reasonably be estimated at 

six percent (6%) of the facility’s heat rate.

Finally, in addition to the heat rate degradation from normal wear and tear on the turbines, DPEC

also suggested a compliance margin based on potential degradation in other elements of the 

combined-cycle plant that would cause the overall plant heat rate to rise (i.e., cause efficiency to 

fall). DPEC proposed a 3% degradation rate to account for these factors. The other elements of 

the combined-cycle plant include the following: 

• Degradation in Turbine Exhaust Flow: The gas turbine manufacturer’s degradation 

curves predict potential recoverable and non-recoverable degradation in gas turbine 

exhaust flow over the 48,000-maintenance cycle. This degradation in exhaust flow could 

result in a direct reduction in the ability of the steam turbine to generate power, which 

could further degrade the plant’s overall efficiency. While degradation in the exhaust 

flow is expected to be partially offset by degradation in exhaust temperature (which 

raises over the maintenance cycle), this offset is not expected to make up for anticipated 

degradation in the reduction in steam turbine power as a result of reduced exhaust flow. 

• Degradation in Performance of Steam Turbine and Other Equipment: Degradation in the 

performance of the heat recovery steam generator, steam turbine, heat transfer, cooling 

tower, and ancillary equipment such as pumps and motors is also expected to occur over 

the course of a major maintenance cycle.

b) BACT Limit:

By establishing the energy efficiency for the combined-cycle turbine as BACT, permit 

conditions must be developed to ensure that Calpine DPEC installs and operate an energy 

efficient turbine in an energy efficient manner. 

EPA has developed an emission limit in tons of GHG per MWh produced that must be met 

during the initial and periodic stack testing. Since ambient conditions can affect the efficiency 

during a stack test and cannot be predicted at this time, the emission limit is being set using 

International Organization for Standardization (ISO) conditions. ISO 3977-2 is corrected for the 

following conditions: 
Calpine Corporation, Deer Park Energy Center Page 19 of 38

Deer Park, Texas (Harris County)

• Ambient Dry Bulb Temperature: 59o

F 

• Ambient Relative Humidity: 60% 

• Barometric Pressure: 14.69 psia 

• Fuel Lower Heating Value: 20,647 Btu/lb 

• Fuel HHV/LHV Ratio: 1.1086 

1) BACT Limit for the Combined-Cycle Combustion Turbine Generator

To ensure Calpine DPEC operates its facility to minimize greenhouse gases, EPA proposes to 

establish an CO2 emission limit/MWh. To determine an appropriate heat rate limit for continuous 

operations, the baseline annual average heat rate (HHV) of 6,852 Btu/kWh is used with the 3.3% 

design margin taken into account followed by a six percent (6%) performance margin reflecting 

efficiency losses due to equipment degradation prior to maintenance overhauls, and then a three 

percent (3%) degradation margin reflecting the variability in operation in auxiliary plant 

equipment due to use over time, resulting in the annual average heat rate (HHV) of 7,728 

Btu/kWh (See Appendix, Table 4). Additionally, to determine the heat input limit for this 

facility, the heat rate is calculated assuming that all steam generated in the heat recovery steam

generator is used to generate electricity in the existing on-site steam turbine even though there 

are periods when some or all of the generated steam is sold to a neighboring facility rather than 

sent to the on-site steam turbine.

The proposed GHG PSD permit, if approved, requires an output-based BACT limit of 0.460 tons 

CO2/MWh (net) for both the FD2 and FD3 engines on a 30-day rolling average and an annual 

GHG BACT limit of 1,045,635 tons CO2e per year for the FD2 series engine and 1,063,650 

tons of CO2e per year for the FD3 series engine on a 365-day rolling average. This is with the 

understanding that the FD2 series will be upgraded to the FD3 series within a statutory 

timeframe of 18 months under the conditions of this permit. In establishing an enforceable 

BACT limit over the lifetime of the turbine, Calpine accounted for the anticipated degradation of 

the equipment over time between regular maintenance cycles, as discussed in this section. (See 

Appendix, Table 4 for calculations)

c) Operating Conditions 

 Listed below are the operating conditions and work practice for the heat recovery steam 

generator and the plant-wide operations that ensure that CTG5 is operating at the highest 

possible efficiency.

1) HRSG5 Unit Operating Conditions

The Heat Recovery Steam Generator (HRSG5) energy efficiency processes, practices and 

designs considered include:

i. Energy efficient heat exchanger design. In this design, each pressure level 

incorporates an economizer section(s), evaporator section, and superheater section(s);

ii. Addition of insulation to the HRSG5 panels, high-temperature steam and water lines 

and to the bottom portion of the stack; 
Calpine Corporation, Deer Park Energy Center Page 20 of 38

Deer Park, Texas (Harris County)

iii. Filtration of the inlet air to the combustion turbine and periodic cleaning of the tubes 

(performed at least every 18 months) is performed to minimize fouling; and 

iv. Minimization of steam vents and repairs of steam leaks.

2) Plant Wide Operating Conditions

Within the combined-cycle power plant, several plant-wide, overall energy efficiency 

processes, practices and designs are included as BACT requirements because the additional 

operating conditions/practices help maintain the efficiency of the turbine. The requirements 

include: 

i. Fuel gas preheating. For the F-class combustion turbine based combined-cycle, the 

fuel gas is pre-heated to temperature of approximately 300o

F with high temperature 

water from the HRSG;

ii. Drain operation. Operation drains are controlled to minimize the loss of energy from 

the cycle but closing the drains as soon as the appropriate steam conditions are 

achieved;

iii. Multiple combustion turbine/HRSG trains. Multiple combustion turbine/HRSH trains 

help with part-load operation. A higher overall plant part-load efficiency is achieved 

by shutting down trains operating at less efficient part-load conditions and ramping 

up the remaining train(s) to high-efficiency full-load operation; 

iv. Boiler feed pump fluid drives. To minimize the power consumption at part-loads, the 

use of fluid drives or variable-frequency drives are used to minimize the power 

consumption at part-load conditions; 

d) BACT Compliance:

For both the FD2 and FD3-series, the combined-cycle combustion turbine unit is designed with a 

number of features to improve the overall efficiency. The additional combustion turbine design 

features include:

1. Inlet evaporative cooling to utilize water to cool the inlet air and thereby increasing the 

turbine’s efficiency; 

2. Periodic burner tuning as part of a regularly scheduled maintenance program to help 

ensure a more reliable operation of the unit and maintain optimal efficiency; 

