## PREVENTION OF SIGNIFICANT DETERIORATION PERMIT FOR GREENHOUSE GAS EMISS IO NS ISSUED PURSUANT TO THE REQUIREMENTS AT 40 CFR 

## § 52.21

U.S. ENVIRONMENTAL PROTECTION AGENCY, REGION 

### 6

PSD PERMIT NUMBER: PSD-TX-1298-GHG

P ERM I TTEE: Pinecrest Energy Center

, LLC
3608 Preston Road

, Suite 225
Plano

, TX 75093

FACILITY NAME: · P inecres t Energy Center, LLC Pinecrest Energy Center ( PEC)

FACILITY LOCATION: 1002 East Park Avenue Lufkin, TX 75904

Pursuant to the provisions of the Clean Air Act (CAA), Subchapter I

, Pa rt C ( 42 U.S.C. § 7470

, 

### et seq. )

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

Federal Implementation Plan at 40 CFR 

### § 52.2305 (effective May 1

, 2011 and published at 76 FR 25178), the U.S. Environmental Protcx:tion Agency, Region 6 is issuing a 

### Prevention of Significant D eterioration (PSD) permit to Pinecrest Energy Center, LLC (Pinecrest) for greenhouse gas (GHG) emissions. The permit applies to the construction of a new natural gas fired combined cycle electric generating plant, Pinecrest Energy Center (PEC), to be located near Lufkin

, Angelina County

, T exas

.

Pinecrest is authorized to construct a new natural gas fired combined cycle electric generating plant 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 N o. PSD- TX-1298. Failure to comply wi th an y condition or term set f011h in this PSD permit may result i n enforcement action pursuant to Section 113 of the C l ean Air Act (CAA). This PSD permit does not relieve Pinecrest of the responsibility to comply wi th any other applicable provisions of the CAA (including applicable imp l ementing regulations 

### 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 .1 5(b)(3), this PSD P ermit becomes effective immediately
upon issuance of this fi 1 decision.

_ A- 

### I 

# U

I

Wren Stenger, Director Date

Multimedia Planning and Pennitting Division2 

### Pinecrest LL C (PSD-TX-1298 -GHG ) Prevention of S ig n ificant D et er io ra tion Permi t For G ree nh o u se Gas Emissions
Final Permit Co nd it io ns

PROJE CT D ES CR IPTION

Pinecrest En e rg y

Cen ter is proposing to construct a n e w combined cyc le el ec tr ic genera ti n g plant (PEC) in Angelina County, Texa s. PEC will gene ra te 637 - 735 megawatts (MW) of

g ross el ec trical power near the City of Lufkin. The PEC will consist of the following source s of G HG emissions:

• Two na tu ra l gas-fi re d combustion turbine s equipped with l ea n pre- mix lo w-NOx combustor s;

• Two na tu ra l gas-fi re d duc t bu rn er sy st ems;

• Na tu ra l gas piping and met er ing;

• One diese l f

uel-fi re d emergency el ec trical gene ra tor eng in e;

• One diese l f

uel-fi re d fire water pump eng in e;

• One n a tu ra l gas-fired aux ili ary boil er ; and

• El ec tri ca l equipment insulated with sulfur h ex af luoride (SF 6 

### ).

E QUIPME NT LIST

The following devi ce s are subj ec t to this GHG PS D p er mit.

F IN E PN D e s cr i p t ion

C T G 1 /H R SG1 C T G 2 /H R SG2 U 1

- S T K

U 2

- S T K 2 Nat

u r al Ga s

- Fi r ed C o m

b i n e d C y cle C o m b u s ti o n T u rb i n es ( C o m

bu s ti o n U n i t s )

. T h e c o m bu s ti o n t u rb i n e s a r e e q u i pp ed w ith h eat r ec o v e r y s t ea m g e n e r at or s ( H R SG) a n d s ele c ti v e cata l y t i c r e d u cti o n ( S C R )

. A U X B L R A U X B L R 1 A u x ilia r y B o iler ( C o m b u s t i o n U n it )

. T h e bo iler h as a m a x i m u m d e s i g n h e a t i n p u t r ate o f 15 0 M M b t

u / h r , a n d is f

i r ed w i t h n a t

u r al g a s

.

FWP1 F W P 1

- STK 1 Fi r e W ater P u m p ( C o m bu s t i o n U n it )

. 50 0 h or s e p o w er ( h p ) Die s el

- Fi r ed Fi r e W ater P u m

p r ated at 3. 4 M M B t

u / h r a n d l i m ited to 10 0 h o u r s o f op e r ati o n p er y ear f o r n on

- e m e r g e n c y a c ti v i tie s

.

EM G E N 1 EM G E N1

-

STK 1 E m

e r g e n c y G e n e r at o r ( C o m

b us ti o n U n it )

. 1,07 2 h or s e po w er ( h p ) Die s el

- Fi r ed E m e r g e n c y G e n e r at o r r ated at 7. 9 MM B t u / h r a n d l i m

i ted to 10 0 h o u r s of
op e r ati o n p er y ear f

o r n on

- e m e r g e n c y act i v itie s

.
SF 6

- F UG SF 6

- F UG SF 6 I n s u lated E lect r ical Eq u i p m e n t ( i

. e

. , ci r c u it br ea k e r s ) w i th 40 0 lb SF 6
ca p aci t y

. NG

- F UG NG

- F UG P ro ce s s F ug i t i v e s

.3



### I. GENE RAL PERM IT CONDITIONS

A. PERM IT EXPIRATION

As provided in 40 CFR §52.21 (r) , this PS D p er mit shall b ec ome invalid if construction:

1. is not commen ce d (a s d ef in ed in 40 CFR §52.21 (b )( 9)) within 18 months after the

app rov al tak es ef

f ec t;

2. is discontinued for a p er i od of 18 months or mo re ; or

3. is not completed within a reasonab le tim e.

Pu r su ant to 40 CFR § 52.21 (r) , EPA m ay extend the 18 -month p er iod upon a wr itt en sa tis fac to r y showing th a t an extension is justified.

B. PERM IT NO TIFICATION REQUIREMENTS

P er mitt ee sh all notify EP A Region 6 in wr iti ng or by el ec tronic mail of th e:

1. da te constru ction is commen ce d, postm ar ked within 30 days of such d ate;

2. ac tu al da te of initial st ar tup, as d ef in ed in 40 CFR § 60.2, postm ar k ed within 15 day s o f

su ch d ate ; and

3. da te upon whi ch initial performance tests will co mm en ce , in accordance with the

p rovisions of S ec tion VI, postm ar k ed not less than 30 day s p rior to such d ate. Notifi ca tion may be prov id ed with the submitta l of the p erforman ce test protocol re qui re d

pu r su ant to Condition VI.C.

C. FA CI LITY OPE RA TI ON

At all times, including periods of st ar tup, s hutdown, and maintenan ce, Per mitt ee sh all, to the extent prac ti ca

bl e, ma in tain and opera te the f ac ility in cluding a sso c iated a ir pollution control equipment in a mann er consistent with good a ir pollution control prac ti ce for minimizing emissions. Det er

min ation of wh e th e r ac ce ptable opera ti ng and maintenance p ro ce du re s are being used will be b ased on info rmation ava il able to the EPA, which may in clude, but is not lim it ed to, monitoring re sults, re view of op erating maintenan ce p ro cedure s a nd inspection of the fac ili ty.4



### D. MALFUNCTION REPORTING

1. P er mitt ee sh all notify EP A by mail within 48 hour s following the discov ery of any fa ilu r e of a ir pollution control equipment, pro ce ss e quip ment, or of a p ro ce ss to opera te in a

no rmal mann er , which results in an increa se in G HG emissions above the allowable emission limits stated in S ec tions II and II I of this p er mit.

2. W ithin 10 days of the re s to ra ti on of no rmal operations af ter any fa ilu re des cr ib ed in I.D.1., P er

mitt ee sh all provide a wr itt en supplement to the initial notifi ca ti on that include s

a d es cr iption of the malfunctioning equipment or abnormal operation, the d a te of the initial malfun ction, the p er iod of time ov er wh ich emissions w er e in cr ea sed due to the fa ilu re , the ca

use of the fa ilu re , the estimated resu lt ant emissions in ex ce ss of those allowed in S ec tion II and II I, and the methods utilized to mitiga te emissions and re stor e

no rmal operations.

3. Compliance with this malfunction notifi ca tion provision shall not excuse or oth er wise constitute a d efen se to any violation of this p er mit or any law or regulation su c h malfun ction may ca

us e.

E. RI G HT OF ENT RY

EP A authorized re p re sen ta tiv es, upon the p re sentation of cred entials, sha ll be p er mitt ed:

1. to e nt e r the p r e mis e s wh e r e the f ac ili t y is lo ca t e d o r wh e r e a n y r ec o r ds ar e r e qui re d to be k e pt und e r the t e r

ms a nd c onditions of this PS D p er mit;

2. du r ing no r

m a l busin e ss hou r s, to h a ve a cce ss to a n d to c o p y a n y r e c o r ds r e q ui re d to be k e pt und e r the t e r

ms a nd c onditions of this PS D p er mit;

3. to insp ec t a n y e quipm e n t , op era tion, or m e thod s u bj ec t to re qui re m e nts in this PS D

p er mit; a nd,

4. to s a mple m a t er i a ls a nd e missions fr om the sou rc e ( s )

.

F. T RAN S F E R O F OW N E R S HIP

In the event of any chang es in control or ownership of the fac iliti es to be constructed, this PS D

p er mit shall be binding on all subsequent own er s and op erators. P er mittee sh all notify the

su ccee ding o wn er and o perator of the existen ce of the PS D p er mit and its conditions by le tt er; a

co py of the le tt er shall be fo rwarded to EP A Re g ion 6 within thirty days of the le tt er signa tu re

.5



### G. SE VE RA BILI TY

The p rovisions of this PS D p er mit ar e severab le, and, if any provision of the PS D p er mit is held invalid, the re m ainder of this PS D p er mit shall not be af

f ec ted.

H. ADH ERE NCE TO APPLICATION AND CO MPLIA NCE WITH OTHE R ENVIRONMENT AL LAWS

P er mitt ee sh all constru ct this proj ec t in compliance with this PS D P er mit, the appli ca tion on whi ch this p er

mit is based, the TCEQ PS D p er mit PS D- TX -1298 ( wh en issu ed) and a ll othe r appli ca ble federal, state, and lo ca l a ir q ua li ty regulations. This PS D p er mit does not re l ea se the
P er mitt ee fr om any li ability for compliance with o th er appli ca ble fe d e ra l, sta te and loca l environmental laws and regulations, including the Cl ea n Air Ac t.6



### I. ACRONYMS AND ABBREVIATIONS

API Amer ic an P et ro le um In s ti tu te BACT Best Availab le Cont ro l T ec h no l og y BSC FD B illi on St andard Cu b ic Feet p er

Day C AA Clean Air A ct CC Carbon Conte nt CCS Carbon Capture and Se questra ti on C EM S Continuous Emi ss i on s Mo n it oring System C FR C od e of Fe d er al Regulations CH 4 M et ha ne CO 2 Carbon Di oxi de CO 2 e Carbon Di oxide Eq uivale nt CT Com bu s ti on Tu rb i ne D L NB Dry Low-NO x Burner ds cf Dry St andard Cu b ic Foot EF Emission Fa ctor EPN Emission Point Numb er FIN Facility Id entification Numb er FR Fe der al Register GHG Gr ee nh o us e Gas gr Gr ai ns GWP Gl ob al Warming Po te n ti al HHV Hi g h Heat ing Va lue hr Ho ur LAER Lowest Achievab le Emi ss ion Rate lb Po und LD AR Leak Detection and Repair MMB tu M illi on Br iti sh Therm al Un its M SS M ai ntenan ce, S ta rt-up and Shutdow n mtpa M illi on Tons p er Annum NNSR Nonattainment New Sour ce Review N 2 O Nit ro us Oxid es NO x Nit ro g en Oxid es NS PS New Sour ce Performan ce Standa rd s P SD Preven ti on of Si g nif ic ant Det eri or atio n QA/QC Quality A ss uran ce and/or Qua li ty Cont ro l S C FH Sta ndard Cu b ic Feet p er

Ho ur SCR Selective Cataly tic Reduction SF 6 Sulfur He xaflu or ide TAC Tex as Administr at ive C od e T CEQ Tex as Co mm ission on Environmental Qu al it y TPY Tons p er Year USC United States C od e VOC V olatile Organ ic Compo un d7

F IN E P N De s crip t i o n G H G M a s s B a s is T P Y CO e 2 , 3 B ACT Requir e m en t s T P Y 2

CTG1/HRSG1 U 1

- S T K C o m b i n ed C y cle C o m bu s ti o n T u rb i n e/Heat R ec o v e r y Ste a m Ge n e r at or 4 C O 2 1,446,186

1,447,653 942.0 lb C O 2 / M W h ( g ro ss )

w i t h d u ct b u r n i n g

. 5 See S p ecial C o n d iti o n III. A .1. Sta r t u p e m i s s i o n s l i m i ted to 50 0 h o u r s p er y ear a n d 8 3 t o n s C O 2 / h r

. See S p ecial C o n d iti on s III. A .1

. a n d III. A .4. e. C H 4 26.8

N 2 O 2.7

CTG2/HRSG2 U 2

- S T K C o m b i n ed C y cle C o m bu s ti o n T u rb i n e/Heat R ec o v e r y Ste a m Ge n e r at or 4 C O 2 1,446,186

1,447,653 942.0 lb C O 2 / M W h ( g ro ss )

w i t h d u ct b u r n i n g

. 5 See S p ecial C o n d iti o n III. A .1. Sta r t u p e m i s s i o n s l i m i ted to 50 0 h o u r s p er y ear a n d 8 3 t o n s C O 2 / h r

. See S p ecial C o n d iti on s III. A .1

. a n d III. A .4. e. C H 4 26.8

N 2 O 2.7

A U X B L R A U X B L R A u x ilia r y B o iler C O 2 7,680

7,687 G oo d C o m bu s ti o n a n d O p e r ati n g P r actice s

. L i m it to 87 6 h o u r s o f op e r ati o n p er y ea r

. See S p ecial C o n d iti o n s III. B

. C H 4 0.14

N 2 O 0.01

EM G E N1 EM G E N1

- S T K E m

e r g e n c y Ge n e r at o r C O 2 64

64 G oo d C o m bu s ti o n a n d O p e r ati n g P r actice s

. L i m it to 10 0 h o u r s o f op e r ati o n p er y ea r

. See S p ecial C o n d iti o n s III. C. C H 4 No

N u m e r ical L i m it E s ta b li s h e d 6

N 2 O No

N u m e r ical L i m it E s ta b li s h e d 6

FWP1 FWP1

-

STK Fi r e W ater P u m p C O 2 28

28 G oo d C o m bu s ti o n a n d O p e r ati n g P r actice s

. L i m it to 10 0 h o u r s o f op e r ati o n p er y ea r

. See S p ecial C o n d iti o n s III. C. C H 4 No

N u m e r ical L i m it E s ta b li s h e d 6

N 2 O No

N u m e r ical L i m it E s ta b li s h e d 6 

### II. A nnu al Emission Limits

Annu a l emissions, in tons per year (TP Y) on a 12 -month rolling total, sh all not ex cee d the following if the Gen eral El ec tr ic 7FA.05 is sel ec ted as the combustion turbine mode l:

Tab le 1A. A nnu al Emission Limits 1



### - Gen er al Electr ic 7FA.05

28

F IN E P N De s crip t i o n G H G M a s s B a s is T P Y CO e 2 , 3 B ACT Requir e m en t s T P Y 2

NG

- F UG NG

- F UG Nat u r al Gas F u g it i v es 6,8 C O 2 0.81 510 I m p l e m e n tati o n o f A

VO Mo n it or i n g

. See S p ecial C o n d iti o n III. D. CH 4 20.4

SF 6

- F UG SF 6

- F UG SF 6 I n s u lated Eq u i p m e nt 6 SF 6 No N u m e r ical L i m it E s ta b li s h e d 6 23 I ns t ru m e n ted m o n it or i n g a nd ala r m

. See S p ecial c o n d iti o n III. D.

T ota l s 7 C O 2 2,900,145 2,903,627 C H 4 74 N 2 O 5.4 1. Comp li an ce with the an nu al emission limi ts (t on s p er y ea r) is bas ed on a 12 -month ro lling total. 2. The TPY emission limits specified in this ta b le are not to be ex cee d ed for th is facility and in cl ude emissi on s from the f ac i li ty during all op erations and in cl ude MSS act ivities. 3. Gl ob al Warming Po te n ti a ls (G WP ): CH 4 = 25 , N 2 O = 298, SF 6 = 22,800 4. The a nnu al emi ss ions lim it for the com

bu s ti on tu rb i nes is bas ed on op erating at maximum du ct

burn er firing for 8,260 hours p er

y ea r, and op erating during s ta rtup, shutdown, and m ai n te nan ce (M SS) for 50 0 hours p er y ea r

. The a nnu al emi ss ion lim it includ es emissions from MS S. 5. The lb /M Wh BACT lim it for the com

bu s ti o n tu rb ine do es not a pp ly during s ta rtup. 6. A ll valu es indicated as “ No Numer ic al Limit Es ta b li shed” are le s s than 0.01 TPY with appropriate ro un ding. The emi ss ion lim it

w ill be a d esign/w or k pr actice standard as sp eci fied in the perm it. 7. The total emi ss ions for CH 4 and CO 2 e in cl ude the PTE for p ro ce ss f ug i ti ve emi ss i on s of CH 4 . Total emission s are for informa ti on only and d o n ot co ns ti tu te an emission lim it. 8. EPN NG-FUG includes fugitive emissions from piping and other components, as well as emissions from gaseous fuel line purging and maintenance/repair/replacement of fugitive components.9

F IN E P N De s crip t i o n 2 G H G M a s s B a s is T P Y CO e 2 , 3 B ACT Requir e m en t s T P Y 2

CTG1/HRSG1 U 1

- S T K C o m b i n ed C y cle C o m bu s ti o n T u rb i n e/Heat R ec o v e r y Ste a m Ge n e r at or 4 C O 2 1,398,427

1,399,842 909. 2 lb C O 2 / M W h ( g ro ss )

w i t h d u ct b u r n i n g

. 5 See S p ecial C o n d iti o n III. A .1. Sta r t u p e m i s s i o n s l i m i ted to 50 0 h o u r s p er y ear a n d 84
t o n s C O 2 / h r

. See S p ecial C o n d iti on s III. A .1

. a n d III. A .4. e. C H 4 25.9

N 2 O 2.6

CTG2/HRSG2 U 2

- S T K C o m b i n ed C y cle C o m bu s ti o n T u rb i n e/Heat R ec o v e r y Ste a m Ge n e r at or 4 C O 2 1,398,427

1,399,842 909. 2 lb C O 2 / M W h ( g ro ss )

w i t h d u ct b u r n i n g

. 5 See S p ecial C o n d iti o n s III. A .1. Sta r t u p e m i s s i o n s l i m i ted to 50 0 h o u r s p er y ear a n d 84
t o n s C O 2 / h r

. See S p ecial C o n d iti on s III. A .1

. a n d III. A .4. e. C H 4 25.9

N 2 O 2.6

A U X B L R A U X B L R A u x ilia r y B o iler C O 2 7,680

7,687 G oo d C o m bu s ti o n a n d O p e r ati n g P r actice s

. L i m it to 87 6 h o u r s o f op e r ati o n p er y ea r

. See S p ecial C o n d iti o n s III. B

. C H 4 0.14

N 2 O 0.01

EM G E N1 EM G E N1

- S T K E m

e r g e n c y Ge n e r at o r C O 2 64

64 G oo d C o m bu s ti o n a n d O p e r ati n g P r actice s

. L i m it to 10 0 h o u r s o f op e r ati o n p er y ea r

. See S p ecial C o n d iti o n s III. C

. C H 4 No

N u m e r ical L i m it E s ta b li s h e d 6

N 2 O No

N u m e r ical L i m it E s ta b li s h e d 6

FWP1 FWP1

-

STK Fi r e W ater

P u mp C O 2 28

28 G oo d C o m bu s ti o n a n d O p e r ati n g P r actice s

. L i m it to 10 0 h o u r s o f op e r ati o n p er y ea r

. See S p ecial C o n d iti o n s III. C

. C H 4 No

N u m e r ical L i m it E s ta b li s h e d 6

N 2 O No

N u m e r ical L i m it E s ta b li s h e d 6

NG

- F UG NG

- F UG Nat u r al Gas F u g it i v es 6 C O 2 0.81 510 I m p l e m e n tati o n o f A VO Mo n it or i n g

. See S p ecial C o n d iti o n III. D. CH 4 20.4 

### Annu a l emissions, in tons per year (TP Y) on a 12 -month rolling total, sh all not ex cee d the following if the Siemens SGT6-5000 F( 4) is sel ec ted as the combustion turbine mode l:

Tab le 1 B. Annual Emission Limits 1



### - Siemen s SGT6 -5000F(4)10

F IN E P N De s crip t i o n 2 G H G M a s s B a s is T P Y CO 2 e 2,3 B ACT Requir e m en t s T P Y 2

SF 6

- F UG SF 6

- F UG SF 6 I n s u lated Eq u i p m e nt SF 6 No N u m e r ical L i m it E s ta b li s h e d 6 23 I ns t ru m e n ted m o n it or i n g a nd ala r m

. See S p ecial c o n d iti o n III. D.

