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

### § 52.21

U.S. ENV IRO NMENTAL PROTECTION AGENCY, REGION 6

PSD PERMIT NUMBER : PSD-TX-979-GHG



### PERMITTEE : Calp in e Corporation 7 17 Texas
, Suite 1000 Hou s ton , TX 77002



### FACILITY NAME: Ca lpin e Corporation, Deer Park E n ergy Cen ter (DPEC) LLC



### FACILITY LOCATION: 5665 Highway 225 De e r Park, TX 77536

Pur sua nt to the provisions of th e C lean Air Act (CAA)
, Subchapter I
, Part C (4 2 U.S.C. Section 7470
, e t

. Seq.), and the Code of Federal Regulations (CFR) Title 40
, Section 52.21
, and th e Federal Impl e mentation P l an at 40 C FR 

### § 52.23 05 (effec tive May I
, 2011 as publi s hed at 76 FR 25178)
, the U .S. Env ironm e ntal Protection Agency
, Region 6 (EPA) i s issuing a Prevention of Significant D e t e ri ora tion (PSD) permit t o the Ca lpin e Corporation
, Deer Park E n ergy Ce nt er (DPEC) LL C for Greenhou se Gas (GHG) emissions

. T h e Permit app li es to th e t wo -ph ase construction of a new 180 megawatt (MW)
natur a l gas- fired combined-cycle combustion turbine
, id e ntified as CTG5 / HRSG5
, to augment the exis tin g power ge n era tion a t the exis tin g fa ci lit y located in Deer Park
, Texas.

Ca lpin e Corpora ti o n i s authorized to construct at th e Calp in e Corporatio n , Deer Park E ner gy Cente r (DPEC) as d escr ib ed herein
, in accordance with the permit app l ication (a nd plan s s ubmitted with th e permit app li ca t io n ), the federal PSD regulations at 40 CFR § 52.2 1
, and other terms an d conditions se t forth in tru s PSD permit in eonjunction with the corresponding Texas Co mmi ss ion on Environmenta l Quality (TCEQ) PSD p e rmit No. PSD-TX- 979. Failure to comp l y w ith any condition or term set forth in tlli s PSD Permit ma y r es ult in enforceme nt ac ti on pur s u a nt to Section 11 3 of the Clean Air Act (CAA). Trus PSD Permit does not reli eve Ca lpin e Corpo ration of the responsibility to comply with any other applicable provi sions of the CAA (inc ludin g app l icable impl e m e ntin g regulations in 40 CFR Patt s 5 1
, 52
, 60
, 6 1 ,72 throu g h 75
, a nd 98) or other federal and s t a te requir ements (including th e s t a t e PSD
program that remains under approval at 40 CFR 

### § 52.2303)

.

In accordance w ith 40 CFR § 124.15(b)(3)
, this PSD Permit b eco m es effec tive imm e di a tely upon is s uance of tru s final decision.

# ~&-- Car l E

. Ed lund
, P. E, Director Date Multimedia Plarulin g and**Pt ~rm** **ittin g**  Division

### C alpin e C orporation
, Deer P a rk E n e r gy Ce nt e r (DP EC ) LL C ( P S D- T X -979

- G H G) Pre v enti o n of S i g nificant D e terior a tion P e rmit F or G r ee nhou se G as E mi ss i o n s 

### F in a l P e r m it Co nditi o n s

P RO JEC T D ESC RIPTIO N

T h e proposed faci lit y i s a n atura l gas-fired comb i ned

- cyc l e e l ectr i c generating unit at the Deer Park E n e r gy Ce n ter (DPEC) LLC powe r plant in Ha rr is Co u nty, Texas. W i th this construction permit
, Ca l pine Corpora t ion w ill constr u c t a new natura l gas

- fired combined-cycl e combustion turbi n e generator (CTG) u n i t , identified as CTGS / HRSGS
, with a generating capacity of approximate l y 180 

### MW which i s of t h e s imi l ar design and output as the other existing four ( 4)
natura l gas

- fi r e d co m bined

- cyc l e combustion turbine un i ts at the plant. Construction will be comple t ed i n two phases: in ph ase o n e, a new Siemens F D 2

- ser i es turbine will be constructed; in
t he seco n d p h ase, the FD2 tu r bine w hi ch w il l be m odified and upgraded to the FD3

- s eries wit h in the s t atutory time l ines as defined by th i s permit. The steam p roduced from the new combustion turbine wi ll ex h a u st to a de d ica t ed Heat Recovery Steam Generator (HRSG) to produce steam. The s t eam prod u ce d from t he HRSG i s ro u ted t o e it her th e existing steam tu r bine unit to p r oduce

e l ectric it y fo r sa l e t o th e Elect ri c R e li ab il i t y Counc il of Texas (ERCOT ) powe r gr i d or may b e

so l d fo r u se a t an ad j a c e nt indu st ri a l faci li ty.