3. Insulation blankets are utilized to minimize the heat loss through the combustion turbine 

shell and help improve the overall efficiency of the machine; and 

4. Hydrogen will be used to cool the generators resulting in a lower electrical loss and 

higher unit efficiency. 
Calpine Corporation, Deer Park Energy Center Page 21 of 38 

Deer Park, Texas (Harris County)

Calpine DPEC’s proposed method to demonstrate compliance with the CO2 emission limit of 

0.421 tons of CO2 per MWh (net)18 established as BACT by using fuel flow meters to monitor 

the quantity of fuel combusted in the electric generating unit and performing periodic scheduled 

fuel sampling pursuant to 40 CFR 75.10(3)(ii) and the procedures listed in 40 CFR 75, Appendix 

G. Results of the fuel sampling will be used to calculate a site-specific Fc factor, and that factor 

will be used in the equation below to calculated CO2 mass emissions. In conjunction with the 

flow meter methodology, Calpine will determine the CO2 hourly emission rate and CO2 mass 

emissions using an O2 monitor pursuant to 40 CFR Subpart 75 and appendix F of 40 CFR 

Subpart 75. The proposed permit also includes an alternative compliance demonstration method 

in which Calpine DPEC may install, calibrate, and operate a CO2 CEMS and volumetric stack 

gas flow monitoring system with an automated data acquisition and handling system for 

measuring and recording CO2 emissions. To demonstrate compliance with the CO2 BACT limit 

of 0.460 tons of CO2 per MWh (net) using CO2 CEMS, the measured hourly CO2 emissions are 

divided by the net hourly energy output and averaged daily. 

Currently, the four existing natural gas-fired turbines at Deer Park utilize fuel flow meters and 

monthly GCV (Gross Calorific Value) sampling in order to comply with the Acid Rain quality 

assurance and monitoring requirements of 40 CFR 75, Appendix D and G. The proposed natural 

gas-fired turbine identified as CTG5/HRSG5 will also comply with the fuel flow metering and 

GCV sampling requirements listed in Appendix D. Calpine DPEC proposes to determine a sitespecific Fc factor using the ultimate analysis and GCV in equation F-7b of 40 CFR 75, Appendix 

F. The site-specific Fc factor will be re-determined annually in according to 40 CFR 75, 

Appendix F, §3.3.6. 

The equation for estimating CO2 emissions as specified in 40 CFR 75.10(3)(ii) is as follows: 

WCO2 = (Fc × H × Uf × MWCO2)/2000

Where:

WCO2 = CO2 emitted from combustion, tons/hour

MWCO2 = molecular weight of CO2, 44.0 lbs/mole

Fc = Carbon-based Fc-Factor, 1040 scf/MMBtu for natural gas or site-specific Fc factor

H = hourly heat input in MMBtu, as calculated using the procedure in 40 CFR 75, Appendix F, §5

Uf = 1/385 scf CO2/lb-mole at 14.7 psia and 68°F 

Calpine DPEC is subject to all applicable requirements for fuel flow monitoring and quality 

assurance pursuant to 40 CFR 75, Appendix D, which includes: 

• Fuel flow meter- meets an accuracy of 2.0%, required to be tested once each calendar 

quarter pursuant to 40 CFR 75, Appendix D, §2.1.5 and §2.1.6(a)) 

• Gross Calorific Value (GCV)- determine the GCV of pipeline natural gas at least 

once per calendar month pursuant to 40 CFR 75, Appendix D, §2.3.4.1 

Additionally, this approach is consistent with the CO2 reporting requirements of 40 CFR 98, 

Subpart D- GHG Mandatory Reporting Rule for Electricity Generation. Furthermore, Calpine 

DPEC proposed CO2 monitoring method is consistent with the recently proposed New Source 

 

18 Output-based limits will be based on ton of CO2 versus ton of CO2e because all emissions determined by monitoring 

methodology in accordance to 40 CFR Part 75 are done in lbs of CO2 as opposed to lbs of CO2e.
Calpine Corporation, Deer Park Energy Center Page 22 of 38

Deer Park, Texas (Harris County)

Performance Standards, Subpart TTTT- Standards of Performance for Greenhouse Gas 

Emissions for Electric Utility Generating Units (40 CFR 60.5535(c)) which allows for electric 

generating units firing gaseous fuel to determine CO2 mass emissions by monitoring fuel 

combusted in the affected electric generating unit and using a site specific Fc factor determined 

in accordance to 40 CFR 75, Appendix F. 

The calculated hourly CO2 concentration result for emission point, CTG5/HRSG5, is required to 

be compared to the measured hourly CO2 concentration from the CO2 emission monitor. If the 

mean difference between the calculated and measured CO2 concentration result is greater than 

10%, Calpine shall review the emission units and monitoring instrumentation operational 

performance. This comparison is generally similar to the Relative Accuracy Test Audit (RATA) 

trial run standards provided in 40 CFR Part 75(E)(2). From this review, any corrective measures 

taken are to be identified, recorded, including the reason for the CO2 emissions difference and 

corrective measures completed within 48 hours of the corrective measures being taken. If 

Calpine DPEC chooses to install and operate the CO2 CEMS equipped with a volumetric stack 

gas monitoring system, the CO2 concentration calculation and mean difference comparison is no 

longer a requirement and the applicant shall rely on the data from the CO2 CEMS for compliance 

purposes. 

The emission limits associated with CH4 and N2O are calculated based on emission factors 

provided in 40 CFR Part 98, Table C-2 and the actual heat input (HHV). Comparatively, the 

emissions from CO2 contribute the most (greater than 99%) to the overall emissions from the 

CTGs and; therefore, additional analysis is not required for CH4 and N2O. To calculate the CO2e 

emissions, the draft permit requires calculation of the emissions based on the procedures and 

Global Warming Potentials (GWP) contained in the Greenhouse Gas Regulations, 40 CFR Part 

98, Subpart A, Table A-1. Records of the calculations would be required to be kept to 

demonstrate compliance with the emission limits on a 365-day average, rolling daily. 

An initial stack test demonstration will be required for CO2 emissions from emission unit. An 

initial stack test demonstration for CH4 and N2O emissions are not required because the CH4 and 

N2O emission are approximately 0.09% of the total CO2e emissions from the CTGs and are 

considered a de minimis level in comparison to the CO2 emissions. 