T ota l s 7 C O 2 2,804,627 2,808,007 C H 4 72.3 N 2 O 5.2 1. Comp li an ce with the an nu al emission limi ts (t on s p er y ea r) is bas ed on a 1 2 month ro lli ng total. 2. The TPY emission limits specified in this ta b le are not to be ex cee d ed for th is facility and in cl ude emissi on s from the f ac i li ty during all op erations and in cl ude MSS act ivities. 3. Gl ob al Warming Po te n ti a ls (G WP ): CH 4 = 25, N 2 O = 298, SF 6 = 22,800 4. The a nnu al emi ss ions lim it for the com

bu s ti on tu rb i nes is bas ed on op erating at maximum du ct

burn er firing for 8,260 hours p er

y ea r, and op erating during s ta rtup, shutdown, and m ai n te nan ce (M SS) for 50 0 hours p er y ea r

. The a nnu al emi ss ion lim it includ es emissions from MS S. 5. The lb /M Wh BACT lim it for the com

bu s ti o n tu rb ine do es not a pp ly during s ta rtup. 6. A ll valu es indicated as “ No Numer ic al Limit Es ta b li shed” are le s s than 0.01 TPY with appropriate ro un ding. The emi ss ion lim it

w ill be a d esign/w or k pr actice standard as specified in the perm it. 7. The total emi ss ions for CH 4 and CO 2 e in cl ude the PTE for p ro ce ss f ug i ti ve emi ss i on s of CH 4 . Total emission s are for informa ti on only and d o not co ns ti tu te an emission lim it. 8. EPN NG-FUG includes fugitive emissions from piping and other components, as well as emissions from gaseous fuel line purging and maintenance/repair/replacement of fugitive components.11



### Annu a l emissions, in tons per year (TP Y) on a 12 -month rolling total, sh all not ex cee d the following if the Siemens SGT6-5000 F( 5) is sel ec ted as the combustion turbine mode l:

Tab le 1C. A nnu al Emission Limits 1



### - Siemens SGT6 -5000F(5)

F IN E P N De s crip t i o n G H G M a s s B a s is T P Y CO 2 e 2 , 3 B ACT Requir e m en t s T P Y 2

U 1

- S T K U 1

- S T K C o m b i n ed C y cle C o m bu s ti o n T u rb i n e/Heat R ec o v e r y Ste a m Ge n e r at or 4 C O 2 1, 569,269

1, 570,854 912.7 lb C O 2 / M W h ( g ro ss )

w i t h d u ct b u r n i n g

. 5 See S p ecial C o n d iti o n III. A .1. Sta r t u p e m i s s i o n s l i m i ted to 50 0 h o u r s p er y ear a n d 85
t o n s C O 2 / h r

. See S p ecial C o n d iti on s III. A .1

. a n d III. A .4. e. C H 4 29

N 2 O 2.9

U 2

- S T K U 2

- S T K C o m b i n ed C y cle C o m bu s ti o n T u rb i n e/Heat R ec o v e r y Ste a m Ge n e r at or 4 C O 2 1,569,269

1,570,854 912.7 lb C O 2 / M W h ( g ro ss )

w i t h d u ct b u r n i n g

. 5 See S p ecial C o n d iti o n s III. A .1. Sta r t u p e m i s s i o n s l i m i ted to 50 0 h o u r s p er y ear a n d 85
t o n s C O 2 / h r

. See S p ecial C o n d iti on s III. A .1

. a n d III. A .4. e. C H 4 29

N 2 O 2.9

A U X B L R A U X B L R A u x ilia r y B o iler C O 2 7,680

7,687 G oo d C o m bu s ti o n a n d O p e r ati n g P r actice s

. L i m it to 87 6 h o u r s o f op e r ati o n p er y ea r

. See S p ecial C o n d iti o n s III. B

. C H 4 0.14

N 2 O 0.01

EM G E N1 EM G E N1

- S T K E m

e r g e n c y Ge n e r at o r C O 2 64

64 G oo d C o m bu s ti o n a n d O p e r ati n g P r actice s

. L i m it to 10 0 h o u r s o f op e r ati o n p er y ea r

. See S p ecial C o n d iti o n s III. C

. C H 4 No

N u m e r ical L i m it E s ta b li s h e d 6

N 2 O No

N u m e r ical L i m it E s ta b li s h e d 6

FWP1 FWP1

-

STK Fi r e W ater

P u mp C O 2 28

28 G oo d C o m bu s ti o n a n d O p e r ati n g P r actice s

. L i m it to 10 0 h o u r s o f op e r ati o n p er y ea r

. See S p ecial C o n d iti o n s III. C

. C H 4 No

N u m e r ical L i m it E s ta b li s h e d 6

N 2 O No

N u m e r ical L i m it E s ta b li s h e d 6

NG

- F UG NG

- F UG Nat u r al Gas F u g it i v es 6,8 C O 2 0.8 510 I m p l e m e n tati o n o f A VO Mo n it or i n g

. See S p ecial C o n d iti o n III. D. CH 4 20.412

F IN E P N De s crip t i o n G H G M a s s B a s is T P Y CO e 2 , 3 B ACT Requir e m en t s T P Y 2

SF 6

- F UG SF 6

- F UG SF 6 I n s u lated Eq u i p m e nt SF 6 No N u m e r ical L i m it E s ta b li s h e d 6 23 I ns t ru m e n ted m o n it or i n g a nd ala r m

. See S p ecial c o n d iti o n III. D.

T ota l s 7 C O 2 3, 146,311 3,150,030 C H 4 78.7 N 2 O 5.8 1. Comp li an ce with the an nu al emission limi ts (t on s p er y ea r) is bas ed on a 1 2 month ro lli ng total. 2. The TPY emission limits specified in this ta b le are not to be ex cee d ed for th is facility and in cl ude emissi on s from the f ac i li ty during all op e rations and in cl ude MSS act ivities. 3. Gl ob al Warming Po te n ti a ls (G WP ): CH 4 = 25, N 2 O = 298, SF 6 = 22,800 4. The a nnu al emi ss ions lim it for the com

bu s ti on tu rb i nes is bas ed on op erating at maximum du ct

burn er firing for 8,260 hours p er

y ea r, and op erating during s ta rtup, shutdown, and m ai n te nan ce (M SS) for 50 0 hours p er y ea r

. The a nnu al emi ss ion lim it includ es emissions from MS S. 5. The lb /M Wh BACT lim it for the com

bu s ti o n tu rb ine do es not a pp ly during s ta rt up. 6. A ll valu es indicated as “ No Numer ic al Limit Es ta b li shed” are le s s than 0.01 TPY with appropriate ro un ding. The emi ss ion lim it

w ill be a design/w or k pr actice standard as sp eci fied in the permit. 7. The total emi ss ions for CH 4 and CO 2 e in cl ude the PTE for p ro ce ss f ug i ti ve emi ss i on s of CH 4 . Total emission s are for informa ti on only and d o n ot co ns ti tu te an emission lim it. 8. EPN NG-FUG includes fugitive emissions from piping and other components, as well as emissions from gaseous fuel line purging and maintenance/repair/replacement of fugitive components.13



### III. SPECIAL PERM IT CONDITIONS

A. Re qu irement s for Com bu stion Turbine Generator s (CTG) a nd Heat R ec overy S te am Ge ne ra to r s (HRSG) (EP Ns : U1

- ST K a nd U2

- ST K)

The P er mitt ee sh a ll co mp ly with Table 1A, 1B, or 1C d epending on the sel ec tion of manufac tu rer and model of combined cycle combustion turbine sel ec t ed. Upon sel ec tion of

a combustion turbine mod e l, Pinecrest must submit a p er mit appli ca tion amen dment to

re move the tu rbine models not sel ec ted.

1. Com bu stion Tu rbine Gen er ator (CTG) B ACT Emission Limits

Ta b le 2. B ACT Emission Limit s f or Com bu stion Tu rbines on a 12 month rolling av er age

Tu r bine Mod e l G r oss H ea t R a t e , with

du c t bu r n e r f i r ing ( B tu/k W h) ( HH V ) Output B a s e d Emission L imit ( lb C O 2 / M W h) g r oss with du c t bu r

ning S t ar tup Emission
L imit ( tons C O 2 /h r)

G e n e r a l El ec t r ic 7 F A .05 7,925.0 942. 0 83
S i e m e ns S GT6

- 5000 F( 4) 7,649.0 909.2 84
S i e m e ns S GT6

- 5000 F( 5) 7,679.0 912.7 85

a. Within 60 day s after ac hieving the maximum production ra te at which the affected fac ili ty will be o perated, but not later th a n 180 d ays of the da te of initial st ar tup of the combustion turbine generators, the P er mitt ee shall perfor

m an initia l emission test f

or CO 2 and use emission fac to r s fr om 40 CFR P ar t 98.
The P er mitt ee sha ll ensure th at G H G emissions fr om the Combustion Turbine Generator and h ea t recovery st ea m generator ( U1 -STK and U2-STK) into the atmosph er e do not ex cee d the limits in lbs CO 2 /M Wh (gross) fr om Table 2
du ring the test. To d et er

mine this BAC T emission limit, P er mittee sh a ll

ca lcula te the limit based on the m ea su re d hourly ene rg y output (MWh (gross )) while the CTG is opera ti ng at or above 90% of its de si gn ca pacity with duc t

bu rner firing, and the re s ults shall be co rrected to IS O c onditions (59 o F, 14.7 psi a, and 67% humidity). If the CTG do es not m ee t the de si gn emissions limit, th en the P er

mitt ee sh a ll re medy the C TG ’s fa ilu re to m ee t the design emissions limit, will make co rrections to the C TG

, and will onl y combust fu el to perform

re qui re d tuni ng and modifi ca tions nece ss ary to d emonst ra te complian c e. b. The hourly gross electric output from the 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

a chieving 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 turbine generator.14



### c. The CO 2 

### mass emission values shall be calculated over each operational hour of the compliance period and summed. The summed hourly CO 2 

### mass emission values shall be divided by the combined sum of the 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 generator. The resulting quotient is added to the sum of quotients of the previous 11 operating months and divided by 12 to determine compliance with the
12 -month rolling average. d. Upon initial demonstration that the combustion turbine complies with the emission limit via emission tests, the Permittee shall not exceed the combustion turbine and duct burner annual firing rate, Btu/kWh (HHV) from Table 2 on a 12-month rolling average. To determine the limit, the Permittee shall calculate the average hourly heat input rate over the applicable compliance period consistent with equation F-20 and procedure provided in 40 CFR Part 75, Appendix F § 5.5.2 and the GCV of the fuel combusted for the corresponding compliance period. Add the quotient to the sum of the quotients of the previous 11 operating months and divide by 12 to determine the
12 -month rolling average.

e. The Permittee shall not discharge or cause the discharge of emissions into the atmosphere in excess of the limits in tons of CO 2 

### e on a 12 -month rolling total as listed in Table 1.

2. Monito ring of CO 2 Emissions for EPNs: U1

- ST K a nd U2 -STK

a. Upon initial demonst ra tion that the combustion turbine gen erator s are in compliance with the emissions limit via an emission test, the P er mi ttee sh all not disch arge or ca use the discharge of emissions fr om the Combustion Turbine
Gen erator (CTG) and h ea t r ec overy st ea m generator (H RS G) (EP Ns U1 -STK and
U2 -STK) into the atmosph er e in ex ce ss of limits in tons of CO 2 e on a 12-month rolling av er age as li sted in Table 1A, 1B, or 1C, a t all times including periods of startup and shutdown. To determine the amount of CO2e, the Permittee shall calculate the amount of CO 2 

### , CH 4 

### and N 2 

### O in tpy based on the equation G-4 of 40 CFR 75, Appendix G and 40 CFR Part 98, Appendix C. 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 CO 2 

### e emitted in Tons/hr for the operational month. The resulting
CO 2 

### e value is added to the previous 11 months to determine the 12 month rolling total of CO 2 

### e emissions. The Permittee shall determine compliance with the CH 4 

### and N 2 

### O emissions on a 12-month rolling total. The Permittee shall determine compliance with the CH4 and N 2 

### O emissions limits contained in Section II using the default CH 4 

### and N 2 

### O emission factors contained in Table C-2 of 40 CFR Part 98 and the measured actual hourly heat input (HHV).15



### 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
CO 2 

### CEMS system provided in 40 CFR § 75.10(a)(3) and (a)(5). If a CO 2 

### CEMS system is utilized, the hourly CO 2 

### emission value shall be measured by installing and operating 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 CO 2 

### CEMS system provided 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 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 CO 2 

### 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 CO 2 

### emission monitoring system.

3. U1

- ST K a nd U2

- ST K Co m bu stion Tu rbine Work Pra ct ice a nd Op er at io nal
Re qu irements

a. The combined cycle combustion 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 gross calorific value for a period of five years. Upon request, the Permittee shall provide a sample and/or analysis of 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 fuel combusted in the combustion turbine and duct burners shall be measured and recorded using an in-line flow meter and automatically record the data with a data acquisition and handling system. The steam load and/or heat input to the steam turbine shall also be measured and recorded.

c. The Permittee shall measure and record the 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, the Permittee shall install, and continuously operate, and maintain the HRSGs equipped with a SCR so emissions are at or below the emissions limits specified in this permit and TCEQ permit PSDTX1298.

e. The Permittee shall perform an annual compliance test, at or above 90% of

ma ximum load operations for the atmospheric conditions which exist during testing,16 

### corrected to ISO conditions to demonstrate compliance with the proposed heat rate in Table 2. f. On or after initial performance testing, the Permittee shall use BACT practices and designs represented in the permit application.

4. Re qu irement s du ring Com bu stion Tu rbine (EPNs: U1

- ST K a nd U2

- ST K) Sta rt up and S hu tdown

a. P er mitt ee sh all minimize emissions during st ar t-u p and shutdown ac tivitie s b y
op era ti ng and maintaining the f ac ili ty and a sso ciated a ir pollution control equipment in acc ordance with good a ir pollution control prac ti ce s, s af e o pe ra ting prac ti ce s, and

p rotection of the fac ili ty. b. Emissions during st ar tup and shutdown ac tivities shall be minimized by limiting the du ra tion of op eration in st ar tup and shutdown mode a s f ollows: i. A st ar tup is d ef

in ed as th e p er iod that begins when the d a ta acquisition and
h andling sy st em m ea sure s fu e l flow to the combustion turbine and ends when the

c ombustion turbine gen erator lo ad re ac hes 60 percent. A planned st ar tup f or each combustion turbine is limited to 360 minutes per event. ii. A shutdown is d ef

in ed as the p er iod that begins when the combustion

tu rbine generator output drops below 60 p er cent load and ends when there is no lon ger m ea su r ea

ble fue l flow to the combustion turbine. A plann ed shutdown of the combustion turbine is limited to 60 minutes per ev ent.

c. St ar tup and shutdown emissions shall not exceed the BACT emission limits in
T able 2. d. The maximum h ea t input sh all be limit ed to the va lu es identified in Table 3 du ring st ar tup.

e. St ar tups ar e limited to 500 hours on a 12 -month rolling b asis. f. The st ar tup emissions and h ea t input limits ar e also shown in T able 3 b elo w.

T a b le 3. Sta rt up Emissions and Heat I npu t Limitat io ns

Tu r bine Mod e l B A C T Emission

L imit ( tons C O 2 /h r) Annu a l Emission

L imit ( tons C O 2 e / y

r ) M a x imum H ea t I

nput ( MM B tu/h r) GE 7 FA.05 83 41,678 1401.2 S GT6

- 5000 F( 4) 84 41,847 1406.9 S GT6

- 5000 F( 5) 85 42,475 1428.0

g. P er mitt ee must record the tim e, date, fue l h ea t inp ut ( HHV) in MMBtu/hr and du ra tion of each st ar tup and shutdown ev ent in order to ca lcula te tota l CO 2 e emissions. The reco rds must include hou rly CO 2 emission lev els as m ea su red by
th e fu e l flow meter and/or O 2 emission monitor ( or CO 2 CEMS with volumetr ic

st ac k gas flow ra te) and the ca lculations based on the ac tu al h ea t input for the
CO 2 , CO 2 e, O 2 , N 2 O, and CH 4 emissions during e ac h startup and shutdown17 

### ev ent based

on the equations re p resented in the p er mit appli ca tion. The se reco rds must be k ep t for five (5) year s f ollowing the da te of su ch ev ent. h. The 12 -month rolling av er age BACT emission li mit ations in Sp ec ia l Condition
II I.A.1. does not include p er iods of st ar tup.

B. Re qu irement s for Auxiliary Boiler (EPN: AUX BL R)

1. Boiler shall combust only pipeline quality natural gas. 2. Permittee shall measure and record the fuel flow rate using an inline flow meter and automatically record the data with a data acquisition and handling system. 3. Permittee shall calibrate and perform preventative maintenance check of the fuel gas flow meters and document annually. 4. Permittee shall perform cleaning of the burner tips annually, at a minimum. 5. Permittee shall perform cleaning of the convection section tubes annually, at a minimum. 6. The maximum firing rate for the auxiliary boiler shall not exceed 150 MMBtu/hr.
7. The one-hour maximum firing rate shall be calculated daily to demonstrate compliance with the firing rate in III.B.6. 8. Total f

iring hours of the auxiliary boiler must not exceed 876 hours per year.
9. Records of firing hours shall be recorded daily. A 12-month rolling total of boiler hours of operation shall be calculated to demonstrate compliance with the limitation of hours in III.B.8.
10. Permittee shall install, operate, and maintain an automated air/fuel control system. 11. Permittee shall calibrate and perform preventative maintenance on the air/fuel control analyzers once per quarter, at a minimum. 12. Permittee shall install, operate, and maintain an O2 analyzer on the boiler. 13. Oxygen analyzers shall continuously monitor and record oxygen concentration in the boiler. It shall reduce the oxygen readings to an averaging period of 6 minutes or less and record it at that frequency.
14. The oxygen analyzers shall be quality-assured at least quarterly using cylinder gas audits (CGAs) in accordance with 40 CFR Part 60, Appendix F, Procedure 1, § 5.1.2, with the following exception: a relative accuracy test audit is not required once every four quarters (i.e., four successive quarterly CGAs may be conducted).
15. Compliance with the Annual Emission Limit shall be demonstrated on a 12- month total, rolling monthly, calculated in accordance with 40 CFR § 98.33(a)(1)(i).

C. Re qu irement s for the Fi re Wa ter Pump (EPN: FWP1-STK) a nd Emerg ency Ge ne ra t or (EPN: EMGE N1 -ST K)

1. The Fire Water Pump (FWP1-STK) and Emergency Gene ra tor (EMGEN1-STK) are

a uthorized to fire di ese l fu e l containing no more th an 0.5 p er cent sulfur by weight.18



### Upon re qu est, P er

mitt ee sh all provide a sample and/or an an alysis of the fuel-fi re d in the emission units (EMGEN1-STK and FWP1-STK) or sh a ll a llow a sample to be taken by
EP A for an alysis to demonst ra te the p ercent sulf ur of the fue l. 2. The Fire Water Pump and Emergency Gene ra t or ar e limit ed to 100 hours of nonemergency op eration per y ea r for each unit and a h ea t input value of 3.4 MMBtu/hr and 7.9 MMBtu/hr for the Fire Water Pump and the Em e rgency Generat or , re sp ec tiv ely. Complian ce with the 100 hour non -em er gen cy operationa l requi re ment is det er min ed

on a 12 -month rolling basis. 3. The Fire Water Pump and Emergency Gene ra t or sh all m ee t the appli ca ble monitoring and r ec ordkeeping requi re ments a s requi re d in 40 CFR P ar t 60 Subp ar t III I, Standards of Perfo rman ce for Stationary Comp re ssi on Ignition Interna l Combustion Eng in e s. 4. P er mitt ee sh all insta ll and maintain an op erational non- re s e tt able elapsed ti me meter for the Fire Water Pump and Emergency Generator.
5. P er mitt ee sh all maintain a f

ile of a ll r ec ords, da ta m ea su re ments, repo rts and do cuments re lated to the op eration of the Fire Water Pumps and Emergenc y G en era to r, including, but not limited to, the follow in g : a ll reco rds or repo rt s
p er taining to maintenance p erformed, a ll r ec ords relating to pe rf ormance tests and monitoring of the emergency gen erator and fire pump equipment; for each diese l fu e l oil de liv ery, do cuments fr om the fuel supplier cer ti fying compliance with the fue l sul fur content limit of Sp ec ia l Condition III. C.1., fuel h ea t input va lu es and hours of

op eration re quired in Sp ec i a l Condition III. C.2.; and all other in formation re qui re d by this p er mit reco rd ed in a p er

manent form suitable for insp ec ti on. The f ile must be

re ta in ed for not less than five y ea r s following the d a te of su ch m ea su re ments, maintenan ce , re p orts, and/or r ec ords.

D. Re qu irement s for Fugitive Emission So u rce s (EPNs: NG-FUG and SF6-FU G)

1. The P er

mitt ee sh all implement an auditory/visual/olfac to ry (AVO) method for d et ec ti ng l ea king from na tu ra l gas piping components and make observ ations on a d aily b asis.
2. For emission unit SF6-FUG, SF 6 emissions sha ll be ca lculated annually (calendar

y ea r) in acc ordance with the mass balance approach provided in equation DD-1 of the Mand a to ry Greenhou se Ga s Repo r ti ng rules for El ec trical T ra nsmission and Distribution Equipme nt Us e, 40 CFR P ar t 98, Subp ar t DD. P er mitt ee sh a ll not

ex cee d insulated ci rc uit b reak er SF 6 

### capacity exceeding 400 lbs.
3. P er mitt ee sh all equip the ci rc uit break er s with a low p re ssu r e al ar m and a low

p re ssu re lo ckout. The SF 6 l ea k det ec tion sy st e m sh all be able to detect a leak of at
l ea st 1 lb per ye ar

. 4. P er mitt ee sh all maintain a f

ile of a ll r ec ords, da ta m ea su re ments, repo rts and do cuments re lated to the fu gitive emission sources in cluding, but not limited to, the following: a ll records or re po rts p er taining to maintenan ce performed, all r ec ords19 

### re lating to compliance with the Monitoring and Qua li ty Assu ran ce and Qualit y Control (QA/Q C) p ro ce du re s outlined in 40 CFR § 98.304. 5. The P er

mitt ee provided da ta to show that minimal quantities of n a tu ra l gas ar e rel ea sed to the atmosph er e du ring turbine fu el line shutdown maintenan ce and when

p erfo r mi n g re p a ir or mainten an ce on sm a ll equipment and fugitive components.

IV. RECORDKEEPING AND REP OR TING

1. In ord er to demonstra te complian ce with the GHG emission limits in Table 1, the
P er mitt ee will monitor the following paramet er s and summ ar ize the d a ta o n a ca len da r month basis.

a. Op era ti ng hour s for a ll air emission source s; b. The n a tu ra l ga s fu el usa ge for a ll combustion sour ce s, using continuous fue l flow monitor s (a group of equ ipment ca n utilize a common fue l flow met er , as long a s

ac tu a l fu el usage is a llo c ated to the individua l equipment based upon ac tu a l

op era ti ng hour s and maximum firing ra t e) ; and

c. Annua l fu el sampling for na tu ra l ga s.

