PREVENTION OF SIGNIFICANT DETERIORATION PERMIT 

FOR GREIENHOUSE GAS EMISSIONS 

ISSUED PURSUANT TO THE REQUIREMENTS AT 40 CFR § 52.21 

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION 6 

PSD PERMIT NlJMBER: PSD-TX-1012-GHG 

PERI\fITfEE: The City of Austin dba Austin Energy 

721 Barton Springs Road 

Austin, TX 78704 

FACILITY NAME: Sand Hill Energy Center 

FACILITY LOCATION: 1101 Fallwell Lane 

Del Valle, TX 78617 

Pursuant to the provisions of the Clei!m Air Act (CAA), Subchapter L Part C (42 U.S.C. Section 

7470, et. Seq.), and the Code ofFede:ral Regulations (CFR) Title 40, Section 52.21, and the 

Federal Implementation Plan at 40 CFR § 52.2305 (effective May I, 2011 and published at 76 

FR 25178), the U.S. Environmental Protection Agency, Region 6 is issuing a Prevention of 

Significant Deterioration (PSD) permit to the City of Austin dba Austin Energy (Austin Energy) 

for Greenhouse Gas (GHG) emissions. The Permit applies to the construction of an additional 

natural gas fired combined-cycle electric generating unit at the existing Sand Hill Energy Center 

(SHEC), located in Del Valle, Travis: County, Texas. 

Austin Energy is authorized to constmct a new natural gas fired combined cycle electric 

generating unit 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 this PSD permit in conjunction with the corresponding Texas 

Commission on Environmental Quality (TCEQ) PSD pennit No. PSD-TX-1012M2. Failure to 

comply with any condition or term s•;:t forth in this PSD Permit may result in enforcement action 

pursuant to Section 113 of the Clean Air Act (CAA). This PSD Permit does not relieve Austin 

Energy of the responsibility to comp.ly with any other applicable provisions of the CAA 

(including applicable implementing liegulations in 40 CFR Parts 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. l 5(b ), this PSD Permit becomes effective 30 days after the 

service of notice of this final decision unless review is requested on the pennit pursuant to 40 

CFR §124.19. 

-: ( -: ' dL 7::::- 'I fa'! /1 cf 

Wren Stenger, Director Date 

Multimedia Planning and Permitting Division 
The City of Austin dba Austin Energy, 

Sand Hill Energy Center (PSD-TX-48106-GHG) 

Prevention of Significant Deterioration Permit 

For Greenhouse Gas Emissions 

1I>raft Permit Conditions 

PROJECT DESCRIPTION 

The City of Austin dba Austin Energy (Austin Energy) is proposing to construct a new combined 

cycle electric generating unit at the Sand Hill Energy Center (SHEC) in Travis County, Texas. 

The existing SHEC is a natural gas-fired combined-cycle base load P-Ower generating station 

that currently operates in a 1 by l by 1 ( 1 x 1 x I) configuration (one combustion turbine, one 

heat recovery steam generator (HRSG) and one steam turbine) with a combustion turbine, 

(HRSG) equipped with duct burners:, and a steam turbine. The new combined-cycle electric 

generating facility includes a new combustion turbine (GE.7FA.04) and HRSG equipped with 

duct burners. The resulting new facility will be a natural gas-fired combined cycle generating 

unit in a 2 by 2 by 1(2x2 x 1) configuration (two combustion turbines, two HRSGs, and one 

steam turbine) that utilizes the existing non-modified steam turbine. Austin Energy retains the 

option to operate the existing or new facility in a 1 x 1 x 1 combined-cycle configuration, and 

with the addition of the new facility add the second option to operate the plant in a 2 x 2 x 1 

combined- cycle configuration. The proposed facility at the SHEC will generate an additional 

222 megawatts (MW) of gross electrical power. The additional facility at the SHEC will consist 

of the following sources ofGHG emissions: 

• One natural gas-fired combustion turbine (GE.7FA.04). The combustion turbine is 

equipped with a heat recovery steam generator (HRSG) and duct burners, dry low-NOx 

(DLN) combustion system, and selective catalytic reduction (SCR); 

• Natural gas fugitive emission sources; and 

• Electrical equipment insulated with sulfur hexafluoride (SF6) 

EQUIPMENT LIST 

The following devices are subject to this GHG PSD permit. 

FIN/EPN Description 

l Natural Gas-Fin!<! Combined Cycle Combustion Twbine (Combustion Units). 

SH8 The combustion turbine is equipped with a heat recovery steam generator 

(HR.SG) with duct burners and selective catalytic reduction (SCR). 

SF6-FUG SF6 Insulated Elec:trical Equipment (i.e., circuit breakers) with 59 lb SF6 

capacity. 

MS-FUG Combined Cycle natural gas meter skid fugitives unit 8 

PB-FUG Combined Cycle Power Block fugitives unit 8 

2 
I. GENERAL PERMIT CONI>ITIONS 

A. PERMIT EXPIRATION 

As provided in 40 CFR §52.21(r), this PSD Pennit shall become invalid if construction: 

1. is not commenced (as defined in 40 CFR §52.2l(b)(9)) within 18 months after the 

approval takes effect~ or 

2. is discontinued for a period olf 18 months or more; or 

3. is not completed within a reasonable time. 

Pursuant to 40 CFR §52.21 (r), EPA may extend the 18-month period upon a written satisfactory 

showing that an extension is justified. 

B. PERMIT NOTIFICATION REQUIREMENTS 

Pennittee shall notify EPA Region 6 in writing or by electronic mail of the: 

I. date construction is commenced, postmarked within 30 days of such date; 

2. actual date of initial startup, as defined in 40 CFR §60.2, postmarked within 15 days of 

such ~ and 

3. date upon which initial perfo1rmance tests will commence, in accordance with the 

provisions of Section VI, postmarked not less than 30 days prior to such date. 

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

pursuant to Condition VI.C. 

C. FACILITY OPERATION 

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

extent practicable, maintain and ope1rate 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 and maintenance procedures are being 

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

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

D. MALFUNCTION REPORTING 

1. Permittee shall notify EPA by mail within 48 hours following the discovery of any failure 

3 
of air pollution control equipment, process equipment, or of a process to operate in a 

normal manner, which results in an increase in GHG emissions above the allowable 

emission limits stated in Sections Il and III of this permit. 

2. Within 10 days of the restoration of normal operations after any failure described in 

I.D. L, 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 of time over which emissions were increased due to the 

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

alJowed in Section II and ID,. and the methods utilized to mitigate emissions and restore 

normal operations 

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

constitute a defense to any vi1olation 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; 

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

kept under the terms and conditions of this PSD Permit; 

3. to inspect any equipment, op1eration, or method subject to requirements in this PSD 

Permit; and, 

4. to sample materials and emis:sions from the source(s). 

F. TRANSFER OF 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 days of the letter signature. 

G. SEVERABILITY 

The provisions of this PSD Permit ar1e severable, and, if any provision of the PSD Permit is held 

invalid, the remainder of this PSD Pe:rmit shall not be affected. 

4 
H. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER 

ENVIRONMENTAL LA W:S 

Permittee shaIJ construct this project in compliance with this PSD Permit, the application on 

which this permit is based, the TCEQ PSD Permit PSD-TX-48106 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 ABBD:VIATIONS 

A VO Auditory, Visual, and Olfactory _______ _, *"'-T~-~~~Bm"7\ ailable C011t1ol Technology 

CAA Clean Air Act 

CC Carbon Content 

CCS Carbon Capture a.'ld Sequestration 

CEMS Continuous Emissions Monitoring System 

CFR Code of Federal Regulations 

CH4 Metha:ne 

C02 Carbon Dioxide 

CC>ie Carbon Dioxide Equivalent 

CT Combustion Turbine 

EF Emission Factor 

EPN Emission Point Number 

FIN Facility Identification Number 

FR Federa~ Register 

GCV Gross Calorific Value 

GHG Greenhouse Gas 

GWP Globall Warming Potential 

HHV High Heating Value 

lb Pound 

LD AR Leak Detection and Repair 

.MMBtu Million British Thermal Units 

MSS Maint1;mance, Start-up and Shutdown 

N20 Nitrous Oxides 

NSPS New Source Performance Standards 

02 Oxyg{m 

PSD Prevention of Significant Deterioration 

QA/QC Quality Assurance and/or Quality Control 

RATA Relative Accuracy Test Audit 

TAC Texas Administrative Code 

TCEQ Texas Commission on Environmental Quality 

TOC Total Organic Carbon 

TPY Tons per Year 

USC United States Code 

VOC Volatile Organic Compound 

5 
II. Annual Emission Limits 

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 electricity (BTU/kWh). Any out-put based 

emissions, in pounds ofC02 per megawatt hour (lbs/MWh) on a 365-day rolling average and 

annual emissions, in tons C02e per year (TPY) on a 365-day rolling total basis shall not exceed 

the following· 

Table t. Annual Emission Limits1 

GOG Mass Basis TPY FIN EPN Descriptio111 C02e2.3 BACT Requirements 

TPY 

C<h 1,460,3864 

930 lbs COi/MWh on a 

SH8 t"' 'I' Ttn Combustion. Ciit 2'1.s i,461,908 365-"~y rolling average 

;,n o Turbine basis. See pennit 

conditions ill.A. I. 

N10 2.84 

No 

C<h Numerical 

Limit No Implementation of A VO 

PB-FUG PB-FUG Natural Gas Establisheds Numerical Program. 

MS-FUG MS-FUG Fugitives No Limit See permit conditions 

CCL Numerical Establisheds ill.B.l. 

Limit 

Established5 

Electrical No No 

SF6-FUG SF6-FUG Equipment SF6 Numerical Numerical See permit conditions 

Limit Limit ill.B.2. through ITI.B.4. Fugitives Established6 Established6 

Totals' COz 1,460,386 

CIL 33 COze 

NzO 2.8 1,462,052 

SF6 0.00015 

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

2. The TPY emission limits specified in this table are not to be exceeded fort.his facility and include emissions 

from the facilit)- during all operations and mclude MSS activities. 

3. Global Warming Potentials (GWP): CH.i = 25. Ni()= 298, SF6=22,800 

4. The annual emissions limit for the combustion turbine is based on operating at maximwn duct burner firing for 

8, 760 hours per year. The annual emiss:ion limit includes emissions from MSS. 

5. Natural gas emissions from EPNs PB-Fl.JG and MS-FUG are estimated to be 5.64 TPY of CRi. 0. 13 TPY COi, 

and J 41 TPY CO:!e. The emission limit will be a design/work practice standard as specified in the permit. 

6. SF6 emissions from EPN SF6-FUG are ~stima ed to be 0.00015 TPY of SF6and 3 TPY COie. The emission 

limit will be a design/work practice standard as specified in the permit. 

7. The total emissions include the PfE for natural gas and electrical equipment fugitive emissions. These totals are 

given for infonnational purposes only and do not constitute emission limits. 

6 
m. SPECIAL PERMIT CONDITIONS 

A. Requirements for Combustion Turbine and Heat Recovery Steam Generator 

(HRSG) (EPN: SH8) 

1. Combustion Turbine 11JACT Emission Limits 

Table 2. BACT Emission Limits for Combustion Turbine on a 365 da rolling average 

Turbine Model 

Gross Heat Rate, with 

duct burner firing 

(Btu/kWh) (HHV)1 

Output Based 

Emission Limit (lbs 

COVMWh) gross 

with duct burning1 

1 These limits apply with and without duct burner firing and includes startup and shutdown. 

a. For facility operations in a 1 x 1 x 1 plant configuration operation, compliance 

with the output based emission limit shall be detennined by the following method. 

The C02 mass emission values shall be calculated over each operational hour of 

the compliance period and summed. The summed hourly COz mass emission 

values shall be divided by the summed hourly total gross electrical output. 

Compliance shall be demonstrated on a 365-day rolling average basis. 

b. For facility operations in a 2 x 2 x 1 plant configuration operation, compliance 

with the output based emission limit shall be determined as follows: 

1. The hourly gross electric output from the existing non-modified steam 

turbine shall be: apportioned based on either the measured steam load or 

measured heat input. A plan to demonstrate the apportionment of the gross 

electric output shall be submitted within 60 days after achieving the 

maximum prod:uction rate at which the affected facility will be operated, 

but not later thm1 180 days of the date of initial startup of the combustion 

turbine generator. 

11. The C02 mass emission values shall be calculated over each operational 

hour of the compliance period and summed. The summed hourly C02 mass 

emission value:s shall be divided by the combined sum of the hourly total 

gross electrical output from the steam turbine (as determined by the 

corresponding <apportionment calculations represented in the plan) and the 

total gross electrical load from the combustion turbine. Compliance shall 

be demonstrated on a 365-day rolling average basis. 

c. Within 60 days after achieving the maximum production rate at which the affected 

facility will be operated, but not later than 180 days of the date of initial startup of 

the combustion tu bim~ generators, the Permittee shall perform an initial emission 

7 
test for C02 and use emission factors from 40 CFR Part 98. The Permittee shall 

ensure that GHG emissions from the Combustion Turbine and Heat Recovery 

Steam \,enerator (HRSG) (EPN: SH8) into the atmosphere do not exceed the 

limits in lbs CO:JMW]h (gross) from Table 2 during the test. To determine 

compliance with the BACT emission limit, the Permittee shall calculate the 

emission rate based on the measured hourly energy output {MWh (gross)), when 

operating in a lxlxl configuration, while the combustion turbine is operating at or 

above 90% of its design capacity with duct burner firing, .and the results shall be 

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

combustion turbine do·es not meet the design emissions limit, then the Permittee 

shall remedy the combustion turbine's failure to meet the design emissions limit , 

will make corrections to the Combustion Turbine, and will only combust fuel to 

perform required tunimg and modifications necessary to demonstrate compliance. 

d. Upon initial demonstration that the combustion turbine complies with the emission 

limit via emission tests, the Perrnittee shall not exceed the combustion turbine 

gross heat rate Btu/kWh (lllIV) from Table 2 on a 365-day rolling average and 

shall not discharge or ·~ause the discharge of emissions into the atmosphere in 

excess of the limits in tons of C02e on a 365-day rolling total as listed in Table 

I.To determine this linnit, the Permittee shall calculate the average hourly heat 

input rate over the applicable compliance period consistent with equation F-20 and 

the procedure provided in 40 CFR Part 75, Appendix F § 5.5.2 and the measured 

gross hourly energy output for the month. 

2. Monitoring of Emissions for Combustion Turbine and Heat Recovery Steam 

Generator (HRSG) (J PN: SH8) 

a. Upon initial demonstration that the combustion turbine complies with the 

emissions limit via emission tests, the Perrnittee shall not discharge or cause the 

discharge of emissions from the Combustion Turbine or HRSG into the 

atmosphere in excess of the limits from Table I in tons of C02e on a 365-day 

rolling total basis, at all times including periods of startup and shutdown, To 

determine the amount of C02e, the Permittee shall calculate the amount of COi, 

CH4 and N20 in TPY based on the equation G-4 of 40 CFR 75, Appendix G and 

40 CFR Part 98, Appendix C on a 365-day rolling total basis. The TPY values are 

multiplied by the respective Global Warming Potentials (GWP) contained in the 

Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1 to calculate 

the amount of C02e emitted in Tons/hr for the operational day. The resulting 

C02e value is added tio the previous 365-day rolling total of C02e emissions. The 

Permittee shall determine compliance with the CH4 and N20 emissions limits 

8 
contained in Section 11[ using the default CRi and N20 emission factors contained 

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

b. As an alternative, the Permittee may install and operate a volumetric stack gas 

flow monitor and associated data acquisition and handling system in accordance 

with the C02 CEMS system provided in 40 CFR 75.JO(a)(3) and (a)(5). If a C02 

CEMS system is utili2:ed, the hourly C02 emission value shall be measured by 

installing and operatinig a volumetric stack gas flow monitor or calculating the 

volumetric stack gas flow by the procedures of 40 CFR Part 75, Appendix D and 

associated data acquisition and handling system in accordance with the COi 

CEMS system provid(~ in 40 CFR § 75.10. 

c. In accordance with 40 CFR Part 75, Appendix D and 40 CFR Part 60, the 

Permittee shall ensure, that all required fuel flow meters are installed, a periodic 

schedule for gross calorific value (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 commences commercial operation (as 

defined in 40 CFR § 72.2). 

d. The 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. 

e. The Permittee shall meet the appropriate quality assurance requirements specified 

in 40 CFR Part 75, Appendixes D and F and 40 CFR Part 60 for the fuel flow 

meter and/or C02 emission monitoring system. 

3. Work Practice and Ope:ratiooal Requirements for Combustion Turbine and 

Heat Recovery Steam Generator (HRSG) (EPN: SH8) 

a. The combined cycle c;ombustion turbine and duct burners are limited to burning 

only pipeline natural gas. 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 GCV for a period of five years. 

Upon request, the Permittee shall provide a sample and/or analysis of the GVC for 

the fuel fired in the combustion turbine and/or duct burners or shall allow a 

sample to be taken by EPA for analysis. 

b. The flow rate of the fiJel combusted in combustion turbine and duct burners shall 

be measured and recorded using an inline flow meter and automatically record the 

data with a data acquisition and handling system. The steam load and/or heat 

9 
input to the steam turbine shall also be measured and recorded. 

c. Pennittee shall measure and record the gross energy output (MWh (gross)) on an 

hourly basis. 

d. 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 

HRSG equipped at or below the emissions limits specified in this permit. 

e The Permittee shall perform an annual compliance test, at or above ninety percent 

{90%) of maximuml1oad operations for the atmospheric conditions which exist 

during testing, corrected to ISO conditions to demonstrate compliance with the 

proposed heat rate in Table 2. 

f On or after initial performance testing, Permittee shall use the combustion turbine, 

HRSG, and Plant-wide energy efficiency processes, work practices and designs as 

represented in the application. 

g. The Permittee shall minimize emissions during start-up and shutdown activities 

by operating and maintaining the facility and associated air pollution control 

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

practices, and protection of the facility. 

B. Requirements for Fugitive Emission Sources (EPNs: MS-FUG, PB-FUG and SF6-

FUG) 

1. The Permittee shall implement an auditory/visual/olfactory (AVO) method for 

detecting leaking from natural gas piping components, and make observations on a 

daily basis. 

2 . 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 insulated circuit breaker SF6 capacity exceeding 59 lbs. 

3. Permittee shall equip the circuit breakers with a low pressure alarm and a low 

pressure lockout. The SF'6 leak detection system shall be able to detect a leak of at 

least lib per year. 

4. Permittee shalJ 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 records 

relating to compliance with the Monitoring and Quality Assurance and Quality 

Control (QA/QC) procedures outlined in 40 CFR 98.304. 

10 
IV. RECORDKEEPING AND 1lEPORTING 

1. In order to demonstrate compniance with the GHG emission limits in Table 1, the 

Permittee will monitor the foHowing 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 e:quipment 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 finng rate); and 

c. Annual fuel sampling of natural gas for gross calorific value (GCV). 