For startup and shutdown operating scenarios for the proposed CTG, BACT will be achieved by 

minimizing the duration of the start-up and shutdown events, consistent with market demands, 

and by engaging the pollution control equipment (e.g., the SCR system in combined-cycle) as 

soon as practicable, based on vendor recommendations and guarantees. During periods of startup 

and shutdown, the permittee must record the time, date, fuel heat input (HHV) in MMBtu/hr and 

the duration of each startup and shutdown event. All emissions during startup and shutdown are 

minimized by limiting the duration of operation. The estimated 70 tons/hour (See calculations in 

Table 5 of the Appendix) illustrate that startup and shutdown emissions are lower than “normal” 

emissions and are accounted for in the Annual Facility Emissions (Table 1 of Appendix). To 

demonstrate compliance with the startup and shutdown emissions, Calpine shall record the time, 

date, fuel heat input and duration of each startup and shutdown event. The duration of operation 

during startup and shutdown are defined as follows: 
Calpine Corporation, Deer Park Energy Center Page 23 of 38

Deer Park, Texas (Harris County)

1. A startup of CTG5 is defined as the period that begins when there is measureable fuel 

flow to the CTG5 and ends when the CTG5 load reaches 60 percent. A startup for each 

CTG5 is limited to 480 minutes. 

2. A shutdown of each CTG5 is defined as the period that begins when CTG5 load falls 

below 60 percent and ends when there is no longer measureable fuel flow to CTG5. A 

shutdown for CTG5 is limited to 180 minutes. 

Under draft terms, records of all emissions calculations for startup and shutdown events shall be 

kept on-site for a period of 5-years. After review of the submitted materials, EPA agrees with 

and adopts Calpine’s BACT analysis for the natural gas-fired combined-cycle combustion 

turbines. 

X. GHG BACT for the Fugitive Emission Sources (NG-FUG)

Step One: Identify All Potentially Available Control Technologies

The control technology for process fugitive emissions of GHGs are: 

• Leakless Technology 

• Instrument Leak detection and repair (LDAR) programs 

• Remote Sensing 

• Auditory, Visual, and Olfactory (AVO) Monitoring 

Step Two: Eliminate Technically Infeasible Control Options

• Leakless Technology – Leakless technology valves may be incorporated in situations where 

highly toxic or otherwise hazardous materials are present. Likewise, some technologies, such 

as bellows valves, cannot be repaired without a unit shutdown. Because natural gas is not 

considered highly toxic nor a hazardous material, this gas does not warrant the risk of unit 

shutdown for repair, and therefore leakless valve technology for fuel lines is considered 

technically impracticable.

• Instrument LDAR Programs – Is considered technically feasible. 

• Remote Sensing – Is considered technically feasible. 

• AVO Monitoring – Is considered technically feasible.

Step Three: Rank Remaining Control Technologies by Control Effectiveness

Instrument LDAR programs and the alternative work practice of remote sensing using an 

infrared camera have been determined by EPA to be equivalent methods of piping fugitive 

controls.19 The most stringent LDAR program, 28LAER, provides for 97% control credit for 

valves, flanges, and connectors.

As-observed AVO methods are generally somewhat less effective than instrument LDAR and 

remote sensing, since they are not conducted at specific intervals. However, since pipeline 

natural gas is odorized with very small quantities of mercaptan, as-observed olfactory 

observation is a very effective method for identifying and correcting leaks in natural gas systems. 

 

19 73 FR 78199-78219, December 22, 2008.
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Deer Park, Texas (Harris County)

Due to the pressure and other physical properties of plant fuel gas, as-observed audio and visual 

observations of potential fugitive leaks are likewise moderately effective.

Step Four: Evaluate Top Control Alternatives

Although instrument LDAR and/or remote sensing of piping fugitive emissions in natural gas 

lines may be somewhat more effective than as-observed AVO methods, these methods are not 

economically practicable for GHG control from components in fuel gas service. The incremental 

GHGs controlled by implementation of the 28LAER or a comparable remote sensing program is 

less than 60 tons CO2e per year, or less than 0.0001% of the total project’s proposed CO2e 

emissions. 

Step Five: Select BACT

EPA has reviewed and Calpine’s Fugitive Emission Sources top-down BACT analysis. Based on 

the economic impracticability of instrument monitoring and remote sensing for fuel gas piping 

components, EPA proposes to incorporate as-observed AVO as BACT for the piping 

components in new combustion turbine generator and heat recovery steam generator and 

proposes an annual BACT emission limit of 60 tons per year CO2e. Calpine also identified and 

adopted the use of dry compressor seals, use of rod packing for reciprocating compressors, and 

the use of low-bleed gas-driven pneumatic controllers or air-driven pneumatic controllers as 

BACT for fugitives. EPA determines that the AVO program for fugitives for control of CH4

emissions is BACT.

XI. GHG BACT for the SF6 Insulated Electrical Equipment (SF6-FUG)

Step One: Identify All Potentially Available Control Technologies

Several control options can be used to help minimize GHG emissions for the SF6 circuit 

breakers which include: 

• Use of dielectric oil or compressed air circuit breakers – these types of circuit breakers do 

not contain any GHG pollutants and serve as a substitute for SF6 circuit breakers. 

Potential alternatives to SF6 circuit breakers are addressed in the National Institute of 

Standards and Technology (NTIS) Technical Note 1425, Gases for Electrical Insulation 

and Arc Interruption: Possible Present and Future Alternatives to Pure SF620 

• Totally enclosed SF6 circuit breakers with leak detection system - Modern SF6 circuit 

breakers, as opposed to the older SF6 circuit breakers, are designed as a totally enclosedpressure system which reduces the potential for SF6 emissions. These systems are 

equipped with a density alarm that provides a warning when 10% of the SF6 (by weight) 

has escaped. This identifies potential leak problems before the bulk of the SF6 can escape 

 

20Christophorous, L.G., J.K. Olthoff, and D.S. Green, Gases for Electrical Insulation and Arc Interruption: Possible Present and 

Future Alternatives to Pure SF6, NIST Technical Note 1425, Nov. 1997, <http://www.epa.gov/electricpowersf6/documents/new_report_final.pdf> 
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Deer Park, Texas (Harris County)

Step Two: Eliminate Technically Infeasible Control Options

At this time, sulfur hexafluoride (SF6)-containing circuit breakers are the only commercially 

available circuit breakers. While there are other potential dielectric, non-greenhouse gas 

substances such as oil and air that could be used, these types of circuit breakers are all in the 

research stage and thus are not technically feasible for use at the DPEC.