2. P er mitt ee sh all implement an AVO progra m and k ee p records of the monitoring results,

as we ll as the rep a ir

and mainten an ce records.
3. P er mitt ee sh all maintain a ll reco rds, data, m ea surements, re po rts, and do cuments re lated to the op eration of the fac ili ty, including, but not l imit ed to, the following: a ll records o r

re po rts p er taining to signifi ca nt maintenance performed on any sy st em or device at the fa c ili ty; duration of st ar tup and shutdown; the initial st ar tup p er iod for the emission units; pollution control units; malfunctions; all records relating to performan ce tests,

ca lib ra tions, ch ecks, and monitoring of combustion equipment; du ra tion of an inoperative monitoring d evice and emission units with the re qui re d co rresponding emission data ; and all other in fo rmation re q ui re d by this per mit reco rded in a p er

manent fo rm suitable for insp ec tion. The records must be re ta in ed for not less than five ye ar s f ollowing the d ate of

su ch m ea su re ments, maintenan ce , re po rts, and/or reco rds.
4. P er mitt ee sh all maintain records of all GHG emission units and CO 2 

### emission

cer ti fication tests and monitoring and compliance in f o rmation re qui re d by this p er mit.
5. P er mitt ee sh all maintain records and submit a wr itt en re po rt of all GHG ex ce ss emissions
to EPA se mi -annu ally, ex ce pt when more fre q uent re po rting is specifi ca lly requi re d b y an appli ca ble subp ar t or the Administ ra tor or a ut ho rized re p re senta tiv e, on a ca se-by- ca se b asis

, d eter

min es that more frequ ent repo rting is nece ss ary to acc u ra tely a ss ess the complian ce st atus of the source. The re po rt is due on the 30 th 

### d ay following the end of

eac h se mi -annu al period and shall include the f ol lowing:

a

. Time int er

v als, da ta and magnitude of the ex ce ss emissions, the na tu re and ca use (if known), co rrective ac ti ons tak en and p rev entive m ea su re s ad opted;20



### b. Appli ca

ble time and d a te of eac h p er iod during which the monitoring equipment was inoperative (monitoring down- tim e) ;

c. A statement in the re po rt of a n egative d ec la ra tion, th at is, a st atement when no

e x ce ss emissions o cc u rr ed or wh en the monitorin g equipment has not b ee n inopera tiv e, repai re d or adjusted; and d. Any fa ilu re to conduc t a ny requi re d source testing, monitor in g , or other complianc e

ac tivitie s. 6. Ex ce ss emissions sha ll be d ef in ed a s any period in which the fac ili ty e mi ssions ex cee d a maximum emission lim it se t fo rth in this p er mit.
7. Ex ce ss emissions indi ca ted by GHG emission sou rc e c er ti fication testing or complianc e moni toring sh all be considered violations of the appli ca ble emission limit for the purpose of this p er

mit. 8. All records requi re d by this PS D p er mit shall be reta in ed and remain a cce ssible for not less than 5 ye ar s following the da te of su ch m ea su rements, mainten an ce, an d re po r ti ng.

V. S HA KEDOWN PE RI O DS

The combustion turbine emission limit s a nd re qui re ments in conditions II., II I.A.1., and II I.B. sh all not apply du ring combustion shakedown periods. Shak edown is d ef in ed as the period b eginning with initia l st ar tup and ending no later th an initial performance testing, du ring whi ch the P er

mitt ee conducts operationa l and contractual testing and tuning to en su re the

s afe, efficient and re li able o peration of the plant. The sh aked ow n p er iod sh all not ex cee d the time p er iod for perfo rmance testing as sp ec ified in 40 CFR § 60.8. The re quirements of

sp ecia l condition I. C. of this p er mit shall app ly at all time s.

VI. PERFORM ANCE TESTING

A. The P er

mitt ee sh all perform st ac k sampling and other testing to e st ablish the ac tu a l pa tt er n and quantities of a ir con ta min ants being e mitt ed into the atmosph er e from the st ac ks of the Combustion Turbine s and H RS Gs ( U1 -STK and U2 -STK) and the Au x ili ary Boile r ( AU XBLR) to det er

mi ne the initia l complian ce with the CO 2 emission limit s e st ablished in this p er mit. Sampling sh all be condu cted in a cc ordance with 40 CFR § 60.8 and EPA Method
3a or 3b for the con centration of CO 2

.

1. Multiply the CO 2 hourly av er a ge emission ra te det er min ed und er maximum

op era ti ng test conditions by 8,760 hours for the combustion turbine s a nd 876 hour s for the aux ili ary boiler.
2. If the abo ve ca lculated CO 2 emission total does no t ex cee d the TPY sp ec ified on
Tab le 1, no compliance st ra tegy n ee ds to be developed. If the abo ve ca lculated CO 2 emission tota l ex cee ds the TPY sp ec ified in Table 1, the
fac ili ty sha ll:21 

### a. Do cument the potential to ex cee d in the test re po r t; and b. Explain within the re po rt how the fac ili ty will a ssu re complian ce with the CO 2

e mission limit listed in Table 1.

B. Within 60 d ay s after ac hieving the maximum production ra te at which the affected fac ili t y will be op erated, but not later th an 180 d ays af ter initial st ar

tup of the facility, pe rf

o rmanc e tests( s) must be condu cted and a wr itt en report of the performance testing results furnished to EPA. Additional sampling may be requi re d by TCEQ or EP A. C. P er mitt ee sh all submit a perfo rmance test protocol to EPA no later th an 30 d ay s prior to the

t est to allow re view of the test plan and to ar ra nge for an EPA observ er to be p re sent at the test. The p erforman ce test shall be condu cted in ac cordance with the submitted protocol, and any change s re qui red by EP A.
D. The tu r

bine sh all be te st ed at or above 90 % of maximum load op erations for the atmosph er ic conditions which exist during testing. The d uct burn er s shall be te st ed at th e ir maximum firing ra te within the m ec h anical limits of the equipment for the atmosph er ic conditions which exists du ring the performance test while the tu rbine is opera ti ng a s close to ba se lo ad

a s possible. The te st ed turbine lo a d sha ll be id entified in the sampling re p ort. The p er mit holder sh a ll p re sent in the p erfo rmance te st p rotocol the mann er in whi ch st ac k sampling will be ex ec uted in order to demonst ra te complian ce with the emissions limits conta in e d in
S ec tion II.
E. Air emissions fr om each H RS G exh aust st ac k shall be te st ed while firin g at the minimum lo ad in the no rmal operating ra nge. The n ormal opera ti ng ra n ge consistent with emission limits is to be d et er

min ed during st a ck testing. Air emissions that will be sampled and

a nalyzed while at the minimum load include (but ar e not limited to) CO 2

. F. Performan ce tests must be condu cted un der su ch conditions to ensure re p resentative

p erformance of the affected fac ili ty. The owner or operator must make available to EPA

su ch records as may be n ece ss ary to det er mine the conditions of the p erfo rman ce tests. G. The owner or op erator shall provide, or cause to be p rovided, pe rf ormance testing fac iliti e s a s follows:
1. Sampling po rts adeq ua te for test methods appli ca b le to this fac ili ty, 2. S af e sampling platform(s ),
3. S af e ac ce ss to sampling platform(s), and 4. Utilitie s for sampling and testing equipment.
H. Unless oth er

wise sp ecified, eac h performance test sha ll c onsist of th re e separa te runs using the appli ca

ble test me th od. E ac h run shall be conducted for the time and u nd er the conditions sp ec ified in the appli ca ble st an d ar d. Fo r purposes of det er mi ning compliance with an appli ca

ble st an d ar d, the ar ithme tic m ea n of the re sults of the th re e runs sh a ll app ly.22



### VII. Ag ency Notifica t io ns

P er mitt ee sh all submit GHG p er mit appli ca tions, p er

mit amendments, and other appli ca ble

p er mit information to:

Mult imedia Planning and P er mitting Division
EP A Region 6
1445 Ross Av enue (6 PD-R )
Da ll a s, TX 75202
Em ail: Gr oup R6Ai rP er

mits@EP A. gov

P er mitt ee sh all submit a co py of a ll c omplian ce and en fo rcement cor re sp o nd en ce a s re quired b y this Approval to Construct to:

C omplian ce Assu ra nce and Enfo rcement Division
EP A Region 6
1445 Ross Av enue (6EN )
Da ll as, TX 75202P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 i 

### TABLE OF CONTENTS

1.0 INTRODUCTION

............................................................................................................. 1
FORM PI

- 1 GENERAL APPLICATIO N

....................................................................................... 2
2.0 PROJECT SCOPE

........................................................................................................ 11

2.1 Introduction

.......................................................................................................... 11 2.2 Combustion Turbine Generator

............................................................................ 11 2.3 Heat Recovery Steam Generator

......................................................................... 12 2.4 Auxiliary Boiler

..................................................................................................... 12 2.5 Diesel Fired Emergency Equipment

..................................................................... 12 2.6 Natural Gas/Fuel Gas Piping

............................................................................... 12 2.7 Electrical Equipment Insulated with Sulfur Hexafluoride (SF 6 )

.............................. 13
PROCESS FLOW DIAGRAM

.................................................................................................... 14
PLOT PLAN

.............................................................................................................................. 15
AREA MAP

............................................................................................................................... 16
3.0 GHG EMISSION CALCULA TIONS

................................................................................ 17
3.1 GHG Emissions From Combined Cycle Combustion Turbine

.............................. 17 3.2 Auxiliary Boiler

..................................................................................................... 17 3.3 GHG Emissions From Natural Gas/Fuel Gas Piping Fugitives and Natural Gas/Fuel Gas Maintenance and Startup/Shutdown Related Releases

................ 18 3.4 GHG Emissions From Diesel Fired Emergency Engines

...................................... 18 3.5 GHG Emissions From Electrical Equipment Insulated with SF 6 ............................ 19
TABLE 3 -1 ANNUAL GHG EMISSION SUMMARY

............................................................... 20
TABLE 3 -2 ANNUAL GHG EMISSION CALCULATIONS – GE 7FA COMBINED CYCL E COMBUSTION TURBINE

.............................................................................................. 21
TABLE 3 -3 STARTUP GHG EMISSION CALCULATIONS - GE F7FA TURBINES

............... 22
TABLE 3 -4 GH G ANNUAL EMISSION CA LCULATIONS - SIEMENS SGT6

- 5000F(4) COMBINED CYCLE COMBU STION TURBINES

.......................................................... 23
TABLE 3 -5 STARTUP GHG EMISSION CALCULATIONS - SIEMENS SGT6

- 5000F(4) TURBINES

.................................................................................................................... 24
TABLE 3 -6 GHG EMISSION CALCULA TIONS - SIEMENS SGT6

- 5000F(5) COMBINED CYCLE COMBUST ION TURBINES

.............................................................................. 25
TABLE 3 -7 STARTUP GHG EMISSION CALCULATIONS - SIEMENS SGT6

- 5000F(5) TURBINES

.................................................................................................................... 26
T ABLE 3 -8 GHG EMISSION CALCULA TIONS - AUXILIARY BOILER

.................................. 27
TABLE 3 -9 GHG EMISSION CALCULA TIONS - NATURAL GAS PIPING

............................. 28
TABLE 3

- 10 GASEOUS FUEL VE NTING DURING TURBINE SHUTDOWN/MAINTENANCE AND SMALL EQUIPMENT AND FUGITIVE COMPONENT REPAIR/REPLACEMEN T . 29
TABLE 3

- 11 GHG EMISSION CALCULA TIONS - EMERGENCY ENGINES

.............. 30P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 ii TABLE 3

- 12 GHG EMISSION CA LCULATIONS - E LECTRICAL EQUIPMENT INSULATED WITH SF6

..................................................................................................................... 31
4.0 PREVENTION OF SIGNIF ICANT DETERIORATION APPLICABILITY

......................... 32
TCEQ PSD NETTING TAB LES

................................................................................................ 33
5.0 BEST AVAILABLE CONTR OL TECHNOLOGY (BACT)

................................................ 36
5.1 BACT for the Combined Cycle Combustion Turbine

............................................ 37 5.1.1 Step 1: Identify All Available Control Technologies 37 5.1.2 Step 2: Eliminate Technically Infeasible Options 43 5.1.3 Step 3: Rank Remaining Control Technologies 44 5.1.4 Step 4: Evaluate Most Effective Controls and Document Results 44 5.1.5 Step 5: Select BACT 48 5.2 BACT for SF 6 Insulated Electrical Equipment

....................................................... 57 5.2.1 Step 1: Identify All Available Control Technologies 57 5.2.2 Step 2: Eliminate Technically Infeasible Options 57 5.2.3 Step 3: Rank Remaining Control Technologies 58 5.2.4 Step 4: Evaluate Most Effective Controls and Document Results 58 5.2.5 Step 5: Select BACT 58 5.3 BACT for Auxiliary Boiler

..................................................................................... 58 5.3.1 Step 1: Identify All Available Control Technologies 58 5.3.2 Step 2: Eliminate Technically Infeasible Options 59 5.3.3 Step 3: Rank Remaining Control Technologies 60 5.3.4 Step 4: Evaluate Most Effective Controls and Document Results 60 5.3.5 Step 5: Select BACT 60 5.4 BACT for Emergency Engines

............................................................................. 60 5.4.1 Step 1: Identify All Available Control Technologies 61 5.4.2 Step 2: Eliminate Technically Infeasible Options 61 5.4.3 Step 3: Rank Remaining Control Technologies 62 5.4.4 Step 4: Evaluate Most Effective Controls and Document Results 62 5.4.5 Step 5: Select BACT 62 5.5 BACT for Natural Gas Fugitives

........................................................................... 62 5.5.1 Step 1: Identify All Available Control Technologies 62 5.5.2 Step 2: Eliminate Technically Infeasible Options 62 5.5.3 Step 3: Rank Remaining Control Techno logies 63 5.5.4 Step 4: Evaluate Most Effective Controls and Document Results 63 5.5.5 Step 5: Select BACT 63
MAP OF EXISTING CO 2 PIPELINES AND POTENT IAL GEOLOGIC STORAGE SITES IN TEXAS

.......................................................................................................................... 65
T ABLE 5 -1 CALCULATION OF DESIG N HEAT RATE FOR GE 7 FA

.................................... 66
TABLE 5 -2 CALCULATION OF DESIG N HEAT RATE FOR SIEMENS SGT6

- 5000F(4)

....... 67
TABLE 5 -3 CALCULATION OF DESIG N HEAT RATE FOR SIEMENS SGT6

- 5000F(5)

....... 68
6.0 OTHER PSD REQUIREMENTS

.................................................................................... 69
6.1 Impacts Analysis

.................................................................................................. 69P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 iii 6.2 GHG Preconstruction Monitoring

......................................................................... 69 6.3 Additional Impacts Analysis

................................................................................. 69
7.0 PROPOSED GHG MONITOR ING PROVISIONS

.......................................................... 71



### APPENDICES

APPENDIX A: GHG PSD APPLICABILITY FLOWCHART – NEW SOURCESP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 1 

## 1.0 I NTRODUCTION

Pinecrest Energy Center, LLC ( Pinecrest ) is hereby submitting this application for a G reenhouse G as (GHG) Prevention of Significant Deterioration (PSD) air quality permit for the construction

o f a new combined cycle electric generating plant, Pinecrest Energy Center ( PCEC ), in Angelina County, Texas. PCEC will consist of two natural gas

- fired combustion turbines, each exhausting to a fired heat recovery steam generator (HRSG) to produce steam to drive a shared steam turbine. Three models of combustion turbines are being considered for this site: the General Electric 7FA .05 , the Siemens SGT6

- 5000F(4), and the Siemens SGT6

- 5000F(5) . The final selection of the combustion turbine model will not be made until after the permit is issued. The State and PSD air permit application for non

- GHG pollutants was submitted to the Texas Commission on Environmental Quality (TCEQ) on June 22, 2012.

The General Electric 7FA .05 combustion turbine has a maximum b ase- load electric power output of approximately 183 MW, the Siemens SGT6

- 5000F(4) is approximately 205 MW, and the Siemens SGT6

- 5000F(5) is approximately 232 MW. The maximum electric power output from the steam turbine is approximately 271 MW for both the GE and Siemens configurations. All three combustion turbines are F

- Class turbines.

On June 3, 2010, the EPA published final rules for permitting sources of GHGs under the 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/yr of GHGs and modifications increasing GHG emissions more than 75,000 tons/yr on a carbon dioxide equivalent (CO 2 e) basis at existing major sources are subject to GHG PS D review, regardless of whether PSD was triggered for other pollutants.

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 PCEC project for construction of two combined cycle power plant unit s trigger s PSD review for GHG regulated pollutants because the project will increase GHG emissions by more than 100 ,000 tons/yr. Included in this application are a project scope description, GHG emissions calculations, GHG netting analysis, and a GHG Best Available Control Technology (BACT) analysis.

1 75 FR 31514 (June 3, 2010).

2 75 FR 81874 (Dec

. 29, 2010).

### 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: Pinecrest Energy Center, LLC
Texas Secretary of State Charter/Registration Number ( if applicable ): 0801593860

B. Company Official Contact Name: Kathleen Smith

Title: President
Mailing Address: 4011 West Plano Parkway, Suite 128
City: Plano State: TX ZIP Code: 75093
Telephone No.: 281-253-4385 Fax No.: 972-964-0807 E-mail Address: ksmith@coronado-ventures.com

C. Technical Contact Name: Kathleen Smith

Title: President
Company Name: Pinecrest Energy Center, LLC
Mailing Address: 4011 West Plano Parkway, Suite 128
City: Plano State: TX ZIP Code: 75093
Telephone No.: 281-253-4385 Fax No.: 972-964-0807 E-mail Address: ksmith@coronado-ventures.com

D. Site Name: Pinecrest Energy Center

E. Area Name/Type of Facility: Electric Generating Facility Permanent Portable

F. Principal Company Product or Business: Generation of Electricity
Principal Standard Industrial Classification Code (SIC): 4911
Principal North American Industry Classification System (NAICS): 221112

G. Projected Start of Construction Date: 06/01/2013
Projected Start of Operation Date: 10/01/2015

H. Facility and Site Location Information (If no street address, pr ovide clear driving directions to the site in writing.):

Street Address: 1002 East Park Avenue

City/Town: Lufkin County: Angelina ZIP Code: 75904
Latitude (nearest second): 31°21'35"N Longitude (nearest second): 94°41'43"W

TCEQ – 10252 (Revised 02/12) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v18) Page 1 of 9

.

### 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 submitte d 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 or enforcement action? If Yes , attach a copy of any correspondence from the agency. YES NO

C. Number of New Jobs: 50

D. Provide the name of the State Senator and State Repr esentative and district numbers for this facility site:

Senator: Robert Nichols District No.: 3 (1 for 2012 elections)
Representative: James White District No.: 12 (5 7 for 2012 elections)
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 indica ting what type of permit is requested. (check all that apply, skip for change of location)

Construction Flexible Multiple Plant Nonattainment Prevention of Significant Deterioration Hazardous Air Pollutant Major Source Plant-Wide Applicability Limit

Other:

D. Is a permit renewal applicati on being submitted in conjunctio n with this amendment in accordance with 30 TAC 116.315(c). YES NO

TCEQ – 10252 (Revised 02/12) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v18) Page 2 of 9

.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. YES NO

1. Current Location of Facility (If no st reet 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, provi de 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 cons idered a major source of criteria pollutants or HAPs? YES NO

F. Consolidation into this Permit: List any standard permits, exempti ons or permits by rule to be consolidated into this permit including those for planned maintenance, startup, and shutdown.

List: None

G. Are you permitting planned maintenance, startup, and shutdown emissions? If Yes , attach information on any changes to emissions under th is application as specified in VII and VIII. YES NO

H. Federal Operating Permit Requirement s (30 TAC Chapter 122 Applicability)
Is this facility located at a site require d 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 To Be Determined Operational Flexibility/Off-Permit Notification Streamlined Revision for GOP None

TCEQ – 10252 (Revised 02/12) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v18) Page 3 of 9

.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 Requirement s (30 TAC Chapter 122 Applicability) (continued)
2. Identify the type(s) of FOP(s) issued and/or FOP app lication(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 modifica tion 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 modifica tion 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).

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 contam inant in this application? YES NO
3. Do the facilities handle, load , unload, dry, manufacture, or process grain, seed, legumes, or vegetables fibers (agricultural facilities)? 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): 156.2 tpy
Sulfur Dioxide (SO 2 ): 38.8 tpy
Carbon Monoxide (CO): 418.8 tpy
Nitrogen Oxides (NO x ): 260.2 tpy
Particulate Matter (PM): 289.3 tpy

PM 10 microns or less (PM 10 ): 257.9 tpy

PM 2.5 microns or less (PM 2.5 ): 250.9 tpy
Lead (Pb):
Hazardous Air Pollutants (HAPs): < 10 tons/yr for individual HAP and < 25 ton/yr for all HAPs
Other speciated air contaminants not listed above: 267.2 ton/yr NH 3 ; 17.8 ton/yr H 2 SO 4 ; 24.0 ton/yr (NH 4 ) 2 SO 4

TCEQ – 10252 (Revised 02/12) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v18) Page 4 of 9

.TCEQ – 10252 (Revised 02/12) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v18) Page 5 

### 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: Kathleen Smith

Title: President
Mailing Address: 4011 West Plano Parkway, Suite 128
City: Plano State: TX ZIP Code: 75093
Telephone No.: 281-253-4385

B. Name of the Public Place: Kurth Memorial Library
Physical Address (No P.O. Boxes): 706 South Raguet
City: Lufkin County: TX ZIP Code:75904
The public place has granted authorization to place the application for public viewing and copying. 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 and PSD and/or Nonattainment Permits) for this facility site.

The Honorable: Wes Suiter
Mailing Address: P.O. Box 908
City: Lufkin State: TX ZIP Code: 75902-0908
2. Is the facility located in a municipality or an extraterritorial jurisdiction of a municipality? (For Concrete Batch Plants) YES NO

Presiding Officers Name(s):

Title:
Mailing Address:
City: State: ZIP Code:
3. Provide the name, mailing address of the chief executive of the city for the location where the facility is or will be located.

Chief Executive: Bob Brown
Mailing Address: 300 E. Shepherd Avenue
City: Lufkin State: TX ZIP Code: 75901

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.TCEQ – 10252 (Revised 02/12) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v18) Page 6 

### Texas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

V. Public Notice Information (complete if applicable) (continued)
3. Provide the name, mailing address of the Indian Governing Body for the location where the facility is or will be located. (continued)
Name of the Indian Governing Body: NA

Title:
Mailing Address:
City: State: ZIP Code:

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 b ilingual program provided by the district? YES NO

If Yes , list which languages are required by the bilingual program? Spanish

VI. Small Business Classification (Required)

A. Does this company (including parent companies and subsidiary companies) have fewer than 100 employees or less than $6 million in annual gross receipts? YES NO

B. Is the site a major stationary s ource for federal air quality permitting? YES NO

C. Are the site emissions of any regulated air po llutant greater than or equal to 50 tpy? YES NO

D. Are the site emissions of all regulated ai r 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

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.TCEQ – 10252 (Revised 02/12) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v18) Page 7 

### Texas Commission on Environmental Quality Form PI-1 General Application for Air Preconstruction Permit and Amendment

VII. Technical Information

B. Are any schools located within 3,000 feet of this facility? YES NO

C. Maximum Operating Schedule:
Hours: 24 hr/day Day(s): 7 day/week Week(s): 52 week/year Year(s): 8,760 hr/year
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 activ ity and indicate which years the MSS activities have been included in the emissions inventories. Attach pages as needed.
MSS activities are listed on Tables A-16 and A-17 of the attached application.

This is a new site and there have b een no previous emission inventories.

E. Does this application involve any air contaminants for which a disaster review is required? YES NO

F. Does this application include a pollutant of concern on the Air Pollutant Watch List (APWL )? YES NO
VIII. State Regulatory Requirements Applicants must demonstrate compliance with all app licable state regulations to obtain a permit or amendment . The application must contain detailed attach ments addressing applicability or non applicability; identify state regulations; show how requirements are met; and include comp liance demonstrations.