2. Permittee shall implement an AVO program and keep records of the monitoring resuits, 

as well as the repair and maintenance records. 

3. Permittee shall maintain all records, data, measurements, reports, and documents related 

to the operation of the facility, including, but not limited to, the following: all records or 

reports pertaining to significant maintenance performed on any system or device at the 

facility; duration of startup, slhutdown; the initial startup period for the emission units; 

pollution control units, malfunctions; all records relating to performance tests, 

calibrations, checks, and monitoring of combustion equipment; duration of an inoperative 

monitoring device and emission units with the required corresponding emission data; and 

all other information required! by this permit recorded in a permanent form suitable for 

inspection. The records must be retained for not less than five years following the date of 

such measurements, maintenance, reports, and/or records. 

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

certification tests and monitoring and compliance information required by this permit. 

5. Perrnittee shall maintain records and submit a written report of all GHG excess emissions 

to EPA semi-annually, except when: more frequent reporting is specifically required by 

an applicable subpart; or the Administrator or authorized representative, on a case-bycase basis, determines that more frequent reporting is necessary to accurately assess the 

compliance status of the sow·ce. The report is due on the 30th day following the end of 

each semi-annual period and shall include the following: 

a. Time intervals, data and magnitude of the excess emissions, the nature and cause (if 

known), corrective actions taken and preventive measures adopted; 

b. Applicable time and da.te of each period during which the monitoring equipment 

was inoperative (monitoring down-time); 

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

11 
excess emissions occwrred or when the monitoring equipment has not been 

inoperative, repaired or adjusted; and 

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

activities. 

6. Excess emissions shall be de:fined as any period in which the facility emissions exceed a 

maximum emission limit set forth in this permit. 

7. 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. 

8. All records required by this J>SD Pennit shaJJ he retained and remain accessible for n~oti.-----­

less than 5 years following the date of such measurements, maintenance, and reporting. 

V. SHAKEDOWN PERIODS 

The combustion turbine emission limits and requirements in conditions II., Ill.A. l ., and ID.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 Pennittee conducts operational and 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 

performance testing as specified in 40 CFR § 60.8. The requirements of special condition I.C. of 

this permit shall apply at all times. 

VL PERFORMANCE TESTING 

A. The Permittee shall perform staclk sampling and other testing to establish the actual pattern 

and quantities of air contaminants being emitted into the atmosphere from the stack of the 

Combustion Turbine and HRSG (SH8) 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. 

1. Multiply the C02 hourly average emission rate determined under maximum 

operating test conditions by 8, 760 hours for the combustion turbine. 

2. If the above calculated C 02 emission total does not exceed the tons per year (TPY) 

specified on Table 1, no compliance strategy needs to be developed. 

If the above calculated C02 emission total exceeds the tons per year (TPY) specified 

in Table 1, the facility shall: 

a. Document the potential to exceed in the test report~ and 

b. Explain within the report how the facility will assure compliance with the C02 

emission limit listed in Table 1. 

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B. Within 60 days after achieving the maximum production rate at which the affected facility 

will be operated, but not later than 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 m:ay be required by TCEQ or EPA. 

C. Permittee shall submit a performance test protocol to EPA no later than 30 days prior to the 

test to allow review of the test pl:an and to arrange for an EPA observer to be present at the 

test. The performance test shall be conducted in accordance with the submitted protocol, and 

any changes required by EPA. 

D. 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 or 

above their maximum firing rate within the mechanical limits of the equipment for the 

atmospheric conditions which exists during the performance test while the turbine is 

operating as close to base load as possible. The tested turbine load shall be identified in the 

sampling report. The permit hold!er shall present in the performance test protocol the manner 

in which stack sampling will be •~xecuted in order to demonstrate compliance with the 

emissions limits contained in Section Il. 

E. Air emissions from the 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 that will be sampled and analyzed while 

at the minimum load include (but are not limited to) C02. 

F. Performance tests must be condUlcted 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. 

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

follows: 

1. Sampling ports adequatu for test methods applicable to this facility, 

2. Safe sampling platform(s), 

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

4. Utilities for sampling and testing equipment. 

H. 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 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. 

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Vll. Agency Notifications 

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

permit information to: 

Multimedia Planning and Permitting Division 

EPA Region6 

1445 Ross Avenue (6 PD·R) 

Dallas, TX 75202 

Email: Group R6AirPermits(@EPAgov 

Permittee shall submit a copy of all c:ompliance and enforcement correspondence as required by 

this Approval to Construct to: 

Compliance Assurance and Enforcement Division 

EPA Region 6 

1445 Ross Avenue (6EN) 

Dallas, TX 75202 

14 
TRC Environmental Corporation | The City of Austin dba Austin Energy © 2011 RMT, Inc.

All Rights Reserved

Final

505 EAST HUNTLAND DRIVE, SUITE 250, AUSTIN, TEXAS 78752 ● 512.329.6080 PHONE ● 512.329.8750 FAX ● WWW.TRCSOLUTIONS.COM

Prevention of Significant Deterioration 

Greenhouse Gas Permit Application 

Sand Hill Energy Center 

Del Valle, Travis County, Texas

September 2013 

Prepared For

The City of Austin dba Austin Energy

Submitted to:

U.S. Environmental Protection Agency

Region VI

Multimedia Planning and Permitting

Division

Fountain Place 12th Floor, Suite 1200

1445 Ross Avenue

Dallas, Texas 75202

Submitted by:

The City of Austin dba Austin Energy

721 Barton Springs Rd

Austin, Texas 78704
TRC Environmental Corporation | The City of Austin dba Austin Energy i

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Table of Contents 

List of Acronyms .......................................................................................................................................iii

Executive Summary...................................................................................................................................v

1. Introduction...................................................................................................................................1‐1

2. Project Description .......................................................................................................................2‐1

2.1 Need for the Facility and Conceptual Design................................................................2‐1

2.2 The Existing SHEC Facility...............................................................................................2‐1

2.3 The Proposed Project.........................................................................................................2‐3

2.4 Process Description............................................................................................................2‐7

2.4.1 Emission Control Equipment for the Combined Cycle Unit ..........................2‐8

2.5 Natural Gas Piping ............................................................................................................2‐8

2.6 Electrical Equipment Insulated with Sulfur Hexafluoride (SF6) .................................2‐8

3. Greenhouse Gas Emission Calculations....................................................................................3‐1

3.1 GHG Emissions from Combined Cycle Combustion Turbine.....................................3‐1

3.2 GHG Emissions from Natural Gas Piping Fugitives and Natural Gas Maintenance

and Startup/Shutdown Related Releases........................................................................3‐1

3.3 GHG Emissions from Electrical Equipment Insulated with SF6..................................3‐4

3.4 Total Project GHG Emissions ...........................................................................................3‐4

4. Prevention of  Significant Deterioration Applicability............................................................4‐1

4.1 Applicability .......................................................................................................................4‐1

4.2 Requirements ......................................................................................................................4‐1

4.2.1 Best Available Control Technology....................................................................4‐1

4.2.2 Air Quality Impact Analysis................................................................................4‐2

4.2.3 GHG Preconstruction Monitoring ......................................................................4‐2

4.2.4 Additional Impacts Analysis ...............................................................................4‐2

4.2.5 Other Required Analyses.....................................................................................4‐3

5. GHG Control Technology Analysis ...........................................................................................5‐1

5.1 Overview.............................................................................................................................5‐1

5.2 BACT Analysis for Greenhouse Gas (GHG) Emissions ...............................................5‐2

5.2.1 BACT Analysis for Combined Cycle Unit.........................................................5‐2
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5.2.2 BACT Analysis for Natural Gas Fugitives.......................................................5‐17

5.2.3 BACT Analysis for SF6 Insulated Electrical Equipment ................................5‐21

List of Tables

Table 3‐1 Annual GHG Emissions – Combustion Turbine Combined Cycle Unit.......3‐2

Table 3‐2 Annual GHG Emission Calculations – Natural Gas Piping............................3‐3

Table 3‐3 GHG Emission Calculations – Electrical Equipment Insulated with SF6 ......3‐5

Table 3‐4 Annual GHG Emissions ‐ Total Project..............................................................3‐6

Table 5‐1 Summary of GHG Permit Emission Limits for Combined Cycle Units ........5‐3

Table 5‐2 CCS Cost Analysis for Combined Cycle Unit.................................................5‐11

Table 5‐3 Estimated Performance Combustion Turbine 7FA.04 ...................................5‐14

Table 5‐4 Proposed Greenhouse Gas BACT Limits for SH8 (Simple Cycle Output

Basis) .....................................................................................................................5‐19

List of Figures

Figure 1‐1 Site Location Map..................................................................................................1‐2

Figure 1‐2 Facility Plot Plan – Existing and Proposed Equipment...................................1‐3

Figure 2‐1 Plot Plan..................................................................................................................2‐4

Figure 2‐2 Process Flow Diagram for New Combined Cycle Unit...................................2‐5

Figure 2‐3 Process Flow Diagram for Existing + New Combined Cycle Unit.................2‐6

Figure 5‐1 Potential Geologic CO2 Storage Sites in Texas, Louisiana, and Mississippi.5‐8

List of Appendices

Appendix A TCEQ Applicable Forms

TCEQ Form PI‐1 General Application

TCEQ Table 1(a) Emission Point Summary

Appendix B Emissions Calculations and Documentation

Appendix C BACT Analysis Calculations and Documentation
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List of Acronyms 

AVO audio/visual/olfactory

BACT Best Available Control Technology

Btu British thermal unit

CAAA Clean Air Act Amendments

CCS carbon capture and storage

CFR Code of Federal Regulations

CO carbon monoxide

CO2 carbon dioxide

CTG combustion turbine generator

DB duct burner

DOE US Department of Energy

DLN dry low‐NOx

F Fahrenheit

FIP Federal Implementation Plan

Ft feet

GE General Electric

GHG greenhouse gas

GWP global warming potential

H2O water

HAP Hazardous Air Pollutant

HHV higher heating value

HRSG heat recovery steam generator

HP high pressure

IP intermediate pressure

K degrees on the Kelvin scale

kW kilowatt

LAER Lowest Achievable Emission Rate

lb/hr pounds per hour

lb/MMBtu pounds per million British thermal units
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LHV

LP

lower heating value

low pressure

MACT Maximum Achievable Control Technology

MMBtu/hr million British thermal units per hour

MW

NETL

Megawatt

National Energy Technology Laboratory

NOx nitrogen oxides

NSPS New Source Performance Standards

NSR New Source Review

NTIS National Institute of Standards and Technology

O2 oxygen

ppmvd parts per million by volume, dry basis

PNG pipeline natural gas

PSD Prevention of Significant Deterioration

PTE potential to emit

RACT Reasonably Available Control Technology

RBLC RACT/BACT/LAER Clearinghouse

SAR South Austin Regional

SHEC Sand Hill Energy Center

scf standard cubic feet

SCR Selective Catalytic Reduction

SER Significant Emission Rate

SIP State Implementation Plan

STG steam turbine generator

TCEQ Texas Commission on Environmental Quality

Tpy tons per year

USEPA United States Environmental Protection Agency

VOC volatile organic compounds
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Executive Summary 

The City of Austin (dba Austin Energy) is proposing to build‐out the Sand Hill Energy Center

(SHEC) located in Del Valle, Texas by adding a new pipeline natural gas (PNG) fired

combustion turbine generator (CTG) and heat recovery steam generator (HRSG) with natural

gas fired duct burners to the existing combined cycle electricity generating unit at SHEC.  The

new unit will share the existing 189 MW steam turbine generator (STG) with the combustion

turbine and HRSG associated with existing combined cycle unit.  The proposed new

combustion turbine generator is an updated version of the same General Electric (GE) Model

7FA unit currently in operation as part of the combined cycle unit.   

Because the SHEC facility is an existing major source of greenhouse gas (GHG) emissions and

the project increases facility GHG emissions by more than 75,000 tons per year on a carbon

dioxide equivalent (CO2e) basis, the project is also subject to prevention of significant

deterioration (PSD) new source review program for GHG emissions.  EPA is authorized under a

Federal Implementation Plan (FIP) to issue PSD permits in Texas for GHG sources until Texas

submits the required SIP revision for GHG permitting and it is approved by EPA.  The key

element of PSD review for GHG is the best available control technology (BACT) analysis.

Sources of GHG emissions include the combustion turbine and duct burner combustion

emissions of carbon dioxide (CO2), nitrous oxide (N2O) and methane (CH4), the natural gas

piping component leaks and other releases of natural gas (including CH4) and the electric circuit

breaker sulfur hexafluoride (SF6) leak emissions.  The latter two sources are minimal compared

to the combined cycle emissions and BACT is addressed for these with a combination of

effective design and work practices.

The BACT analysis for the proposed new combined cycle unit’s GHG emissions evaluates two

applicable options: carbon capture and sequestration (CCS) and energy efficiency measures.  As

with other recent GHG BACT analyses for permits for similar units, it was determined that the

CCS technology currently has significant technical hurdles but may also ruled out based on

poor cost‐effectiveness, with the capital cost of carbon capture, transport and storage exceeding

the capital cost of the proposed project.  As such, electrical generation efficiency measures are

proposed as BACT for the project GHG emissions.  This BACT technology determination is

supported based on the low‐carbon pipeline natural gas fuel, and the very efficient combustion

turbine combined cycle technology, which compares favorably to similar units.

Consistent with recent GHG PSD permits for natural gas‐fired combined cycle projects, the

proposed BACT emission limits include and output‐based GHG limit (ton CO2e/MWh), a heat
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rate limit (Btu/kWh) and an overall GHG emissions cap that takes into account start‐up, part‐

load and duct burner emissions.  Because of facility‐specific design considerations, specifically

the proposed CTG, HRSG and duct burner sharing an STG with another CTG, HRSG and duct

burner that are not subject to GHG BACT, the proposed GHG emission limits must take a

slightly different form that those for other brand new 2x1 combined cycle units.  A typical

combined cycle unit that is designed and built with one or more CTGs and STGs is amenable to

a limit that includes the electric generation output of both the CTGs and STGs, in order to “take

credit” for the excellent efficiency associated with this combined cycle technology and show

very low GHG ton/MWh limits and Btu/kWh heat rate limits.  Because of the shared STG in this

“2 on 1” configuration, it is not possible to determine how much of the output generated by the

steam turbine is attributable to the new CTG and HRSG versus the existing CTG and HRSG.  As

such, Austin Energy is proposing that the new unit’s GHG limits be based on the output of the

combustion turbine alone.  As such, the proposed limits are greater in terms of the proposed

ton/MWh and Btu/kWh limits, but are shown to be comparable to GHG BACT combined cycle

limits (based on CTG and STG output) in recently issued permits.
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Section 1 

Introduction 

The City of Austin (dba Austin Energy) is proposing to build‐out the Sand Hill Energy Center

(SHEC) located in Del Valle, Travis County, Texas by adding to the existing combined cycle unit

at the facility.  The existing combined cycle unit at the SHEC was conceived and constructed to

include this new unit when Austin’s energy demands grew to the point where additional

generating capacity would be required.  The proposed project will add a new pipeline natural

gas (PNG) fired combustion turbine and heat recovery steam generator (HRSG) to the existing

combined cycle electricity generating unit at SHEC.  A site location map is included as

Figure 1‐1 and a plot plan of the existing and proposed facility is presented as Figure 1‐2.   

Construction will include the installation of a General Electric (GE) model 7FA.04 combustion

turbine and a heat recovery steam generator (HRSG) with natural gas fired duct burners (the

Project).  The new combustion turbine generator (CTG) is rated at 173.9 MW at base load at

68°F.  The new combined cycle unit will share an existing 189 MW steam turbine generator

(STG) which is part of the existing combined cycle unit.  Proposed emission controls technology

includes dry low‐NOx (DLN) combustion and selective catalytic reduction (SCR) for nitrogen

oxides (NOx) emission control and an oxidation catalyst to reduce emissions of carbon

monoxide (CO) and volatile organic compounds (VOC).   

The City of Austin will submit an amendment application to the Texas Commission on

Environmental Quality (TCEQ) to authorize the addition of this second combustion turbine and

HRSG at its SHEC facility.  On June 3, 2010, the U.S. Environmental Protection Agency (EPA)

published final rules for permitting sources of greenhouse gases (GHGs) under the prevention

of significant deterioration (PSD) and Title V air permitting programs, known as the GHG

Tailoring Rule.1  After July 1, 2011, new sources having the potential to emit more than 100,000

tons per year of GHGs and modifications increasing GHG emissions more than 75,000 tons per

year on a carbon dioxide equivalent (CO2e) basis at existing major sources are subject to GHG

PSD review, regardless of whether PSD is triggered for other pollutants.  The existing SHEC

facility is an existing PSD major source based on potential criteria pollutant emissions greater

than 250 tons per year and GHG emissions greater than 100,000 tons per year of CO2e.

                                                     

1 75 FR 31514 (June 3, 2010)
DRAWN BY:

APPROVED BY:

PROJECT NO:

FILE NO.

DATE:

& 0 2,000

FEET

1 " = 2,000 '

1:24,000

E:\CityofAustinTX\2012_196475\196475-002am1.mxd Printed By: jpapez on 9/7/2012, 16:23:23 PM

10011 Meadowglen Lane

Houston, TX 77042

Phone: 713.244.1000

TRC - GIS

0 2.5 5 Miles

SOURCE:

ESRI ONLINE BING AERIAL, AND

DELORME WORLD BASE MAP

SITE LOCATION

Nearest School

Del Valle Opportunity Center

(~1.1 Miles From Property)

PROPERTY LINE

MAP EXTENT

PAPEZ J

196475-001-002

196475-002am1.mxd

STANKO E

FIGURE 1-1

SITE LOCATION MAP

SAND HILL ENERGY CENTER

DEL VALLE, TRAVIS COUNTY, TEXAS

AUGUST 2013

A

1 MILE

3000 FT.

LEGEND

PROPERTY BOUNDARY

× NEAREST RESIDENCE

SAND HILL ENERGY Nearest Residence

CENTER (SHEC)

SOUTH AUSTIN REGIONAL (SAR)

WASTE WATER TREATMENT PLANT
0 25 50 100 APPROXIMATE SCALE - METERS 633,337 mE BENCHMARK 3,342,624 mN STORAGE AMMONIA EQUIPMENT PROPOSED HOUSTON, TEXAS 77042 713-244-1000 SUITE 100 10011 MEADOWGLEN LANE SHEET TITLE PROJECT FACILITY PLOT PLAN Figure 1-2 SAND HILL ENERGY CENTER (SHEC) Del Valle, Travis County, Texas DRAWN BY: O.F. APPROVED BY: E.S. PROJ. No: 196475.1000.0000 DATE: AUGUST 2013 WITH EXISTING AND PROPOSED EQUIPMENT
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On December 23, 2010, EPA issued a Federal Implementation Plan (FIP) authorizing EPA to

issue PSD permits in Texas for GHG sources until Texas submits the required SIP revision for

GHG permitting and it is approved by EPA.2

The SHEC proposed Project for the addition of a second combined cycle combustion turbine

triggers PSD review for GHG regulated pollutants because the project will increase GHG

emissions by more than 75,000 tons/year and the site is an existing major PSD source.  This

application is being submitted to EPA pursuant to its regulatory authority under the FIP.  