21 

Step Three: Rank Remaining Control Technologies by Control Effectiveness

The only remaining technically feasible options for insulating electrical equipment associated 

with the combustion turbine process are totally enclosed SF6 circuit breakers with a leak 

detection system. 

Step Four: Evaluate Top Control Alternatives

There no other control alternatives available at this time as stated in Step 2, therefore SF6 circuit 

breakers will only be considered. 

Step Five: Select BACT

Based on Calpine’s top-down BACT analysis for fugitive emissions, Calpine concludes that 

using state-of-the-art enclosed-pressure SF6 circuit breakers with leak detection is the appropriate 

BACT control technology option. The proposed GHG PSD permit, if approved, is comprised of 

a 72 pound SF6 insulated circuit breaker. Calpine will monitor the SF6 emissions annually in 

accordance with the requirements of the Mandatory Greenhouse Gas Reporting rules for 

Electrical Transmission and Distribution Equipment Use. The annual SF6 emissions will be 

calculated according to the mass balance approach in Equation DD-1 of Subpart DD. EPA 

concurs with and adopts Calpine’s best work practice standards for control of SF6 emissions and 

the state-of-the-art enclosed-pressure SF6 circuit breakers with leak detection for fugitive SF6

emissions as BACT.

XII. Threatened and Endangered Species

Pursuant to Section 7(a)(2) of the Endangered Species Act (ESA) (16 U.S.C. 1536) and its

implementing regulations at 50 CFR Part 402, EPA is required to insure that any action 

authorized, funded, or carried out by EPA is not likely to jeopardize the continued existence of 

any federally-listed endangered or threatened species or result in the destruction or adverse 

modification of such species’ designated critical habitat. 

To meet the requirements of Section 7, EPA is relying on a Biological Assessment (BA) 

prepared by the applicant and reviewed by EPA. Further, EPA designated Calpine as its 

non-federal representative for purposes of preparation of the BA and for conducting informal 

consultation. 

A draft BA has identified twelve (12) species as federally endangered or threatened in Harris 

County by the U.S. Fish and Wildlife Service (USFWS), National Marine Fisheries Service 

(NMFS) and the Texas Parks and Wildlife Department (TPWD). 

 

21 Christophorous, L.G. et al., pp. 28-29 
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Deer Park, Texas (Harris County)

EPA has determined that issuance of the proposed permit to Calpine for construction of the 

combustion turbine generator/heat recovery steam generator will have no effect on five (5) of 

these listed species, specifically the smalltooth sawfish (Pristis pectinata), the red-cockaded 

woodpecker (Picoides borealis), the whooping crane (Grus americana), the Louisiana black bear 

(Ursus americanus luteolus), and the red wolf (Canis rufus). These species are either thought to 

be extirpated from the county or Texas or are not present in the action area. 

The remaining seven (7) species identified are species that may be present in the action area in 

certain circumstances. As a result of this potential occurrence and based on the information 

provided in the draft BA, the issuance of the permit may affect, but is not likely to adversely 

affect the following species. As a result, EPA will submit the final draft BA to the Southwest 

Region, Clear Lake, Texas Ecological Services Field Office of the USFWS for its concurrence 

that issuance of the permit may affect, but is not likely to adversely affect the following species:

• Houston toad (Bufo houstonensis). 

• Texas prairie dawn-flower (Hymenoxys texana). 

EPA will also submit the final draft BA to the NOAA Southeast Regional Office, Protected 

Resources Division of NMFS for its concurrence that issuance of the permit may affect, but is 

not likely to adversely affect the following species:

• leatherback sea turtle (Dermochelys coriacea) 

• green sea turtle (Chelonia mydas) 

• Kemp’s ridley sea turtle (Lepidochelys kempii) 

• loggerhead sea turtle (Caretta caretta) 

• West Indian manatee (Trichechus manatus) 

Any interested party is welcome to bring particular concerns or information to our attention 

regarding this project’s potential effect on endangered species. The final draft biological 

assessment can be found at EPA’s Region 6 Air Permits website at 

http://yosemite.epa.gov/r6/Apermit.nsf/AirP. 

XIII. Magnusson-Stevens Act

The 1996 Essential Fish Habitat (EFH) amendments to the Magnuson-Stevens Fishery 

Conservation and Management Act (Magnuson-Stevens Act) set forth a mandate for NOAA’s 

National Marine Fisheries Service (NMFS), regional fishery management councils (FMC), and 

other federal agencies to identify and protect important marine and anadromous fish habitat. 

To meet the requirements of the Magnuson-Stevens Act, EPA is relying on an EFH Assessment

prepared by the applicant and reviewed by EPA. 

The action area of the project site affects tidally influenced portions of the Buffalo Bayou 

(Houston Ship Channel) which connects to Upper Galveston Bay. These tidally influenced 

portions have been identified as potential habitats of postlarval, juvenile, and subadult red drum 
Calpine Corporation, Deer Park Energy Center Page 27 of 38

Deer Park, Texas (Harris County)

(Sciaenops ocellatus), Spanish mackerel (Scomberomorus maculatus), pink shrimp (Penaeus 

duorarum), white shrimp (Penaeus setiferus) and brown shrimp (Farfantepenaeus aztecus). The 

EFH Amendment information was obtained from the Gulf of Mexico Fishery Management 

Council (http://www.gulfcouncil.org/).

Based on the information provided in the EFH Assessment, EPA concludes that the proposed 

PSD permit allowing Calpine DPEC to construct the combustion turbine generator/heat recovery 

generator, identified as CTG5/HRSG5, will have no adverse impacts on EFH.

XIV. National Historic Preservation Act (NHPA)

Section 106 of the NHPA requires EPA to consider the effects of this permit action on properties 

eligible for inclusion in the National Register of Historic Places. To make this determination, 

EPA relied on a cultural resource report prepared by Blanton and Associates, Inc. (“Blanton”), 

Calpine’s consultant, submitted on May 4, 2012. 

Blanton conducted an a cultural resource survey within a 1,000-meter radius of the construction 

site which included a review of the Texas Historical Commission’s online Texas Archaeological 

Site Atlas (TASA) and a pedestrian survey. Based on the information provided in the cultural 

resources report, no archaeological resources or historic structures were found. The site is 

located in a modern industrial facility in a highly developed, industrialized zone surrounded by 

oil and gas refineries. 