A. Will the emissions from the proposed facility protect public health and welfare, and comply with all rules and regulations of the TCEQ? 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 perform ance 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 app licable federal regulations to obtain a permit or amendment The application must contain detailed attachme nts addressing applicability or non applicability; identify federal regulation subparts; show how requiremen ts are met; and include compliance demonstrations.

A. Does Title 40 Code of Federal Regulations Part 60, (40 CFR Part 60) New Source Performance Standard (NSPS) apply to a facility in this application? 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

C. Does 40 CFR Part 63, Maximum Achievable Control Technology (MACT) standard apply to a facility in this application? YES NO

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.TCEQ – 10252 (Revised 02/12) PI-1 Form This form is for use by facilities subject to air quality permit requirements and may be revised periodically. (APDG 5171v18) Page 8 

### 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 app licable federal regulations to obtain a permit or amendment The application must contain detailed attachme nts addressing applicability or non applicability; identify federal regulation subparts; show how requiremen ts are met; and include compliance demonstrations.

D. Do nonattainment permitting requirements apply to this application? YES NO

E. Do prevention of significant deterioration perm itting requirements apply to this application? YES NO

F. Do Hazardous Air Pollutant Major Source [FCAA 112(g)] requirements apply to this application? 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: $75,000
Company name on check: Coronado Powe r Investments 1 LLC Paid online?: YES NO
Is a copy of the check or money order a ttached to the original submittal of this application? YES NO N/A

Is a Table 30 (Form 10196) entitled, Estimated Capital Cost and Fee Verification, attached? YES NO N/A

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.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 11 

## 2.0 P ROJECT 

## S COPE



### 2.1 I NTRODUCTION

With this application, Pinecrest is seeking authorization to construct a new combined cycle electric generati ng plant, PCEC

, in Angelina County, Texas. The power generating equipment, as well as ancillary equipment that will be sources of GHG emissions at the site, are listed below:

 Two natural gas

- fired combustion turbines equipped with lean pre

- mix low

- NO x combustors

 Two natural gas

- fired duct burner systems

 Natural gas piping and metering

 One diesel fuel

- fired emergency electrical generator engine

 One diesel fuel

- fired fire water pump engine

 One natural gas

- fired auxiliary boiler

 Electrical equipment insulated with sulfur hexafluoride (SF 6 )

A process flow diagram is included at the end of this section

.
The business purpose of the PCEC is to generate 637 - 735 megawatts (MW), of gross electrical power near the City of Lufkin in an efficient manner while increasing the reliability of the electrical supply for the State of Texas. One of the factors in siting the plant is the availability of surface water from the City of Lufkin to be used as cooling water at the plant. Pipeline n atural gas is chosen as the only fuel for the combustion turbines and duct burner systems due to local availability of fuel and infrastructure to support delivery of the fuel to the facility in adequate volume and pressure.



### 2.2 C OMBUSTION 

### T URBINE 

### G ENERATOR

The plant will consist of two identical natural gas

- fired combustion turbine generators (CTGs), with three models being considered: the General Electric 7FA .05

, the Siemens SGT6

- 5000F(4), and the Siemens SGT6

- 5000F(5). The final selection of the combustion turbine model will l ikely be made after the permit is issued. Each combustion turbine will exhaust to an HRSG. Emission point numbers (EPNs) for the combustion turbine/HRSG units are identified as U1

- STK and U2

- STK.

The combustion turbine will burn pipeline natural gas to rotate an electrical generator to generate electricity. The main components of a combustion turbine generator consist of a compressor, combustor, turbine, and generator. The compressor pressurizes combustion air to the combustor where the fuel is mixed with the combustion air and burned. Hot exhaust gases then enter the turbine where the gases expand across the turbine blades, driving a shaft to power an electric generator. The exhaust gas will exit the combustion turbine and be routed to the HRSG for s team production.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 12 

### 2.3 H EAT 

### R ECOVERY 

### S TEAM 

### G ENERATOR

Heat recovered in the HRSG will be utilized to produce steam. Steam generated within the HRSG will be utilized to drive a steam turbine and associated electrical generator. The HRSG will be equipped with duct burners for supplemental steam production. The duct burners will be fired with pipeline

- quality natural gas. The duct burners have a maximum heat input capacity of 750 MMBtu/hr per unit. The exhaust gases from the unit, including emissions from the CT and the duct burners, will exit through a stack to the atmosphere.

The normal duct burner operation will vary from 0 to 100 percent of the maximum capacity. Duct burners will be located in the HRSG prior to the selective catalytic reduction system.

S team produced by each of the two HRSGs will be routed to the steam turbine (FIN STG

- 1). The two combustion turbines and one steam turbine will be coupled to electric generators to produce electricity for sale to the Electric Reliability Council of Texas power grid. Each GE combustion turbine model has a maximum base

- load electric power output of approximately 215 MW, the Siemens SGT6

- 5000F(4) is approximately 205 MW, and the Siemens SGT6

- 5000F(5) is approximately 232 MW. The maximum electric power output from the steam turbine is approximately 271 MW for both the GE and Siemens configurations.

The units may operate at reduced load to respond to changes in system power requirements and/or stability.



### 2.4 A UXILIARY 

### B OILER

One auxiliary boiler (EPN AUXBLR ) will be available to facilitate startup of the combined cycle units . The auxiliary boiler will have a maximum heat input of 150 MMBtu/hr and will burn pipeline natural gas. The auxiliary boiler could operate up to 876 hours per year.



### 2.5 D IESEL 

### F IRED 

### E MERGENCY 

### E QUIPMENT

The site will be equipped with one nominally rated 1,072

- hp diesel

- fired emergency generator (EPN: EMGEN1

- STK) to provide electricity to the facility in case of power failure. A nominally rated 500

- hp diesel

- fired pump (EPN: ENG

- FWMAIN) will be installed at the site to provide water in the event of a fire. Each emergency engine will be limited to 100 hours operation per year for purposes of maintenance checks and readiness testing.



### 2.6 N ATURAL 

### G AS 

### /F UEL 

### G AS 

### P IPING

Natural gas will be delivered to th e site via pipeline . Gas will be metered and piped to the new combustion turbine s and duct burners

. Project f ugitive emissions from the gas piping components associated with the new CTG/HRSG unit s will include emissions of methane (CH 4 ) and carbon dioxide ( CO 2 )

. T he natural gas piping is designate d as EPN NG

- FUG

.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 13 

### 2.7 E LECTRICAL 

### E QUIPMENT 

### I NSULATED WITH 

### S ULFUR 

### H EXAFLUORIDE 

### (SF 6 

### )

The generator circuit breaker s associated with the proposed unit s will be insulated with SF 6 . SF 6 is a colorless, odorless, non

- flammable gas. It is a fluorinated compound that has an extremely stable molecular structure. The unique chemical properties of SF 6 make it an efficient electrical insulator. The gas is used for electrical insulation, arc quenching, and current interruption in high

- voltage electrical equipment. SF 6 is only used in sealed and safe systems which under normal circumstances do not leak gas. The capacity of the circuit breaker s associated with the proposed plant is currently estimated to be 400 lb of SF 6 .
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” SF 6 gas

.WATERSTEAMEPN:U2‐STKSTEAMCOMBUSTORHEATRECOVERYSTEAMGENERATOR, SCR,&OXIDATIONCATALYSTSTEAMTURBINEELECTRICGENERATOREPN:U1‐STKCOMPRESSORTURBINEAIRELECTRICGENERATOREPN:CT1LOV‐VNTEPN:ST1LOVNATURALGASFROMPIPELINEAMMONIASTORAGEANDEPN:NG‐FUGEPN:NH3‐FUGMake‐upWaterEPN:CWTPermitApplication Filename:PFD2012‐06‐19.xlsDrawnby: Checkedby: ProjectNo.: Date: Sheet:ERapier LMoon 012205 6/19/2012 1of1PROCESSFLOWDIAGRAMPINECRESTENERGYCENTEREPN:CT2LOV‐VNTWATERSTEAMCONDENSERCOMPRESSORCOMBUSTORAIRELECTRICGENERATORTURBINEHEATRECOVERYSTEAMGENERATOR,SCR,& OXIDATIONCATALYSTSTEAMWATERDISTRIBUTIONCOOLINGTOWERBlowdown

### Pinecrest Energy Center,LLC Lufkin, Texas

Drafted By: J. Knowles Date: 06/19/2012 Project No.: 12205 Reviewed By: L. Moon Datum: NAD 1983 Map Sources: ESRI i-cubed imagery 

# q PLOT PLAN Pinecrest Energy Center Site Boundary

! (

SITE LOCATION 0 500 1,000 Feet 0 150 300 Meters 1 inch = 375 feet 1:4,500 Scale BENCHMARK 2: UTM Zone 15 339265.71 m E 3470756.41 m N BENCHMARK 1: UTM Zone 15 338752.77 m E 3470718.90 m N Cooling Tower FWP1-STK

DSL-TK2 NG-FUG U1-STK

U2-STK

NH3-FUG AUXBLR ST1LOV-VNT DSL-TK1 EMGEN1-STK CT2LOV-VNT CT1LOV-VNT

### Pinecrest Energy Center , LLC Lufkin, Texas

Drafted By: J. Knowles Date: 06/19/2012 Project No.: 12205 Reviewed By: L. Moon Datum: NAD 1983 Map Sources: ESRI i-cubed imagery, 

# q

! ( 

### AREA MAP Pinecrest Energy Center

SITE LOCATION 0 0.5 1 Miles 0 0.5 1 Kilometers 1 inch = 2,000 feet 1:24,000 Scale Benchmark 1: UTM Zone 15 339529.85 mE 3470588.75 mN Benchmark 2: UTM Zone 15 338311.32 mE 3471017.83 mN

Site Boundary 3000 Foot BoundaryP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 17 

## 3.0 GHG E M ISSION 

## C ALCULATIONS



### 3.1 GHG E MISSIONS 

### F ROM 

### C OMBINED 

### C YCLE 

### C OMBUSTION 

### T URBINE

GHG emission s for the combustion turbine s and HRSG are calculated in accordance with the procedures in the Mandatory Greenhouse Reporting Rules, Subpart D – Electric Generation. 3 Annual CO 2 emissions are calculated using the methodology in equation G

- 4 o f the Acid Rain Rules

. 4

Where:

W CO 2 = CO 2 emitte d from combustion, tons/yr.

MW CO 2 = Molecular weight of carbon dioxide, 44.0 lb/lb

- mole.

F c = Ca rbon based F

- factor, 1040 scf/MMBtu for natural gas.

H = Annual heat input in MMBtu.

Uf = 1/385 scf CO 2 /lb

- mole at 14.7 psia and 68 °F.

Emissions of CH 4 and nitrous oxide ( N 2 O) are calculated using the emission factors (kg/MMBtu) for natural gas combustion from Table C

- 2 of the Mandatory Greenhouse Gas Reporting Rules. 5 The g lobal w arming p otential factors used to calculate carbon dioxide equivalent ( CO 2 e)

em issions are based on Table A

- 1 of the Mand atory Greenhouse Gas Reporting Rules.

A separate set of turbine/HRSG calculations is provided for each of the three models being considered: the General Electric 7FA, the Siemens SGT6

- 5000F( 4), and the Siemens SGT6

- 5000F(5). Calculations of GHG emissions from the combined cycle turbines are presented on Tables 3

- 2, 3

- 3, 3 -4 , 3

- 5, 3

- 6, and 3 -7.



### 3.2 A UXILIARY 

### B OILER

CO 2 emissions from the natural

- gas

- fired auxiliary boilers are calculated using the emission factors (kg/MMBtu) for natural gas from Table C

- 1 of the Mandatory Greenhouse Gas Reporting

3 40 C.F.R. 98, Subpart D – Electricity Generation

4 40 C.F.R. 75, Appendix G – Determination of CO 2 Emissions

5 Default CH 4 and N 2 O Emission Factors for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C -2P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 18 Rules. 6 CH 4 and N 2 O emissions from the auxiliary boilers are calculated using the emission factors (kg/MMBtu) for natural gas from Table C

- 2 of the Mandatory Greenhouse Gas Reporting Rules. 7 The g lobal w arming p otential factors used to calculate CO 2 e emissions are based on Table A

- 1 of the Mand atory Greenhouse Gas Reporting Ru les. 8

Calculations of GHG emissions from the auxiliary boiler are presented on Table 3 -8

.



### 3.3 GHG E MISSIONS 

### F ROM 

### N ATURAL 

### G AS 

### /F UEL 

### G AS 

### P IPING 

### F UGITIVES AND 

### N ATURAL 

### G AS 

### /F UEL 

### G AS 

### M AINTENANCE AND 

### S TARTUP 

### /S HUTDOWN 

### R ELATED 

### R ELEASES

GHG emission calculations for natural gas /fuel gas piping component fugitive emissions are based on emission factors from Table W

- 1A of the “2012 Technical Corrections, Clarifying and Other Amendments to the Greenhouse Gas Reporting Rule, and Proposed Confidentiality Determinations fo r Certain Data Elements of the Fluorinated Gas Source Category” which was signed on August 3, 2012 9

. The concentrations of CH 4 and CO 2 in the natural gas are based on a typical natural gas analysis. Since the CH 4 and CO 2 content of natural gas is variable, the concentrations of CH 4 and CO 2 from the typical natural gas analysis are used as a worst case estimate. The g lobal w arming p otential factors used to calculate CO 2 e emissions are based on Table A

- 1 of the Mand atory Greenhouse Gas Repor ting Rules. 10

GHG emission calculations for releases of natural gas related to piping maintenance and turbine startup/shutdowns are calculated using the same CH 4 and CO 2 concentrations as natural
gas /fuel gas piping fugitives.

Calculations of GHG emission s from natural gas piping fugitives is presented on Table 3 -9

. Calculations of GHG emissions from releases of natural gas related to piping maintenance and turbine startup/shutdowns is presented on Table 3

- 10

.



### 3.4 GHG E MISSIONS 

### F ROM 

### D IESEL 

### F IRED 

### E MERGENCY 

### E NGINES

CO 2 emission calculations from the diesel

- fired emergency generator and fire pump engine are calculated using the emission factors (kg/MMBtu) for Distillate Fuel Oil No. 2 from Table C

- 1 of the Mandatory Greenhouse Gas Reporting Rules. 11 CH 4 and N 2 O emission calculations from the diesel

- fired engines are calculated using the emission factors (kg/MMBtu) for Petroleum from Table C

- 2 of the Mandatory Greenhouse Gas Reporting Rules. 12

6 Default CO 2 Emission Factors and High Heat Values for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C -1 The g lobal w arming

7 Default CH 4 and N 2 O Emission Factors for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C -2

8 Global Warming Potentials , 40 C.F.R. Pt. 98, Subpt. A, Tbl. A

- 1.

9 http://www.epa.gov/climatechange/emiss ions/technical

- corrections.html (last visited August 9, 2012)

10 Global Warming Potentials , 40 C.F.R. Pt. 98, Subpt. A, Tbl. A

- 1.

11 Default CO 2 Emission Factors and High Heat Values for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C -1

12 Default CH 4 and N 2 O Emission Factors for Various Types of Fuel , 40 C.F.R. 98, Subpt. C, Tbl. C -2P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 19 p otential factors used to calculate CO 2 e emissions are based on Table A

- 1 of the Mandatory Greenhouse Gas Reporting Rules. 13

Calculations of GHG emissions from the emergency engines are presented on Table 3

- 11

.



### 3.5 GHG E MISSIONS 

### F ROM 

### E LECTRICAL 

### E QUIPMENT 

### I NSULATED WITH 

### SF 6

SF 6 emissions from the new generato r circuit breaker and yard breaker associated with the proposed unit s are calculated using a predicted SF 6 annual leak rate of 0.5% by weight. The global warming potential factors used to calculate CO 2 e emissions are based on Table A

- 1 of the Mandatory Greenhouse Gas Reporting Rules. 14

Calculations of GHG emissions from electrical equipment insulated with SF 6 are presented on Table 3

- 12

.

13 Global Warming Potentials , 40 C.F.R. Pt. 98, Subpt. A, Tbl. A

- 1.

14 Global Warming Potentials , 40 C.F.R. Pt. 98, Subpt. A, Tbl. A

- 1.Table 3-1 Plantwide GHG Emission Summary Pinecrest Energy Center

Name EPN Normal Operation GHG Mass Emissions Startup/Shutdown GHG Mass Emissions Total GHG Mass Emissions Normal Operation

CO 2 e Startup/Shutdown CO 2 e Total CO 2 e ton/yr ton/yr ton/yr ton/yr ton/yr ton/yr Unit 1 (GE F7FA.05) U1-STK 1,404,579 41,637 1,446,216 1,405,902 41,676 1,447,578 Unit 2 (GE F7FA.05) U2-STK 1,404,579 41,637 1,446,216 1,405,902 41,676 1,447,578 Unit 1 (Siemens SGT6-5000F(4)) U1-STK 1,356,650 41,806 1,398,455 1,357,928 41,845 1,399,773 Unit 2 (Siemens SGT6-5000F(4)) U2-STK 1,356,650 41,806 1,398,455 1,357,928 41,845 1,399,773 Unit 1 (Siemens SGT6-5000F(5)) U1-STK 1,526,868 42,433 1,569,300 1,528,306 42,473 1,570,779 Unit 2 (Siemens SGT6-5000F(5)) U2-STK 1,526,868 42,433 1,569,300 1,528,306 42,473 1,570,779 Auxiliary Boiler AUXBLR 7,680 7,680 7,687 7,687 Natural Gas Fugitives NG-FUG 21 21 426 426 Gas Venting TRB-MSS 0.11 0 426 426 Emergency Generator EMGEN1-STK 64 64 65 65 Fire Water Pump FWP1-STK 28 28 28 28 SF 6 Insulated Equipment SF6-FUG 0.001 0.001 24 24

Sitewide Emissions 1 3,061,528 3,146,393 3,065,268

2/11/2013Table 3-2 GHG Annual Emission Calculations - GE F7FA.05 Combined Cycle Combustion Turbines Pinecrest Energy Center

GHG Emissions Contribution From Natural Gas Fired Combustion Turbines

EPN Average Heat Input 1 Annual Heat Input 2 Pollutant Emission Factor GHG Mass
Emissions 4 CO 2 e
(MMBtu/hr) (MMBtu/yr) (kg/MMBtu) 3 (tpy) (tpy)
CO 2 1,404,550.5 1 1,404,550.5

U1-STK 2,861 23,634,263 CH 4 1.0E-03 26.0 21 546.0 (GE F7FA) N 2 O 1.0E-04 2.6 310 805.9
Totals 1,404,579.1 1,405,902.4

CO 2 1,404,550.5 1 1,404,550.5

U2-STK 2,861 23,634,263 CH 4 1.0E-03 26.0 21 546.0 (GE F7FA) N 2 O 1.0E-04 2.6 310 805.9

Totals 1,404,579.1 1,405,902.4

Total for 2 Turbines 2,809,158.1 2,811,804.7

Note 1. The average heat input for the GE F7FA scenario is based on the HHV heat input at 100% load, with maximum duct
firin g , at 69 o F ambient tem p erature. 2. Annual heat input based on 8,260 hours per year operation. 3. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.

4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr
Fc = Carbon based F-factor,1040 scf/MMBtu
H = Heat Input (MMBtu/yr)

U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F

MW CO2 = Molecule weight of CO 2 , 44.0 lb/lbmole

5. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Global Warming
Potential 5

2/11/2013Startup/Shutdown GHG Emissions From GE F7FA Turbine

EPN Heat Input During Startup 1 Annual Heat Input During

Startup 2 Pollutant Emission Factor GHG Mass
Emissions 4 Global Warming
Potential 5 CO 2 e

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu) 3 (ton/hr) (ton/hr)
CO 2 41,636 1 41,636 U1-STK 1,401.2 700,600.0 CH 4 1.0E-03 0.7723 21 16.2
N 2 O 1.0E-04 0.0772 310 23.9 41,636.5 41,676 CO 2 41,636 1 41,636 U2-STK 1,401.2 700,600.0 CH 4 1.0E-03 0.7723 21 16.2
N 2 O 1.0E-04 0.0772 310 23.9 41,636.5 41,676

Note 1. The following hourly firing rates Information is from Table A-3, in Appendix A of the PSD application submitted to TCEQ on 06/22/2012. Turbine Duct Burner Total Hourly Operating CTG Data Heat Input Heat Input Heat Input

Mode Case Number MMBtu/hr MMBtu/hr MMBtu/hr

Maximum Hourly Heat Input During Startup 48% Load, 15 ° F Ambient, no Duct Burner Firin g 13 1,401.2 0 1,401.2

2. Based on 500 hours per year of startups. 3. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.
4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4
W CO2 = (Fc x H x U f X MW CO2 )/2000
W CO2 = CO 2 emitted from combustion, tons/hr Fc = Carbon based F-factor,1040 scf/MMBtu H = Heat Input (MMBtu/hr)
U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F
MW CO2 = Molecule weight of CO 2 , 44.0 lb/lbmole 5. Global Warming Potential factors from Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 

### Table 3-3 Startup GHG Emission Calculations - GE F7FA.05 Turbines Pinecrest Energy Center

2/11/2013EPN Average Heat Input 1 Annual Heat Input 2 Pollutant Emission Factor GHG Mass
Emissions 4 CO 2 e

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu) 3 (tpy) (tpy)
CO 2 1,356,622.0 1 1,356,622.0

U1-STK 2,764 22,827,773 CH 4 1.0E-03 25.1 21 527.3 (Siemens SGT6-5000F(4)) N 2 O 1.0E-04 2.5 310 778.4

Totals 1,356,649.6 1,357,927.7

CO 2 1,356,622.0 1 1,356,622.0

U2-STK 2,764 22,827,773 CH 4 1.0E-03 25.1 21 527.3 (Siemens SGT6-5000F(4)) N 2 O 1.0E-04 2.5 310 778.4
Totals 1,356,649.6 1,357,927.7

Total for 2 Turbines 2,713,299.1 2,715,855.4

Note 1. The average heat input for the Siemens scenarios are based on the HHV heat input at 100% load, with maximum duct
firin g , at 59 o F ambient tem p erature. 2. Annual heat input based on 8,260 hours per year operation. 3. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.