### E Q ill P MEN T LI S T

T h e fo ll ow in g devices a r e subjec t to this GHG P SD per mi t.



### Emi ss ion U nit Id

. D es cription N o.

CTG5 / HRSG5 (FD2

- Natural G as- Fired Siemen FD2-Ser i es 50 1 F Combustion Turbine Gene r ato r (CTG5) Series) rated at a maximum ba se -load e l ectric o u tput of app r oximately 1 68 MW and venting to (Initial Pha se) a dedicated Heat Recov ery Steam Generato r (HRSGS) that i s e quipped with a Selective Catalyt i c Reduction (SCR).

CTG5 / H RSG5 (F03- Natura l Gas-Fire d S i e m en FD3-Se ri es 50 I F Co m b u stion Turbine Ge n erato r (CTGS)

Ser i es) rated at a m ax i m u m base-load e l ectric o ut put of approx i mate l y 1 80 M W and v e nt i ng to

a ded i cated Heat Recovery Steam Gene r ato r (HRSGS) that i s equipped with a Selective (Fina l Pha se) Cata l ytic Reduct i o n (SCR).

NG-FUG Fugit i ve Nat ur a l Gas em i ss ion s from piping components (inciuding va l ves and flan ges)

SF6- FUG SF 6 In s ulated Electrical E quipment (i.e.
, circuit breakers ) con s i sti ng of one new 72 lb SF 6 in s ul ate d ge ner a tor circuit break e r ,Calpine Corporation
, Deer Park Energy Center Deer Park
, TX (Hanis County)

I. GENERAL PERMIT CONDITIONS

A. PERMIT EXPIRATION Page 3 of21 PSD- TX-979-GHG

Pursuant to 40 CFR §52.2 1 (r)
, this PSD Permit shall become invalid if construction:



### 1. is not commenced (as defined in 40 CFR §52.21(b)(9)) within eighteen (18 ) months after the approval takes effect; or

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

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

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

.

B. PERMIT NOT l lFICATION REQUIREMENTS

Permittee shall notify E.P A Region 6 in writing or by electroni

· c mail of the:

1

. date construct i on is commenced
, postmarked within thirty (30) calendar days of such date ;

2. actual date of initial strutup, as defined in 40 CFR § 60.2, postmarked within fifteen (15) calendar days of s uc:h date ;

3. date upon which initial performance tests will commence , in accordance with the provisions of Section V
, postmarked not les s than thirty (30) calendar days prior to s uch date

. N otification may be provided with the submittal of the performance test protocol required pursuant to Section V .E; and

4. date upon which initial certification tests of fuel flow meter and determination of the GCV (Gross Calorific Value) and associated data acquisition and handling sys tem in accordance with 40 CFR 75, Appendix D

. Additionally
, the initial certification or recettification appliGation shall be s ubmitted for the fuel flow meter as required by 40 CFR 75
, Appendix D

.

5. date upon which certification tests of the C0 2 CEMS will co mmence , if Calpine chooses
to install a C0 2 cont inu ous emission monitoring system (CEMS)
, in accordance with 40 CFR § 75.61(a)(l)(i) and 40 CFR Part 60, Appendix B
, Performance Specification 3. Additiona ll y , the in i tial certification or recertification application shall be submitted for theCa lpin e Corporation, Deer Park Energy Center Deer Park
, TX (Han-is County)

C0 2 CEMS as required by 40 CFR 75

. 63

. Page 4 of 21 PSD- TX-979-GHG

6. date upon which the FD3-series combust i on turbine generator is in commercial operation

or date eighteen ( 18 ) months after the completion of initial

. performance te sting
, or whichever

comes first.



### C. FACILITY OPERATION

At all tim es, includin g periods of startup , s hutd own, and malfunction
, Permittee shall
, to the
extent practicable
, maintain and operate the facility including associated air pollution contro l
eq uipment in a mann er consistent w ith good air pollution control practice for minimi zi n g

e mis sions. Determin at i o n of whether acceptab le operating andl maintenance procedures are being used will b e ba se d o n infom1ation ava ilable to the EPA
, which may include, but is not limited to , monitoring results
, review of operating maintenance procedur1es and inspection of th e facility

.

D. 