Upon receipt of the report, EPA sent letters to Indian tribes identified by the Texas Historical 

Commission as having historical interests in Texas to inquire if any of the tribes have historical 

interest in the particular location of the project and to inquire whether any of the tribes wished to 

consult with EPA in the Section 106 process. EPA received no tribal requests for participation as 

a consulting party or comments about the project. 

After considering a report submitted by the applicant, EPA Region 6 determines that because the 

report indicated that no archaeological resources or historic properties are located within the 

construction area of the project and that a potential for the location of archaeological resources is 

low, issuance of the permit to Calpine will not affect properties potentially eligible for listing on 

the National Register. 

EPA will provide a copy of this report to the State Historic Preservation Officer for consultation 

and concurrence with this determination. Any interested party is welcome to bring particular 

concerns or information to our attention regarding this project’s potential effect on historic 

properties. 
Calpine Corporation, Deer Park Energy Center Page 28 of 38

Deer Park, Texas (Harris County)

XV. Environmental Justice (EJ)

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive branch 

policy on environmental justice. Based on this Executive Order, the EPA’s Environmental 

Appeals Board (EAB) has held that environmental justice issues must be considered in 

connection with the issuance of federal Prevention of Significant Deterioration (PSD) permits 

issued by EPA Regional Offices [See, e.g., In re Prairie State Generating Company, 13 E.A.D. 

1, 123 (EAB 2006); In re Knauf Fiber Glass, Gmbh, 8 E.A.D. 121, 174-75 (EAB 1999)]. This 

permitting action, if finalized, authorizes emissions of GHG, controlled by what we have 

determined is the Best Available Control Technology for those emissions. It does not select 

environmental controls for any other pollutants. Unlike the criteria pollutants for which EPA has 

historically issued PSD permits, there is no National Ambient Air Quality Standard (NAAQS) 

for GHG emissions. The global climate-change inducing effects of GHG emissions, according to 

the “Endangerment and Cause or Contribute Finding”, are far-reaching and multi-dimensional 

(75 FR 66497). Climate change modeling and evaluations of risks and impacts are typically 

conducted for changes in emissions that are orders of magnitude larger than the emissions from 

individual projects that might be analyzed in PSD permit reviews. Quantifying the exact impacts 

attributable to a specific GHG source obtaining a permit in specific places and points would not 

be possible [PSD and Title V Permitting Guidance for GHGS at 48]. Thus, we conclude it would 

not be meaningful to evaluate impacts of GHG emissions on a local community in the context of 

a single permit. Accordingly, we have determined an environmental justice analysis is not 

necessary for the permitting record.

XVI. Conclusion and Proposed Action 

Based on the information supplied by Calpine, our review of the analyses contained the TCEQ 

PSD Permit Application and the GHG PSD Permit Application, and our independent evaluation 

of the information contained in our Administrative Record, it is our determination that the 

proposed facility would employ BACT for GHGs under the terms contained in the draft permit. 

Therefore, EPA is proposing to issue Calpine a PSD permit for GHGs for the facility, subject to 

the PSD permit conditions specified therein. This permit is subject to review and comments. A 

final decision on issuance of the permit will be made by EPA after considering comments 

received during the public comment period. 
Calpine Corporation, Deer Park Energy Center Page 29 of 38

Deer Park, Texas (Harris County)

Statement of Basis

Appendix

for

Calpine Corporation, Deer Park Energy Center (DPEC), LLC

Greenhouse Gas Prevention of Significant Deterioration 

Preconstruction Permit

Permit Number: PSD-TX-979-GHG
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Deer Park, Texas (Harris County)

Table 1. Annual Facility Emissions

Output-based emissions limit, in tons per megawatt-hour (tons/MWh) on a 30-day rolling 

average, and annual emissions, in tons per year (TPY) on a 365-day rolling average basis shall 

not exceed the following: 

Phase 1 of Construction

Emission 

Unit Description

GHG Mass Basis BACT

GHG Potential 

Emissions

(TPY)

2,3

Output-based 

BACT CO2

Limit1

Tons per 

year

CO2e

2,3

Annual 

BACT

Limit

(TPY CO2e

2,3)

CTG5 

(FD2) / 

HRSG5

CTG5/HRSG5 

Annual 

Emissions 

CO2 1,044,629 CO2

0.460 

tons/MWh

7,730

Btu/KWh

1,044,629

1,045,635

CH4 19.34 CH4 406

N2O 1.93 N2O 599

NGFUG 

Fugitive 

Natural Gas 

emissions from 

piping 

components

(including 

valves & 

flanges)

CO2 0.11 CO2 0.11 60

CH4

4 2.84 CH44 59.69

SF6-

FUG 

SF6 Insulated 

Electrical 

Equipment SF6 0.00018 SF6 4.3

4.3

1. Compliance with the output-based emission limits (on a per hour basis) is based on a 30-day rolling 

average. 

2. Compliance with the annual emission limits (tons per year) is based on a 365-day rolling average. 

3. The tpy emission limits specified in this table are not to be exceeded for this facility and includes emissions 

only from the facility during normal operations and startup and shutdown activities.

4. Because the emissions from this unit are calculated to be 96% methane (CH4), the remaining pollutant 

emission (CO2) is not presented in the table.

5. Because the emissions from this unit are calculated to be over 99.9% carbon dioxide (CO2), the remaining 

pollutant emissions (CH4 and N2O) are not presented in the table.
Calpine Corporation, Deer Park Energy Center Page 31 of 38

Deer Park, Texas (Harris County)

Phase 2 of Construction

Emission 

Unit Description

GHG Mass Basis BACT

GHG Potential 

Emissions

(TPY)

2,3

Output-based 

BACT CO2

Limit1

Tons per 

year

CO2e

2,3

Annual 

BACT

Limit

(TPY CO2e

2,3)

CTG5 

(FD2) / 

HRSG5

CTG5/HRSG

5 Annual 

Emissions 

CO2 1,062, 627 CO2

0.460 

tons/MWh

7,730

Btu/KWh

1,062, 627

1,063,650

CH4 19.67 CH4 413

N2O 1.97 N2O 610

NGFUG 

Fugitive 

Natural Gas 

emissions 

from piping 

components

(including 

valves & 

flanges)

CO2 0.11 CO2 0.11 60

CH4

4 2.84 CH44 59.69

SF6-

FUG 

SF6 Insulated 

Electrical 

Equipment SF6 0.00018 SF6 4.3

4.3

1. Compliance with the output-based emission limits (on a per hour basis) is based on a 30-day rolling 

average. 