4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr
Fc = Carbon based F-factor,1040 scf/MMBtu
H = Heat Input (MMBtu/yr)

U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F

MW CO2 = Molecule weight of CO 2 , 44.0 lb/lbmole

5. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Table 3-4 GHG Annual Emission Calculations - Siemens SGT6-5000F(4) Combined Cycle Combustion Turbines Pinecrest Energy Center

Global Warming
Potential 5

2/11/2013Startup/Shutdown GHG Emissions From Siemens SGT6-5000F(4)

EPN Heat Input During Startup 1 Heat Input During Startup 2 Pollutant Emission Factor GHG Mass
Emissions 4 Global Warming
Potential 5 CO 2 e

(MMBtu/hr) (MMBtu/yr) ( k g /MMBtu ) 3 (ton/hr) (ton/hr)
CO 2 41,805 1 41,805 U1-STK 1,406.9 703,446.6 CH 4 1.0E-03 0.7754 21 16.2837
N 2 O 1.0E-04 0.0775 310 24.0379 Totals 41,806 41,845 CO 2 41,805 1 41,805 U2-STK 1,406.9 703,446.6 CH 4 1.0E-03 0.7754 21 16.2837
N 2 O 1.0E-04 0.0775 310 24.0379 Totals 41,806 41,845

Note 1. The following hourly firing rates Information is from Table A-3, in Appendix A of the PSD application submitted to TCEQ on 06/22/2012. Turbine Duct Burner Total Hourly Operating CTG Data Heat Input Heat Input Heat Input

Mode Case Number MMBtu/hr MMBtu/hr MMBtu/hr

Maximum Hourly Heat Input During Startup 50% Load, 10 ° F Ambient, no Duct Burner Firin g 13 1,406.9 0 1,406.9

2. Based on 500 hours per year of startup. 3. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.
4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4
W CO2 = (Fc x H x U f X MW CO2 )/2000
W CO2 = CO 2 emitted from combustion, tons/hr Fc = Carbon based F-factor,1040 scf/MMBtu H = Heat Input (MMBtu/hr)
U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F
MW CO2 = Molecule weight of CO 2 , 44.0 lb/lbmole 5. Global Warming Potential factors from Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Table 3-5 Startup GHG Emission Calculations - Siemens SGT6-5000F(4) Turbines Pinecrest Energy Center

2/11/2013EPN Average Heat Input 1 Annual Heat Input 2 Pollutant Emission Factor GHG Mass
Emissions 4 CO 2 e

(MMBtu/hr) (MMBtu/yr) (kg/MMBtu) 3 (tpy) (tpy)
CO 2 1,526,836.5 1 1,526,836.5

U1-STK 3,110 25,691,961 CH 4 1.0E-03 28.3 21 593.5 (Siemens SGT6-5000F(5)) N 2 O 1.0E-04 2.8 310 876.1

Totals 1,526,867.6 1,528,306.1

CO 2 1,526,836.5 1 1,526,836.5

U2-STK 3,110 25,691,961 CH 4 1.0E-03 28.3 21 593.5 (Siemens SGT6-5000F(5)) N 2 O 1.0E-04 2.8 310 876.1
Totals 1,526,867.6 1,528,306.1

Total for 2 Turbines 3,053,735.3 3,056,612.2

Note 1. The average heat input for the Siemens scenarios are based on the HHV heat input at 100% load, with maximum duct
firin g , at 59 o F ambient tem p erature. 2. Annual heat input based on 8,260 hours per year operation. 3. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.

4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr
Fc = Carbon based F-factor,1040 scf/MMBtu
H = Heat Input (MMBtu/yr)

U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F

MW CO2 = Molecule weight of CO 2 , 44.0 lb/lbmole

5. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Table 3-6 GHG Emission Calculations - Siemens SGT6-5000F(5) Combined Cycle Combustion Turbines Pinecrest Energy Center

Global Warming
Potential 5

2/11/2013Startup/Shutdown GHG Emissions From Siemens SGT6-5000F(5)

EPN Heat Input During Startup 1 Annual Heat Input During

Startup 2 Pollutant Emission Factor GHG Mass
Emissions 4 Global Warming
Potential 5 CO 2 e

(MMBtu/hr) (MMBtu/yr) ( k g /MMBtu ) 3 (ton/hr) (ton/hr)
CO 2 42,432 1 42,432 U1-STK 1,428.0 713,994.5 CH 4 1.0E-03 0.7870 21 16.5279
N 2 O 1.0E-04 0.0787 310 24.3983 Totals 42,433 42,473 CO 2 42,432 1 42,432 U2-STK 1,428.0 713,994.5 CH 4 1.0E-03 0.7870 21 16.5279
N 2 O 1.0E-04 0.0787 310 24.3983 Totals 42,433 42,473

Note 1. The following hourly firing rates Information is from Table A-3, in Appendix A of the PSD application submitted to TCEQ on 06/22/2012. Turbine Duct Burner Total Hourly Operating CTG Data Heat Input Heat Input Heat Input

Mode Case Number MMBtu/hr MMBtu/hr MMBtu/hr

Maximum Hourly Heat Input During Startup 50% Load, 10 ° F Ambient, no Duct Burner Firin g 15 1,428.0 0 1,428.0

2. Based on 500 hours per year of startups. 3. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.
4. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4
W CO2 = (Fc x H x U f X MW CO2 )/2000
W CO2 = CO 2 emitted from combustion, tons/hr Fc = Carbon based F-factor,1040 scf/MMBtu H = Heat Input (MMBtu/hr)
U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F
MW CO2 = Molecule weight of CO 2 , 44.0 lb/lbmole 5. Global Warming Potential factors from Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Table 3-7 Startup GHG Emission Calculations - Siemens SGT6-5000F(5) Turbines Pinecrest Energy Center

2/11/2013GHG Potential To Emit Emissions From Natural Gas Fired Auxilliary Boiler

EPN Maximum Heat
In p ut 1 Pollutant Emission Factor GHG Mass Emissions CO 2 e
(MMBtu/yr) (kg/MMBtu) 2 (tpy) (tpy)
CO 2 53.02 7,679.53 1 7,679.5
131,400 CH 4 1.0E-03 0.14 21 3.0
N 2 O 1.0E-04 0.01 310 4.5 Totals 7,679.7 7,687.1

Note 1. Annual fuel use and heating value of natural gas from Table A-10 State/PSD air permit application 2. Factors based on Table C-1 and C-2 of 40 CFR Part 98, Mandatory Greenhouse Gas Reporting. 3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Table 3-8 GHG Emission Calculations - Auxilliary Boiler Pinecrest Energy Center

Global Warming
Potential 3

AUXBLR

2/11/2013Table 3-9 GHG Emission Calculations - Natural Gas Piping Pinecrest Energy Center

GHG Emissions Contribution From Fugitive Natural Gas Piping Components

EPN Source Fluid Count Emission CO 2 2 Methane 3 Total Type State Factor 1 (tpy) (tpy) (tpy) scf/hr/comp Valves Gas/Vapor 600 0.121 0.51 12.73 NG-FUG Flanges Gas/Vapor 2400 0.017 0.29 7.15 Relief Valves Gas/Vapor 5 0.193 0.007 0.17 Sampling Connections Gas/Vapor 10 0.031 0.0022 0.054 Compressors Gas/Vapor 3 0.30 0.006332 0.1578
GHG Mass-Based Emissions 0.81 20.27 21.1 Global Warming Potential 4 1 2 1
CO 2 e Emissions 0.81 425.6 426.4

Note 1. Emission factors from Table W-1A of 40 CFR 98 Mandatory Greenhouse Gas Reporting included in the August 3, 2012 Technical Corrections

2. CO 2 emissions based on vol% of CO 2 in natural gas 1.41%

3. CH 4 emissions based on vol% of CH 4 in natural gas 96.10% 4. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.

Example calculation: 600 valves 0.123 scf gas lbmole 44 lb CO 2 8760 hr ton = 0.51 ton/y r

hr * valve scf gas 385 scf lbmole yr 2000 lb 0.0141 scf CO2

2/11/2013CO 2 3 CH 4 4 Total

Volume 1 Press. Temp. Press. Temp. Volume 2 Annual Annual Annual

(ft 3 ) (psig) (°F) (psig) (°F) (scf) (tpy) (tpy) (tpy)
1,146 50 50 0 68 5,277 0.0042 0.11

6.7 50 50 0 68 31 0.00002 0.00061

GHG Mass-Based Emissions 0.0043 0.1060 0.11 Global Warming Potential 5 1 2 1
CO 2 e Emissions 0.0043 2.2 2.2

1. Initial volume is calculated by multpilying the crossectional area by the length of pipe using the following formula: V i = pi * [(diameter in inches/12)/2] 2 * length in feet = ft 3

2. Final volume calculated using ideal gas law [(PV/ZT) i = (PV/ZT) f ]. V f = V i (P i /P f ) (T f /T i ) (Z f /Z i ), where Z is estimated using the following

equation: Z = 0.9994 - 0.0002P + 3E-08P 2

. 3. CO 2 emissions based on vol% of CO 2 in natural gas 1.41% from natural gas analysis
4. CH 4 emissions based on vol% of CH 4 in natural gas 96.1% from natural gas analysis 5. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.

Example calculation:

5277 scf Nat Gas 0.014 scf CO2 lbmole ton = = 0.0042 ton/yr CO 2

yr scf Nat Gas 385 scf 2000 lb Location

Turbine Fuel Line Shutdown/Maintenance

Small Equipment/Fugitive Component Repair/Replacement

44 lb CO 2

lbmole TABLE 3-10 Gaseous Fuel Venting During Turbine Shutdown/Maintenance and

Small Equipment and Fugitive Component Repair/Replacement Pinecrest Energy Center

Initial Conditions Final Conditions

2/11/2013GHG Emissions Contribution From Diesel Combustion In Emergency Engines

Assumptions Generator Fire Water Pump Ann.Operating Schedule 100 100 hours/year Power Rating 1,072 500 hp
Max Fuel Combustion 57.3 24.7 gal/hr Heating Value of No. 2 Fuel Oil 1 0.138 0.138 MMBtu/gal Max Hourly Heat Input 7.9 3.4 MMBtu/hr Annual Heat Input 790.7 340.9 MMBtu/yr

EPN Heat Input Pollutant Emission Factor GHG Mass Emissions CO 2 e
(MMBtu/yr) (kg/MMBtu) 2 (tpy) (tpy)
CO 2 73.96 64.3 1 64.3
EMGEN1-STK 790.7 CH 4 3.0E-03 0.0026 21 0.1
N 2 O 6.0E-04 0.0005 310 0.2

64.33 64.5

CO 2 73.96 27.7 1 27.7
FWP1-STK 340.9 CH 4 3.0E-03 0.0011 21 0.0
N 2 O 6.0E-04 0.0002 310 0.1

Totals 27.73 27.8

Calculation Procedure Annual Emission Rate = annual heat Input X Emission Factor X 2.2 lbs/kg X Global Warming Potential / 2,000 lbs/ton

Note 1. Default high heat value based on Table C-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 2. GHG factors based on Tables C-1 and C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. Table 3-11 GHG Emission Calculations - Emergency Engines Pinecrest Energy Center

Global Warming
Potential 3

2/11/2013Table 3-12 GHG Emission Calculations - Electrical Equipment Insulated With SF 6 Pinecrest Energy Center

Assumptions Insulated circuit breaker SF 6 capacity 400 lb

Estimated annual SF 6 leak rate 0.5% by weight
Estimated annual SF 6 mass emission rate 0.001 ton/yr

Global Warmin g Potential 1 23,900 Estimated annual CO 2 e emission rate 23.9 ton/yr

Note 1. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.

2/11/2013P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 32 

## 4.0 P REVENTION OF 

## S IGNIFICANT 

## D ETERIORATION 

## A PPLICABILITY

Because the project emissions increase of GHG is greater than 100 ,000 ton/yr of CO 2 e, PSD is triggered for GHG emissions. The emissions netting analysis is documented on the attached TCEQ PSD netting tables: Table 1F and Table 2F

. Note that this is a new Greenfield site and, as such, there are no contemporaneous emission changes associated with the project. Also included in Appendix A is the “The GHG PSD APPLICABILI TY FLOWCHART – NEW SOURCES” from the PSD and Title V Permitting Guidance for Greenhouse Gases

.

.TABLE 1F AIR QUALITY APPLICATION SUPPLEMENT

Permit No.: 179334, PSD-TX-1298 Application Submittal Date: Company Pinecrest Energy Center, LLC RN: RN106444755 Facility Location: 1002 East Park Avenue City Lufkin County: Angelina
Permit Unit I.D.: GTG/HRSG1 and GTG/HRSG2 Permit Name: Pinecrest Energy Center Permit Activity: Project or Process Description:

Complete for all pollutants with a project POLLUTANTS
emission increase. Ozone CO SO 2 PM GHG CO 2 e NOx VOC Nonattainment? (yes or no) No No Existing site PTE (tpy) 0 0 Proposed project increases (tpy from 2F) 3 3,146,393 3,150,162

Is the existing site a major source? If not, is the project a major source by itself? (yes or no) Yes If site is major, is project increase significant? (yes or no) Yes Yes If netting required, estimated start of construction: 6/1/13 5 years prior to start of construction: 6/1/08 Contemporaneous estimated start of operation: 10/1/15 Period Net contemporaneous change, including proposed project, from Table 3F (tpy) 3,146,393 3,150,162 FNSR applicable? (yes or no) Yes Yes

1. Other PSD pollutants 2. Nonattainment major source is defined in Table 1 in 30 TAC 116.12(11) by pollutant and county. PSD thresholds are found in 40 CFR § 51.166(b)(1). Construction of new combined cycle electric generating plant

This form for GHG only New Major Source Modification

3. Sum of proposed emissions minus baseline emissions, increases only. Nonattainment thresholds are found in Table 1 in 30 TAC 116.12(11) and PSD thresholds in 40 CFR § 51.166(b)(23). 4. Since there are no contemporaneous decreases which would potentially affect PSD applicability and an impacts analysis is not required for GHG emissions, contemporaneous emission changes are not included on this table. The presentations made above and on the accompanying tables are true and correct to the best of my knowledge.

Signature Title Date New Major Source ModificationTABLE 2FPROJECT EMISSION INCREASEPollutant(1):GHGPermit:101542Baseline Period:N/AtoN/AA BAffected or Modified Facilities(2)Permit No.FIN EPN1CTG1/HRSG1 U1-STK 1015420.000.001,569,300 1,569,300 1,569,3002CTG2/HRSG2 U2-STK 1015420.000.001,569,300 1,569,300 1,569,3003AUXBLRAUXBLR1015420.000.007,680 7,680 7,6804NG-FUGNG-FUG1015420.000.0021 21 215TRB-MSS TRB-MSS 1015420.000.000.11 0 06EMGEN1 EMGEN1-STK1015420.000.0064 64 647FWP1 FWP1-STK1015420.000.0028 28 288SF6-FUGSF6-FUG1015420.000.000.0010 0.0010 0.001091011121415Page Subotal(9)3,146,393ProjectIncrease(8)ActualEmissions(3)BaselineEmissions(4)ProposedEmissions(5)ProjectedActualEmissionsDifference(B - A)(6)Correction(7)TABLE 2FPROJECT EMISSION INCREASEPollutant(1):CO2ePermit:101542Baseline Period:N/AtoN/AA BAffected or Modified Facilities(2)Permit No.FIN EPN1CTG1/HRSG1 U1-STK 1015420.000.001,570,779 1,570,779 1,570,7792CTG2/HRSG2 U2-STK 1015420.000.001,570,779 1,570,779 1,570,7793AUXBLRAUXBLR1015420.000.007,687 7,687 7,6874NG-FUGNG-FUG1015420.000.00426 426 4265TRB-MSS TRB-MSS 1015420.000.00426 426 4266EMGEN1 EMGEN1-STK1015420.000.0065 65 657FWP1 FWP1-STK10154289101112131415Page Subotal(9)3,150,162ActualEmissions(3)BaselineEmissions(4)ProposedEmissions(5)ProjectedActualEmissionsDifference(B - A)(6)Correction(7)ProjectIncrease(8)PageSubotal3,150,162All emissions must be listed in tons per year (tpy). The same baseline period must apply for all facilities for a given NSR pollutant.1. Individual Table 2F's should be used to summarize the project emission increase for each criteria pollutant.2. Emission Point Number as designated in NSR Permit or Emissions Inventory.3. All records and calculations for these values must be available upon request.4. Correct actual emissions for currently applicable rule or permit requirements, and periods of non-compliance. These corrections, as well as any MSS previously demonstrated under 30 TAC 101, should be explained inthe Table 2F supplement.5. If projected actual emission is used it must be noted in the next column and the basis for the projection identified in the Table 2F supplement.6. Proposed Emissions (column B) Baseline Emissions (column A).7. Correction made to emission increase for what portion could have been accommodated during the baseline period. The justification and basis for this estimate must be provided in the Table 2F supplement.8. Obtained by subtracting the correction from the difference. Must be a positive number.9. Sum all values for this page.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 36 

## 5.0 B EST 

## A VAILABLE 

## C ONTROL 

## T ECHNOLOGY 

## (BACT)

The PSD rules define BACT as:

Best available control technology means 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 oth er 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. In no event shall application of best available control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR parts 60 and 61. If the Administrator determines that technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design, equipment, work practice, operational standard, or combination thereof, may be prescribed instead to satisfy the requirement for the application of best available control technology. Such standard shall, to the degree possible, set forth the emissions reduction achievable by implementation of such design, equipment, work practice or operation, and shall provide for compliance by means which achieve equivalent results. 15

In the EPA g uidance document titled PSD and Title V Permitting Guidance for Greenhouse Gases

, EPA recommended the use of the Agency’s five

- step “top

- down” BACT proces s to determine BACT for GHGs. 16 In brief, the top

- down process calls for all available control technologies for a given pollutant to be identified and ranked in descending order of control effectiveness. The permit applicant should first examine the highest

- ranked (“top”) option. The top

- ranked options should be established as BACT unless the permit applicant demonstrates to the satisfaction of the permitting authority that technical considerations, or energy, environmental, or economic impacts justify a conclusion that the top ranked technology is not “achievable” in that case. If the most effective control strategy i s eliminated in this fashion, then the next most effective alternative should be evaluated, and so on, until an option is selected as BACT.

EPA has broken down this analytical process into the following five steps:

Step 1: Identify all available control technologies. Step 2: Eliminate technically infeasible o ptions. Step 3: Rank remaining control technologies.

15 40 C .F.R. § 52.21(b)(12.)

16 EPA, PSD and Title V Permitting Guidance for Greenhouse Gases

, p. 18 (N ov

. 2010 ).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 37 Step 4: Evaluate most effective controls and document results. Step 5: Select the BACT.



### 5.1 BACT FOR THE 

### C OMBINED 

### C YCLE 

### C OMBUSTION 

### T URBINE



### 5.1.1 Step 1: Identify All Available Control Technologies

5.1.1.1 Inherently Low er

- Emitting Processes/Practices/Designs

A summary of available, lower greenhouse gas emitting processes, practices, and designs for combustion turbine power generators is presented below. The proposed energy efficiency processes, practices and designs discussed in Step 1 will be the same for three models of combustion turbines being considered for this site: the General Electric 7FA, the Siemens SGT6

- 5000F(4), and the Siemens SGT6

- 5000F(5 ) . The BACT limits proposed in Step 5 are specific to each turbine model.



### 5.1.1.1.1

Combustion Turbine Design 

### Combustion Turbine E nergy E fficiency Processes, P ractices, and Designs

CO 2 is a product of combustion of fuel containing carbon, which is inherent in any power generation technology using fossil fuel. It is not possible to reduce the amount of CO 2 generated from combustion, as CO 2 is the essential product of the chemical reaction between the fuel and the oxygen in which it burns, not a byproduct caused by imperfect combustion. As such, there is no technology available that can effectively reduce CO 2 generation by adjusting the conditions in which combustion takes place

.
The only effective means to reduce the amount of CO 2 generated by a fuel

- burning power plant is to generate as much electric power as possible from the combustion, thereby reducing the amount of fuel needed to meet the plant’s required power output. This result is obtained by using the most efficient generating technologies available, so that as much of the energy content of the fuel as possible goes into generating power.

The most efficient way to generate electricity from a natural gas fuel source is the use of a combined cycle design. For fossil fuel technologies, efficiency ranges from approximately 30 -50 % (higher heating value [HHV]). A typical coal

- fired Rankine cycle power plant has a base load efficiency of approximately 3 0 % (HHV), while a modern F

- Class natural gas fired combined cycle unit operating under optimal conditions has a base load efficiency of approximately 5 0 % (HHV).

Combined cycle units operate based on a combination of two thermodynamic cycl es : the B rayton and the Rankine cycles. A combustion turbine operates on the Brayton cycle and the HRSG and steam turbine operate on the Rankine cycle. The combination of the two thermodynamic cycles allows for the high efficiency associated with combined cycle plants.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 38 In addition to the high

- efficiency primary components of a combustion turbine, there are a number of other design features employed within the turbine that can improve the overall efficiency of the machine. These additional features include those summarized below.

Periodic Burner Tuning Modern F

- Class combustion turbines have regularly scheduled maintenance programs. These maintenance programs are important for the reliable operation of the unit, as well as to maintain optimal effic iency. As the combustion turbine is operated, the unit experiences degradation and loss in performance. The combustion turbine maintenance program helps restore the recoverable lost performance. The maintenance program schedule is determined by the numb er of hours of operation and/or turbine starts. There are three basic maintenance levels, commonly referred to as combustion inspections, hot gas path inspections, and major overhauls. Combustion inspections are the most frequent of the maintenance cycle s. As part of this maintenance activity, the combustors are tuned to restore high ly efficient low

- emission operation.

Reduction in Heat Loss Modern F

- Class combustion turbines have high operating temperatures. The high operating temperatures are a result of the heat of compression in the compressor along with the fuel combustion in the burners. To minimize heat loss from the combustion turbine and protect the personnel and equipment around the machine, insulation blankets are applied to the combustion turbine casing. These blankets minimize the heat loss through the combustion turbine shell and help improve the overall efficiency of the machine.

Instrumentation and Controls Modern F

- Class combustion turbines have sophisticated instrumentation and contr ols to automatically control the operation of the combustion turbine. The control system is a digital

type and is supplied with the combustion turbine. The distributed control system (DCS) controls all aspects of the turbine’s operation, including the fu el feed and burner operations, to achieve efficient low

- NO X combustion. The control system monitors the operation of the unit and modulates the fuel flow and turbine operation to achieve optimal high

- efficiency low

- emission performance for full

- load and p art

- load conditions.



### 5.1.1.1.2

The HRSG take s waste heat from the combustion turbine exhaust and uses the waste heat to convert boiler feed water to steam. Duct burning involves burning additional natural gas in the ducts to the heat recovery boiler, which increases the temperature of the exhaust coming from the combustion turbines and thereby creates additional steam for the steam turbine. The duct burner firing provides additio nal power generation capacity during periods of high electrical demand. 