### MALFUNCTION REPORTING

1

. Permittee s hall no tif y E P A by mail within forty-eight (48) hour s following the discovery of any failure of air p o lluti on control equipment, pr ocess equipment
, or of a process t o

o perat e in a normal manner, which results in a n increase in C0 2 em is s ion s above the allowable emission limit s s tat ed in Section II of this pennit.

2. Within ten ( 1 0) day s of the re s torati on of normal opera tion s afte r any failure de scr ib e d in Section I.D.l
, th e P e rmitt ee s h a ll pr ovi d e a wr itt en s uppl ement to the initial n ot ifi ca tion that includ es a de scr ipti o n of the malfunctioning equi pm ent o r a bn or mal operation
, th e date of the initial malfuncti on , the period ofti m e over which emissio ns were incr eased due t o the fa ilur e , the cause of the failure
, the estimated resultant e mi ssions in excess of tho se a ll owe d in Section II
, a nd the methods utiliz ed to mitigate em i ssions and restore normal opera tion s

.

3

. Complia n ce with thi s malfunction no tific a ti on provision s hall not excuse or o th erwise

co n stit ute a defense: to any viola ti o n of thi s p ermit or any l aw o r re g ul a tion suc h malfunction
may cause.



### E. RIGHT OF ENTRY

EPA a uth orized representatives, upon the presentation of credent i a l s , s h a ll be permitted:

1. to enter the premises where th e facility is l ocated or w h ere any reco rd s are required to be kept und er th e terms and co nditi ons of thi s PSD P ermi t ;Ca lpin e Corporat i on , D ee r Park Energy Center Deer P ark
, TX (Har ri s Co unty) P age 5 of2 1 P SD- TX-979-GHG

2. durin g normal b us in ess h ours , to ha ve access to and t o cop y any record s r e quir e d t o b e 

### kept un der the t e rm s ar.'1d con dition s of thi s P SD P ern1it ;

3. to in s pect any e qui pme nt , o p erat i on , o r m e th od s ubject to r e quirement s in thi s P SD Permit ; and
,

4. t o s ampl e materi

. al s and e mi ss ion s fro m the so ur ce(s).



### F. TRANSFER O l F 

### OWNERSHIP

In the ev ent of any c h anges in c ontrol or ow n ers hip of th e facilitie s to b e construc t e d
, thi s PSD P erm it s hall be binding o n a ll su b se qu ent owners a nd o p e rator s

. Permittee s hall notify the

s uc cee din g ow n er and operator of the ex i ste nc e of th e PSD P erm it a nd it s condi ti ons by l etter; a copy of th e l etter s h a ll be f o rwarded to EPA Re g ion 6 w ithin t hirty (3 0) da ys of th e lett e r

s ignature

.



### G. SEVERABILITY

The provi s i on s of thi s PSD Pe rmit are severab l e , and
, if a n y provision o fth e PSD Permit i s h e ld in va lid b y a co urt of compete nt jur i s diction
, th e rem ai nd e r of thi s PSD P er mit s hall not b e affec t e d.



### H. ADHERENCE TO APPLICATION AND COMPLIANCE WITH OTHER ENVIRONMENTAL LAWS

P e rmittee s h a ll co n s truct a nd opera t e thi s project in co mplian ce wit h thi s PSD Permit
, the
app l ication o n which thi s permit i s bas e d
, the TC E Q PSD Permit No. PSD-TX-979-GHG
, as fin a l i ze d and a ll o th er app li cab l e f e d era l
, s t a t e , and l oca l a ir qua li ty regulation s

. T hi s PSD permit doe s not re l ease th e P e rmitt ee from any li a bility for comp l iance with ot h er app li cab l e federa l
, s t a te and l ocal e n v ir onmenta l l aws and r eg ulations
, incl udin g th e C l ean A ir Act.



### I. ACRONYMS AND ABBREVIATIONS

AVO**~=tarT** I...JJ\.

....... l Btu C AA CE M S C FR C H 4 

### co C0 2 Audio
, Vi s u al
, and O l fac tor y Best Avail a b l e C ontro l T e chnolo gy Briti s h thermal unit C l

ean A i r Act Co ntinu o u s Emiss i ons Mon i torin g S ys t em Code of Fede r a l R eg ulation s M e thane Ca rbon Mono x i de Ca rbon Dio x id eCalpine Corporation
, Ol ee r Park E nergy Ce nter D e er Park
, TX ( Harri s County)

C 0 2 e DCS OP EC d scf EPN ERCOT FR GHG
g r GWP HHV hp Ill' HRSG KWh lb MMBtu MW MWh N 2 0 NS PS PSD QAIQ C RATA SCFH SCR SF 6 TAC T CEQ tp y 