2. Compliance with the annual emission limits (tons per year) is based on a 365-day rolling average. 

3. The tpy emission limits specified in this table are not to be exceeded for this facility and includes emissions 

only from the facility during normal operations and startup and shutdown activities.

4. Because the emissions from this unit are calculated to be 96% methane (CH4), the remaining pollutant 

emission (CO2) is not presented in the table.

5. Because the emissions from this unit are calculated to be over 99.9% carbon dioxide (CO2), the remaining 

pollutant emissions (CH4 and N2O) are not presented in the table.
Calpine Corporation, Deer Park Energy Center Page 32 of 38

Deer Park, Texas (Harris County)

Table 2: Annual Emissions for the FD2 Combined-cycle Combustion Turbine and Steam Generator (CTG5/HRSG5) –

Phase 1 of Construction

Total Heat Input Capacity (MMBtu/yr)1 = 17,577,900 Greenhouse Gas

CO2 CH4 N2O

Emission Factor2 (kg/MMBtu) 1.00E-03 1.00E-04

Global Warming Potential3 (GWP) 1 21 310

GHG Potential Emissions4,5 (tpy) 1,044,629 19.34 1.93

Total GHG Potential Emissions (tpy) 1,044,651

CO2e

6 (tpy) 1,044,629 406 599

Total CO2e

7 (tpy) 1,045,635

Methodologies and Assumptions

1 Total Heat Input Capacity was determined from the projected annual firing rate information provided by Calpine and reviewed by the EPA

Operating Mode

Annual 

Operating 

Hours (hr/yr)

Turbine Heat Input 

(MMBtu/hr)

Duct Burner 

Heat Input 

(MMBtu/hr)

Total Hourly 

Heat Input 

(MMBtu/hr)

Total Annual Heat 

Input (MMBtu/hr)

Base Load, 70oF Ambient, Avg Duct Burner Firing 6,760 1,827.5 110 1937.5 13,097,500 

Base Load, 90oF Ambient, Peak Duct Burner 

Firing 1,500 1602.8 595 2,197.8 3,296,700 

Base Load, 90oF Ambient, Peak Duct Firing, 

Power Augmentation 500 1,712.4 655 2,367.4 1,183,700 

8,760 17,577,900

2 CH4 and N2O GHG factors are based on Table C-2 of 40 CFR 98 

3 Greenhouse Warming Potentials (GWP) are from Table A-1 of 40 CFR Part 98, Subpart A. Mandatory Greenhouse Gas Reporting

4 CO2 emissions is based on Equation G-4, Appendix G, 40 CFR Part 75, Appendix G where the yearly emission was calculated instead of hourly

WCO2 = (Fc x H x Uf x MWCO2)/2000

where: WCO2 = CO2 emitted (tons/yr) H = Heat Input (MMBtu/yr) MWCO2 = Molecular Weight of CO2 = 44.0 lbs/mole

Fc = Carbon-base F factor, 1040 scf/MMBtu Uf = 1/385 scf CO2/lb-mole 5 Greenhouse Warming Potentials (GWP) are from Table A-1 of 40 CFR Part 98, Subpart A and GHG Potential Emissions (tons/year) = Throughput (MMBtu/yr) x 

Emission Factor (kg/MMBtu) x (2.2 lbs/kg) x (1 ton/2000 lbs) 

6 CO2e (tpy) = GHG Potential Emissions x GWP for each pollutant

7 Total CO2e (tpy) = (CO2 Potential Emissions x CO2 GWP) + CH4 Potential Emissions x CH4 GWP) + (N2O Potential Emissions x N2O GWP)
Calpine Corporation, Deer Park Energy Center Page 33 of 38

Deer Park, Texas (Harris County)

Table 3: Annual Emissions for the FD3 Combined-Cycle Combustion Turbine and Steam Generator (CTG5/HRSG5) 

Phase 2 of Construction

Total Heat Input Capacity (MMBtu/yr)1 17,880,750 Greenhouse Gas

CO2 CH4 N2O

Emission Factor2 (kg/MMBtu) 1.00E-03 1.00E-04

Global Warming Potential3 (GWP) 1 21 310

GHG Potential Emissionsb (tpy) 1,062,627 19.67 1.97

Total GHG Potential Emissions (tpy) 1,080,728

CO2e

6 (tpy) 1,062,627 413 610

Total CO2e

7 (tpy) 1,063,650

Methodologies and Assumptions

1 Total Heat Input Capacity was determined from the projected annual firing rate information provided by Calpine and reviewed by the EPA

Operating Mode

Annual Operating 

Hours (hr/yr)

Turbine Heat Input 

(MMBtu/hr)

Duct Burner 

Heat Input 

(MMBtu/hr)

Total Hourly Heat 

Input (MMBtu/hr)

Total Annual Heat 

Input (MMBtu/hr)

Base Load, 70oF Ambient, Avg Duct Burner Firing 6,760 1,873 110 1,983 13,097,500 

Base Load, 90oF Ambient, Peak Duct Burner Firing 1,500 1,752 595 2,347 3,520,050 

Base Load, 90oF Ambient, Peak Duct Firing, Power 

Augmentation

500 1,871 655 2,526 1,263,200 

8,760 17,880,750

2 CH4 and N2O GHG factors are based on Table C-2 of 40 CFR 98 

3 Greenhouse Warming Potentials (GWP) are from Table A-1 of 40 CFR Part 98, Subpart A. Mandatory Greenhouse Gas Reporting

4 CO2 emissions is based on Equation G-4, Appendix G, 40 CFR Part 75, Appendix G where the yearly emission was calculated instead of hourly

WCO2 = (Fc x H x Uf x MWCO2)/2000

where: WCO2 = CO2 emitted (tons/yr) H = Heat Input (MMBtu/yr) MWCO2 = Molecular Weight of CO2 = 44.0 lbs/mole

Fc = Carbon-base F factor, 1040 scf/MMBtu Uf = 1/385 scf CO2/lb-mole 5 Greenhouse Warming Potentials (GWP) are from Table A-1 of 40 CFR Part 98, Subpart A and GHG Potential Emissions (tons/year) = Throughput (MMBtu/yr) x 

Emission Factor (kg/MMBtu) x (2.2 lbs/kg) x (1 ton/2000 lbs) 