### Heat Recovery Steam Generator E nergy E fficiency Processes, Practices, and DesignsP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 39 The mo dern F

- Class combustion turbine

- based combined cycle HRSG is generally a horizontal

, natural circulation

, drum

- type heat exchanger designed with three pressure levels of steam
g eneration, reheat, split superheater sections with interstage attemperation, post

- combustion emissions control equipment, and condensate recirculation. The HRSG is designed to maximize the conversion of the combustion turbine exhaust gas waste heat to ste am for all plant ambient and load conditions. Maximizing steam generation will increase the steam turbine’s power generation, which maximizes plant efficiency

.
Heat Exchanger Design Considerations HRSGs are heat exchangers designed to capture as much thermal energy as possible from the combustion turbine exhaust gases. This is performed at multiple pressure levels. For a drum

type configuration, each pressure level incorporates an economizer secti on(s), evaporator section, and superheater section(s). These heat transfer sections are made up of many thin

walled tubes to provide surface area to maximize the transfer of heat to the working fluid. Most of the tubes also include extended surfaces (e.g., fins). The extended surface optimizes the heat transfer, while minimizing the overall size of the HRSG. Additionally, flow guides are used to distribute the flow evenly through the HRSG to allow for efficient use of the heat transfer surfaces and post

- combustion emissions control components. Low

- temperature economizer sections employ recirculation systems to minimize cold

- end corrosion, and stack dampers are used for cycling operation to conserve the thermal energy within the HRSG when the unit is off line.

Insulation HRSGs take waste heat from the combustion turbine exhaust gas and uses that waste heat to
convert boiler feed water to steam. As such, the temperatures inside the HRSG are nearly equivalent to the exhaust gas temperatures of the turbine. For F

- Class combustion turbines, these temperatures can approach 1,200°F. HRSGs are designed to maximize the conversion of the waste heat to steam. One aspect of the HRSG design in maximizing this waste heat conversion is the use of insulation. Insulation minimizes heat loss to the surrounding air

, thereby improving the overall efficiency of the HRSG. Insulation is applied to the HRSG panels that make up the shell of the unit, to the high

- temperature steam and water lines, and typically to the bottom portion of the stack.

Minimizing Fouling of Heat Exchange Surfaces HRSGs are made up of a number of tubes within the shell of the unit that are used to generate steam from the combustion turbine exhaust gas waste heat. To maximize this heat transfer, th e tubes and their extended surfaces need to be as clean as possible. Fouling of the tube surfaces impedes the transfer of heat. Fouling occurs from the constituents within the exhaust gas stream. To minimize fouling, filtration of the inlet air to the combustion turbine is performed. Additionally, cleaning of the tubes is performed during periodic outages. By reducing the fouling, the efficiency of the unit is maintained.

Minimiz ing Vented Steam and Repair of Steam Leaks As with all steam

- generated power facilities, minimization of steam vents and repair of steam leaks is important in maintaining t he plant ’s efficiency . A combined cycle facility has just a fewP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 40 locations where steam is vented from the system, including at the deaerator vents, blowdown tank vents, and vacuum pumps/steam jet air ejectors. These vents are necessary to improve the overall heat transfer within the HRSG and condenser by removing solids and air that potentially blankets the heat transfer surfaces lowering the equipment’s perf ormance. Additionally, power plant operators are concerned with overall efficiency of their facilities. Therefore, steam leaks are repaired as soon as possible to maintain facility performance. Minimization of vented steam and repair of steam leaks will be performed for this project

.



### 5.1.1.1.3

The steam turbine for this project will be a modern, high

- efficiency, reheat, condensing unit. Steam turbines have been in operation for over a century, and are generally classified as impulse or reaction. However, most modern turbines employ both impulse and reaction blading. The overall efficiency of the unit is affected by a number of items, including the inlet steam conditions, the exhaust steam conditions, the blading design, the turbine seals, and the generator efficiency. 

### Steam Turbine Energy Efficiency Processes, Practices, and Designs

Use of Reheat Cycles The efficiency of a steam turbine is directly related to the steam conditions entering the turbine. The higher the steam temperature and pressure, the higher the overall efficiency. To achieve the higher temperatures, reheat cycles are employed. This is necessary to minimize the moisture content of the exhaust steam. If the moisture content of the exhaust steam is too high, erosion of the last

- stage turbine blades occurs. This cycle reheats partially expanded steam from the steam turbine. For a modern combined cycle facility, the high

- pressure inlet and intermediate

- pressure inlet steam temperatures typically are 1,050°F and above, and the high

pressure steam turbine inlet pressure is typically in the range of 1,800

- 2,400 psig.

Use of Exhaust Steam Conde nser Steam turbine efficiency is also improved by lowering the exhaust steam conditions of the unit. The lower the exhaust pressure, the higher the overall turbine efficiency. For high

- efficiency units, the exhaust steam is saturated under vacuum conditions. This is accomplished by the use of a condenser. The condenser is typically a shell and tube heat exchanger with cooling water flowing through the tubes and the turbine exhaust steam condensing in the shell. The condensing steam creates a vacuum in the condenser, which increases steam turbine efficiency. This vacuum is dependent on the temperature of the cooling water. As the temperature of the cooling water is lowered, the absolute vacuum attainable is lowered and the steam turbine is more efficie nt.

Efficient Blading Design Blading design also affects the overall efficiency of the turbine. As noted earlier, steam turbines have been used to generate power for over a century, and are either imp ulse or reaction design. The blade design has evolved for high

- efficiency transfer of the energy in the steam to power generation. Additionally, 3- D computer

- aided design technology is also employed to provide theP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 41 highest efficiency blade design. Blade materials are also important components in blade desig n, which allow for high

- temperature and large exhaust areas to improve performance.

Turbine seals are also important in the overall performance of the steam turbine. The high

pressure steam will leak to the atmosphere along the turbine shaft, as well as bypass the turbine stages if sealing is not employed. The steam turbine designers have multiple steam seal designs to obtain the highest efficiency from the steam turbine.

Efficient Steam Turbine Generator Design The steam turbine generator is also a key element in the overall performance of the steam turbine. The modern generator is a high

- efficiency unit. The generator for modern steam turbines is typically cooled by one of three methods. These methods are ope n- air cooling, totally enclosed water to air cooling, or hydrogen cooling. These cooling methods allow for the highest efficiency of the generator, resulting in an overall high

- efficiency steam turbine. According to Siemens representatives, there is no energy penalty between the three cooling methods. The cooling method for the PCEC steam turbine will be either totally enclosed water to air cooling or hydrogen cooling. The selection of the cooling method will be made by the equipment provider based on atmospheric condi tions for the particular site.



### 5.1.1.1.4

There are a number of other components within the combined cycle plant that help improve overall efficiency, including: 

### Plant

- wide E nergy Efficiency Processes, P ractices, and Designs

**•** Fuel gas preheating – The overall efficiency of the combustion turbine is increased with increased fuel inlet temperatures. For the F

- Class combustion turbine based combined cycle, the fuel gas is generally heated with high temperature water from the HRSG. This improves the efficiency of the combustion turbine.

**•** Drain operation – Drains are required to allow for draining the equipment for maintenance (i.e., maintenance drains), and also to allow condensate to be removed from the steam piping and drains for operation (i.e., o peration drains). Operation drains are generally controlled to minimize the loss of energy from the cycle. This is accomplished by closing the drains as soon as the appropriate steam conditions are achieved.

**•** Multiple combustion turbine/HRSG trains – Mult iple combustion turbine/HRSG trains help with part

- load operation. The multiple trains allow the unit to achieve higher overall plant part

- load efficiency by shutting down a train operating at less efficient part

- load conditions and ramping up the remaini ng train to high

- efficiency full

- load operation.

**•** Boiler feed pump fluid drives – The boiler feed pumps are used as the means to impart high pressure on the working fluid. The pumps require considerable power. To minimize the power consumption at part

- loa ds, the use of fluid drives or variable

- frequency drives can be employed. For this project, fluid drives areP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 42 being used to minimize power consumption at part

- load, improving the facility’s overall efficiency.



### 5.1.1.2 Add

- On Controls

In addition to power generation process technology options discussed above, it is appropriate to consider add

- on technologies as possible ways to capture GHG emissions that are emitted from natural gas combustion in the proposed project’s CTG/HRSG unit s an d to prevent them from entering the atmosphere. These emerging carbon capture and storage (CCS) technologies generally consist of processes that separate CO 2 from combustion process flue gas, and then inject it into geologic formations such as oil and gas reservoirs, unmineable coal seams, and underground saline formations . Of the emerging CO 2 capture technologies that have been identified, only amine absorption is currently commercially used for state

- of

- the

- art CO 2 separation processes. Amine absorption has been applied to processes in the petroleum refining and natural gas processing industries and for exhausts from gas

- fired industrial boilers

. Other potential absorption and membrane technologies are currently considered developmental.

The U.S. Depa rtment of Energy’s National Energy Technology Laboratory ( DOE

- NETL) provides the following brief description of state

- of

- the

- art post

- combustion CO 2 capture technology and related implementation challenges:

“ ...In the future, emerging R&D will provide numer ous cost

- effective technologies for capturing CO 2 from power plants. At present, however, state

- of

- the

- art technologies for existing power plants are essentially limited to amine absorbents. Such amines are used extensively in the petroleum refining and natural gas processing industries... Amine solvents are effective at absorbing CO 2 from power plant exhaust streams

— about 90 percent removal

— but the highly energy

- intensive process of regenerating the solvents decreases plant electricity output... ” 17

The DOE -N ETL adds:

“ ...Separating CO 2 from flue gas streams is challenging for several reasons:

**•** CO 2 is present at dilute concentrations (13

- 15 volume percent in coal

- fired systems and 3

- 4 volume percent in gas

- fired turbines) and at low pressure (15

- 25 pounds per square inch absolute [ psia ] ), which dictates that a high volume of gas be treated.

17 DOE

- NETL, Carbon Sequestration: FAQ Information Portal

,

http://extsearch1.netl.doe.gov/search?q=cache:e0yvzjAh22cJ:www.netl.doe.gov/technologies/carbon_seq/FAQs/te
ch

- status.html+emerging+R%26D&access=p&output=xml_no_dtd&ie=UTF

8&client=default_frontend&site=default_collection&proxystylesheet=default_frontend&oe=ISO

- 8859 -1 (last visited Feb. 27, 2012 ).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 43 **•** Trace im purities (particulate matter, sulfur dioxide, nitrogen oxides) in the flue gas can degrade sorbents and reduce the effectiveness of certain CO 2 capture
processes.

**•** Compressing captured or separated CO 2 from atmospheric pressure to pipeline pressure (about 2 ,000 psia) represents a large auxiliary power load on the overall power plant system... ” 18

For the combustion turbines being considered for this project, the CO 2 stack concentration at base load and ISO conditions for the General Electric 7FA is 3.9 vol% without duct burner firing and 5.4 vol% with duct burner firing; the Siemens SGT6

- 5000F(4) is 3.9 vol% without duct burner firing and 5.2 vol% with duct burner firing; and the Siemens SGT6

- 5000F(5) is 3.8 vol% without duct burner firing and 4.9 vol% with duct burner firing

.

If CO 2 capture can be achieved at a power plant, it would need to be routed to a geologic formation capable of long

- term storage. The long

- term storage potential for a formation is a function of the volumetric capacity of a geologic formation and CO 2 trapping mechanisms within the formation, including dissolution in brine

, react ions with minerals to form solid carbonates

, and/or adsorption in porous rock. The DOE

- NETL describes the geologic formations that could potentially serve as CO 2 storage sites as follows:

“ Geologic carbon dioxide (CO 2 ) storage involves the injection of supercritical CO 2 into deep geologic formations (injection zones) overlain by competent sealing formations and geologic traps that will prevent the CO 2 from esc aping. Current research and field studies are focused on developing better understanding of 11 major types of geologic storage reservoir classes , e ach having their own unique opportunities and challenges. Understanding these different storage classes provides insight into how the systems influence fluids flow within these systems today, and how CO 2 in geologic storage would be anticipated to flow in the future. The different storage formation classes include: deltaic, coal/shale, fluvial, alluvial, strandplain, turbidite, eolian, lacustrine, clastic shelf, carbonate shallow shelf, and reef. Basaltic interflow zones are also being considered as potential reservoirs. These storage reservoirs contain fluids that may include natural gas, oil, or saline water; any of which may impact CO 2 storage differently...” 19



### 5.1.2 Step 2: Eliminate Technically Infeasible Options

A mine absorption technol ogy for CO 2 capture has been applied to processes in the petroleum refining and natural gas processing industries, so it is technically feasible to apply that technology to exhausts for power plants. However, that technology has not been commercially available to power plants gas turbine exhausts, which have considerably larger flow volumes and considerably lower CO 2 concentrations. The high energy demand, high water demand,

18 Id

.
19 DOE

- NETL

, Carbon Sequestration: Geologic Storage Focus Area,

http://www.netl.doe.gov/technologies/carbon_seq/corerd/storage.html (last visited Feb. 27, 2012)P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 44 technical difficulties and economic costs associated with CCS are addressed in Step 4 of this section.


### 5.1.3 Step 3: Rank Remaining Control Technologies

As all of the energy efficiency related processes, practices, and designs discussed in Section 5.1.1 .1 of this application are being proposed for this project, a ranking of the control technologies is not necessary for this application. As documented in Step 4 below

, implementation of CCS technology is not economically reasonable, leaving energy efficiency measures as the only feasible emission control options.



### 5.1.4 Step 4: Evaluate Most Effective Controls and Document Results

As all of the energy efficiency related processes, practices, and designs discussed in Section 5.1.1 .1 of this application are being proposed for this project, an examination of the energy, environmental, and economic impacts of the efficiency designs is not necessary for this application.

In this section, PCEC addresses the potential energy, environmental, and economic fea sibility of implementing CCS technology as BACT for GHG emissions from the proposed project’s gas turbine/HRSG trains. Each component of CCS technology (i.e., capture and compression, transport, and storage) is discussed sep arately.



### 5.1.4.1 CO 2 

### Capture and Compression

Though amine absorption technology for CO 2 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 t o apply to power plant gas turbine exhausts, which have considerably larger flow volumes and considerably lower CO 2 concentrations. The Obama Administration’s Interagency Task Force on Carbon Capture and Storage confirms this in its recently completed rep ort on the current status of development of CCS systems:

“Current technologies could be used to capture CO 2 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 CO 2 capture capacities used in current industrial processes are generally much smaller than the capacity 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.” 20

20 Report of the Interagency Task Force on Carbon Capture and Storage at 50 ( Aug

. 2010 ).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 45 In its current CCS research program plans, the DOE

- NETL confirms that commercial CO 2 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) D evelop technologies that can separate, capture, transport, and store CO 2 using either direct or indirect systems that result in a less than 10 percent increase in the cost of energy by 2015; (2) D evelop technologies that will support industries’ ability to predict CO 2 storage capacity in geologic formations to within ±30 percent by 2015; (3) D evelop technologies to demonstrate that 99 percent of injec ted CO 2 remains in the injection zones by 2015; (4) C omplete 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, effe ctive commercial deployment both domestically and abroad beginning in 2020 and through the next several decades.” 21 A

To corroborate that commercial availability of CO 2 capture technology for large

- scale power plant projects will not occur for several more years, Alstom, one of the major developers of commercial CO 2 capture technology using post

- combustion amine absorption, post

- combustion chilled ammonia absorption, and oxy

- combustion, states on its web site that its CO 2 capture technology will become commercially available in 2015. 22 B 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 CO 2 emissions generated by a project of the size of PCEC

.
Another challenge of CO 2 capture is conservation of water resources. 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's as well as the level of duct firing in the HRSG. Adding CO 2 separation facilities and compression equipment significantly increases the cooling water requirements of a generating station. Studies have indicated that the water consumption of a natural fired combined cycle facility with CCS may have an increased water consumption of more than 90%.



### 5.1.4.2 CO 2 

### Transport

Even if it is assumed that CO 2 capture and compression could feasibly be achieved for the proposed project, the high

- volume CO 2 stream generated would need to be transported to a facility capable of storing it. Potential geologic storage sites in Texas, Louisiana, and

21 DOE

- NETL, Carbon Sequestration Program: Technical Program Plan, at 10 (Feb. 2011).

22 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/ (last visited Sept.28, 2011).P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 46 Mississippi to which CO 2 could be transported if a pipeline was constructed are delineated on the map found at the end of Section 5. 23 The potential length of such a CO 2 transport pipeline is uncertain due to the uncertainty of identifying a site(s) that is suitable for large

- scale, long

- term CO 2 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 CO 2 , which is an enhanced oil recovery (EOR) reservoir site located within 45 miles of the proposed project.

However, none of the EOR reservoir or other geologic formation sites have yet been technically demonstrated for large

- scale, long

- term CO 2 storage.

In comparison, the closest site that is currently being field

- tested to demonstrate its capacity for large

- scale geological storage of CO 2 is the Southwest Regional Partnership on Carbon Sequestration’s (SWP) SACROC test site, which is located in Scurry County, Texas approximately 490 miles away (see the map at the end of Section 5 for the test site location). Therefore, to access this potentially large

- scale storage capacity site, assuming that it is eventually demonstrated to indefinitely store a substantial portion of the large volume of CO 2 generated by the proposed project, a very long and sizable pipeline would need to be constructed to transport the large volume of high

- pressure CO 2 from the plant to the storage facility, thereby rendering implementation of a CO 2 transport system infeasible.



### 5.1.4.3 CO 2 

### Storage

Even if it is assumed that CO 2 capture and compression could feasibly be achieved for the proposed project and that the CO 2 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, CO 2 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 CO 2 into the formations. P otential environmental impacts resulting from CO 2 injection that still require assessment before CCS technology can be considered feasible include:

**•** Uncertainty concerning the significance of dissolution of CO 2 into brine,

**•** Risks of brine displacement resul ting from large

- scale CO 2 injection, including a pressure leakage risk for brine into underground drinking water sources and/or surface water,

**•** Risks to fresh water as a result of leakage of CO 2 , including the possibility for damage to the biosphere, underground drinking water sources, and/or surface water, 24

**•** Potential effects on wildlife. and

23 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 CO 2 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 (last visited Feb. 27, 2012).

24 Id.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 47 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 CO 2 are located within 4 5 miles of the proposed project, but such nearby sites have not yet been technically demonstrated with respect to all of the suitability factors described above. In comparison, the closest site tha t is currently being field

- tested to demonstrate its capacity for geological storage of the volume of CO 2 that would be generated by the proposed power unit, i.e., SWP’s SACROC test site, is located in Scurry County, Texas approximately 490 miles away. It should be noted that, based on the suitability factors described above, currently the suitability of the SACROC site or any other test site to store a substantial portion of the large

vo lume of CO 2 generated by the proposed project has yet to be fully demonstrated.

Based on the reasons provided above, PCEC 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, PCEC has estimated such costs. Construction of a carbon capture system at the PCEC si te would require installation of the following major pieces of equipment:

**•** Two Amine Scrubber Vessels

**•** Two CO 2 Strippers

**•** Four Amine Transfer Pumps

**•** Four Flue Gas Fans

**•** Four CO 2 Gas Compressor

**•** One Amine Storage Tank

The estimated costs associated with implementation of a carbon capture system at the PCEC Plant are shown in the table below. A control cost for implementing CCS in terms of $/ton of CO 2 avoided was calculated using the “cost of electricity” methodology outlined in the U.S. Department of Energy document “Cost and Performance Baseline for Fossil Energy Plants Volume 1: Bituminous Coal and Natural Gas to Electricity”, Revision2, November 2010, DOE/NETL

- 2010/1397.

Two Combustion Turbines and One Steam Turbine Without CCS Two Combustion Turbines and One Steam Turbine With CCS Estimated Plant Construction Cost $443,800,000 $974,000,000

Net Power Output (MW) 688.4 595.3 Net Plant HHV efficiency 49.9% 42.9% Annualized Cost of CO 2 Capture $ 242

, 608

, 288 /yr

Annualized Cost of CO 2 Transport $3, 883

, 000 /yrP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 48 Annualized Cost of CO 2 Storage $27,54 2, 874 /yr

Cost

- of

- Electricity (COE) ($/MWh) @ 85% capacity factor 73.3 $/MWh 125. 8 $/MWh

CO 2 Emissions (Siemens SGT6

- 5000F(5)) 3,238 ,5 86 tons/yr 32 3, 858.6 tons/yr

Cost of CO 2 Avoided $9 2

. 65 /ton CO 2

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% (HHV) to approximately 42.9% (HHV). 25



### 5.1.5 Step 5: Select BACT

PCEC proposes as BACT for this project, the following energy efficiency processes, practices, and designs for the proposed combined cycle combustion turbines :

**•** Use of Combined Cycle Power Generation Technology

**•** Combustion Turbine Energy Efficiency Processes, Practices, and Designs

o Efficient turbine design

o Turbine inlet air cooling

o Periodic turbine burner tuning

o Reduction in heat loss

o Instrumentation and controls

**•** HRSG Energy Efficiency Processes, Practices, and Designs

o Efficient heat exchanger design

o Insulation of HRSG

o Minimizing Fouling of heat exchange surfaces

o Minimizing vented steam and repair of steam leak s

**•** Steam Turbine Energy Efficiency Processes, Practices, and Designs

o Use of Reheat Cycles

o Use of Exhaust Steam Condenser

o Efficient Blading Design

o Efficient Ge nerator Design

**•** Plant

- wide Energy Efficiency Processes, Practices, and Designs

o Fuel gas preheating

o Drain operation

o Multiple combustion turbine/HRSG trains

25 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 2010P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 49 o Boiler feed pump fluid drive design

To determine the appropriate heat

- input efficiency limit, PCEC started with the turbine ’s d esign base load net h eat r ate for combined cycle operation and then calculated a compliance margin based upon reasonable degradation factors that may foreseeably reduce efficiency under real

world conditions. The design base l oad net h eat rate for the combustion turbines being considered for this project are as follows: the General Electric 7FA design base load net heat rate is 6674 Btu/kWhr (HHV) without duct burner firing and 7051 Btu/kWhr (HHV) with duct burner firing; the Siemens SGT6

- 5000F(4) design base load net heat rate is 6782 Btu/kWhr (HHV) without duct burner firing and 7045 Btu/kWhr (HHV) with duct burner firing; and the Siemens SGT6

- 5000F(5) design base load net heat rate is 68 45 Btu/kWhr (HHV) without duct burner firing and 7050 Btu/kWhr (HHV) with duct burner firing . Note that th ese rate s reflect the facility’s “net” power production, meaning the denominator is the amount of power provided to the grid; it does not reflect the total amount of energy produced by the plant, which also includes auxiliary load consumed by operation of the plant. To be consistent with other recent GHG BACT determinations, the net heat rate without duct firing is used to calculate the heat

- input efficiency limi t.

To determine an appropriate heat rate limit for the permit, the following compliance margins are added to the base heat rate limit :

**•** A 3.3% design margin reflecting the possibility that the constructed facility will not be able to achieve the design hea t rate.

**•** A 6% performance margin reflecting efficiency losses due to equipment degradation prior to maintenance overhauls.

**•** A 3% degradation margin reflecting the variability in operation of auxiliary plant equipment due to use over time.

Design and construction of a combined

- cycle power plant involves many assumptions about anticipated performance of the many elements of the plant, which are often imprecise or not reflective of conditions once installed at the site. As a consequence, the facility also calculates an “Installed Base Heat Rate”, which represents a design margin of 3.3% to address such items as equipment underperformance and short

- term degradation.