Included in this application is a project description including a description of current

operations, GHG emissions calculations, a PSD applicability determination and a GHG Best

Available Control Technology (BACT) analysis.  TCEQ permit application forms, emission

calculations, and BACT analysis documentation are appended to this document.

                                                     

2 75 FR 81874 (December 29, 2010)
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Section 2 

Project Description 

2.1 Need for the Facility and Conceptual Design 

Austin Energy requires additional generation to support a fast growing population and job

growth in both the City of Austin and Travis County.  Austin has been the fastest growing city

in the country for the past three years.  Since 2009 the population of Travis County has

increased by 98,415 individuals, an increase of almost 10%3.  Current projections indicate that

county population is expected to continue to increase at this rate adding another 102,000 people

by 20174.  Travis County has added 67,186 new jobs since 20095 and this trend is expected to

continue and keep pace with the projected population growth.  The existing STG at the SHEC

was sized to allow for population growth and increased power demands by accommodating the

installation of an additional combustion turbine and HRSG.

Annual residential electricity consumption in Texas for 2011 was 145,654,228 MWh, an increase

of 15,857,077 MWh (or 10.9%) from just two years earlier6.  The population of the state increased

by 892,379 individuals over this same two‐year period, growing from 24,782,302 to 25,674,681 as

of July 1, 2011 7.   

Based on the current average residential electricity usage per person of 5.673 MWh/yr/person

for Texas, and a projected population increase in Travis County of over 200,000 persons from

2009 to 2017, the residential electricity demand is projected to increase by 1,136,968 MWh/year.  

The maximum additional capacity of the new unit is approximately 206 MW and this translates

to 1,443,648 MWh annually based on a capacity factor of 80%.  Therefore, the projected increase

in local residential demand alone (over an eight‐year period) represents 79% of the additional

power available from the project.

2.2 The Existing SHEC Facility 

The existing facility equipment, operations and emissions are regulated under Prevention of

Significant Deterioration (PSD) permit No PSDTX1012M1 and Texas Commission on

Environmental Quality (TCEQ) Permit No. 48106.  The current generating units include six

                                                     

3 Perryman Group

4 Population estimates from Perryman Group

5 Travis County employment from the Texas Workforce Commission

6 Energy Information Administration

7 US Census
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natural gas fired GE LM6000 aero derivative design simple cycle combustion turbines and the

existing natural gas fired GE Frame 7FA combustion turbine combined cycle unit including

natural gas fired duct burners, a HRSG and a steam turbine generator.  The six simple cycle

units are designated in the permit as EPN’s SH1, SH2, SH3, SH4, SH6 and SH7.  The first four

units (SH1‐4) commenced operation in 2001 and the two newer units (SH6 and SH7)

commenced operation in 2010.  These units have a nominal output rating of 50 MW each and

serve as “peaking” units that start up to help meet demand during peak (higher) periods.  The

LM6000 turbines utilize GE’s spray inter‐cooled turbine (Sprint) design and power

augmentation and include water injection and SCR for NOx control.

The existing combined cycle unit commenced operation in 2004 and is designated in the TCEQ

PSD permit as EPN SH5 and has a GE 7FA.03 combustion turbine – a previous version of the

7FA model.  The turbine is equipped with dry low NOX (DLN) (model DLN2.6) combustors.  Its

HRSG is equipped with natural gas fired duct burners and SCR.  The steam turbine generator

for this unit was sized to accommodate the addition of a second similarly sized combustion

turbine, with a space immediately adjacent to the southeast of the SH5 unit for the proposed

SH8 unit, as shown in the plot plan in Figure 1‐2.  The current combined cycle unit is a one‐on‐

one (1 x 1) configuration (one CTG with HRSG and one STG), but following the addition of the

proposed new turbine and HRSG it will be a 2 x 1 configuration (two CTGs/HRSGs and one

STG).  The present combustion turbine has a nominal rated output of 164 MW and the steam

turbine generator currently produces up to 157 MW but will be capable of up to 189 MW output

with the addition of the proposed second combustion turbine.  As such, the maximum

combined generating output of the combined cycle unit will increase from 321 MW for the

existing 1 x 1 configuration to 527 MW for the proposed 2 x 1 configuration.  The STG was

originally sized for the planned build‐out to a 2 x 1 configuration.

The existing cooling tower was sized for the full STG capacity in the 2 x 1 configuration, so no

new cooling tower capacity is needed.  Saturated steam from the STG is condensed prior to

being recirculated along with makeup water to the HRSG for reheating.  Condenser cooling is

provided by circulating water that is in turn cooled by ambient air in the direct‐contact

mechanical draft cooling tower.  The water that is used in the cooling tower makeup is

reclaimed water that is treated onsite.  The reclaimed water is obtained from the adjoining

South Austin Regional (SAR) wastewater treatment plant.

Ancillary equipment includes two existing aqueous ammonia storage tanks (19% aqueous

ammonia solution) that store the SCR reagent for the units.  One aqueous ammonia tank stores

SCR reagent for all six simple cycle turbines.  The other tank stores ammonia solution for the

combined cycle unit and would also serve the proposed new unit.  The aqueous ammonia goes

to a vaporizer unit and is then injected into the flue gas upstream of the SCR catalyst.  There are
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also four existing cooling towers and three natural gas fired inlet air heaters associated with the

simple cycle units and one existing cooling tower associated with the combined cycle unit.

2.3 The Proposed Project 

The new combined cycle unit is anticipated to operate as a base‐loaded unit, with up to 8,760

full‐load hours per year, but may also operate at partial loads, and/or start‐up and shutdown as

needed to meet electricity demand.  The duct burners for the new unit will be rated at 681.5

MMBtu/hr based on the higher heating value (HHV) of the pipeline natural gas fuel, and may

operate at full capacity for up to 8760 hours per year.  The new combined cycle turbine is

expected to start‐up numerous times per year.

As described above, the new combustion turbine and HRSG will be located alongside the

existing GE 7FA.03 turbine that is presently operating in combined cycle mode in a 1 x 1

configuration with a single CTG/HRSG supplying steam to a single STG.  The existing STG is

sized such that it will be able to accommodate the build‐out with additional steam from the new

HRSG of the proposed GE 7FA.04 combustion turbine; thus the new configuration will be 2 x 1

with two CTGs/HRSGs supplying steam to one STG.

The proposed combustion turbine will utilize DLN combustors and SCR to control NOx

emissions.  Aqueous ammonia from the existing combined cycle ammonia storage tank will be

vaporized in a new ammonia vaporizer dedicated to the SCR for the proposed unit.  The

proposed PNG‐fired duct burner will have a maximum heat input capacity of 681.5 MMBtu/hr

(HHV).  An oxidation catalyst will be located in the HRSG downstream of the duct burners and

upstream of the SCR ammonia injection grid and will control emissions of CO as well as VOC.   

GHG emissions from the proposed Project are discussed in detail in Section 3 of this

application.  A facility plot plan with existing and proposed equipment labeled is included as

Figure 2‐1.  A process flow diagram for the proposed unit is included as Figure 2‐2 and a

process flow diagram that shows integration of the proposed unit with the existing combined

cycle unit is included as Figure 2‐3.

There are no upstream or downstream impacts that would preclude addition of the proposed

unit to the SHEC, because the existing the plant natural gas piping and infrastructure is

designed to handle a second GE 7FA combustion turbine and duct burner.  The existing steam

turbine was designed to achieve full capacity with a second GE 7FA and HRSG, which would

improve the heat rate and thermal efficiency of the unit, providing more electricity per unit of

natural gas consumed.  The existing balance of plant equipment including circulating water,

condensate water, cooling water systems and the cooling tower were designed to support an

additional 7FA and HRSG.   
SH2 SC CTWR-1 SC CTWR-2 SC CTWR-3 0 25 50 100 APPROXIMATE SCALE - METERS SH-VNT-1A HTR-01 HTR-02 633,337 mE HTR-03 BENCHMARK 3,342,624 mN SH8 SH-TNK 49 SH-VNT-8A SH-VNT-8B CC MS FUG CC AMFUG STORAGE AMMONIA L E G E N D Existing Emission Point Number (EPN) Volume and Area Source Fugitives Proposed Emission Point Number (EPN) HTR-01 SH8HOUSTON, TEXAS 77042 713-244-1000 SUITE 100 10011 MEADOWGLEN LANE

SHEET TITLE PROJECT DRAWN BY: O.F. APPROVED BY: E.S. PROJ. No: 196475.1000.0000 DATE: AUGUST 2013 FACILITY PLOT PLAN Figure 2-1 SAND HILL ENERGY CENTER (SHEC) Del Valle, Travis County, Texas WITH EXISTING AND PROPOSED EQUIPMENT


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The existing condenser was constructed to support steam flow from a second HRSG operating

in bypass.  The plant switchyard is designed to support the electrical production of the

additional unit.  The plant access road is adequate to support construction and maintain

operation of the additional unit.  There will be small increases of natural gas fugitives from

piping associated with the proposed CTG.

The cooling tower, which uses water from the adjacent City of Austin waste water treatment

plant, will require additional make‐up water.  There would also be an increased volume of

process water and equipment cooling water usage.  There will also be small increases in

wastewater due to blow‐down from the new HRSG.

2.4 Process Description 

The GE 7FA.04 CTG consists of a compressor, burners, turbine and generator on a single shaft

as shown in Figure 2‐2.  Ambient air is introduced to the unit after inlet air filtration and (on

high temperature days) evaporative cooling, where an atomized mist of water is used to reduce

the air temperature, increasing air density and thus increasing the output of the turbine.  

Filtered (and cooled) air is compressed in the compressor section prior to combustion with PNG

in the combustion zone.  Products of combustion from the burner go to the turbine section

where they expand to rotate the turbine that drives the compressor and the generator.  The

exhaust gas exits the turbine at approximately 1100°F and is delivered to the HRSG via

ductwork.  The HRSG design is a 3‐pressure reheat design with high‐pressure (HP),

intermediate pressure (IP) and low pressure (LP) sections.  A duct burner may be used to

deliver additional heat to the HP section of the HRSG by combustion of pipeline natural gas

using residual oxygen in the flue gas.  Heat recovered in the HRSG will be utilized to produce

steam.   

High pressure steam generated within the HRSG will be used to drive the existing STG and

associated electrical generator attached to the same shaft.  After expansion in the steam turbine,

saturated steam goes to a condenser and is cooled back to water before being returned to the

HRSG for reuse.  The condenser is cooled via a closed cycle cooling water loop that uses a

cooling tower to maintain the circulating water temperature low enough for effective condenser

operation.  The mechanical induced draft cooling tower uses large fans to draw air into the

tower and across the path of the water so that direct contact and heat transfer is made between

the hot water and cooler air.  Some of the cooling water is lost via evaporation and drift

(droplets) and some additional water is lost to blow‐down (used to keep solids concentrations

from building up) and must be made up via introduction of make‐up water to the circulating

cooling water.  The cooling tower is equipped with mist eliminators to minimize drift and

conserve water.
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2.4.1 Emission Control Equipment for the Combined Cycle Unit 

The emission control technologies proposed for the combustion turbine and duct burner

exhaust gases include DLN combustors located within the combustion turbine and an SCR

system located within the HRSG to control NOx emissions.  An oxidation catalyst and efficient

combustion controls will be used to control emissions of CO and VOC.  Emissions of other

pollutants are minimized through the proposed use of low‐sulfur pipeline natural gas, as well

as efficient combustion in the combustion turbine and duct burner.

2.5 Natural Gas Piping 

Austin Energy is proposing to utilize PNG as the only fuel for the proposed combustion turbine

and duct burner.  The natural gas is delivered to the site via an existing natural gas pipeline that

serves the site.  Gas will be metered and piped to the new combustion turbine and duct burner.  

The natural gas is assumed to have a HHV of 1,022 Btu/standard cubic foot (scf) and a

maximum sulfur content of 0.23 grains per 100 scf.  Fugitive emissions from any new gas piping

components associated with the new combined cycle unit will include emissions of methane

and carbon dioxide, components of the natural gas.

2.6 Electrical Equipment Insulated with Sulfur Hexafluoride (SF6) 

Sulfur hexafluoride (SF6) is a fluorinated compound with an extremely stable molecular

structure.  The unique chemical properties of SF6 make it an efficient electrical insulator.  The

gas is used for electrical insulation, arc quenching and current interruption in high voltage

electrical equipment.  The capacity of the generator circuit breaker associated with the proposed

unit will be approximately 59 pounds SF6 is only used in sealed and safe systems which under

normal circumstances do not leak gas, however we account for potential emissions from this

equipment in this application to be conservative.

The proposed circuit breaker at the generator output will have a low pressure alarm and a low

pressure lockout.  The alarm will alert operating personnel of any leakage in the system and the

lockout prevents any operation of the breaker due to lack of “quenching and cooling” SF6 gas.
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Section 3 

Greenhouse Gas Emission Calculations 

3.1 GHG Emissions from Combined Cycle Combustion Turbine 

Combustion turbine performance and emissions are affected by ambient temperature and

turbine load.  Performance, exhaust and emission were developed for the combustion turbine

firing natural gas at three combustion turbine steady‐state loads (minimum, 75%, and 100%),

three different ambient temperatures (0 °F for worst‐case winter conditions, 68 °F for average

annual conditions, and 112 °F for worst‐case summer conditions), and for the effect of

evaporative cooling based on GE’s Gas Turbine Performance Simulation program.  Combined

cycle stack parameters and emissions that take into account HRSG duct firing are based on GE

Energy’s preliminary heat balance estimate for the S207FA.04 combined cycle integrated with

the existing unit for design ambient conditions of 68°F and 60% relative humidity at base load

with the evaporative cooling on and no duct burner.  Emissions estimates and stack parameters

for a total of 14 total combustion turbine steady‐state operating scenarios were extrapolated

from the design heat balance and presented in Appendix B, Table 1.

GHG emissions for the proposed combined cycle combustion turbine (see Table 3‐1) are

calculated in accordance with the procedures outlined in the Mandatory Greenhouse Gas

Reporting Rules.  Carbon dioxide (CO2), methane (CH4) and nitrous oxide (N2O) emissions are

calculated using the emission factors for natural gas combustion from Table C‐1 and Table C‐2

of 40 CFR Part 98.  The global warming potential factors used to calculate carbon dioxide

equivalent (CO2e) emissions are based on 40 CFR Part 98, Table A‐1.

3.2 GHG Emissions from Natural Gas Piping Fugitives and Natural Gas 

Maintenance and Startup/Shutdown Related Releases 

GHG emission calculations for natural gas piping component fugitive emissions (see Table 3‐2)

are based on emission factors from Table W‐1A of the Mandatory Greenhouse Gas Reporting

Rules.  The concentrations of CH4 and CO2 in the natural gas are based on a typical natural gas

analysis.  The global warming potential factors used to calculate CO2e emissions are based on

Table A‐1 of 40 CFR Part 98.

GHG emission calculations for releases of natural gas related to piping maintenance and turbine

startup/shutdowns are calculated using the same CH4 and CO2 concentrations as natural gas

piping fugitives.
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Table 3-1 

Annual GHG Emissions – Combustion Turbine Combined Cycle Unit 

Source 

Annual 

Heat Input1

(MMBtu/yr) Pollutant 

Emission Factor2 

(kg/MMBtu) 

GHG Mass 

Emissions 

(tons/yr) 

Global 

Warming 

Potential3

CO2e 

(tons/yr) 

Combustion 

turbine plus 

duct burner 

22,716,339 CO2 53.02 1,327,624 1 1,327,624 

CH4 1.0E-03 25.0 21 526 

N2O 1.0E-04 2.5 310 776 

GHG Totals 1,327,651 1,328,926 

CO2e +10% margin added for measurement error 1,461,818 

1. Annual heat input based on 8760 hours per year of operation of the combustion turbine at maximum heat input rate and with 

duct burner firing at 681.5 MMBtu/hr for 8760 hours per year

2

 CO2, CH4 and N2O emission factors based on Tables C-1 and C-2 of 40 CFR 98

3

 Global warming potential factors based on Table A-1 of 40 CFR 98

Example Calculations: 

Combustion	Turbine	Fuel	ሺbased	on	maximum	hourly	heat	input	rateሻ ൌ 	8760	

hr

yr

	x	1911.6	

MMBtu

hr

ൌ 	16,746,049	

MMBtu

yr

Duct	Burner	Fuel	ሺbased	on	maximum	hourly	heat	input	rateሻ ൌ 	8760	

hr

yr

	x	681.5	

MMBtu

hr

ൌ 	5,970,290	

MMBtu

yr

Total	Fuel	 ൌ 	16,746,049	

MMBtu

yr

൅ 	5,970,290	

MMBtu

yr

ൌ 	22,716,339	

MMBtu

yr

22,716,339	

MMBtu

hr x	 ൬53.02		 kg	CO2

MMBtu൰ 	x ൬2.2046	 lbkg൰x൬ ton2000	lb൰ x	 ൬1	 CO2eCO2 ൰ ൌ 	1,327,624	tons	CO2eyr

22,716,339	

MMBtu

hr x	 ൬0.001		 kg	CH4

MMBtu൰ 	x ൬2.2046 lbkg൰ 	x	 ൬ ton2000	lb൰ 	x	 ൬21	 CO2eCH4 ൰ ൌ 	526	tons	CO2eyr

22,716,339	

MMBtu

hr 	x	 ൬0.0001	 kg	N2O

MMBtu൰ 	x ൬2.2046	 lbkg൰ 	x	 ൬ ton2000	lb൰ 	x	 ൬310	 CO2eN2O ൰ ൌ 	776	 tons	CO2eyr
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Table 3-2 

Annual GHG Emission Calculations – Natural Gas Piping

Source 

Component 

Type Fluid State Count 

Emission 

Factor1 CO2

2 CH43 Total 

scf/hr/comp tons/yr tons/yr tons/yr 

Additional 

Natural Gas 

Fugitives 

Valves Gas/Vapor 194 0.121 0.093 4.017 

Flanges 161 0.017 0.011 0.468 

Relief Valve 35 0.193 0.027 1.156 

GHG Mass Based Emissions 0.130 5.642 

Global Warming Potential4 1 21 

CO2e Emissions 0.13 118.48 118.6 

1

 Emission factors from Table W-1A of 40 CFR Part 98 Mandatory Greenhouse Gas Reporting 

2

 CO2 emissions based on vol% CO2 in natural gas of 0.79% 

3

 CH4 emissions based on vol% CH4 in natural gas of 94.14% 

4

 Global warming potential based on Table A-1 of 40 CFR Part 98 Mandatory Greenhouse Gas Reporting 

Example Calculations: 

CO2 Emissions from Valves 

194	valves	x	 ൬0.121	 scf	gas

hr െ valve൰ 	x	 ൬0.0079	

scf	CO2

scf	gas ൰ 	x	 ൬

lb െ mole	CO2

385.5	scf	CO2 ൰ 	x	 ൬44	

lb	CO2

lb െ mole൰ 	x ൬8760

hr

yr൰

x	 ൬ ton

2000	lb൰ ൌ 	0.093	

ton	CO2

year

CH4 Emissions from Valves 

194	valves	x	 ൬0.121	 scf	gas

hr െ valve൰ 	x	 ൬0.9414	

scf	CH4

scf	gas ൰ 	x ൬

lb െ mole	CH4

385.5	scf	CH4 ൰ x	 ൬16	

lb	CH4

lb െ mole൰ x ൬8760	

hr

yr൰

x ൬ ton

2000	lb൰ ൌ 	4.017	

tons	CH4

year
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3.3 GHG Emissions from Electrical Equipment Insulated with SF6

SF6 emissions from the new generator circuit breaker associated with the proposed unit (see

Table 3‐3) are calculated using a predicted SF6 annual leak rate of 0.5% by weight per year, the

IEC standard for new equipment leakage8.  The global warming potential factors used to

calculate CO2e emissions are based on Table A‐1 of 40 CFR Part 98.   