6 CO2e (tpy) = GHG Potential Emissions x GWP for each pollutant

7 Total CO2e (tpy) = (CO2 Potential Emissions x CO2 GWP) + CH4 Potential Emissions x CH4 GWP) + (N2O Potential Emissions x N2O GWP)
Calpine Corporation, Deer Park Energy Center Page 34 of 38

Deer Park, Texas (Harris County)

Table 4: Output-Based BACT Limits for FD2 and FD3 Combined-Cycle Combustion Turbine and 

Steam Generator (CTG5/HRSG5) 

Base Net Heat Rate in Btu/kWh (HHV) 

(without duct firing) 6,852.0

+3.30% Design Margin

Heat Rate due to Design Margin (Btu/kWh (HHV)1 7,078.1

+6.00% Performance Margin

Heat Rate due to Performance Margin and Design 

Margin (Btu/kWh (HHV)) 7,502.8

+3.00% Degradation Margin

Calculated Base Net Heat Rate with Compliance 

Margins (Btu/kWh (HHV)) 7,727.9 

Calculation of Output-Based BACT Limit (ton CO2/MWh) for CTG5/HRSG55

EPN

Base Heat 

Rate 

(Btu/kWh)

6

Heat Input 

Required to 

Produce 1 

MW 

(MMBtu/h)

2

tons 

CO2e per 

year3

Total Heat 

Input 

Capacity 

(MMBtu/yr)3 tons 

CO2e/MWh4

CTG5/

HRSG5 7727.9 7.73 1,063,650 17,880,750 0.460

1

Base Heat Rate was calculated accounting for a 3.3% margin of error in design and construction of the new turbine

2

Heat Input was calculated by dividing the Base Heat Rate by a factor of 1000

3

Values obtained from Table 2 for the FD2 series and Table 3 for the FD3 series of the SOB Appendix 4

tons CO2e/MWh = ((tons CO2e per year)/(total heat input capacity/Heat Input Required to produce 1 MW)). 

Output-based limits will be based on CO2 versus CO2e because all emissions determined by monitoring 

methodology in accordance to 40 CFR Part 75 are in lbs of CO2 as opposed to lbs of CO2e.

5

Ongoing Output-based BACT limit averaged over each 30-day consecutive period 6

Base Heat Rate was calculated accounting for 3.3% design margin, 6.0% performance margin and a 3.0% 

degradation margin (See SOB, Step 5 discussion of GHG BACT for the Combined-cycle Combustion Turbine 

Generator)
Calpine Corporation, Deer Park Energy Center Page 35 of 38

Deer Park, Texas (Harris County)

Table 5. Startup and Shutdown Hourly Emissions Calculations 

Total Heat Input Capacity 

(MMBtu/hr)

1 1,164

Greenhouse Gas

CO2 CH4 N2O

Emission Factor2 (kg/MMBtu) 1.00E-03 1.00E-04

Global Warming Potential3 (GWP) 1 21 310

GHG Potential Emissions4,5 (tons per hour) 69 1.28E-03 1.28E-04

Total GHG Potential Emissions (tons per hour) 69

CO2e

6 (tons per hour) 69 2.69E-02 3.97E-02

Total CO2e

b (tons per hour) 69

Methodologies and Assumptions

1 Total Heat Input Capacity was determined from the hourly firing rate information provided by Calpine and 

reviewed by the EPA. Startup Emission Basis –A startup period begins when an initial flame detection signal is 

recorded in the plant’s Data Acquisition and Handling System (DAHS) and ends when combustion tubine output 

reaches 60% load. Since GHG emissions are proportional to fuel consumption, high GHG emissions during a 

startup occurs at the point of highest fuel consumption (approximately 60% load).

Operating Mode

Turbine 

Heat Input 

(MMBtu/hr)

Duct Burner 

Heat Input 

(MMBtu/hr)

Total Hourly 

Heat Input 

(MMBtu/hr)

Maximum Hourly Heat Input

Base Load, 20oF 

Ambient, Max Duct 

Burner Firing

2,017 452 2,469

Maximum Hourly Heat Input 

during Startup

60% Load, 90oF 

Ambient, no Duct 

Burner Firing

1,164 0 1,164

2 CH4 and N2O GHG factors are based on Table C-2 of 40 CFR 98 3 Greenhouse Warming Potentials (GWP) are from Table A-1 of 40 CFR Part 98, Subpart A. Mandatory Greenhouse Gas 

Reporting

4 CO2 emissions is based on Equation G-4, Appendix G, 40 CFR Part 75, Appendix G where the yearly emission was 

calculated instead of hourly

WCO2 = (Fc x H x Uf x MWCO2)/2000

where: WCO2 = CO2 emitted (tons/yr) H = Heat Input (MMBtu/yr) MWCO2 = Molecular Weight of CO2 = 44.0 lbs/mole 

Fc = Carbon-base F factor, 1040 

scf/MMBtu Uf = 1/385 scf CO2/lb-mole 5 Greenhouse Warming Potentials (GWP) are from Table A-1 of 40 CFR Part 98, Subpart A and GHG Potential Emissions 

(tons/year) = Throughput (MMBtu/yr) x Emission Factor (kg/MMBtu) x (2.2 lbs/kg) x (1 ton/2000 lbs)

6 CO2e (tpy) = GHG Potential Emissions x GWP for each pollutant 7 Total CO2e (tpy) = (CO2 Potential Emissions x CO2 GWP) + CH4 Potential Emissions x CH4 GWP) + (N2O Potential 

Emissions x N2O GWP)
Calpine Corporation, Deer Park Energy Center Page 36 of 38

Deer Park, Texas (Harris County)

Table 6. Fugitive Emissions (Valves)

Source 

Types Fluid State Count

Emission 

Factor1 

(scf/hr/comp)