To establish an enforceable BACT condition that can be achieved over the life of the facility, the permit limit must also account for anticipated degradation of the equipment over time between regular maintenance cycles. The manufacturer’s degradation curves project anticipated degradation rate of 5% within the first 48,000 hours o f the gas turbine’s useful life; they do not reflect any potential increase in this rate which might be expected after the first major overhaul and/or as the equipment approaches the end of its useful life. Further, the projected 5% degradation rate represents the average , and not the maximum or guaranteed, rate of degradation for the gas turbines. Therefore, PCEC proposes that, for purposes of deriving an enforceable BACT limitation on the proposed facility’s heat rate, gas turbine degradation may reasonab ly be estimated at 6% of the facility’s heat rate.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 50 Finally, in addition to the heat rate degradation from normal wear and tear on the combustion turbines, PCEC is also providing a reasonable compliance margin based on potential degradation in other elements of the combined cycle plant that would cause the overall plant heat rate to rise ( i.e. , cause efficiency to fall). Degradation in the performance of the heat recovery steam generator, steam turbine, heat transfer, cooling tower, and ancillary equipm ent such as pumps and motors is also expected to occur over the course of a major maintenance cycle.

As a result of these adjustments, PCEC is proposing the following output based CO 2 /MWh BACT limits for the Project, on a 12 month rolling average, excluding startup hours:

Turbine Model Gross Heat Rate With Duct Firing (Btu/kWh)

(HHV) Output Based Emission Limit With Duct Firing ( lb CO 2 /MWh) gross

General Electric 7FA .05 7925.0 942.0

Siemens SGT6

- 5000F(4) 7649.0 909.2

Siemens SGT6

- 5000F(5) 7679.0 912.7

The calculation of the heat rate s and the equivalent lb CO 2 /MWhr is provided on Table s 5-2 , 5

- 3, and 5 -4 of this application. While energy efficiency will be a consideration for final selection of a turbine, other considerations will include the capacity of the turbine, cost, reliability, and predict ed longevity of the turbines.

While starting up the combustion turbines following ignition, a large portion of the energy input to the combustion turbine is used for heating the turbine casings and rotors, boiler tubes, main steam piping, and other portions of the thermal system rather than the production of electricity. During this startup period, the steam turbine does not generate electricity in a combined cycle mode until the thermal equipment is at an appropriate operating temperature and sufficient steam is produced in the heat recovery steam generator. Therefore, PCEC proposes that the 12 month rolling average output based BACT limits exclude startup hours. For purposes of compliance with the emission limits for non

- GHG pollutants, the startup period is defined as the period of time when there is measurable fuel flow to the combustion turbine and ends when the combustion turbine load reaches 60 percent. However, for purposes of an output based GHG emission limit, the plant start up period will be defined as the period of time when there is measurable fuel flow to the combustion turbine and ends when the steam turbine is synchronized to the electrical grid. The annual emissions of GHG and CO 2 e during periods of startup are provided on Tables 3

- 3, 3

- 5, and 3

- 7.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 51 On March 27, 2012, the EPA proposed New Source Performance Standard (NSPS), Subpart TTTT, that would control GHG emissions from new power plants. 26 The proposed rule would apply to fossil

- fuel fired electric generating units that generate electricity for sale and are larger than 25 MW. The EPA proposed that new power plants meet a twelve month rolling average output based standard of 1,000 lb CO 2 /M Wh gross. The proposed emission rate for the PCEC turbines on a gross electrical output basis are all well with in the emission limit in proposed NSPS Subpart TTTT.

PCEC performed a search of the EPA’s RACT/BACT/LAER Clearinghouse for natural gas fired

co mbustion turbine generators and found no entries which address BACT for GHG emissions. Although not listed in the RACT/BACT/LAER Clearinghouse, a GHG BACT analysis was performed by the following natural gas fired power generation facilities: Russell City Energy Center , Palmdale Hybrid Power Plant, Lower Colorado River Authority Ferguson Plant, Cricket Valley Energy Center, Pioneer Valley Energy Center, Deer Park Energy Center, Channel Energy Center, and La Paloma Energy Center

. A discussion of the PCEC ’s proposed BACT as compared to those projects is provided below. Note that the BACT limits represented in these permits are typically reported without duct burner firing, so the PCEC without duct burner firing BACT limits are used in the comparison.

Palmda le Hybrid Power Project The application for the Palmdale Hybrid Power Project (PHPP) was submitted in May 2011 and

a final permit was issued by the Antelope Valley Air Quality Management District on October 18, 2011 . The permit authorizes the construction of two natural

- gas

- fired GE 7FA combustion turbine generators, with 500 MMBtu/hr duct fired heat recovery steam generators, and one steam turbine generator to be located in Palmdale, California. The project included a 50 MW, 251 acre sol ar thermal array field with a solar steam boiler on the 333 acre site. The permit listed a GHG BACT limit of 774 lb CO 2 /MW

- hr source

- wide net output and 7,319 Btu/kWhr source wide net heat rate, 365 rolling average

.
The application submitted by PHPP represented as BACT, a heat rate of 6,970 Btu/kWh, based on the higher heating value (HHV) of natural gas with two CTGs operating at 100% with no solar input and with no duct firing. 27 T he PHPP application did not state whether the 6,970 Btu/kWh heat rate represented as BACT, is on a gross electrical output basis or a net electrical output basis. A CO 2 emission rate of 0.408 short tons of CO 2 /MW

- hr was derived from the heat rate of 6,970 Btu/Kw

- hr

, based on a CO 2 emission factor of 53.06 kg CO 2 /MMBtu. 0.408 short tons of CO 2 /MW

- hr equates to 816 lb CO 2 /MW

- hr.

The BACT representations in the Palmdale permit and the application cannot be directly compared to the representations for the PCEC for the following reasons:

26 Standards of Performance for Greenhouse Gas Emissions for New Stationary Sources: Electric Utility Generating Units, 77 Fed Reg 22392, April 13, 2012

27 AECOM Memorandum to Lisa Bingham and Joe Lapka, Response to EPA Comments on PHPP GHG BACT Analysis, July 15, 2011.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 52 1. The permit limit of 774 lb CO 2 /MW

- hr do es not correspond to the representations in the PHPP application. PHPP represented a CO 2 emission rate of 0.408 short tons CO 2 /MW

hr (816 lb CO 2 /MW

- hr) for the two combustion turbines, without duct burner firing which was derived from the represented design heat rate of 6,970 Btu/kW

- hr. The CO 2 emission rate associated with the permit heat rate limit of 7,319 Btu/kW

- hr would be 856.9 lb CO 2 /MW

- hr

. The basis of the 774 lb CO 2 /MWhr permit limit is unclear.

2. The U.S. EPA, Region 9, in its response to comments, stated that the BACT limit was being set at 7,319 Btu/kWh to account for “a variety of factors that can affect heat rate, including seasonal variations (i.e. temperature, humidity) and equipment degradation”. 28 The 7,319 Btu/kWh limit provides on ly a 5% compliance margin over the represented “design” heat rate of 6,970 Btu/kWh. This is not consistent with the Cricket Vall ey Energy Center, Pioneer Valley Energy Center, Lower Colorado River Authority Ferguson Plant , Deer Park Energy, and Channel Energy Center GHG permits discussed below. The Palmdale permit does not account for the design margin of the equipment or degradation of supporting equipment.

3. The “design” heat rate proposed by PHPP was for two CTGs operating at 100% load. The 365 day rolling average permit limit of 7,319 Btu/kW

- hr does not account for lower efficiencies at reduced loads.

Lower Colorado River Authority Ferguson Plant

The application for the LCRA Ferguson Plant was submitted in March 2011. The application included two natural

- gas

- fired GE 7FA combustion turbines, heat recovery steam generators without no additional duct firing, and one steam turbine generator to be located in Marble Falls, Texas. The permit, issued November 10, 2011, included BACT limits of 0.459 ton CO 2 /MWh (net) on a 365 day rolling average and an average net heat rate of 7,720 Btu/kWh (HHV) on a 365 day rolling average.

For comparison purposes, PC EC proposes net heat rates for the General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines at ISO conditions, without duct burner firing, of 7,5 28.8

, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis) , respectively , which accounts for des ign margins, performance margins, and degradation margins . The proposed emission rates on a ton CO 2 /MWh (net) basis for General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines, without duct firing, are 0.447, 0.455, and 0.4 67 ton CO 2 /MWh (net)

.
Cricket Valley Energy Center

The Cricket Valley Energy Center (CVEC) air permit application proposed the construction of three natural

- gas

- fired GE 7FA combustion turbines, with 596.8 MMBtu/hr duct fired heat

28 U.S. Environmental Protection Agency, Region 9, “Responses to Public Comments on the Proposed Prevention of Significant Deterioration Permit for the Palmdale Hybrid Power Project”, Oct. 2011.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 53 recovery steam generator s, and three steam turbine generators to be located in Dover, New York. The CVEC application represented that the GE 7FA turbines operating in combined cycle mode have a design base heat rate of 6,742 Btu/kW

- hr at ISO conditions with no duct firing (based on net output). Based upon the design efficiency, and adding a reasonable margin of compliance, CVEC proposed a limit of 7,605 Btu/kW

- hr (ISO conditions without duct firing) as BACT for the proposed project. The draft permit specifies that the facility is required conduct a thermal efficiency test on a minimum of one combustion turbine annually.

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines at ISO conditions, without duct burner firing, of 7,5 28.8

, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts for design margins, performance margins, and degradation margins. The highest proposed heat rate for the PCEC application is within 2.2 % of the proposed CVEC proposed limit and the lowest proposed heat rate is 1. 0 % lower than the proposed CVEC proposed limit. The efficiencies from two similarly sized combined cycle electric generating units will not be identical due to differences in the properties and variability of the natural gas; the geographic location - h igher combustion turbine efficiencies are achieved at lower elevations and at cooler ambient temperatures due to denser ambient air; differences in combustion turbine designs, heat

reco very steam generator designs and steam turbine designs; and electric generating unit load generation flexibility requirements - operating an electric generating unit as a base load unit is more efficient than operating as a load cycling unit to respond to fluctuations in customer electricity or steam demands.

Pioneer Valley Energy Center

The Pioneer Valley Energy Center (PVEC) air permit application proposed the construction of a 431 MW natural

- gas

- fired combined cycle turbine generator to be located in Westfield, Massachusetts. The PVEC air application proposed to construct a Mitsubishi M501G combined cycle turbine. The air permit for the project was issued April 12, 2012. The permit contained an initial GHG limit of 825 lbs of CO 2 e/MWh grid to be demonstrated during initial performance test and a 365

- day rolling average limit of 895 lbs of CO 2 e/MWh grid
.
For comparison purposes, PCEC proposes CO 2 e emission rate s for the General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines

, without duct firing, at ISO conditions, of 89 4.9 , 9 09.2 , and 9 23.7 lb CO 2 e/MWh ( net basis ), respectively, which accounts for design margins, performance margins, and degradation margins. The highest proposed CO2e emission rate in the PCEC application is wi thin 3.2 % of the proposed PVEC limit and the lowest proposed CO2e emission rate is within 0.0 1 % of the proposed PVEC limit. The efficiencies from two similarly sized combined cycle electric generating units will not be identical due to differences in the properties and variability of the natural gas; the geographic location - higher combustion turbine efficiencies are achieved at lower elevations and at cooler ambient temperatures due to denser ambient air; differences in combustion turbine designs, heat recovery steam generator designs and steam turbine designs; and electric generating unit load generation flexibility requirements - operating an electric generating unit as a base load unit isP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 54 more efficient than operating as a load cycling unit to respond to fluctuations in customer electricity or steam demands.

Deer Park Energy Center

The application for the Calpine Deer Park Energy Center was submitted in September 2011 and the permit was issued on November 29, 2012 . The permit a uthorize s a fifth Siemens 501F CTG/HRSG train and ancillary equipment at the existing Deer Park Energy Center located in Deer Park, Texas. The permit contains a CO 2 emission rate limit of 0.460 ton CO 2 /MWh (net) and a BACT net heat rate for the Project of 7,730 Bt u/kWh (HHV), (without duct burner firing)

.
For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines at ISO conditions, without duct burner firing, of 7,5 28.8

, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts for design margins, performance margins, and degradation margins. The proposed emission rates on a ton CO 2 /MWh (net) basis for General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines, without duct firing, are 0.447, 0.455, and 0.4 67 ton CO 2 /MWh (net)

.
Channel Energy Center

The application for the Calpine Channel Energy Center was submitted in October 2011 and the permit was issued on November 29, 2012. The permit authorize s a third Siemens 501F CTG/HRSG train and ancillary equipment at the existing Channel Energy Center located in Pasadena, Texas. The permit contains a CO 2 emission rate limit of 0.460 ton CO 2 /MWh (net) and a BACT net heat rate for the Project of 7,730 Btu/kWh (HHV), (without duct burner firing)

.
For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines at ISO conditions, without duct burner firing, of 7,5 28.8

, 76 49.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts for design margins, performance margins, and degradation margins. The proposed emission rates on a ton CO 2 /MWh (net) basis for General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines, without duct firing, are 0.447, 0.455, and 0.4 67 ton CO 2 /MWh (net)

. La Paloma Energy Center

The application for the La Paloma Energy Center was submitted in March 201 2 and a draft permit has not yet been issued. The Pinecrest Energy Center proposes the same plant configuration and same gas turbine options as the La Paloma Energy Center application , with the exception that the GE 7FA.05 turbine is being proposed for the Pinecrest Energy Center and the GE 7FA.04 turbine is being proposed for the La Paloma Energy Center. The proposed GHG BACT net heat rate limits for the Siemens turbines for both applications are the same and the proposed heat rate limits for the GE 7FA.05 turbine is slightly higher than the heat rate limit f or the GE 7FA.04.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 55 E.S. Joslin Power Station

The application for the E.S. Joslin Power Station was submitted to the TCEQ in June 2012 and a draft permit has not yet been issued. Calhoun Port Authority (CPA) proposed to convert the existing conventional steam plant at the station, located in Calhoun County, Texas, to a combined cycle configuration by adding three natural gas

- fired General Electric 7FA CTGs and three unfired HRSGs with a shared steam turbine (a 3x3x1 combined cycle configuration). CPA proposed an efficiency limit of 7,730 Btu/KWh as BACT for GHG emissions; however, CPA did not propose an output

- based emission limitation (e.g., lb CO 2 e /MWh) for the project.

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines at ISO conditions, with out duct burner firing, of 7,5 28.8

, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts for design margins, performance margins, and degradation margins.

S.R. Bertron Unit 5

The application for Unit 5 at the S.R. Bertron Generating Station was submitted to the TCEQ in November 2012. NRG Texas Power, LLC (NRG) proposed to construct a new natural gas

- fired combined cycle electric generating unit and ancillary equipment at the S.R. Bertron Generating Station in Harris County, Texas. The new facility will have either a 2x2x1 or a 2x2x2 configuration (two CTGs, two fired HRSGs, and either one or two steam turbines). Three CTG models are under consideration for the project: the General Electric 7FA.05, the Mitsubishi Heavy Industries (MHI) 501GAC, and the Siemens F(5). NRG proposed a heat rate standard of 7,730 Btu/kWh (HHV) , net generation, without duct burner firing, (for any CTG model). NRG also proposed CO 2 e mass emission limits of 1,203,838 tpy for each CTG/HRSG unit ( supplementary fired) with the General Electric 7FA.05, 1,344,347 tpy for each CTG/HRSG unit (supplementary fired) with the Siemens F(5), and 1,468,007 tpy for each CTG/HRSG unit (supplementary fired) with the MHI 501GAC. (Note that NRG did not propose emi ssion limits in terms of mass of emitted CO 2 e /MWh. )

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines at ISO conditions, without duct burner firing, of 7,5 28.8

, 76 49.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts for design margins, performance margins, and degradation margins.

Cedar Bayou Unit 5

The application for Unit 5 at the Cedar Bayou Generating Station was submitted to the TCEQ in No vember 2012. NRG Texas Power, LLC (NRG) proposed to construct a new natural gas

- fired combined cycle electric generating unit and ancillary equipment at the Cedar Bayou Generating Station in Chambers County, Texas. The new facility will have either a 2x2x1 or a 2x2x2 configuration (two CTGs, two fired HRSGs, and either one or two steam turbines). Three CTG models are under consideration for the project: the General Electric 7FA.05, the MitsubishiP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 56 Heavy Industries (MHI) 501GAC, and the Siemens F(5). NRG proposed a heat rate standard of 7,730 Btu/kWh (HHV) , net generation, without duct burner firing, (for any CTG model). NRG also proposed CO 2 e mass emission limits of 1,203,838 tpy for each CTG/HRSG unit (supplementary fired) with the General Electric 7FA.05, 1,344,347 tpy for each CTG/HRSG unit (supplementary fired) with the Siemens F(5), and 1,468,007 tpy for each CTG/HRSG unit (supplementary fired) with the MHI 501GAC. (Note that NRG did not propose emission limits in terms of mass of emitted CO 2 e /MWh. )

For comparison purposes, PCEC proposes net heat rates for the General Electric 7FA, Siemens SGT6

- 5000F(4), and Siemens SGT6

- 5000F(5) turbines at ISO conditions, without duct burner firing, of 7,5 28.8

, 7649.0, and 7,771.7 Btu/kWh (HHV, net basis), respectively, which accounts for design margins, performance margins, and degradation margins.



### 5.2 BACT FOR 

### SF 6 

### I NSULATED 

### E LECTRICAL 

### E QUIP MENT



### 5.2.1 Step 1: Identify All Available Control Technologies

Step 1 of the Top

- Down BACT analysis is to identify all feasible control technologies. One technology is the use of state

- of

- the

- art SF 6 technology with leak detection to limit fugitive emissions. In comparison to older SF 6 circuit breakers, modern breakers are designed as a totally enclosed

- pressure system with far lower potential for SF 6 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 S F 6 (by weight) has escaped. The use of an alarm identifies potential leak problems before the bulk of the SF 6 has escaped, so that it can be addressed proactively in order to prevent further release of the gas.

One alternative considered in this analysis is to substitute another, non

- GHG substance for SF 6 as the dielectric material in the breakers. Potential alternatives to SF 6 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 SF 6. 29



### 5.2.2 Step 2: Eliminate Technically Infeasible Options

According to the report NTIS Technical Note 1425, SF 6 is a superior dielectric gas for nearly all high voltage applications

. 30

29 Christophorous, L.G., J.K. Olthoff, and D.S. Green, Gases for Electrical Insulation and Arc Interruption: Possible
Present and Future Alternatives to Pure SF 6, NIST Technical Note 1425, Nov.1997. 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 SF 6 - insulated equipment. The report concluded that although “...various gas mixtures show

30 Id. at 28 – 29.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 57 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 o f 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 SF 6 .



### 5.2.3 Step 3: Rank Remaining Control Technologies

The use of state

- of

- the

- art SF 6 technology with leak detection to limit fugitive emissions is the highest ranked control technology that is technically feasible for this application.



### 5.2.4 Step 4: Evaluate Most Effective Controls and Document Results

E nergy, environmental, or economic impacts were not addressed in this analysis because the use of alternative, non

- greenhouse

- gas substance for SF 6 as the dielectric material in the breakers is not technically feasible

.



### 5.2.5 Step 5: Select BACT

Based on this top

- down analysis, PCEC concludes that using state

- of

- the

- art enclosed

- pressure SF 6 circuit breakers with leak detection would be the BACT control technology option. The circuit breakers will be designed to meet the latest of the American National Standards Institute ( ANSI ) C37.013 standard for high voltage circuit breakers

. 31 The proposed circuit breaker at the generator output will have a low pressure alarm and a low pressure lockout. This alarm will function as an early leak detector that will bring potential fugitive SF 6 emissions prob lems to light before a substantial portion of the SF 6 escapes. The lockout prevents any operation of the breaker due to lack of “quenching and cooling” SF 6 gas.

PCEC will monitor emissions annually in accordance with the requirements of the Mandatory Greenhouse Gas Reporting rules for Electrical Transmission and Distribution Equipment Use

. 32
Annual SF 6 emissions will be calculated according to the mass balance approach in Equation DD

- 1 of Subpart DD.



### 5.3 BACT FOR 

### A UXILIARY 

### B OILER

One nominally rated 150 MMBtu/hr auxiliary boiler (EPN AUXB LR ) will be utilized to facilitate startup of the combined cycle units

. The auxiliary boiler will be limited to 876 hours of operation
per year.

31 ANSI Standard C37.013, Standard for AC High

- Voltage Generator Circuit Breakers on a Symmetrical Current

. 32 See 40 C.F.R. Pt. 98, Subpt. DD.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 58 

### 5.3.1 Step 1: Identify All Available Control Technologies

Step 1 of the Top

- Down BACT analysis is to identify all feasible control technologies. The following technologies were identified as potential control options for boilers:

**•** Use of low carbon fuels

**•** Use of good operating and maintenance practices

**•** Energy efficient design

**•** Low Annual Capacity

The auxiliary boiler will utilize natural gas which is the lowest carbon fuel available at the PCEC site. Therefore, formation of CO 2 from combustion of the fuel will be minimized.

Good operating and maintenance practices for the boiler include following the manufacturer’s recommended operating and maintenance procedures; maintaining good fuel mixing in the combustion zone; and maintain the proper air/fuel ratio so that sufficient oxygen is provided to provide complete combustion of the fuel while at the same time preventing introduction of more air than is necessary into the boiler.

The auxiliary boiler is designed for a thermal energy efficiency of approximately 80 %. The energy efficient design of the boiler includes insulation to retain heat within the boiler and a computerized process control system that will optimize the fuel/air mixture and limit excess air in the boiler.

The au xiliary boiler will be used to facilitate startup of the two combustion turbines and the annual hours of operation will be limited to 876 hours per year.



### 5.3.2 Step 2: Eliminate Technically Infeasible Options

This step of the top

- down BACT analysis eliminates any control technology that is not considered technically feasible unless it is both available and applicable.

Use of natural gas as a low carbon fuel is technically feasible for this emission source.

Use of good operating and maintenance practices is technically feasible for this emission

source.

Use of an energy efficient design for the boiler is technically feasible.

Use of a low annual capacity for the auxiliary boiler is technical feasible since the boiler is only used to facilitate star tups for the two combustion turbines.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 59 

### 5.3.3 Step 3: Rank Remaining Control Technologies

As all of the energy efficiency related processes, practices, and designs discussed in Section 5.3.1 of this application are being proposed for the auxiliary boiler, a ranking of the control technologies is not necessary for this application.



### 5.3.4 Step 4: Evaluate Most Effective Controls and Document Results

As all of the energy efficiency related processes, practices, and designs discussed in Section 5.3.1 of this application are being proposed for this project, an examination of the energy, environmental, and economic impacts of the efficiency designs is not necessary for this application.