3.4 Total Project GHG Emissions 

Table 3‐4 summarizes total Project GHG emissions based on the sum of CO2e emissions for the

proposed combined cycle unit, natural gas pipeline fugitives and SF6 emissions from the new

generator circuit breaker.  Emissions are speciated as CO2, CH4, N2O and SF6 and converted to

equivalent CO2e and summed to calculate total project GHG.

                                                     

8 International Electrotechnical Commission Standard 62271‐1, 2004.
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Table 3-3 

GHG Emission Calculations – Electrical Equipment Insulated with SF6 

Estimated Quantity of SF6 in New Equipment 59 pounds 

Annual Leak Rate 0.50% of quantity present 

Annual Emission Rate 0.295 lb/yr 

Annual SF6 Emissions 0.0001475 ton/yr of SF6 

Global Warming Potential Factor for SF6 23,900 

Annual CO2e Emissions 3.53 ton/yr of CO2e 

Example Calculation: 

59	lb	SF6	x	 ൬

0.50%

yr ൰ 	x ൬ ton

2000	lb൰ x	23,900	

CO2e

SF6 ൌ 	3.53	

tons	CO2e

yr

   
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Table 3-4 

Annual GHG Emissions - Total Project 

Source 

Annual Potential Emissions, tons/year 

CO2 CH4 N2O SF6 GHG, CO2e 

Combined Cycle Unit (with 10% margin) 1,460,386 27.5 2.8 0 1,461,818 

Natural Gas Pipeline Fugitives 0.13 5.64 0 0 118.6 

Electrical Equipment Leaks 0 0 0 0.00015 3.53 

Total Project 1,460,386 33.2 2.8 0.00015 1,461,941 
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Section 4 

Prevention of 

Significant Deterioration Applicability 

4.1 Applicability 

The existing Sand Hill Energy Center is an existing major stationary source as defined under the

Clean Air Act.  PSD applies to GHG emissions from a proposed modification to an existing

major source if the following is true:

 The emissions increase and the net emissions increase of GHGs from the modification

would be equal to or greater than 75,000 tons per year on a CO2e basis and greater than

zero tons per year on a mass basis.

Because the proposed Project’s net emissions increase of GHG is greater than 75,000 ton/year of

CO2e (see Table 3‐4), PSD review is triggered for GHG emissions.  The emissions netting

analysis is documented on the TCEQ PSD netting tables (Table 1F and 2F) included in

Appendix A.   

4.2 Requirements 

The PSD regulations state that facilities subject to PSD review must perform an air quality

analysis (which can include atmospheric dispersion modeling and preconstruction ambient air

quality monitoring), and BACT analysis for those pollutants that exceed the pollutant‐specific

significant emission rates (SERs) identified in the regulations as well as an additional impacts

analysis that examines the impacts of air emissions from the project on visibility, soils and

vegetation.   

4.2.1 Best Available Control Technology 

The proposed Project must utilize BACT controls for pollutants subject to PSD from each piece

of new equipment.  BACT is defined as the optimum level of control applied to pollutant

emissions based upon consideration of energy, economic and environmental factors.  In a BACT

analysis, the energy, environmental, and economic factors associated with each alternate control

technology are evaluated, in addition to the benefit of reduced emissions that the technology

would bring.  The BACT analysis for the proposed facility is detailed in Section 5.   
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4.2.2 Air Quality Impact Analysis 

An impact analysis is not being provided with this application in accordance with EPA’s

recommendations:

Because there are no NAAQS or PSD increments for GHGs, the requirements in sections 52.21(k) and

51.166(k) of EPA’s regulations to demonstrate that a source does not cause or contribute to a violation of

the NAAQS are not applicable to GHGs.  Therefore, there is no requirement to conduct dispersion

modeling or ambient monitoring for CO2 or GHGs.9

An impact analysis for non‐GHG emissions is being submitted with the State/ PSD/

Nonattainment application submitted to the TCEQ.

4.2.3 GHG Preconstruction Monitoring 

A pre‐construction monitoring analysis for GHG is not being provided with this application in

accordance with EPA’s recommendations:

EPA does not consider it necessary for applicants to gather monitoring data to assess ambient air quality

for GHGs under section 52.21(m)(1)(ii), section 51.166(m)(1)(ii), or similar provisions that may be

contained in state rules based on EPA’s rules.  GHGs do not affect “ambient air quality” in the sense that

EPA intended when these parts o EPA’s rules were initially drafted.  Considering the nature of GHG

emissions and their global impacts, EPA does not believe it is practical or appropriate to expect

permitting authorities to collect monitoring data for the purpose of assessing ambient air impact of

GHGs.10

A pre‐construction monitoring analysis for non‐GHG emissions is being submitted with the

State/PSD/Nonattainment application submitted to the TCEQ.

4.2.4 Additional Impacts Analysis 

A PSD additional impacts analysis is not being provided with this application in accordance

with EPA’s recommendations:

Furthermore, consistent with EPA’s statement in the Tailoring Rule, EPA believes it is not necessary for

applicants or permitting authorities to assess impacts from GHGs in the context of the additional impacts

analysis or Class I area provisions of the PSD regulations for the following policy reasons.  Although it is

clear that GHG emissions contribute to global warming and other climate changes that result in impacts

on the environment, including impacts on Class I areas and soils and vegetation due to the global scope of

                                                     

9 EPA, PSD and Title V Permitting Guidance For Greenhouse Gases at 48‐49

10 Id. at 49
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the problem, climate change modeling and evaluations of risks and impacts of GHG emissions is typically

conducted for changes in emissions orders of magnitude larger than the emissions from individual

projects that might be analyze 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 with current

climate change modeling.  Given these considerations, GHG emissions would serve as the more

appropriate and credible proxy for assessing the impact of a given facility.  Thus, EPA believes that the

most practical way to address the considerations reflected in the Class I area and additional impacts

analysis is to focus on reducing GHG emissions to the maximum extent.  In light of these analytical

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

satisfy the additional impacts analysis and Class I area requirements of the rule related to GHGs.11

A PSD additional impacts analysis for non‐GHG emissions is being submitted with the

State/PSD/Nonattainment application submitted to the TCEQ.

4.2.5 Other Required Analyses 

Under Section 7 of the Endangered Species Act, Section 106 of the National Historic

Preservation Act and Executive Order 12898 [59 FR 7629 (February 16, 1994)], any action

authorized or permitted by EPA must ensure that it will not adversely impact federally listed

endangered species, historic areas and disproportionately minority or low income populations,

respectively.  Austin Energy has developed a Biological Assessment and Cultural Resources

Survey for the proposed Project.  This assessment and all relevant correspondence are included

in Appendix D.

                                                     

11 Id
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Section 5 

GHG Control Technology Analysis 

5.1 Overview 

Pre‐construction review for new major stationary sources involves an evaluation of BACT.  The

BACT methodology presented herein is based on USEPA’s recommended “top‐down,” 5‐step

analysis process to evaluate the available and applicable emission control technologies for the

affected pollutants.  BACT as defined in 40 CFR Part 52.21(b)(12) is:  

“An Emissions limitation (including a visible emission standard) based on the maximum degree of

reduction for each pollutant subject to regulation under the Act which would be emitted from any

proposed major stationary source or major modification which the Administrator, on a case‐by‐case basis,

taking into account energy, environmental, and economic impacts and other costs, determines is

achievable for such source or modification through application of production processes or available

methods, systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion

techniques for control of such pollutant.”    

At the head of the list in the top‐down analysis are the control technologies and emissions limits

that represent the Lowest Achievable Emission Rate (LAER) determinations, which, under

NSR/PSD regulations, represent the most effective control alternative and must be considered

under the BACT analysis process.  BACT cannot be determined to be less stringent than the

emission limits established by an applicable New Source Performance Standard (NSPS) for the

affected air emission source, but no NSPS limit has been finalized for GHG emissions from

utility sources.  The methodology uses a 5‐step process, which is summarized below.

Step 1: Identify All Control Technologies 

The first step in a “top‐down” analysis is to identify all available control options, including

lower emitting processes, practices, and post‐combustion controls.

Step 2: Eliminate Technically Infeasible Options 

The second step of the “top‐down” analysis is to eliminate the technically infeasible control

options from those identified in Step 1, including options that have not been “demonstrated”; or

more specifically, a technology that has not been installed and operated successfully on a

similar type of unit of comparable size.  Technologies that are in development and testing stages

are classified as not available and therefore infeasible.
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Step 3: Rank Remaining Control Technologies by Control Effectiveness

The third step of the “top‐down” analysis is to rank all the remaining (feasible) control

alternatives based on their control effectiveness.  The following informational databases,

clearinghouses, documents, and studies were used to identify recent control technology

determinations for similar source categories and emission units:

 USEPA’s RACT/BACT/LAER Clearinghouse (RBLC)

 Federal/State/Local new source review permits

 Technical journals, newsletters, and reports

 Information from air quality control technology suppliers

 Engineering design studies for this and similar units

Step 4: Evaluate Most Effective Controls 

The additional evaluations of feasible controls consider and compare the energy,

environmental, and economic impacts associated with implementing the viable control

alternatives.  The economic impact analysis is performed to assess the cost to purchase and

operate the control technology.  The capital cost and operating/annual costs are estimated and a

total equivalent annualized cost ($/year) is divided by the quantity of pollutant removed

(tons/year) to calculate the cost effectiveness ($/ton) of a control technology.  

Step 5: Select BACT 

The highest ranked control technology from Step 3 that is not eliminated in Step 4 based on

unacceptable economic, energy, or environmental impacts, is proposed as BACT for the

pollutant and emission unit under review.

5.2 BACT Analysis for Greenhouse Gas (GHG) Emissions 

As described in Section 3, the sources of GHG emissions for the proposed Project include the

new combined cycle combustion turbine/duct burner, natural gas pipeline fugitives and

electrical equipment insulated with SF6.   

5.2.1 BACT Analysis for Combined Cycle Unit 

5.2.1.1 Identification of GHG Control Options 

A search of the RBLC for “carbon dioxide” did not yield any results for combined cycle

combustion turbines; however, Austin Energy is aware of several projects which have recently

been permitted with GHG emission limits.  These facilities are identified in Table 5‐1 below.   
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Table 5-1 

Summary of GHG Permit Emission Limits for Combined Cycle Units 

Facility State 

Combustion 

Turbine 

Manufacturer / 

Model 

Permit 

Status 

Combined Cycle GHG BACT 

Limits 

Simple Cycle 

Combined Cycle 

Output Basis 

lb CO2e / MWh 

Combined 

Cycle Heat 

Rate Btu/kWh 

(HHV) 

Estimated 

Simple Cycle 

Heat Rate, 

Btu/kWh (HHV)* 

Russell City CA Siemens 501F Final 7,730 10,385 

Pacificorp UT Siemens 5000F Final 950 10,385 

LCRA Ferguson TX GE 7FA Final 918 7,720 10,009 

Kennecott UT GE 7FA Final 7,642 10,009 

Pioneer Valley MA 

Mitsubishi 

501G Final 895 

CPV Valley NY Siemens 5000F Draft 925 10,385 

CPV Woodbridge NJ GE 7FA Final 925 7,605 10,009 

Cricket Valley NY GE 7FA Final 913** 7,605 10,009 

Hess Newark NJ GE 7FA Final 887 7,522 10,009 

Calpine Deer Park TX Siemens 501F Final 920 7,730 10,385 

Calpine Channel TX Siemens 501F Final 920 7,730 10,385 

*Representative base load simple cycle (combustion turbine only) heat rate for model of combustion turbine 

used / not project-specific data or permit limit 

**No output-based (lb CO2e/MWh) limit in permit, but this lb CO2e/MWh value is calculated based on permit 

limits on heat rate (Btu/kWh) and emission factor (lb/MMBtu): 

lb CO2e/MWh = lb CO2e/MMBtu x Btu/kWh x 103

 kWh/MWh x MMBtu/106 BTU 

 
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Additional details on these combined cycle facility permits and limits are provided in

Appendix C, Table 1.   

Based on engineering knowledge and judgment and permit applications submitted to EPA

Region 6 for similar facilities, the following potentially applicable GHG control technologies

were evaluated:   

 Carbon Capture and Storage

 Electrical Generation Efficiency

Carbon Capture and Storage (CCS) 

Capture and compression, transport, and geologic storage of the CO2 is a post‐combustion

technology that is not considered commercially viable for natural gas combustion sources at this

time.  However, because EPA Region 6 has requested consideration of CCS by other GHG

permit applicants, CCS is evaluated further in this analysis including an evaluation of its cost‐

effectiveness.  CCS systems involve the use of adsorption or absorption processes to remove

CO2 from flue gas, with subsequent desorption to produce a concentrated CO2 stream.  The

concentrated CO2 is then compressed to supercritical temperature and pressure, a state in which

CO2 exists as neither a liquid nor a gas, but instead has physical properties of both liquids and

gases.  The supercritical CO2 would then be transported to a location that allows for

underground injection into a suitable geological storage reservoir, such as a deep saline aquifer

or depleted coal seam, or used in crude oil production for enhanced oil recovery (EOR).

Electrical Generation Efficiency 

Other than capture and sequestration of GHG emitted by combustion, the only known option

for reducing GHG emissions from natural gas combined cycle units is through maximization of

the energy released during the combustion process and then through the maximization of the

use or capture of that energy.  To minimize GHG emissions, it is desirable to use less fuel to

generate a given amount of electrical energy.  There are several factors that may affect the

amount of GHG produced per MW‐hour of energy produced.  These include low carbon fuels

and the thermodynamic and mechanical efficiency of the combustion unit.

5.2.1.2 Elimination of Technically Infeasible Alternatives 

All options identified above are considered “technically” feasible for the purposes of this BACT

analysis.
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5.2.1.3 Ranking of Remaining Technologies Based on Effectiveness 

Both CCS and electrical generation efficiency are considered “technically” feasible and are

ranked in order of desirability below:

1. Carbon Capture and Storage (CCS)

2. Electrical Generation Efficiency  

5.2.1.4 Evaluation of Control Technologies 

The energy, environmental, and economic feasibility of implementing the different control

technologies as BACT for GHG emissions from the proposed Project’s gas turbine/HRSG train

are evaluated below for the two technically feasible control technologies:

1. Carbon Capture and Storage (CCS)

2. Electrical Generation Efficiency

Carbon Capture and Storage (CCS) 

Each component of CCS technology (i.e., capture and compression, transport, and storage) is

discussed separately.  These include:

1. Carbon Capture and Compression

2. CO2 Transport

3. CO2 Storage

Carbon Capture and Compression 

Although amine absorption technology for CO2 capture has been applied to processes in the

petroleum refining and natural gas processing industries and to exhausts from gas‐fired

industrial boilers, it is more difficult to apply to power plant gas turbine exhausts, which have

considerably larger flow volumes and considerably lower CO2 concentrations (partial

pressures).  The Obama Administration’s Interagency Task Force on Carbon Capture and

Storage confirms this in its recently completed report on the current status of development of

CCS systems:

“Current technologies could be used to capture CO2 from new and existing fossil energy power plants;

however, they are not ready for widespread implementation primarily because they have not been

demonstrated at the scale necessary to establish confidence for power plant application.  Since the CO2

capture capacities used in current industrial processes are generally much smaller than the capacity
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required for the purposes of GHG emissions mitigation at a typical power plant, there is considerable

uncertainty associated with capacities at volumes necessary for commercial deployment.”12

In its current CCS research program plans, the Department of Energy’s National Energy

Technology Laboratory (DOE‐NETL) confirms that commercial CO2 capture technology for

large‐scale power plants is not yet available and suggests that it may not be available until at

least 2020:

“The overall objective of the Carbon Sequestration Program is to develop and advance CCS technologies

that will be ready for widespread commercial deployment by 2020.”  To accomplish widespread

deployment, four program goals have been established:

1. Develop technologies that can separate, capture, transport, and store CO2 using either direct

or indirect systems that result in a less than 10 percent increase in the cost of energy by 2015;

2. Develop technologies that will support industries’ ability to predict CO2 storage capacity in

geologic formations to within ±30 percent by 2015;

3. Develop technologies to demonstrate that 99 percent of injected CO2 remains in the injection

zones by 2015;

4. Complete Best Practices Manuals (BPMs) for site selection, characterization, site operations,

and closure practices by 2020.  Only by accomplishing these goals will CCS technologies be

ready for safe, effective commercial deployment both domestically and abroad beginning in

2020 and through the next several decades.”13

The partial pressure for CO2 in a natural gas combined cycle flue gas is much lower than the

partial pressure of CO2 in a coal‐fired boiler flue gas: the volume of CO2 in a natural gas

combined cycle stack is typically 3‐5% compared to 11‐12% in a coal fired boiler stack flue gas.

Most carbon capture research and trials to date feature the amine absorption process for coal

fired power plants, because the flue gas has a much higher CO2 partial pressure in a coal boiler.  

Other disadvantages of the amine process that have not been fully addressed are the following:

1. The high concentration of oxygen in the natural gas turbine stack adversely affects

solvents such as amine.   

2. The amine processes also tend also to be prohibitively expensive, for one because of

the cooling that is required to remove sulfur and nitrogen compounds that may

potentially poison the solvent.