Greenhouse Gas

CO2

2 CH43

NG-FUG

Valves Gas/vapor 60 0.123 0.05 1.27

Flanges Gas/vapor 240 0.017 0.03 0.70

Relief 

Valves Gas/vapor 8 0.196 0.01 0.27

Sampling 

Collections Gas/vapor 18 0.123 0.01 0.38

Global Warming Potential3 (GWP) 1 21

GHG Potential Emissions4 (tpy) 0.10 2.62

Total GHG Potential Emissions (tpy) 2.72

CO2e

5 (tpy) 0.10 54.95

Annual CO2e BACT Limit (tpy) 55.05

Methodologies and Assumptions

1 Emission factors from Table W-1A of 40 CFR 98 Mandatory Greenhouse Gas Reporting

2 CO2 emissions based on vol% of CO2 in natural gas (1.33% from Natural Gas Analysis)

3 CH4 emissions based on vol% of CH4 in natural gas (94.44% from natural gas analysis)

4 Greenhouse Warming Potentials (GWP) are from Table A-1 of 40 CFR Part 98, Subpart A

5 CO2e (tpy) = GHG Potential Emissions x GWP for each pollutant

6 Total CO2e (tpy) = (CO2 Potential Emissions x CO2 GWP) + CH4 Potential Emissions x CH4 GWP) + (N2O 

Potential Emissions x N2O GWP)

sample calc

%CO2

60 valves 0.123 scf 0.0133 lb-mole 44.01 lb CO2 8760 hr ton

hr*valve 385.5 scf lb-mole yr 2000 lb
Calpine Corporation, Deer Park Energy Center Page 37 of 38

Deer Park, Texas (Harris County)

Table 7. Miscellaneous Fugitive Emissions from Small Equipment & Component Repair/Replacement

Initial Conditions Final conditions CO2

3 CH44 

Location Volume1

 (ft) Pressure (psig) Temp (oF) Pressure 

(psig)

Temp 

(

o

F)

Volume2

(scf)

Annual 

(tpy)

Annual 

(tpy) Total (tpy)

Turbine Fuel Line 

Shutdown/Maintenance 955 50 50 0 68 4397 0.0033 0.0861 

Small Equipment/Fugitive 

Component Repair/Replacement 6.7 50 50 0 68 31 0.00002 0.0006 

Total GHG Potential Emissions 0.0034 0.0867 0.0901 

Global Warming Potential 1 21 

CO2e Emissions 0.0034 1.8216 1.8250 

1. Initial volume was calculated by multiplying the cross sectional area by the length of the pipe using the following formula: Vi = {π * [(diameter(inches)/12)/2]2 * length(ft)}

2. Final volume was calculated using ideal gas law: [((PV)/(ZT))i=((PV)/(ZT))f]. Vf =[ Vi*(Pi/Pf)*(Tf/Ti)*(Zf/Zi)], where the compressibility factor, Z, is estimated as the following equation:

Zn = 0.9994 - 0.0002Pn + 3e-08Pn

2

3. CO2 emissions is based on % volume of CO2 in Natural gas = 1.33% from natural gas analysis

4. CH4 emissions is based on % volume of CH4 in natural gas = 94.4% from natural gas analysis

5. Global Warming Potential factors are based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting

Example Calculation:

4,397 scf Nat Gas 0.0133 scf CO2 lbmole 44.01 lb CO2 ton = 0.0033 tons CO2

year scf Nat Gas 385.5 scf lbmole 2000 lb yr

Table 8. Fugitive Emissions from Electrical Equipment Insulated with SF6

Assumptions: New insulated circuit breaker SF6 capacity 72 lbs

Estimated annual SF6 leak rate 0.50% weight

Estimated annual SF6 mass emission rate 0.00018 tons/year

Global Warming Potential 23,900

Estimated annual CO2e emission rate 4.302 ton/year

1. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting

2. Estimated annual CO2e emissions was calculated using the following equation:

72 lbs 0.005 (%weight) ton

(GWP)

23,900 = 4.3 

Tons/year year 2000 lbs
Calpine Corporation, Deer Park Energy Center Page 38 of 38

Deer Park, Texas (Harris County)

Table 9. Financial Assessment for Implementation of a Carbon Capture and Storage 

System at the Calpine DPEC Facility

Carbon Capture and 

Storage (CCS) 

Components

Annual System CO2

Throughput (tons of CO2

captured, transported, and 

stored)

Pipeline Length for 

CO2 Transport 

System (km)5

Range of Approximate Annual Costs 

for CCS System (in USD)6

Post-Combustion CO2 Capture and Compression System1

Average Cost2,3,4 956,349 $70,544,632

CO2 Transport System

Average Cost2,3,4 956,349 24 $419,123

CO2 Storage System

Average Cost2,3,4 956,349 $8,918,776

Total Annual Costs for CO2 Capture, Transport and Storage Systems

Average Cost2,3,4 956,349 $79,882,531

Assumptions:

1. Assume that the capture systems is able to capture 90% of the total CO2 emissions generated by the power plant’s gas 

turbines 

2. The minimum cost factor found for implementation/operation of the CO2 capture systems within the cost-related 

information reviewed for CCS technology is found from the “Properties” section of the Greenhouse Gas Mitigation 

Strategies Database (last accessed April 2010) (http:/ghg.ie.unc.edu:8080/GHGMDB/#data), which was obtained 

through the EPA GHG web site (http://www.epa.gov/nsr/ghgpermitting.html). The factor is based on the increased 

cost of electricity (COE; in $/MW-h) resulting from the implementation and operation at a CO2 capture system on a 

natural gas-fired combined-cycle power plant. The factor accounts for annualized capital costs, fixed operating costs, 

variable operating costs, and fuel costs.

3. Maximum costs are from the Report of the Interagency Task Force on Carbon Capture and Storage, pp 33, 34, 37 and 

44 (August 2010) (http://www.epa.gov/climatechange/policy/ccs_task_force.html). The factors from the report are in 

dollars (USD) per tonne of CO2 processed, transported or stored and have been converted to dollars per ton. Per the 

report, the factors are based on the increased cost of electricity (COE; in $/kW-h) of an “energy-generating system, 

including all the costs over its lifetime; initial investment, operations, and maintenance, cost of fuel and cost of capital.”

4. The average costs factors were calculated as the arithmetic mean of the minimum and maximum factors for each of the 

CCS component system and for all

5. The length of the pipeline was the assumed distance to the closest potential geologic storage site, as identified by the 

University of Texas at Austin, Bureau of Economic Geology, Gulf Coast Carbon Center, available at 

<http://www.beg.utexas.edu/gccc/miocene/>. 

6. Cost estimates (for geologic storage of CO2) are limited to capital and operational costs, and do not include potential 

costs associated with long-term liability from Intergovernmental Panel on Climate Change (IPCC) Special Report, 

Carbon Dioxide Capture and Storage (New York: Cambridge University Press, 2005), p.44 

<http://www.ipcc.ch/pdf/special-reports/srccs/srccs_wholereport.pdf>