### 5.3.5 Step 5: Select BACT

Based on this top

- down analysis, PCEC concludes that the use of natural gas as a low carbon fuel; good operating and maintenance practices; energy efficient design; and low annual capacity is selected as BACT for the auxiliary boiler. With the limit annual operation of the auxiliary boiler, the total CO 2 e emissions fr om the boilers are 0.23% of the total site wide emissions.

Among other recently issued or currently pending GHG permits, the Wolverine Power Supply Cooperative permit and the Palmdale Hybrid Power Project permit included BACT determinations for limited use, auxiliary boilers and heaters. The Wolverine Permit included a 72.4 MMBtu/hr diesel

- fired auxiliary boiler, limited to 4,000 hours operation per year. The Permit listed BACT for GHG for the auxiliary boiler to incorporate energy efficient equipment wh erever practical in the design of the auxiliary boiler. The Wolverine Permit did not include an output based BACT limit for the auxiliary boiler.

The application for the Palmdale Hybrid Power Project (PHPP) was submitted in May 2011 and a draft permit was issued by the Antelope Valley Air Quality Management District in August 2011. The PHPP application proposed the construction of a power plant utilizing natural

- gas

fired combustion turbine combined cycle generators located in Palmdale, California. The project also included a 110 MMBtu/hr natural

- gas

- fired auxiliary boiler, limited to 500 hours per year operation, and a 40 MMBtu/hr natural

- gas

- fired heater, limited to 1,000 hours per year operation. The Palmdale Permit listed BACT for GHG for the auxiliary boiler and heater as annual tune

- ups. The Palmdale Permit did not include an output based BACT limit for the auxiliary boiler or heater.



### 5.4 BACT FOR 

### E MERGENCY 

### E NGINES

The PCEC site will be equipped with one nominally rated 1,072

- hp diesel

- fired emergency generator to provide electricity to the facility in case of power failure and one nominally rated 500

- hp diesel

- fired pump to provide water in the event of a fire.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 60 

### 5.4.1 Step 1: I dentify All Available Control Technologies

Step 1 of the Top

- Down BACT analysis is to identify all feasible control technologies. The following technologies were identified as potential control options for emergency engines :

**•** Use of low carbon fuel;

**•** Use o f good operating and maintenance practices ;

**•** Low annual capacity factor.

Engine options includes engine s powered with electricity, natural gas, or liquid fuel, such as gasoline or fuel oil.

Good operating and maintenance practices for the engines include the following:

**•** Operating with recommended fuel to air ratio recommended by the manufacturer and

**•** Appropriate maintenance of equipment, such as periodic readiness testing.

The energy efficiency (energy output divided by energy input) associated with the em ergency generator is 34.0% and the energy efficiency associated with the fire pump engine is 36.8%. These are typical efficiencies for emergency engines.

Each emergency engine will be limited to 100 hours operation per year for purposes of maintenance checks and readiness testing.



### 5.4.2 Step 2: Eliminate Technically Infeasible Options

This step of the top

- down BACT analysis eliminates any control technology that is not considered technically feasible unless it is both available and applicable. The purpose of the engines is to provide a power source during emergencies, which includes outages of the combustion turbines, natural gas supply outages, and natural disasters, such as floods and hurricanes. As such, the engines must be available during emergencies. Electricity and natural gas may not be available during an emergency and therefore cannot be used as an energy source for the emergency engines.

The engines must be powered by a liquid fuel that can be stored on

- site in a tank and supplied to the engine s on demand, such as motor gasoline or diesel. The default CO 2 emission factors for gasoline and diesel are very similar, 70.22 kg/MMBtu for gasoline and 73.96 kg/MMBtu for diesel. Diesel fuel has a much lower volatility than gasoline and can be stored f or longer periods of time. Therefore, di esel is typically the chosen fuel for emergency engines.

Because of the need to store the emergency engine fuel on

- site and the ability to store diesel for longer periods of time than gasoline, it is technically infeasible to utilize a lower carbon fuel than diesel.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 61 The use of good operating and maintenance practices is technically feasible for the emergency engines. Also, a low annual capacity factor for the engines is technically feasible since the engines will only be operated either for readiness testing or for actual emergencies.



### 5.4.3 Step 3: Rank Remaining Control Technologies

Since the remaining technically feasible processes, practices, and designs discussed in Section 5.4.1 of this application for the emergency engines are being proposed for the engines , a ranking of the control technologies is not necessary for this applicat ion.



### 5.4.4 Step 4: Evaluate Most Effective Controls and Document Results

Since the remaining technically feasible processes, practices, and designs discussed in Section 5.4.1 of this application for the emergency engines are being proposed for the engines, an evaluation of the most effective controls is not necessary for this application.



### 5.4.5 Step 5: Select BACT

As a result of this analysis, appropriate operation of the engines through proper fuel to air ratios and maintenance based on recommended readiness testing and low annual hours of operation are selected as BACT for the proposed engines.



### 5.5 BACT FOR 

### N ATURAL 

### G AS 

### F UGITIVES

The proposed project will include natural gas piping components. These components are potential sources of methane and CO 2 emissions due to emissions from rotary shaft seals, connection interfaces, valve stems, and similar points.



### 5.5.1 Step 1: Identify All Available Control Technologies

Step 1 of the Top

- Down BACT analysis is to identify all feasible control technologies. The following t echnologies were identified as potential control options for piping fugitives :

**•** Implementation of leak detection and repair (LDAR) program using a hand held analyzer ;

**•** Implementation of alternative monitoring using a remote sensing technology such as infrar ed cameras; and

**•** Implementation of audio/visual/olfactory (AVO) leak detection program



### 5.5.2 Step 2: Eliminate Technically Infeasible Options

This step of the top

- down BACT analysis eliminates any control technology that is not considered technically feasible unless it is both available and applicable. The use of instrumentP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 62 LDAR and remote sensing technologies are technically feasible. Since pipeline natural gas is odorized with a small amount of mercaptan, an AVO leak detection program for natural gas pi ping components is technically feasible.



### 5.5.3 Step 3: Rank Remaining Control Technologies

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 . Q uarterly 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

. 33 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

. 34 The U.S. EPA has allowed the use of an optical gas imaging instrument as an alternative work practice for a Method 21 portable analyzer for monitoring equipment for leaks in 40 CFR 60.18(g). For components containing inorganic or odorous compounds, periodic AVO walk

- through inspections provide predicted control efficiencies of 97% control for valves, flanges, relief valves, and sampling connections, and 95% for compresso rs. 35



### 5.5.4 Step 4: Evaluate Most Effective Controls and Document Results

The frequency of inspection and the low odor threshold of mercaptans in natural gas make AVO inspections an effective means of detecting leaking components in natural gas service. As discussed in Section 5.5.3, the predicted emission control efficiency is comparable to the LDAR programs using Method 21 portable analyzers.



### 5.5.5 Step 5: Select BACT

Due to the very low Volatile Organic Compound (VOC) content of natural gas, the PCEC will not be subject to any VOC leak detection programs by way of its State/PSD air permit, TCEQ Chapter 115 – Control of Air Pollution from Volatile Organic Compounds, New Source Performance Standards (40 CFR Part 60)

, National Emission Standard for Hazardous A ir Pollutants (40 CFR Part 61); or National Emission Standard for Hazardous Air Pollutants for Source Categories (40 CFR Part 63). Therefore, any leak detection program implemented will be solely due to potential greenhouse emissions. Since the uncontrol led CO 2 e emissions from the natural gas piping represent approximately 0.01% of the total site wide CO 2 e emissions, any emission control techniques applied to the piping fugitives will provide minimal CO 2 e emission reductions.

33 Air Permit Technical Guidance for Chemical Sources: Equipment Leak Fugitives, TCEQ, Oct. 2000

34 Id. at page 52.

35 Id. at page 52.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

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010303 63 Based on this top

- down ana lysis, PCEC concludes that daily AVO inspections is BACT for piping components in natural gas service.Pine Crest Energy CenterNet Output Gross Output Base Net Heat Rate 6,675.5 6534.6 Btu/kWH (HHV) (Without Duct Firing) 3.3% 3.3% Design Margin 6.0% 6.0% Performance Margin 3.0% 3.0% Degradation Margin Calculated Base Heat Rate with Compliance Margins 7528.8 7369.9 Btu/kWH (HHV) (Without Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit Without Duct Burner Firing

EPN Base Heat Rate Electrical Output Basis Heat Input Required to Produce 1 MW Pollutant Emission Factor lb GHG/MWhr 2 Global Warming
Potential 3 lb CO 2 e/MWhr 4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu) 1
CO 2 894.852 1 894.852
CTG/HRSG3 7528.8 Net 7.53 CH 4 1.0E-03 1.66E-02 21 3.49E-01
N 2 O 1.0E-04 1.66E-03 310 5.15E-01
894.9 895.7 CO 2 875.970 1 875.970
CTG/HRSG3 7369.9 Gross 7.37 CH 4 1.0E-03 1.62E-02 21 3.41E-01
N 2 O 1.0E-04 1.62E-03 310 5.04E-01
Totals 876.0 876.8

Net Output Gross Output Base Net Heat Rate 7,249.3 7026.8 Btu/kWH (HHV) (With Duct Firing) 3.3% 3.3% Design Margin 6.0% 6.0% Performance Margin
3.0% 3.0% Degradation Margin Calculated Base Heat Rate with Compliance Margins 8176.0 7925.0 Btu/kWH (HHV) (With Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit With Duct Burner Firing

EPN Base Heat Rate Electrical Output Basis Heat Input Required to Produce 1 MW Pollutant Emission Factor lb GHG/MWhr 2 Global Warming
Potential 3 lb CO 2 e/MWhr 4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu) 1
CO 2 971.778 1 971.778
CTG/HRSG3 8176.0 Net 8.18 CH 4 1.0E-03 1.80E-02 21 3.79E-01
N 2 O 1.0E-04 1.80E-03 310 5.59E-01
971.8 972.7 CO 2 941.942 1 941.942
CTG/HRSG3 7925.0 Gross 7.92 CH 4 1.0E-03 1.75E-02 21 3.67E-01
N 2 O 1.0E-04 1.75E-03 310 5.42E-01
Totals 942.0 942.9

Note
1. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.
2. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr Fc = Carbon based F-factor,1040 scf/MMBtu H = Heat Input (MMBtu/yr)
U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F
MW CO2 = Molecule weight of CO 2 , 44.0 lb/lbmole 3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 4. Example calculation: GHG emissions (lbs) x Global Warming Potential / 1 MW = lb CO2e/MWhr Table 5-1 GHG Emission Calculations - Calculation of Design Heat Rate Limit for GE 7FA.05 Pinecrest Energy Center

2/11/2013Net Output Gross Output Base Net Heat Rate 6,782.0 6615.5 Btu/kWH (HHV) (Without Duct Firing) 3.3% 3.3% Design Margin 6.0% 6.0% Performance Margin 3.0% 3.0% Degradation Margin Calculated Base Heat Rate with Compliance Margins 7649.0 7461.2 Btu/kWH (HHV) (Without Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit Without Duct Burner Firing

EPN Base Heat Rate Electrical Output Basis Heat Input Required to Produce 1 MW Pollutant Emission Factor lb GHG/MWhr 2 Global Warming
Potential 3 lb CO 2 e/MWhr 4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu) 1
CO 2 909.136 1 909.136
CTG/HRSG3 7649.0 Net 7.65 CH 4 1.0E-03 1.69E-02 21 3.54E-01
N 2 O 1.0E-04 1.69E-03 310 5.23E-01
909.2 910.0 CO 2 886.817 1 886.817
CTG/HRSG3 7461.2 Gross 7.46 CH 4 1.0E-03 1.64E-02 21 3.45E-01
N 2 O 1.0E-04 1.64E-03 310 5.10E-01
Totals 886.8 887.7

Net Output Gross Output Base Net Heat Rate 7,045.1 6782.0 Btu/kWH (HHV) (With Duct Firing) 3.3% 3.3% Design Margin 6.0% 6.0% Performance Margin
3.0% 3.0% Degradation Margin Calculated Base Heat Rate with Compliance Margins 7945.7 7649.0 Btu/kWH (HHV) (With Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit With Duct Burner Firing

EPN Base Heat Rate Electrical Output Basis Heat Input Required to Produce 1 MW Pollutant Emission Factor lb GHG/MWhr 2 Global Warming
Potential 3 lb CO 2 e/MWhr 4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu) 1
CO 2 944.400 1 944.400
CTG/HRSG3 7945.7 Net 7.95 CH 4 1.0E-03 1.75E-02 21 3.68E-01
N 2 O 1.0E-04 1.75E-03 310 5.43E-01
944.4 945.3 CO 2 909.136 1 909.136
CTG/HRSG3 7649.0 Gross 7.65 CH 4 1.0E-03 1.69E-02 21 3.54E-01
N 2 O 1.0E-04 1.69E-03 310 5.23E-01
Totals 909.2 910.0

Note
1. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.
2. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr Fc = Carbon based F-factor,1040 scf/MMBtu H = Heat Input (MMBtu/yr)
U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F
MW CO2 = Molecule weight of CO 2 , 44.0 lb/lbmole 3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 4. Example calculation: GHG emissions (lbs) x Global Warming Potential / 1 MW = lb CO2e/MWhr Table 5-2 GHG Emission Calculations - Calculation of Design Heat Rate Limit for SGT6-5000F(4) Pinecrest Energy Center

2/11/2013Net Output Gross Output Base Net Heat Rate 6,890.8 6582.2 Btu/kWH (HHV) (Without Duct Firing) 3.3% 3.3% Design Margin 6.0% 6.0% Performance Margin 3.0% 3.0% Degradation Margin Calculated Base Heat Rate with Compliance Margins 7771.7 7423.6 Btu/kWH (HHV) (Without Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit Without Duct Burner Firing

EPN Base Heat Rate Electrical Output Basis Heat Input Required to Produce 1 MW Pollutant Emission Factor lb GHG/MWhr 2 Global Warming
Potential 3 lb CO 2 e/MWhr 4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu) 1
CO 2 923.718 1 923.718
CTG/HRSG3 7771.7 Net 7.77 CH 4 1.0E-03 1.71E-02 21 3.60E-01
N 2 O 1.0E-04 1.71E-03 310 5.31E-01
923.7 924.6 CO 2 882.353 1 882.353
CTG/HRSG3 7423.6 Gross 7.42 CH 4 1.0E-03 1.64E-02 21 3.44E-01
N 2 O 1.0E-04 1.64E-03 310 5.07E-01
Totals 882.4 883.2

Net Output Gross Output Base Net Heat Rate 7,203.8 6808.7 Btu/kWH (HHV) (With Duct Firing) 3.3% 3.3% Design Margin 6.0% 6.0% Performance Margin
3.0% 3.0% Degradation Margin Calculated Base Heat Rate with Compliance Margins 8124.7 7679.0 Btu/kWH (HHV) (With Duct Firing)

Calculation of lb CO2e/MWhr Heat Rate Limit With Duct Burner Firing

EPN Base Heat Rate Electrical Output Basis Heat Input Required to Produce 1 MW Pollutant Emission Factor lb GHG/MWhr 2 Global Warming
Potential 3 lb CO 2 e/MWhr 4

(Btu/kWhr) (MMBtu/MWhr) (kg/MMBtu) 1
CO 2 965.678 1 965.678
CTG/HRSG3 8124.7 Net 8.12 CH 4 1.0E-03 1.79E-02 21 3.76E-01
N 2 O 1.0E-04 1.79E-03 310 5.55E-01
965.7 966.6 CO 2 912.707 1 912.707
CTG/HRSG3 7679.0 Gross 7.68 CH 4 1.0E-03 1.69E-02 21 3.56E-01
N 2 O 1.0E-04 1.69E-03 310 5.25E-01
Totals 912.7 913.6

Note
1. CH 4 and N 2 O GHG factors based on Table C-2 of 40 CFR 98 Mandatory Greenhouse Gas Reporting.
2. CO 2 emissions based on 40 CFR Part 75, Appendix G, Equation G-4

W CO2 = (Fc x H x U f X MW CO2 )/2000

W CO2 = CO 2 emitted from combustion, tons/yr Fc = Carbon based F-factor,1040 scf/MMBtu H = Heat Input (MMBtu/yr)
U f = 1/385 scf CO 2 /lbmole at 14.7 psia and 68 o F
MW CO2 = Molecule weight of CO 2 , 44.0 lb/lbmole 3. Global Warming Potential factors based on Table A-1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting. 4. Example calculation: GHG emissions (lbs) x Global Warming Potential / 1 MW = lb CO2e/MWhr Table 5-3 GHG Emission Calculations - Calculation of Design Heat Rate Limit for SGT6-5000F(5) Pinecrest Energy Center

2/11/2013P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 69 

## 6.0 O THER 

## PSD R EQUIREMENTS



### 6.1 I MPACTS 

### A NALYSIS

An impacts analysis is not being provided with this application in accordance with EPA’s recommendations:

Since 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 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 CO 2 or GHGs. 36

An impacts analysis for non

- GHG emissions is being submitted with the State/PSD/Non

attainment application submitted to the TCEQ.



### 6.2 GHG P RECONSTRUCTION 

### M ONITORING

A pre

- construction monitoring analysis for GHG is not being provided with this application in accordance with EPA’s recommendations :

EP A 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 of 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 purpose of assessing ambient air impacts of GHGs. 37

A pre

- construction monitoring analysis for non

- GHG emissions is being submitted with the State/PSD/Nonattainment applicati on submitted to the TCEQ.



### 6.3 A DDITIONAL 

### I MP ACTS 

### A NALYSIS

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 e missions

36 EPA, PSD and Title V Permitting Guidance For Greenhouse Gases at 48

- 49.

37 Id. at 49.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 70 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 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 analyzed in PSD permit reviews. Quantifying the exact impacts attributable to a specific GHG source obtaining a permit in specific places and points would not be possible 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 facili ty. 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 at present to satisfy the additional impacts analysis and Class I area requirements of the rules related to GHGs. 38

A PSD additional impacts analysis for non

- GHG emissions is being submitted with the State/PSD/Nonattainment application submitted to the TCEQ

.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 71 

## 7.0 P ROPOSED 

## GHG M ONITORING 

## P ROVISIONS

PCEC proposes to monitor CO 2 emission s by monitoring the quantity of fuel combusted in the turbines and heat recovery steam generators and performing periodic fuel sampling as specified in 40 CFR 75.10(3)(ii) (refer to procedure below). Results of the fuel sampling will be used to calculate a site

- specific Fc factor, and that factor will be used in the equation below to calculate CO 2 mas s emissions.

The PCEC natural gas

- fired turbine s will comply with the fuel flow metering and G ross Calorific Value (G CV ) sampling requirements of 40 CFR Part 75, Appendix D. The site

- specific Fc factor will be determined using the ultimate analysis and Gross Calorific Value in equation F

- 7b of 40 CFR 75, Appendix F. The site

- specific Fc factor will be re

- determined annually in accordance with 40 CFR 75, Appendix F, §3.3.6.

The procedure for estimating CO 2 Emissions specified in 40 CFR 75.10(3)(ii) is as follows:

Affected gas

- fired and oil

- fired units may use the following equation:

W

CO2 = (Fc x H x Uf x MW CO2 )/2000

Where: W

CO2 = CO 2 emitted from combustion, tons/hr

MW CO2 = molecular weight of CO 2 , 44.0 lb/lbmole

Fc = Carbon Based Fc

- Factor, (1040 scf/MMBtu for natural gas or a site

- specific Fc factor )

H = Hourly heat input in MMBtu, as calculated using the procedure in 40 CFR 75, Appendix F, §5)

Uf = 1/385 scf CO 2 /lb

- mole at 14.7 psia and 68 °F

The requirements for fuel flow monitoring and quali ty assurance in 40 CFR 75 Appendix D are as follows:

Fuel flow meter: meet an accuracy of 2.0 %, required to be tested once each calendar quarter (40 CFR 75, Appendix D, §2.1.5 and §2.1.6(a)) Gross Calorific Value (GCV): determine the GCV of pipeline natural gas at least once per calendar month (40 CFR 75, Appendix D, §2.3.4.1)

This monitoring approach is consistent with the CO 2 reporting requirements of the GHG Mandatory Reporting Rule for Electricity Generation (40 CFR 98, Subpart D). Subpart DP REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 72 requir es electric generating sources that report CO 2 emissions under 40 CFR 75 to report CO 2 under 40 CFR 98 by converting CO 2 tons reported under Part 75 to metric tons.

Also, the recently proposed NSPS Subpart TTTT

– Standards of Performance for Greenhouse Ga s Emissions for Electric Utility Generating Units ((40 CFR §60.5535(c)) allows electric generating units firing gaseous fuel and liquid fuel oil to determine CO 2 mass emissions by monitoring fuel combusted in the affected Electric Generating Unit and using a site specific Fc factor determined in accordance with 40 CFR 75, Appendix F. Therefore, PCEC ’s proposed CO 2 monitoring method is consistent with the proposed NSPS Subpart TTTT.P REVENTION OF S IGNIFICANT D ETERIORATION G REENHOUSE G AS P ERMIT A PPLICATION F OR A C OMBINED C YCLE P OWER P LANT AT THE P INECREST E NERGY C ENTER P INECREST E NERGY C ENTER , LLC

Zephyr Environmental Corporation

010303 

## APPENDIX A

GHG PSD APPLICABILITY FLOWCHART – NEW SOURCES

### B-1 

## Appendix A - GHG Applicability Flow Chart – New Sources (On or after July 1, 2011)

2 Determine the new source’s potential to emit (PTE) in tons per year (TPY) for each of the 6 GHG pollutants (CO 2 , CH 4 , N 2 O, HFCs, PFCs and SF 6 ) taking into account enforceable limits.

4 Are the potential GHG emissions on a

CO 2 e basis equal to or greater than 100,000 TPY?

Go to next
page 

### START

NO

YES NO If earlier, see New Source Flow Chart in Appendix A. 1 Will the permit be issued on or after

July 1, 2011?

YES

3 Calculate the GHG emissions on a CO 2 equivalent (CO 2 e) basis using the global warming potential factors applied to the mass of each of the 6 GHG pollutants.

Go to Element 7

### B-2 From prior
page

YES N O

N O

N O 6 Are the potential GHG emissions on a mass basis less than 250 TPY (or 100 TPY if the new source is in a listed category)?

7 Is this a new stationary source subject to PSD for a regulated NSR pollutant other than GHGs?

8 Are the potential GHG emissions equal to or greater than 75,000 TPY? GHG emissions

are subject to PSD as part of

this permit

r ev i ew. 5 Calculate the total GHG emissions on a mass basis.

*The mass-based emission threshold of zero TPY has been excluded from this flow chart because any new source that meets the 75,000 TPY CO 2 e requirement would automatically exceed that mass based rate. GHG emissions

are subject to PSD as part of

this permit

review. GHG emissions

are not subject to PSD as part of this

permit review.

GHG emissions

are not subject to PSD as part of this

permit review. YES

YES