                                                     

12 Report of the Interagency Task Force on Carbon Capture and Storage at 50 (Aug. 2010).

13 DOE‐NETL, Carbon Sequestration Program: Technical Program Plan, at 10 (Feb. 2011).  
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Significant research conducted by Mitsubishi Heavy Industries (MHI) has demonstrated both

the advantage of inhibited amine technology and the significantly greater cost and difficulty for

removal of CO2 from gas turbines as compared to coal boilers.  Further support for the

conclusion that commercial availability of CO2 capture technology for large‐scale power plant

projects will not occur for several more years was found by reviewing information published by

Alstom, a major developer of commercial CO2 capture technology using post‐combustion amine

absorption, post‐combustion chilled ammonia absorption and oxy‐combustion.  Alstom states

on its web site that its CO2 capture technology will become commercially available in 2015.14

However, it should be noted that in committing to this timeframe, the company does not

indicate whether such technology will be able to handle the volume of CO2 emissions generated

by a project the size of this proposed project.

Conservation of water resources is another important challenge associated with CO2 capture.  A

modern natural gas fired combined cycle facility requires four to five million gallons of water

per day for condenser cooling and boiler make‐up service.  This amount will vary based on

ambient temperature and humidity as well as the level of duct firing in the HRSG.  Adding CO2

separation facilities and compression equipment significantly increases the cooling water

requirements of a generating station.  Studies indicate that the water consumption of a natural

fired combined cycle facility with CCS may have an increased water consumption of more than

60%.15

CO2 Transport 

Even if it is assumed that CO2 capture and compression could feasibly be achieved for the

proposed Project, the high‐volume CO2 stream generated would need to be transported to a

facility capable of storing it.  Potential geologic storage sites in Texas, Louisiana, and Mississippi

to which CO2 could be transported if a pipeline was constructed are illustrated in Figure 5‐1.  

The potential length of such a CO2 transport pipeline cannot be determined because no sites can

be identified that are suitable for large‐scale, long‐term CO2 storage.  The hypothetical

minimum length required for any such pipeline(s) is the distance to the closest site with

recognized potential for some geological storage of CO2, which is an enhanced oil recovery

(EOR) reservoir site located within 45 miles of the proposed project.

However, none of the South and Southeast Texas EOR reservoirs or other geologic formation

sites has been demonstrated to support large‐scale, long‐term CO2 storage.   

                                                     

14 Alstom, Alstom’s Carbon Capture Technology Commercially “Ready to Go” by 2015, Nov. 30, 2010,

http://www.alstom.com/australia/news‐and‐events/pr/ccs2015/  

15 Report of the Interagency Task Force on Carbon Capture and Storage at 50 (Aug. 2010).
Figure 5-1: Potential CO2 Storage Areas and Existing CO2 Pipelines 

Source: University of Texas at Austin Bureau of Economic Ecology, Gulf Coast Carbon Center 

SACROC Southwest

Partnership NM

Tech

Frio Test Site

SECARB Pha

SHEC Site
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In comparison, the closest site that is currently being field‐tested to demonstrate its capacity for

large‐scale geological storage of CO2 is the Southwest Regional Partnership on Carbon

Sequestration’s (SWP) SACROC test site, located in Scurry County, Texas, approximately 240

miles away.  A high pressure pipeline would need to be constructed to this site to transport the

CO2.

CO2 Storage 

Even if it is assumed that CO2 capture and compression could feasibly be achieved for the

proposed project and that the CO2 could be transported economically, the feasibility of CCS

technology would still depend on the availability of a suitable sequestration site.  The suitability

of potential storage sites is a function of volumetric capacity of their geologic formations, CO2

trapping mechanisms within formations (including dissolution in brine, reactions with minerals

to form solid carbonates, and/or adsorption in porous rock), and potential environmental

impacts resulting from injection of CO2 into the formations.  Potential environmental impacts

resulting from CO2 injection that still require assessment are significant unknown risks before

CCS technology can be considered feasible include:

— Uncertainty concerning the significance of dissolution of CO2 into brine,

— Risks of brine displacement resulting from large‐scale CO2 injection, including a pressure

leakage risk for brine seeping into underground drinking water sources and/or surface

water,

— Risks to fresh water as a result of leakage of CO2, including the possibility for damage to

the biosphere, underground drinking water sources, and/or surface water,16

— Potential effects on wildlife, and

— Risk of metals leaking from underground formations as a result of the injection of acid

gases.

Potentially suitable storage sites, including EOR sites and saline formations, exist in Texas,

Louisiana and Mississippi.  In fact, sites with such recognized potential for some geological

storage of CO2 are located within 45 miles of the proposed project, but such nearby sites have

not yet been demonstrated to support sequestration with respect to all of the suitability factors

described above.  In comparison, the closest site currently being field‐tested to demonstrate its

capacity for geological storage of the volume of CO2 that would be generated by the proposed

power unit, i.e., SWP’s SACROC test site, is located in Scurry County, Texas approximately 240

                                                     

16 Susan Hovorka, University of Texas at Austin, Bureau of Economic Geology, Gulf Coast Carbon Center, New

Developments: Solved and Unsolved Questions Regarding Geologic Sequestration of CO2 as a Greenhouse Gas

Reduction Method (GCCC Digital Publication #08‐13) at slide 4 (Apr. 2008), available at:

http://www.beg.utexas.edu/gccc/forum/codexdownloadpdf.php?ID=100
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miles away.  It should be noted that the suitability of the SACROC site or any other test site to

store a substantial portion of the CO2 generated by the proposed project has yet to be fully

demonstrated.

Based on the reasons provided above, the City of Austin believes that CCS technology should

be eliminated from further consideration as a potential feasible control technology for purposes

of this BACT analysis.  However, to answer possible questions that the public or the EPA may

have concerning the relative costs of implementing hypothetical CCS systems, the City of

Austin has estimated such costs.  

Cost and Energy Impacts of Carbon Capture and Storage 

The estimated costs associated with implementation of a carbon capture system for the

proposed Project are shown in Table 5‐2 below.  Capital cost components include equipment

(complete with initial chemical and catalyst loadings), materials, labor (direct and indirect),

engineering and construction management and contingencies.  Operating cost components

include operating and maintenance labor, consumables, fuel, waste disposal and co‐product or

by‐product credit.

The capital cost of a CO2 capture system for SHEC would be approximately $170 million17.  

Based on an estimated project capital cost for the addition of a CTG and HRSG of $195 million,

the addition of the CO2 capture portion of CCS control scheme would be expected to add 87%

to the project’s overall capital cost.  The capital cost for the pipeline that would be required to

transport the CO2 to a suitable storage site is estimated to be another $80 million.

In addition to the high construction and operating costs associated with CCS, the carbon

capture equipment requires a substantial amount of energy to operate, thereby reducing the net

electrical output of the plant.  Operation of carbon capture equipment at a typical natural gas

fired combined cycle plant is estimated to reduce the net energy efficiency of the plant from

approximately 50% to approximately 42.9%.18  

The capital cost to construct a suitable 45‐mile pipeline to the nearest site with any potential for

geological storage of CO2 is calculated to be greater than $80 million (Appendix C, Table 2) per

pipeline cost equations developed by DOE‐NETL.19   

                                                     

17 Report of the Interagency Task Force on Carbon Capture and Storage (Aug. 2010).

18 US Department of Energy, National Energy Technology Laboratory, “Costs and Performance Baseline For Fossil

Energy Plants, Volume 1 ‐ Bituminous Coal and Natural Gas to Energy”, Revision 2, November 2010

19 Quality Guidelines for Energy System Studies: Estimating Carbon Dioxide Transport and Storage Costs, National

Energy Technology Laboratory, US Department of Energy, DOE/NETL‐2010/1447 (March, 2010)
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Table 5-2 

CCS Cost Analysis for Combined Cycle Unit 

CCS System Component 

Capital Cost1 

($) 

Cost 1,2 

($/ton) 

CO2 Removed3 

(ton/yr) 

Total Annualized Cost4 

($/year) 

CO2 Capture & 

Compression Facilities $170,000,000 $103 1,314,348 $135,928,752

CO2 Transport Facilities $80,645,746 $6.09 1,314,348 $8,001,398

CO2 Storage Facilities NA5 $0.51 1,314,348 $667,720

Total CCS System Cost > $250,000,000 $110 1,314,348 $144,597,870

Potential Revenue from 

Sale of CO2 for EOR6    ($23) 1,314,348 ($30,229,994)

Total CCS System Cost 

with Sale of CO2 for EOR    $87 1,314,348 $114,367,876  

1. CO2 capture/compression and storage costs are from Report of the Interagency Task Force on Carbon Capture (August, 

2010). Cost includes initial investment, O&M, and cost of fuel. 

2. CO2 transport cost is calculated per pipeline cost equations from Quality Guidelines for Energy System Studies: Estimating 

Carbon Dioxide Transport and Storage Costs, National Energy Technology Laboratory, US Department of Energy, 

DOE/NETL-2010/1447 (March, 2010). 

3. Tons of CO2 removed assumed 90% capture of all CO2 emissions from the combustion turbine and duct burner. 

4. Annualized costs based on 7% interest rate and 20 year equipment life 

5. No capital cost estimate provided for CO2 storage in Report of the Interagency Task Force on Carbon Capture (August, 

2010) 

6. US price from sale of CO2 for Enhanced Oil Recovery (EOR) is $10-40/tonne, from 

http://www.globalccsinstitute.com/publications/global-status-ccs-2012/online/48431

Example Calculations (Total Annualized Cost): 

Capture	&	Comp:	 ቆ$103

ton ቇ 	x ൬

1,314,348	ton	CO2

yr ൰ ൌ 		

$135,928,752

yr

CO2	Transport:	 ቆ$6.69

ton ቇ 	x ൬

1,314,348	ton	CO2

yr ൰ ൌ 		

$8,001,398

yr

CO2	Storage:	 ቆ$0.51

ton ቇ 	x ൬

1,314,348	ton	CO2

yr ൰ ൌ 		

$667,720

yr

Total	CCS	System	Cost:	 ቆ$135,928,752

yr ቇ൅ቆ$8,001,398

yr ቇ ൅ ቆ	$667,720yr ቇ ൌ 		 $144,597,870yr
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Based on the same guidance, the annual pipeline O&M cost would be more than $388,000/year,

and the total annual cost including annualized capital cost would be about $8 million per year.  

A cost is also associated with the monitoring and maintenance of the CO2 storage facility.  The

total equivalent annual cost for all aspects of the site‐specific CCS option total about $132

million/year.  Assuming the system would capture 90% of the combined cycle unit CO2, the cost

effectiveness is calculated at $111/ton CO2.  Assuming that all of the CO2 captured could be sold

for use in Enhanced Oil Recovery (EOR), a $23/ton credit has been applied in the cost analysis,

reducing the net cost of CCS to $88/ton CO2.

Electrical Generation Efficiency 

The following energy efficiency practices are associated with and incorporated into the

proposed combined cycle unit design:

Use of Low Carbon Fuel 

The first aspect to evaluate with regard to an energy efficient process is the source of fuel.  40

CFR part 98 provides emission factors for GHG from the combustion of various fuels.  Natural

gas is listed as the third cleanest fuel with respect to CO2 emissions, the third cleanest fuel with

respect to CH4 emissions and the cleanest fuel with respect to N2O emissions.  The two cleaner

fuels with respect to CO2 emissions (coke oven gas and biogas) are not feasible sources of fuel

for the project based on the need to match the technology choice (natural gas turbine) to the

existing combined cycle unit.  Therefore, with regard to fuels that can be utilized by the project,

natural gas produces the lowest GHG emissions profile.  

Turbine Design/Selection 

In a combined cycle configuration, a HRSG is used to recover what would otherwise be waste

heat lost to the atmosphere in the hot turbine exhaust.  Use of heat recovery from the turbine

exhaust to produce steam to power a steam turbine which generates additional electric power is

the single most effective means of increasing the efficiency of combustion turbines used for

electric power generation.  The overall thermal efficiency for the proposed project is increased

from about 39% for the simple cycle combustion turbine (no heat recovery) unit to about 59%

for the unit in combined cycle configuration including electricity generated in the STG.  In

applications where process heat is needed, the steam produced in the HRSG can also be used to

provide heat to plant processes in addition to or instead of being used to produce additional

electricity.  This “cogeneration” technology is not applicable to electric power generation unless

there is a co‐located steam host or other means of using additional recoverable waste heat.

The existing combined cycle unit at SHEC is operating in a 1 x 1 configuration with a GE 7FA

gas turbine with a 164 MW (nominal at ISO) generator, a HRSG, and a GE D‐11 steam turbine
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with a 189 MW generator.  Not all of this STG capacity can be utilized with only the existing

CTG/HRSG, even with the duct burner firing at maximum design capacity.  Ultimate expansion

of the unit to a 2 x 1 configuration was part of the original design and the existing steam turbine

and cooling tower were sized for a second 7FA and associated HRSG.   

In evaluating different turbines, SHEC decided that a second 7FA provided benefits from an

operations and maintenance perspective that other turbines models did not.  SHEC plant staff is

experienced in operating and maintaining the 7FA and the addition of a second 7FA would

minimize changes to the control system, operating procedures and training.  A second 7FA

would also simplify maintenance by leveraging staff experience as well as reduce the quantity

and cost of spare parts which would be required to maintain two different gas turbines.  

Estimated cost savings associated with selection of a second GE 7FA unit versus a different

turbine model are:

 Operation training: $300,000

 Control system integration: $3,000,000 (exclusive of engineering and design changes and

commissioning complications)

 Spare combustion parts: $3,000,000 to $5,000,000

 Long Term Service Agreement (LTSA): $3,000,000 to $4,000,000 (incremental)

A newer version of the GE 7FA turbine is now available that allows for a higher firing

temperature and therefore improvements in output and heat rate (i.e., greater thermal

efficiency).  The output of the existing GE 7FA.03 CTG is 161.5 MW at full load at the site

ambient average temperature of 68°F and the GE 7FA.04 output is 173.9 MW at this condition.  

Although there would be advantages for SHEC to have identical GE 7FA.03 turbines at the

facility, the improved performance of the 7FA.04 will make the overall efficiency of the

combined cycle unit with the shared STG better and thereby reduce the GHG emissions in

terms of CO2e/MWh of electricity generated.

Heat rate (Btu/kWh) values are provided for the combustion turbine alone (simple cycle) and in

combination with the HRSG/STG output (combined cycle) for each of the 14 operating modes

modeled for the proposed new unit in the spreadsheet of performance and emissions data

provided in Appendix B, Table B‐1, and summarized in Table 5‐3 below.  Example calculations

for heat rates are provided in the footnotes to Table B‐1.
Load Condition % CTG Base Load BASE BASE 75% 50% BASE BASE BASE 75% 53% BASE 

Ambient Temperature deg F 0 0 0 0 68 68 68 68 68 112 Evap. Cooler Status Off Off Off Off On On Off Off Off On 

Evap. Cooler Effectiveness % 0 0 0 0 85 85 0 0 0 85 Duct Burner Status On Off Off Off On Off Off Off Off On Ambient Relative Humidity % 60 60 60 60 60 60 60 60 60 60 Inlet Loss in H2O 4444444444Exhaust Pressure Loss in H2O 16.1 16.1 10.7 7.3 14.4 14.4 14 9.5 7 11.5 CTG Output (Simple Cycle) kW 196,178 196,178 147,133 98,089 179,025 179,025 173,910 130,433 92,172 152,206 STG Output (estimated)* kW 168,683 102,365 86,067 74,672 162,271 95,953 94,620 80,141 71,053 153,844 CC (CTG + STG) Combined Cycle Output kW 364,861 298,543 233,200 172,761 341,296 274,978 268,530 210,574 163,225 306,050 CTG Simple Cycle Heat Rate (HHV) BTU/kWh, HHV 9,744 9,744 10,462 12,470 9,964 9,964 10,020 10,823 12,611 10,454 CTG Simple Cycle Heat Rate, HHV (+ margin**) BTU/kWh, HHV 10,718 10,718 11,508 13,717 10,961 10,961 11,022 11,906 13,872 11,500 Combined Cycle (CTG + STG) Heat Rate (HHV) BTU/kWh, HHV 7,104 6,403 6,601 7,080 7,221 6,488 6,489 6,704 7,121 7,422 Combined Cycle (CTG + STG) Heat Rate (+ margin**) BTU/kWh, HHV 7,815 7,044 7,261 7,788 7,943 7,136 7,138 7,375 7,833 8,165 CTG Heat Consumption (HHV) MMBTU/hr 1,911.6 1,911.6 1,539.4 1,223.2 1,784.0 1,784.0 1,742.4 1,411.7 1,162.4 1,591.1 

CO2 lb/hr 303,110 223,447 179,934 142,976 288,187 208,524 203,666 165,011 135,864 265,647 CO2 lb/MMBTU, HHV 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 N2O lb/hr 0.6 0.4 0.3 0.3 0.5 0.4 0.4 0.3 0.3 0.5 N2O lb/MMBTU, HHV 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 CH4 lb/hr 5.7 4.2 3.4 2.7 5.4 3.9 3.8 3.1 2.6 5.0 CH4 lb/MMBTU, HHV 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 GHG, CO2e lb/hr 303,408 223,666 180,110 143,116 288,470 208,728 203,866 165,173 135,997 265,907 GHG, CO2e lb/MMBTU, HHV 117.0 117.0 117.0 117.0 117.0 117.0 117.0 117.0 117.0 117.0 

GHG, CO2e (Simple Cycle) ton/MWh 0.773 0.570 0.612 0.730 0.806 0.583 0.586 0.633 0.738 0.874 

GHG, CO2e (Simple Cycle + margin**) ton/MWh 0.851 0.627 0.673 0.802 0.886 0.641 0.645 0.696 0.812 0.961 

GHG, CO2e (Combined Cycle) ton/MWh 0.416 0.375 0.386 0.414 0.423 0.380 0.380 0.392 0.417 0.434 GHG, CO2e (Combined Cycle + margin**) ton/MWh 0.457 0.412 0.425 0.456 0.465 0.417 0.418 0.431 0.458 0.478 

** Margin added for measurement error, off-design conditions and degradation 10.0%Example Calculations provided in Appendix B, Table 1

Estimated Performance and Emissions for GE 7FA.04 Combustion Turbine in Simple Cycle and Combined Cycle Mode

Table 5-3

* STG output (kW) estimated by scaling from design case (68 F, evap cooler on, unfired) based on ratio of exhaust energy + duct burner heat input to design case exhaust energy; actual STG outpuoperating, but maximum duct burner firing rate used for all conditions as worst case for permitting
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Simple cycle gross heat rates range from 10,718 to 11,703 Btu/kWh (HHV) at full load without

evaporative cooling.  Combined cycle heat rates are estimated to range from 7,044 to 7,328

Btu/kWh (HHV) for these same operating conditions20.  Heat rates are higher (efficiency lower)

at higher ambient temperatures and lower turbine loads.  The use of evaporative cooling

improves the heat rate by lowering the compressor inlet temperature.  Use of the duct burners

to increase steam production in the HRSG and STG output increases the overall combined cycle

heat rate.

It is worth noting that the outputs and heat rates identified above are based on the specific

turbine design and performance for this project at the SHEC site.  Thus it is likely that these

values may differ somewhat from those published in the manufacturer’s literature or website

summarizing performance for a variety of combustion turbine manufacturers and models.  

Factors that influence the output and heat rate from project to project include ambient

temperature, humidity and site elevation; fuel type/composition and exhaust back pressure

(due to the HRSG, catalysts and the length of the flue gas path – or stack height) will also have a

significant impact on performance.  The combined cycle heat rate of the proposed unit

compares favorably to the heat rate limits included in recent permits for other GE 7FA units, as

well as combined cycle units with other GE turbine models and those of other manufacturers,

which are summarized in Table 5‐1.  Most of these permits have minimum combined cycle heat

rate limits in the range of 7,522 to 7,730 Btu/kWh, HHV.

GHG emission limits for units comparable to the proposed SH8 unit that have output‐based

lb/MWh and or heat rate (Btu/kWh) basis limits are extracted from the comprehensive list in

Appendix C and summarized in Table 5‐1 above.   

5.2.1.5 Determination of BACT for Combined Cycle Unit 

The City of Austin (dba Austin Energy) proposes as BACT for this project, the following energy

efficiency processes, practices, and designs for the proposed combined cycle combustion

turbine:

 Use of Combined Cycle Power Generation Technology

 Use of natural gas as the exclusive fuel

 Efficient turbine design

                                                     

20 SH8 combined cycle heat rates are based on STG outputs extrapolated from the design (full load at 68 degrees F)

case used to model the performance for a 2‐on‐1 configuration with the existing SH5 unit; in some cases with duct

firing the STG output is greater than it can actually be in order to evaluate maximum duct burner firing rates.
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The proposed GE 7FA.04 combustion turbine is the most efficient unit available that is suitable

for incorporation into the existing combined cycle unit as described above, with a gross heat

rate at base load ranging from 9,744 to 10,639 Btu/kWh, HHV, at base load without evaporative

cooling, depending on ambient conditions (refer to Table 5‐3).  For comparison, the existing SH5

unit combustion turbine, as GE 7FA.03 model, has a heat rate ranging from 10,004 to 11,055

Btu/kWh, HHV, across the same range of conditions, so the newer model is about 3 to 4% more

efficient, translating to 3 to 4% lower GHG emissions.  Other manufacturers have made similar

improvements: a chief competitor to the GE 7FA, the Siemens 5000F (Westinghouse 501F)

turbine; has improved simple cycle efficiency from approximately by approximately 4% over

the last 20 or so years.  In combined cycle mode, with the benefit of the HRSG and additional

output from the STG, the gross heat rate of the proposed GE 7FA.04 unit is expected range to

from 7,044 to 7,328 Btu/kWh, HHV without evaporative cooling.  

Because the new combustion turbine will be added to an existing combined cycle unit and its

HRSG will provide steam to a steam turbine generator that is shared with the existing turbine, it

is not possible to determine a combined cycle heat rate standard and output‐based GHG limit

that is separate from the performance of the existing SH5 turbine and HRSG performance.  The

SH5 unit was permitted prior to GHG BACT requirements and as such has no GHG emission

limit or heat rate limit in its permit conditions.  Therefore, the City of Austin is proposing GHG

BACT limits based on the new combustion turbine alone (simple cycle basis) without duct

burner firing:

 Simple cycle output‐based GHG limit of 0.81 ton CO2e/MWh combustion turbine gross

output basis; equivalent to 0.458 ton CO2e/MWh (or 916 lb/MWh) gross output basis for the

combined cycle unit that shares the STG with the existing SH5 combustion turbine, with

unfired HRSG

 Simple cycle combustion turbine gross output heat rate of 13,872 Btu/kWh (HHV);

equivalent to 7,833 BTU/kWh (HHV) gross heat rate for the combined cycle unit that shares

the STG with the existing SH5 combustion turbine, at 68°F with unfired HRSG

The proposed output‐based GHG emission limits are equivalent to the most recent GHG permit

limits for similar combined cycle units as summarized in Table 5‐1 (approximately 0.466 ton

CO2e/MWh or 932 lb/MWh, combined cycle basis) and the proposed heat rate limit is

comparable to the most recent limits for similar units.

As with other recent GHG permits for combined cycle units, compliance with these

performance standards  is determined for operation at 100% load at ISO conditions, without

evaporative cooling or duct burner firing.  This provides a standard basis for comparison of the

GHG limits that are permitted for different projects.  In order to demonstrate that the proposed
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simple cycle GHG limit corresponds to the combined cycle performance indicated above, the

City of Austin proposes to perform the initial compliance test with only the new combined cycle

unit operating (i.e., with SH5 off line).  In order to regulate GHG emissions from all operating

conditions, including those using evaporative cooling and with duct burner firing, the City of

Austin is also proposing a GHG BACT limit on total annual GHG emissions for the combined

cycle combustion turbine and duct burner:

 Annual emission cap of 1,461,818 tons CO2e per year, for the addition of the second

combustion turbine, HRSG and duct burner

The proposed GHG BACT limits for the proposed new unit are summarized in Table 5‐4 below.

This approach of a combination of output based CO2e limits and heat rate limits at standard

conditions and an annual emission cap to cover other operating conditions and emissions has

been used in other recent GHG BACT permit limits for combined cycle units.

Each of the proposed limits is calculated to include a 10% margin to account for measurement

error, equipment and site variations, and degradation over time.

Compliance with the output based emission limits will be based on a 30‐day rolling average.  

Compliance with the annual tons/year limit will be based on a rolling 365‐day total.  In each

case, SHEC proposes to calculate GHG emissions based on continuous monitoring of the fuel

flow to the combustion turbine and duct burner using calibrated fuel flow meters, with heat

input calculated based on weighted average monthly heating values provided by the pipeline

natural gas supplier, and emissions of CO2e calculated based on emission factors and GWPs

from 40 CFR 98 (greenhouse gas monitoring rule).  Gross output (kW) will be continuously

measured and recorded at the combustion turbine generator.

5.2.2 BACT Analysis for Natural Gas Fugitives 

Small amounts of methane may occur from leaking natural gas piping components (process

fugitives) associated with the proposed Project.  The methane emissions from process fugitives

have been conservatively estimated to be 118.6 tons per year (see Table 3‐2) as CO2e.  This is a

negligible (0.011%) contribution to the total GHG emissions from the project.  However, for

completeness, they are addressed in this BACT analysis.   
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5.2.2.1 Identification of GHG Control Options 

The only identified control technology for process fugitive emissions of CO2e is a leak detection

and repair (LDAR) program.  LDAR programs vary in stringency/degree of control as needed

for control of VOC emissions; however due to the negligible amount of GHG emissions from

fugitives, LDAR programs would not be considered for control of GHG emissions alone.
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Table 5-4 

Proposed Greenhouse Gas BACT Limits for SH8 (Simple Cycle Output Basis) 

Form of Limit Limit Averaging Period Basis 

Output-Based 

GHG Limit 

0.81 tons CO2e/MWh 1 30-day rolling 

average 

Simple cycle combustion turbine 

only gross output basis at full load 

Heat Rate 

Limit 

13,872 Btu/kWh (HHV) 2 30-day rolling 

average 

Simple cycle combustion turbine 

only gross output basis at full load 

Annual GHG 

Emission Cap 

1,461,818 tons CO2e/year 365-day rolling 

average 

Includes all stack emissions from 

combustion turbine, duct burner, 

start-ups, shutdowns, malfunctions 

and effects of different operating 

conditions including evaporative 

inlet air cooling 

1. Simple cycle (combustion turbine only) output based GHG limit is equivalent to 0.458 ton CO2e/MWh (or 916 lb/MWh) for 

the combined cycle unit at full load at 68 degrees F 

2. Simple cycle (combustion turbine only) heat rate limit is equivalent to 7,833 BTU/kWh (HHV) gross heat rate for the 

combined cycle unit at full load at 68 degrees F 

   
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5.2.2.2 Elimination of Technically Infeasible Alternatives 

LDAR is considered technically feasible for the proposed Project.

5.2.2.3 Ranking of Remaining Technologies Based on Effectiveness 

The use of a LDAR program with a portable gas analyzer meeting the requirements of 40 CFR

60, Appendix A, Method 21, can be effective for identifying leaking methane.  Quarterly

instrument monitoring with a leak definition of 10,000 part per million by volume (ppmv)

(TCEQ 28M LDAR Program) is generally assigned a control efficiency of 75% for valves, relief

valves, sampling connections, and compressors and 30% for flanges.21 Quarterly instrument

monitoring with a leak definition of 500 ppmv (TCEQ 28VHP LDAR Program) is generally

assigned a control efficiency of 97% for valves, relief valves, and sampling connections, 85% for

compressors, and 30% for flanges.22 The EPA has allowed the use of an optical gas imaging

instrument as an alternative work practice for a Method 21 portable analyzer to monitor

equipment for leaks in 40 CFR 60.18(g).  For components containing inorganic or odorous

compounds, periodic audio/visual/olfactory (AVO) walk‐through inspections provide predicted

control efficiencies of 97% control for valves, flanges, relief valves, and sampling connections,

and 95% for compressors.23

5.2.2.4 Evaluation of Control Technologies 

A cost effectiveness analysis for a basic LDAR program to control process fugitive CH4

emissions is presented in Appendix C, Table 3.  The results of this analysis show that the least

stringent LDAR program (TCEQ’s 28M program) would cost approximately $260 per ton of

CO2e removed, which is not considered to be cost effective for GHG control.

5.2.2.5 Determination of BACT for Natural Gas Fugitives 

Due to the negligible amount of GHG emissions from process fugitives, the only available

control, implementation of an LDAR program, is clearly not cost effective and would result in

no significant reduction of overall project GHG emissions regardless of cost.  Based on these

considerations, BACT is determined to be normal plant maintenance practices as needed for

safety and reliability purposes.

                                                     

21 Air Permit Technical Guidance for Chemical Sources: Equipment Leak Fugitives, TCEQ, Oct. 2000

22 Id

23 Id
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5.2.3 BACT Analysis for SF6 Insulated Electrical Equipment 

5.2.3.1 Identification of GHG Control Options 

State‐of‐the‐art enclosed‐pressure SF6 technology with leak detection is the primary technology

used to limit fugitive emissions.  In comparison to older SF6 circuit breakers, modern breakers

are designed as a totally enclosed‐pressure system with far lower potential for SF6 emissions.  In

addition, the effectiveness of leak‐tight closed systems can be enhanced by equipping them with

a density alarm that provides a warning when 10% of the SF6 (by weight) has escaped.  The use

of an alarm identifies potential leak problems before the bulk of the SF6 has escaped, so that it

can be addressed proactively to prevent further release of the gas.

A second alternative considered in this analysis is to substitute another, non‐GHG substance for

SF6 as the dielectric material in the breakers.  Potential alternatives to SF6 were 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 

SF6.

24

5.2.3.2 Elimination of Technically Infeasible Alternatives 

According to the NTIS Technical Note 1425, SF6 is a superior dielectric gas for nearly all high

voltage applications.25  It is easy to use, exhibits exceptional insulation and arc‐interruption

properties, and has proven its performance by many years of use and investigation.  It is clearly

superior in performance to the air and oil insulated equipment used prior to the development of

SF6‐insulated equipment.  The report concluded that although “...various gas mixtures show

considerable promise for use in new equipment, particularly if the equipment is designed

specifically for use with a gas mixture... it is clear that a significant amount of research must be

performed for any new gas or gas mixture to be used in electrical equipment.”  Therefore there

are currently no technically feasible options besides use of SF6.

5.2.3.3 Ranking of Remaining Technologies Based on Effectiveness 

The use of state‐of‐the‐art SF6 technology with leak detection to limit fugitive emissions is the

highest ranked control technology that is technically feasible for this application.

                                                     

24 Christophorous, 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.

25 Id at 28‐29
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5.2.3.4 Evaluation of Control Technologies 

Energy, environmental, or economic impacts were not addressed in this analysis because the

use of alternative, non‐greenhouse‐gas substances to SF6 as the dielectric material in the

breakers is not technically feasible.  A cost‐effectiveness evaluation was not preformed given

there is only one feasible option.

5.2.3.5 Determination of BACT for GHG for SF6 Insulated Electrical Equipment 

The City of Austin proposes to use circuit breakers with totally enclosed insulation systems

equipped with a low pressure alarm and low pressure lockout.  The lockout will prevent

operation of the breaker if insufficient SF6 remains in the system.
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Appendix A 

TCEQ Applicable Forms 
TCEQ-10252 (Revised 10/12) PI-1 Instructions

This form is for use by facilities subject to air quality requirements and may be

revised periodically. (APDG 5171v19) Page_____ of _____

Texas Commission on Environmental Quality

Form PI-1 General Application for

Air Preconstruction Permit and Amendment

Important Note: The agency requires that a Core Data Form be submitted on all incoming applications unless 

a Regulated Entity and Customer Reference Number have been issued and no core data information has 

changed. For more information regarding the Core Data Form, call (512) 239-5175 or go to 

www.tceq.texas.gov/permitting/central_registry/guidance.html. 

I. Applicant Information

A. Company or Other Legal Name:

Texas Secretary of State Charter/Registration Number (if applicable):

B. Company Official Contact Name:

Title:

Mailing Address:

City: State: ZIP Code:

Telephone No.: Fax No.: E-mail Address:

C. Technical Contact Name:

Title:

Company Name:

Mailing Address:

City: State: ZIP Code:

Telephone No.: Fax No.: E-mail Address:

D. Site Name:

E. Area Name/Type of Facility: Permanent Portable

F. Principal Company Product or Business:

Principal Standard Industrial Classification Code (SIC):

Principal North American Industry Classification System (NAICS):

G. Projected Start of Construction Date:

Projected Start of Operation Date:

H. Facility and Site 

in writing.):

Location Information (If no street address, provide clear driving directions to the site 

Street Address:

City/Town: County: ZIP Code:

Latitude (nearest second): Longitude (nearest second):

 

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TCEQ-10252 (Revised 10/12) PI-1 Instructions

This form is for use by facilities subject to air quality requirements and may be

revised periodically. (APDG 5171v19) Page _____ of _____ 

Texas Commission on Environmental Quality

Form PI-1 General Application for

Air Preconstruction Permit and Amendment

I. Applicant Information (continued)

I. Account Identification Number (leave blank if new site or facility):

J. Core Data Form.

Is the Core Data Form (Form 10400) attached? If No, provide customer reference number 

and regulated entity number (complete K and L).

YES NO

K. Customer Reference Number (CN):

L. Regulated Entity Number (RN):

II. General Information

A. Is confidential information submitted with this application? If Yes, mark each 

confidential page confidential in large red letters at the bottom of each page.

YES NO

B. Is this application in response to an investigation, notice of violation, or enforcement 

action? If Yes, attach a copy of any correspondence from the agency and provide the 

RN in section I.L. above.

YES NO

C. Number of New Jobs:

D. Provide the name of the 

site:

State Senator and State Representative and district numbers for this facility 

State Senator: District No.:

State Representative: District No.:

III. Type of Permit Action Requested

A. Mark the appropriate box indicating what type of action is requested.

Initial Amendment Revision (30 TAC 116.116(e) Change of Location Relocation

B. Permit Number (if existing):

C. Permit Type: Mark the appropriate box indicating what type of permit is requested. 

(check all that apply, skip for change of location)

Construction Flexible Multiple Plant Nonattainment Plant-Wide Applicability Limit

Prevention of Significant Deterioration Hazardous Air Pollutant Major Source

Other:

D. Is a permit renewal application being submitted in conjunction with this 

amendment in accordance with 30 TAC 116.315(c).

YES NO

 

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TCEQ-10252 (Revised 10/12) PI-1 Instructions

This form is for use by facilities subject to air quality requirements and may be

revised periodically. (APDG 5171v19) Page _____ of _____ 

Texas Commission on Environmental Quality

Form PI-1 General Application for

Air Preconstruction Permit and Amendment

III. Type of Permit Action Requested (continued)

E. Is this application for a change of location of previously permitted facilities? 

If Yes, complete III.E.1 - III.E.4.0

YES NO

1. Current Location of Facility (If no street address, provide clear driving directions to the site in writing.):

Street Address:

City: County: ZIP Code:

2. Proposed Location of Facility (If no street address, provide clear driving directions to the site in writing.):

Street Address:

City: County: ZIP Code:

3. Will the proposed facility, site, and plot plan meet all current technical requirements of

the permit special conditions? If “NO”, attach detailed information.

YES NO

4. Is the site where the facility is moving considered a major source of criteria pollutants

or HAPs?

YES NO

F. Consolidation into this Permit: List any standard permits, exemptions or permits by rule to be 

consolidated into this permit including those for planned maintenance, startup, and shutdown.

List:

G. Are you permitting planned maintenance, startup, and shutdown emissions? If Yes, 

attach information on any changes to emissions under this application as specified 

in VII and VIII.

YES NO

H. Federal Operating Permit Requirements 

(30 TAC Chapter 122 Applicability)

Is this facility located at a site required to obtain a federal 

operating permit? If Yes, list all associated permit number(s), 

attach pages as needed).

YES NO To be determined

Associated Permit No (s.):

1. Identify the requirements of 30 TAC Chapter 122 that will be triggered if this application is approved.

FOP Significant Revision FOP Minor Application for an FOP Revision

Operational Flexibility/Off-Permit Notification Streamlined Revision for GOP

To be Determined None

 

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TCEQ-10252 (Revised 10/12) PI-1 Instructions

This form is for use by facilities subject to air quality requirements and may be

revised periodically. (APDG 5171v19) Page _____ of _____ 

Texas Commission on Environmental Quality

Form PI-1 General Application for

Air Preconstruction Permit and Amendment

III. Type of Permit Action Requested (continued)

H. Federal Operating Permit Requirements (30 TAC Chapter 122 Applicability) (continued)

2. Identify the type(s) of FOP(s) issued and/or FOP application(s) submitted/pending for the site.

(check all that apply)

GOP Issued GOP application/revision application submitted or under APD review

SOP Issued SOP application/revision application submitted or under APD review

IV. Public Notice Applicability

A. Is this a new permit application or a change of location application? YES NO

B. Is this application for a concrete batch plant? If Yes, complete V.C.1 – V.C.2. YES NO

C. Is this an application for a major modification of a PSD, nonattainment, 

FCAA 112(g) permit, or exceedance of a PAL permit?

YES NO

D. Is this application for a PSD or major modification of a PSD located within 

100 kilometers or less of an affected state or Class I Area?

YES NO

If Yes, list the affected state(s) and/or Class I Area(s).

List:

E. Is this a state permit amendment application? If Yes, complete IV.E.1. – IV.E.3.

1. Is there any change in character of emissions in this application? YES NO

2. Is there a new air contaminant in this application? YES NO

3. Do the facilities handle, load, unload, dry, manufacture, or 

legumes, or vegetables fibers (agricultural facilities)?

process grain, seed, YES NO

F. List the total annual emission increases associated with the application

(List all that apply and attach additional sheets as needed):

Volatile Organic Compounds (VOC):

Sulfur Dioxide (SO2):

Carbon Monoxide (CO):

Nitrogen Oxides (NOx):

Particulate Matter (PM):

PM 10 microns or less (PM10):

PM 2.5 microns or less (PM2.5):

Lead (Pb):

Hazardous Air Pollutants (HAPs):

Other speciated air contaminants not listed above:

 

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TCEQ-10252 (Revised 10/12) PI-1 Instructions

This form is for use by facilities subject to air quality requirements and may be

revised periodically. (APDG 5171v19) Page _____ of _____ 

Texas Commission on Environmental Quality

Form PI-1 General Application for

Air Preconstruction Permit and Amendment

V. Public Notice Information (complete if applicable)

A. Public Notice Contact Name:

Title:

Mailing Address:

City: State: ZIP Code:

B. Name of the Public Place:

Physical Address (No P.O. Boxes):

City: County: ZIP Code:

The public 

copying.

place has granted authorization to place the application for public viewing and YES NO

The public place has internet access available for the public. YES NO

C. Concrete Batch Plants, PSD, and Nonattainment Permits

1. County Judge Information (For Concrete Batch Plants

facility site.

and PSD and/or Nonattainment Permits) for this 

The Honorable:

Mailing Address:

City: State: ZIP Code:

2. Is the facility located in a municipality or an extraterritorial jurisdiction 

municipality? (For Concrete Batch Plants)

of a YES NO

Presiding Officers Name(s):

Title:

Mailing Address:

City: State: ZIP Code:

3. Provide the name, mailing address of the chief executive and Indian Governing Body; and identify the

Federal Land Manager(s) for the location where the facility is or will be located.

Chief Executive:

Mailing Address:

City: State: ZIP Code:

Name of the Indian Governing Body:

Mailing Address:

City: State: ZIP Code:

 

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TCEQ-10252 (Revised 10/12) PI-1 Instructions

This form is for use by facilities subject to air quality requirements and may be

revised periodically. (APDG 5171v19) Page _____ of _____ 

Texas Commission on Environmental Quality

Form PI-1 General Application for

Air Preconstruction Permit and Amendment

V. Public Notice Information (complete if applicable) (continued)

C. Concrete Batch Plants, PSD, and Nonattainment Permits

3. Provide the name, mailing address of the chief executive and Indian Governing Body; and identify the

Federal Land Manager(s) for the location where the facility is or will be located. (continued)

Name of the Federal Land Manager(s):

D. Bilingual Notice

Is a bilingual program required by the Texas Education Code in the School District? YES NO

Are the children who attend either the elementary school or the middle school closest to 

your facility eligible to be enrolled in a bilingual program provided by the district?

YES NO

If Yes, list which languages are required by the bilingual program?

VI. Small Business Classification (Required)

A. Does this company (including parent companies and subsidiary companies) 

fewer than 100 employees or less than $6 million in annual gross receipts?

have YES NO

B. Is the site a major stationary source for federal air quality permitting? YES NO

C. Are the site emissions of 

50 tpy?

any regulated air pollutant greater than or equal to YES NO

D. Are the site emissions of all regulated air pollutants combined less than 75 tpy? YES NO

VII. Technical Information

A. The following information must be submitted with your Form PI-1

(this is just a checklist to make sure you have included everything)

1. Current Area Map

2. Plot Plan

3. Existing Authorizations

4. Process Flow Diagram

5. Process Description

6. Maximum Emissions Data and Calculations

7. Air Permit Application Tables

a. Table 1(a) (Form 10153) entitled, Emission Point Summary

b. Table 2 (Form 10155) entitled, Material Balance

c. Other equipment, process or control device tables

B. Are any schools located within 3,000 feet of this facility? YES NO

 

U R M # " S
TCEQ-10252 (Revised 10/12) PI-1 Instructions

This form is for use by facilities subject to air quality requirements and may be

revised periodically. (APDG 5171v19) Page _____ of _____ 

Texas Commission on Environmental Quality

Form PI-1 General Application for

Air Preconstruction Permit and Amendment

VII. Technical Information

C. Maximum Operating Schedule:

Hour(s): Day(s): Week(s): Year(s):

Seasonal Operation? If Yes, please describe in the space provide below. YES NO

D. Have the planned MSS emissions been previously submitted as part of an emissions 

inventory?

YES NO

Provide a list of each planned MSS facility or related activity and indicate which years the MSS activities have 

been included in the emissions inventories. Attach pages as needed.

E. Does this application involve any air contaminants for 

required?

which a disaster review is YES NO

F. Does this application include a pollutant 

(APWL)?

of concern on the Air Pollutant Watch List YES NO

VIII. State Regulatory Requirements

Applicants must demonstrate compliance with all applicable state regulations to obtain

a permit or amendment. The application must contain detailed attachments addressing

applicability or non applicability; identify state regulations; show how requirements are met; and

include compliance demonstrations.

A. Will the emissions from the proposed facility protect public 

comply with all rules and regulations of the TCEQ?

health and welfare, and YES NO

B. Will emissions of significant air contaminants from the facility be measured? YES NO

C. Is the Best Available Control Technology (BACT) demonstration attached? YES NO

D. Will the proposed facilities achieve the performance represented in the permit 

application as demonstrated through recordkeeping, monitoring, stack testing, or 

other applicable methods?

YES NO

IX. Federal Regulatory Requirements

Applicants must demonstrate compliance with all applicable federal regulations to

obtain a permit or amendment. The application must contain detailed attachments addressing

applicability or non applicability; identify federal regulation subparts; show how requirements are

met; and include compliance demonstrations.

A. Does Title 40 Code of Federal Regulations Part 60, (40 CFR Part 60) 

Performance Standard (NSPS) apply to a facility in this application?

New Source YES NO

B. Does 40 CFR Part 61, National Emissions Standard for Hazardous Air Pollutants 

(NESHAP) apply to a facility in this application?

YES NO

 

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TCEQ-10252 (Revised 10/12) PI-1 Instructions

This form is for use by facilities subject to air quality requirements and may be

revised periodically. (APDG 5171v19) Page _____ of _____ 

Texas Commission on Environmental Quality

Form PI-1 General Application for

Air Preconstruction Permit and Amendment

IX. Federal Regulatory Requirements

Applicants must demonstrate compliance with all applicable federal regulations to

obtain a permit or amendment. The application must contain detailed attachments addressing

applicability or non applicability; identify federal regulation subparts; show how requirements are

met; and include compliance demonstrations.

C. Does 40 CFR Part 63, Maximum Achievable Control Technology (MACT) standard 

apply to a facility in this application?

YES NO

D. Do nonattainment permitting requirements apply to this application? YES NO

E. Do prevention of significant deterioration 

application?

permitting requirements apply to this YES NO

F. Do Hazardous Air Pollutant Major Source [FCAA 112(g)] 

application?

requirements apply to this YES NO

G. Is a Plant-wide Applicability Limit permit being requested? YES NO

X. Professional Engineer (P.E.) Seal

Is the estimated capital cost of the project greater than $2 million dollars? YES NO

If Yes, submit the application under the seal of a Texas licensed P.E.

XI. Permit Fee Information

Check, Money Order, Transaction Number ,ePay Voucher Number: Fee Amount: $

Paid online? YES NO

Company name on check:

Is a copy of the check or money order attached to 

application?

the original submittal of this YES NO N/A

Is a Table 30 (Form 

attached?

10196) entitled, Estimated Capital Cost and Fee Verification, YES NO N/A

 

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TCEQ-10252 (Revised 10/12) PI-1 Instructions

This form is for use by facilities subject to air quality requirements and may be

revised periodically. (APDG 5171v19) Page_____ of _____ 

Texas Commission on Environmental Quality

Form PI-1 General Application for

Air Preconstruction Permit and Amendment

XII. Delinquent Fees and Penalties

This form will not be processed until all delinquent fees and/or penalties owed to the TCEQ or the Office of 

the Attorney General on behalf of the TCEQ is paid in accordance with the Delinquent Fee and Penalty 

Protocol. For more information regarding Delinquent Fees and Penalties, go to the TCEQ Web site at: 

www.tceq.texas.gov/agency/delin/index.html.

XIII. Signature

The signature below confirms that I have knowledge of the facts included in this application and that these 

facts are true and correct to the best of my knowledge and belief. I further state that to the best of my 

knowledge and belief, the project for which application is made will not in any way violate any provision of the 

Texas Water Code (TWC), Chapter 7, Texas Clean Air Act (TCAA), as amended, or any of the air quality rules 

and regulations of the Texas Commission on Environmental Quality or any local governmental ordinance or 

resolution enacted pursuant to the TCAA I further state that I understand my signature indicates that this 

application meets all applicable nonattainment, prevention of significant deterioration, or major source of 

hazardous air pollutant permitting requirements. The signature further signifies awareness that intentionally 

or knowingly making or causing to be made false material statements or representations in the application is a 

criminal offense subject to criminal penalties.

Name:

Signature:

Original Signature Required

Date:

 

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TCEQ - 10153 (Revised 04/08) Table 1(a) 

This form is for use by sources subject to air quality permit requirements and may be revised periodically. (APDG 5178 v5) 

TEXAS COMMISSION ON ENVIRONMENTAL QUALITY 

Table 1(a) Emission Point Summary

Date: August 2013 Permit No.: 48106 and PSD-TX1012-M1 Regulated Entity No.: RN1Area Name: City of Austin Sand Hill Energy Center (SHEC) Customer Reference No.: C

Review of applications and issuance of permits will be expedited by supplying all necessary information requested on this Table. 

AIR CONTAMINANT DATA

1. Emission Point 2. Component or Air Contaminant Name 3. Air Contaminant E(A) EPN (B) FIN (C) Name (A) Pound Per Hour SH8 SH8 GE 7FA.04 

w/HRSG Combined 

CO2e 333,749 lb/hr 

CC MS FUG CC MS FUG Combined Cycle 

Natural Gas Meter

CO2e 27 lb/hr 

EPN = Emission Point Number FIN = Facility Identification Number 
TCEQ - 10153 (Revised 04/08) Table 1(a)

This form is for use by sources subject to air quality permit requirements and may be revised periodically. (APDG 5178 v5) 

TEXAS COMMISSION ON ENVIRONMENTAL QUALITY 

Table 1(a) Emission Point Summary

Date: August 2013 Permit No.: 48106 and PSD-TX1012-M1 Regulated Entity No.: RN1Area Name: City of Austin Sand Hill Energy Center (SHEC) Customer Reference No.: C

Review of applications and issuance of permits will be expedited by supplying all necessary information requested on this Table. 

AIR CONTAMINANT DATA EMISSION POINT DISCHARGE PARAMETERS 1. Emission Point 4. UTM Coordinates of 

Emission Point 

Source 

5. Building

Height (Ft.) 

6. Height 

Above Ground (Ft.) 

7. Stack Exit Data 

(A) EPN (B) FIN (C) NAME Zone East 

(Meters) 

North 

(Meters)

(A) Diameter 

(Ft.) 

(B) Velocity

(FPS) 

(C) Temperature 

(°F) 

SH8 SH8 GE 7FA.04 

w/HRSG 14 633,590 3,342,923 --- 157.5 18.05 40.15 200 

CC MS 

FUG

CC MS 

FUG

Combined Cycle 

Natural Gas Meter 14 633,514 3,342,925 --- 3.0 --- --- --- 

EPN = Emission Point Number FIN = Facility Identification Number 
TRC Environmental Corporation | The City of Austin dba Austin Energy   

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Appendix B 

Emissions Calculations and Documentation 
Appendix B, Table 1

Estimated Performance and Emissions for GE 7FA.04 Combustion Turbine in Simple Cycle and Combined C

MODE NUMBER 1 2 3 4 5 6 7 8 9 10 

Load Condition % CTG Base Load BASE BASE 75% 50% BASE BASE BASE 75% 53% BASE Ambient Temperature deg F 0 0 0 0 68 68 68 68 68 112 Evap. Cooler Status Off Off Off Off On On Off Off Off On 

Evap. Cooler Effectiveness % 0 0 0 0 85 85 0 0 0 85 Duct Burner Status On Off Off Off On Off Off Off Off On 

Ambient Relative Humidity % 60 60 60 60 60 60 60 60 60 60 Inlet Loss in H2O 4444444444Exhaust Pressure Loss in H2O 16.1 16.1 10.7 7.3 14.4 14.4 14 9.5 7 11.5 Fuel Type Cust Gas Cust Gas Cust Gas Cust Gas Cust Gas Cust Gas Cust Gas Cust Gas Cust Gas Cust Gas Fuel LHV BTU/lb 20,460 20,460 20,460 20,460 20,460 20,460 20,460 20,460 20,460 20,460 Fuel Temperature deg F 365 365 365 365 365 365 365 365 365 365 CTG Output (Simple Cycle) kW 196,178 196,178 147,133 98,089 179,025 179,025 173,910 130,433 92,172 152,206 STG Output (estimated)* kW 168,683 102,365 86,067 74,672 162,271 95,953 94,620 80,141 71,053 153,844 CC (CTG + STG) Combined Cycle Output kW 364,861 298,543 233,200 172,761 341,296 274,978 268,530 210,574 163,225 306,050 CTG Simple Cycle Heat Rate (LHV) BTU/kWh, LHV 8,792 8,792 9,440 11,252 8,991 8,991 9,041 9,766 11,379 9,433 CTG Simple Cycle Heat Rate (HHV) BTU/kWh, HHV 9,744 9,744 10,462 12,470 9,964 9,964 10,020 10,823 12,611 10,454 CTG Simple Cycle Thermal Efficiency % 35.0% 35.0% 32.6% 27.4% 34.3% 34.3% 34.1% 31.5% 27.1% 32.6% CTG Simple Cycle Heat Rate, LHV (+ margin**) BTU/kWh, LHV 9,671 9,671 10,384 12,377 9,890 9,890 9,945 10,743 12,517 10,376 CTG Simple Cycle Heat Rate, HHV (+ margin**) BTU/kWh, HHV 10,718 10,718 11,508 13,717 10,961 10,961 11,022 11,906 13,872 11,500 Combined Cycle (CTG + STG) Heat Rate (LHV) BTU/kWh 6,410 5,778 5,956 6,389 6,515 5,854 5,855 6,049 6,426 6,697 Combined Cycle (CTG + STG) Heat Rate (HHV) BTU/kWh, HHV 7,104 6,403 6,601 7,080 7,221 6,488 6,489 6,704 7,121 7,422 Combined Cycle (CTG + STG) Thermal Efficiency % 48.0% 53.3% 51.7% 48.2% 47.3% 52.6% 52.6% 50.9% 47.9% 46.0% Combined Cycle (CTG + STG) Heat Rate (+ margin**) BTU/kWh, LHV 7,051 6,355 6,552 7,027 7,167 6,439 6,440 6,654 7,068 7,367 Combined Cycle (CTG + STG) Heat Rate (+ margin**) BTU/kWh, HHV 7,815 7,044 7,261 7,788 7,943 7,136 7,138 7,375 7,833 8,165 CTG Heat Cons. (LHV) MMBTU/hr 1,724.9 1,724.9 1,389.0 1,103.7 1,609.7 1,609.7 1,572.2 1,273.8 1,048.8 1,435.7 CTG Heat Consumption (HHV) MMBTU/hr 1,911.6 1,911.6 1,539.4 1,223.2 1,784.0 1,784.0 1,742.4 1,411.7 1,162.4 1,591.1 

CTG Exhaust Flow x10^3 lb/hr 3,733 3,733 3,019 2,466 3,493 3,493 3,435 2,804 2,389 3,086 CTG Exhaust Temperature deg F 1,076 1,076 1,116 1,182 1,130 1,130 1,134 1,172 1,215 1,177 

Exhaust Molecular Weight lb/lbmol 28.48 28.48 28.49 28.5 28.32 28.32 28.35 28.35 28.37 27.87 
Appendix B, Table 1

Estimated Performance and Emissions for GE 7FA.04 Combustion Turbine in Simple Cycle and Combined C

COMBUSTION TURBINE EMISSIONSNOx ppmvd @ 15% O2 9 9 9 9 9 9 9 9 9 9 NOx AS NO2 lb/hr 62 62 50 40 58 58 57 46 38 52 CO ppmvd 9 9 9 11 9 9 9 9 11 9 CO lb/hr 31 31 25 24 28 28 28 23 25 24 UHC ppmvw 7777777777UHC lb/hr 15 15 12 10 14 14 14 11 9 12 VOC ppmvw 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 1.4 

VOC lb/hr 3.0 3.0 2.4 2.0 2.8 2.8 2.8 2.2 1.8 2.4 

PM/PM‐10/PM‐2.5 (filterable) lb/hr 9999999999PM/PM‐10/PM‐2.5 (f+c) lb/hr 12 12 12 12 12 12 12 12 12 12 SO2 lb/MMBTU, HHV 0.000642 0.000642 0.000642 0.000642 0.000642 0.000642 0.000642 0.000642 0.000642 0.000642 

SO2 lb/hr 1.23 1.23 0.99 0.79 1.15 1.15 1.12 0.91 0.75 1.02 CO2 (per 40 CFR 98 Table C‐1 EFs) lb/MMBTU, HHV 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 CO2 (per 40 CFR 98 Table C‐1 EFs) lb/hr 223,447 223,447 179,934 142,976 208,524 208,524 203,666 165,011 135,864 185,984 

N2O (per 40 CFR 98 Table C‐2 EFs) lb/MMBTU, HHV 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 

N2O (per 40 CFR 98 Table C‐2 EFs) lb/hr 0.42 0.42 0.34 0.27 0.39 0.39 0.38 0.31 0.26 0.35 

CH4 (per 40 CFR 98 Table C‐2 EFs) lb/MMBTU, HHV 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 CH4 (per 40 CFR 98 Table C‐2 EFs) lb/hr 4.21 4.21 3.39 2.70 3.93 3.93 3.84 3.11 2.56 3.51 GHG, CO2e (per 40 CFR 98 EFs) lb/hr 223,666 223,666 180,110 143,116 208,728 208,728 203,866 165,173 135,997 186,166 

GHG, CO2e (per 40 CFR 98 EFs) lb/MMBTU, HHV 117.0 117.0 117.0 117.0 117.0 117.0 117.0 117.0 117.0 117.0 COMBUSTION TURBINE EXHAUST ANALYSIS % VOL.Argon % by volume 0.90 0.90 0.89 0.90 0.89 0.89 0.88 0.88 0.89 0.85 

Nitrogen % by volume 75.08 75.08 75.09 75.17 73.91 73.91 74.12 74.14 74.24 70.67 

Oxygen % by volume 12.50 12.50 12.54 12.76 12.25 12.25 12.35 12.42 12.69 11.43 

Carbon Dioxide % by volume 3.91 3.91 3.90 3.79 3.88 3.88 3.86 3.83 3.70 3.85 Water % by volume 7.61 7.61 7.58 7.38 9.08 9.08 8.79 8.73 8.49 13.20 

TOTAL 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 
Appendix B, Table 1

Estimated Performance and Emissions for GE 7FA.04 Combustion Turbine in Simple Cycle and Combined C

DUCT BURNER EMISSIONSDuct Burner Firing Rate* MMBTU/hr, LHV 614.0 614.0 614.0

Duct Burner Firing Rate* MMBTU/hr, HHV 681.5 681.5 681.5

NOx lb/MMBTU, HHV 0.10 0.10 0.10NOx lb/hr 68.15 68.15 68.15

CO lb/MMBTU, HHV 0.10 0.10 0.10

CO lb/hr 68.15 68.15 68.15VOC (per EPA AP‐42 Table 1.4‐2) lb/MMBTU, HHV 0.0054 0.0054 0.0054

VOC lb/hr 3.67 3.67 3.67

PM/PM‐10/PM‐2.5 (F+C) (per EPA AP‐42 Table 1.4‐2) lb/MMBTU, HHV 0.0074 0.0074 0.0074

PM/PM‐10/PM‐2.5 (F+C) lb/hr 5.07 5.07 5.07SO2 lb/MMBTU, HHV 0.00064 0.00064 0.00064

SO2 lb/hr 0.44 0.44 0.44CO2 (per 40 CFR 98 Table C‐1 EF) lb/MMBTU, HHV 116.9 116.9 116.9

CO2 (per 40 CFR 98 Table C‐1 EF) lb/hr 79,663 79,663 79,663

N2O (per 40 CFR 98 Table C‐1 EF) lb/MMBTU, HHV 0.0002 0.0002 0.0002

N2O (per 40 CFR 98 Table C‐1 EF) lb/hr 0.15 0.15 0.15CH4 (per 40 CFR 98 Table C‐1 EF) lb/MMBTU, HHV 0.0022 0.0022 0.0022

CH4 (per 40 CFR 98 Table C‐1 EF) lb/hr 1.50 1.50 1.50

GHG, CO2e (per 40 CFR 98 EF & GWP) lb/MMBTU, HHV 117.0 117.0 117.0

GHG, CO2e (per 40 CFR 98 EF & GWP) lb/hr 79,741 79,741 79,741

HRSG EXHAUST COMPOSITION (VOLUME %)Argon % by volume 0.89% 0.90% 0.89% 0.90% 0.88% 0.89% 0.88% 0.88% 0.89% 0.84% 

Nitrogen % by volume 74.09% 75.08% 75.09% 75.17% 72.87% 73.90% 74.12% 74.14% 74.23% 69.57% 

Oxygen % by volume 9.65% 12.50% 12.54% 12.76% 9.22% 12.25% 12.35% 12.42% 12.69% 8.08% 

Carbon Dioxide % by volume 5.22% 3.91% 3.90% 3.79% 5.27% 3.88% 3.86% 3.83% 3.70% 5.40% Water % by volume 10.15% 7.61% 7.58% 7.38% 11.75% 9.08% 8.79% 8.73% 8.49% 16.11% 

TOTAL 100% 100% 100% 100% 100% 100% 100% 100% 100% 100% HRSG FLUE GAS MOLECULAR WT

Flue Gas lb/lb‐mole 28.33 28.49 28.49 28.50 28.16 28.33 28.35 28.36 28.37 27.69 

HRSG STACK EXHAUST PARAMETERSStack Height AGL ft 127.0 127.0 127.0 127.0 127.0 127.0 127.0 127.0 127.0 127.0 

Stack Diameter ft 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 19.0 

Stack Exhaust Temperature Degrees F 200.0 200.0 200.0 200.0 200.0 200.0 200.0 200.0 200.0 200.0 

Stack Exhaust Flow Rate ACFM 1,066,827 1,052,528 850,915 694,806 1,004,821 990,522 972,947 794,219 676,263 903,448 

Stack Exit Velocity ft/s 62.7 61.9 50.0 40.8 59.1 58.2 57.2 46.7 39.8 53.1 
Appendix B, Table 1

Estimated Performance and Emissions for GE 7FA.04 Combustion Turbine in Simple Cycle and Combined C

UNCONTROLLED & CONTROLLED EMISSIONS (TURBINE + DUCT BURNER)NOx Uncontrolled lb/hr 130.2 62.0 50.0 40.0 126.2 58.0 57.0 46.0 38.0 120.2 NOx Uncontrolled ppmvd@15%O2 13.6 9.7 9.7 8.3 12.7 8.1 8.1 8.1 8.2 12.0 NOx Controlled lb/hr 19.2 12.7 10.4 9.6 19.9 14.4 14.0 11.3 9.3 20.1 NOx Controlled ppmvd@15%O2 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 CO Uncontrolled lb/hr 99.2 31.0 25.0 24.0 96.2 28.0 28.0 23.0 25.0 92.2 CO Uncontrolled ppmvd@15%O2 17.0 8.0 7.9 8.2 15.9 6.4 6.6 6.7 8.8 15.1 CO Controlled lb/hr 11.7 7.8 6.3 5.8 12.1 8.8 8.5 6.9 5.7 12.2 CO Controlled ppmvd@15%O2 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 2.0 VOC lb/hr 6.7 3.0 2.4 2.0 6.5 2.8 2.8 2.2 1.8 6.1 

VOC ppmvd@15%O2 2.0 1.4 1.3 1.2 1.9 1.1 1.1 1.1 1.1 1.7 PM/PM‐10/PM‐2.5 (F+C) lb/hr 17.1 12.0 12.0 12.0 17.1 12.0 12.0 12.0 12.0 17.1 PM/PM‐10/PM‐2.5 (F+C) lb/MMBTU, HHV 0.0066 0.0063 0.0078 0.0098 0.0069 0.0067 0.0069 0.0085 0.0103 0.0075 

PM‐10 incl. Ammonia Salts lb/hr 18.4 13.0 12.8 12.6 18.4 12.9 12.9 12.7 12.6 18.3 PM‐10 incl. Ammonia Salts lb/MMBTU, HHV 0.0071 0.0068 0.0083 0.0103 0.0075 0.0073 0.0074 0.0090 0.0109 0.0080 SO2 lb/hr 1.67 1.23 0.99 0.79 1.58 1.15 1.12 0.91 0.75 1.46 SO2 lb/MMBTU, HHV 0.00064 0.00064 0.00064 0.00064 0.00064 0.00064 0.00064 0.00064 0.00064 0.00064 

H2SO4 lb/hr 1.02 0.75 0.61 0.48 0.97 0.70 0.69 0.56 0.46 0.89 H2SO4 lb/MMBTU, HHV 0.00039 0.00039 0.00039 0.00039 0.00039 0.00039 0.00039 0.00039 0.00039 0.00039 

CO2 lb/hr 303,110 223,447 179,934 142,976 288,187 208,524 203,666 165,011 135,864 265,647 

CO2 lb/MMBTU, HHV 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 116.9 N2O lb/hr 0.6 0.4 0.3 0.3 0.5 0.4 0.4 0.3 0.3 0.5 N2O lb/MMBTU, HHV 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 0.00022 CH4 lb/hr 5.7 4.2 3.4 2.7 5.4 3.9 3.8 3.1 2.6 5.0 CH4 lb/MMBTU, HHV 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 0.0022 GHG, CO2e lb/hr 303,408 223,666 180,110 143,116 288,470 208,728 203,866 165,173 135,997 265,907 GHG, CO2e lb/MMBTU, HHV 117.0 117.0 117.0 117.0 117.0 117.0 117.0 117.0 117.0 117.0 

GHG, CO2e (Simple Cycle) ton/MWh 0.773 0.570 0.612 0.730 0.806 0.583 0.586 0.633 0.738 0.874 

GHG, CO2e (Simple Cycle + margin**) ton/MWh 0.851 0.627 0.673 0.802 0.886 0.641 0.645 0.696 0.812 0.961 

GHG, CO2e (Combined Cycle) ton/MWh 0.416 0.375 0.386 0.414 0.423 0.380 0.380 0.392 0.417 0.434 GHG, CO2e (Combined Cycle + margin**) ton/MWh 0.457 0.412 0.425 0.456 0.465 0.417 0.418 0.431 0.458 0.478 NH3 Slip ppmvd @ 15% O2 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 7.0 

NH3 Slip lb/hr 24.9 16.5 13.4 12.4 25.7 18.6 18.1 14.7 12.0 26.0 

** Margin added for measurement error, off-design conditions and degradation 10.0%Combustion turbine performance and emissions data based on GE Energy gas turbine performance simulation runs at site specific conditions; supplemental data calculated as follows

Formulas / Example Calculations:

Exhaust mole flow rate = exhaust mass flow rate / flue gas molecular weight = lb/hr / lb/lb‐mole = lb‐mole/hr

Dry exhaust mole flow rate = lb‐mole/hr x (1‐ %H20/100)

Dry mole flow rate at 15% O2 = dry lb‐mole/hour x (20.9 ‐ % O2 dry)/(20.9/15)

Pollutant lb/hr = lb‐mole/hr, dry basis, at 15 % O2 x ppmvd @ 15% O2 dry /106 x molecular weight, lb/lb‐mole

Heat Rate (Btu/kWh) = Heat Input Rate (MMBtu/hr) x (10^6 BTU/MMBtu) / Generator Output (MW) / (MW/1000 kW)

* STG output (kW) estimated by scaling from design case (68 F, evap cooler on, unfired) based on ratio of exhaust energy + duct burner heat input to design case exhaust energy; actual STG outpuoperating, but maximum duct burner firing rate used for all conditions as worst case for permitting
Source Pollutant Emission Factor2 GHG Mass Emissions 

(kg/MMBtu) (tons/yr) 

CO2 53.02 1,327,624 1,460,386 

CH4 1.00E‐03 25.0 27.5 2

N2O 1.00E‐04 2.5 2.8 3

GHG Totals 1,327,651 1,460,416 

2 CO2, CH4 and N2O emission factors based on Tables C‐1 and C‐1 of 40 CFR 98.3 Global warming potential factors based on Table A‐1 of 40 CFR 98.

Example Calculations:

Combustion Turbine Fuel = 8760 hr/yr x 1911.6 MMBtu/hr = 16,746,049 MMBtu/yr

Duct Burner Fuel = 8760 hr/yr x 681.5 MMBtu/hr = 5,970,290 MMBtu/yr

Total Fuel = 16,746,049 + 5,970,290 = 22,716,339 MMBtu/yrCarbon Dioxide22,716,339 MMBtu/hr x (53.02 kg CO2/MMBtu) x (2.2046 lb/kg) / (2000 lb/ton) x 1 CO2e/CO2 = 1,327,624 tons CO2e/yrMethane22,716,339 MMBtu/hr x (0.001 kg CH4/MMBtu) x (2.2046 lb/kg) / (2000 lb/ton) x 21 CO2e/CH4= 526 tons CO2e/yrNitrous Oxides22,716,339 MMBtu/hr x (0.0001 kg N2O/MMBtu) x (2.2046 lb/kg) / (2000 lb/ton) x 310 CO2e/N2O = 776 tons CO2e/yr

Annual Fuel Use1

(MMBtu/yr)

Mass Plus 10%

Margin (tons/yr)

Global W

Pote

Combustion turbine

combined cycle unit 22,716,339

1 Annual heat input based on 8760 hours per year of operation of the combustion turbine at an average ambient temperature of 68oF w

and a duct burner firing at 681.5 MMBtu/hr for 8760 hours per year.

Appendix B, Table 2: Annual GHG Emission Calculations – New Combined Cycle Combustion Turbine
Source Component Fluid Count Emission Factor1 CO22 CH43 

Type State (scf/hr/component) (tons/yr) (tons/yr) 

Valves 194 0.121 0.093 4.02

Flanges 161 0.017 0.011 0.47

Relief Valve 35 0.193 0.027 1.16

GHG Mass Based Emissions 0.130 5.64 Global Warming Potential4 1 21

CO2e Emissions 0.130 118.5 

1 Emission factors from Table W‐1A of 40 CFR Part 98 Mandatory Greenhouse Gas Reporting2 CO2 emissions based on vol % CO2 in natural gas of 0.79%3 CH4 emissions based on vol % CH4 in natural gas of 94.14%4 Global warming potential based on Table A‐1 of 40 CFR Part 98 Mandatory Greenhouse Gas Reporting

Example Calculations

CO2 Emissions from Valves194 valves x (0.121 scf gas/hr‐valve) x (0.0079 scf CO2/scf gas) / (385.5 scf/lb‐mole) x (44 lb CO2/lb‐mole) x (8760 hr/yr) / (20

= 0.093 ton CO2 / year

CH4 Emissions from Valves194 valves x (0.121 scf gas/hr‐valve) x (0.9414 scf CH4/scf gas) / (385.5 scf/lb‐mole) x (16 lb CH4/lb‐mole) x (8760 hr/yr) / (200

= 4.017 tons CH4 / year

Natural Gas Fugitives Gas/Vapor

Appendix B, Table 3: Natural Gas Fugitive GHG Emission Calculations
Estimated Quantity of SF6 in New Equipment 59 pounds

Annual Leak Rate 0.50% of quantity present

Annual Emission Rate 0.295 lb/yrAnnual SF6 Emissions 0.0001475 ton/yr of SF6

Global Warming Potential Factor for SF6 23,900

Annual CO2e Emissions 3.53 ton/yr of CO2e

Example Calculation59 lb SF6 x 0.50%/yr / (2000 lb/ton) x 23,900 CO2e/SF6 = 3.53 ton CO2e/yr

Appendix B, Table 4: SF6 Emission Calculations for Electrical Equipment Leaks
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Appendix C 

BACT Analysis Calculations and Documentation 
FACILITY STATE PERMIT PERMIT STATUS EQUIPMENT CONTROL OUTPUT BASIS HEAT RATE INPUT BA

STATUS DATE OPER? DETAILS TECHNOLOGY LB/MWH BTU/KWH LB/MMBT

RUSSELL CITY CA FINAL 2/3/2010 NO NGCC EFFICIENT CTGs NG 7,730 

PACIFICORP UT FINAL 5/4/2011 NO NGCC EFFICIENT CTGs & HRSG 950 ROBINSON POWER PA FINAL 6/30/2011 NO NGCC 1 x GE 7EA + DB EFFICIENT CTGs PALMDALE CA FINAL 10/18/2011 NO NGCC W/SOLAR EFFICIENT CTGs & SOLAR 774* 7,319 117 LCRA FERGUSON TX FINAL 11/10/2011 NO NGCC EFFICIENT CTGs 918 7,720 KENNECOTT UT FINAL 11/22/2011 NO NGCC EFFICIENT CTGs 7,642 

PIONEER VALLEY MA FINAL 4/12/2012 NO NGCC MITSUBISHI 501G EFFICIENT CTGs 895 CPV VALLEY NY DRAFT 7/11/2012 NO NGCC SIEMENS F EFFICIENT CTGs 925 WOODBRIDGE NJ FINAL 8/24/2012 NO NGCC GE 7FA EFFICIENT CTGs 925 7,605 GIBSON COUNTY TN DRAFT 9/4/2012 NO NGCC GE 7FA EFFICIENT CTGs 

CRICKET VALLEY NY FINAL 9/27/2012 NO NGCC GE 7FA HIGH EFFICIENCY CTGS 913** 7,605 120 BLACK HILLS WY FINAL 9/27/2012 NO NGCC GE LM6000 EFFICIENT CTGs 1,100 HESS NEWARK NJ FINAL 10/13/2012 NO NGCC GE 7FA EFFICIENT CTGs 887 7,522 

CALPINE DEER PARK TX FINAL 11/29/2012 NO NGCC SIEMENS 501FD2 EFFICIENT CTGs 920 7,730 CALPINE CHANNEL TX FINAL 11/29/2012 NO NGCC SIEMENS 501FD2 EFFICIENT CTGs 920 7,730 * Includes solar power component** Calculated based on heat rate Btu/kWh and emission factor lb/MMBtu

Recent Permit Limits for Natural Gas-Fired Combined Cycle Combustion Turbines > 25 MW

Greenhouse Gas Emissions

Appendix C, Table 1
Description Cost1 Basis

Capital Cost:AGI Pipeline - 26" diameter 45 mile pipeline

Materials $22,394,963 $64,632 + $1.85 x L x (330.5 x D2 + 686.7 x D + 26,960)

Labor $38,298,649 $341,627 + $1.85 x L x (343.2 x D2 + 2,074 x D + 170,013

Miscellaneous $16,224,170 $150,166 + $1.58 x L x (8,417 x D + 7,234)

Right-of-Way $2,466,697 $48,037 + $1.20 x L x (577 x D + 29,788)

CO2 Surge Tank $1,150,636Pipeline Control System $110,632Total Capital Cost $80,645,746Annual Operating Cost:O&M Cost $388,440 $8,632/mile/yearTotal Annual Operating Cost $388,440Capital Recovery Factor 0.0944 7% interest rate and 20 year equipment lifeAnnualized Capital Cost $7,612,958Total Annual Cost $8,001,398GHG Emissions Removed 1,314,348Cost Effectiveness ($/ton) $6.09Length in miles (L) = 45Diameter in inches (D) = 26

1 CO2 transport cost is calculated per pipeline cost equations from Quality Guidelines for Energy System Studies: 

Estimating Carbon Dioxide Transport and Storage Costs, National Energy Technology Laboratory, US Department Energy, DOE/NETL-2010/1447 (March, 2010).

CO2 Pipeline Construction Cost Estimate

Appendix C - Table 2
Monitoring Cost $2.50 per component per quarter

Number of Valves 194 monitored

Number of Flanges 161 not monitoredNumber of PRVs 35 monitored

Number of Pumps 0 monitored

Number of Compressors 0 monitoredTotal Number Monitored 229 monitored

Total Monitoring Cost $2,290 per year

Number of Repairs 110 per year (12% of monitored components per quarter)

Cost of Repairs $18,686 per year @ $200/component (assumed 85% of leaking component ne

repair; remaining 15% only require minor repair)

Cost to Re-monitor Repairs $275 per year

Total Cost of LDAR $21,251 per year (monitoring+repair+re-monitoring)

Emission Reduction 81.56 ton/year CO2e (based on 28M reduction of 75%)

Cost Effectiveness $260.54 per ton CO2e

Example Calculations:Monitoring cost = ($2.50/component/quarter) x (229 components) x (4 quarters/year) = $2,290/yearTotal cost = $2,290/year + $18,686/year + $275/year = $21,251/yearCost Effectiveness = ($21,251/year) / (81.56 tons/year CO2e) = $260.54/ton CO2e

Cost Analysis for Natural Gas Fugitives LDAR Program

Appendix C, Table 3