## usc voc Car b o n Dio x ide E quival ent D is tribut ed Co ntrol System D ee r P ar k Energy Ce nter Dr y Stan dard C u b i c Foot Emission Point N umb er E lectric Reliabilit y Co un c il of T exas Federal Register Greenhouse Gas Grains G lobal W a rmin g P o t en tial Hi g h He at in g Va l u e Hor se pow e r H o ur H eat Recovery Steam Generator Ki l owatt-hour Pound Million Briti s h Thermal Un i ts Megawatt Megawatt -hour N itrou s O x id es New Source Performance Standards Pr eve ntion of Significant Deteri o rat i on Quality Assurance a nd/or Quality C ontro l R e l ative Accur acy Te s t Audit Standard C ubic Feet Per Hour Selective Ca talytic Reduction Su l fur He xafl uoride Texas Adm i ni s trati ve Co d e Texa s Co mmi ss ion on Environmental Qua l ity Ton s Per Y ea r United States Code Vol a tile Or ga ni c Compounds Page 6 of21 PSD- TX -979-GH GCalpine Corporation
, Deer Park Energy Center Deer Park
, TX (Harris County)



### II. SPECIAL PERMfiT CONDITIONS

A. Facility Emission Limits Page 7 of21 PSD- TX-979-GHG

The proposed BA CT limits are in terms of efficiency measured in units of Btu of fuel energy consumed in order to generate a ki l owatt of electric energy (Btu / kWh)

. The BACT l imit s for the heat rate in term s ofBtu / kWh (HH V) on an annual ba s i s will be the sa me for the FD2 configuration as the FD 3 configuration. The FD3 configuration provides greater electrical output at high ambient temperatures during base load periods. Therefore, for the FD3
, the potential mmual electric ge neration (MWH) and fuel u sage, a s well as corresponding GHG emissions, will be higher on an annual ba s is. Consequent l y, the BA CT limit s, monitoring and recordkeeping requirem ents li sted in tlus pernlit are identical for both the FD2- and FD3-series combined-cycle combustion turbine generators. Any output-based emissions, in tons of C0 2 per megawatt hour (tons / M\Vh) on a 30-day rolling average and armual emissions, in tons of C02e
per year (TPY) on a 365-day rolling average basis sha ll not exceed the following:

(NEXT PAGE)Ca l pine Co rporat i on , Dee r P ark Energy Ce nter Deer Park
, TX ( H arris Cou n ty)



### Tab l e 1 Phase 1 Faci li tv Emis s i on Limit s

P h ase I o f Co n s tru c tion

G H G M ass Ba s i s

E mi ss i o n D es cripti o n G H G

U nit P o t e nt ia l O utpu t- b ase d E mi ss i o n s B ACT C O z ( TPY ) 2 .J Limie

C0 2 1
, 044
, 629 C0 2 0.460
ton s /MWh C T G5 CTG5 / H RSG5 (F D2 ) I An nu a l HR SG 5 E mi ss i o n s 7,730

C f!t 1 9

. 34 C H 4 Btu/KWh

N 2 0 1. 93 N 2 0 Fugit i ve Natura l Gas emissions NG- from piping C02 0

. 11 C O z FUG components ( i ncludin g valves & flange s) C H 4 4 2. 84 C H4 4

SF6

- S F 6 I n s u l ate d

FUG Elect ri ca l Eq u i pm e n t SF 6 0

. 000 1 8 SF 6 Pa ge 8 of21 PSD

- TX

- 979

- GHG

BA CT

A nnual Tons p e r B AC T

yea r Limit C 0 2 e 2

' 3 (T P Y C 0 1 e 2

' 3 )

1
, 044
, 629

1
, 045 ,6 35

406

599

0.11 60

59.69

4

. 3

4.3
I

. C omp li ance w t t h t he outp u t

- ba se d em t ss ton l nntts (o n a per h o ur b as t s) t s ba se d on a 30

- da y r o ll m g average. 2. Co m p li ance with the annua l e mi ss io n l i mit s (tons per yea r ) i s b ased on a 365-day rollin g average. 3. The tp y e m i ss i o n l imit s s pe c ifi ed in t hi s t able are no t t o be exceeded for this facility a nd includes em.ission..s

o nl y from the faci l i ty durin g nom1a l operation s a nd start up and s hutdo w n act ivitie s. 4. B eca u s e the emissions from this unit are ca l c u l ated to be 9 6% methane (C H 4 ), th e rema i nin g pollutant

e mi ss ion (C0 2 ) is not pre se nted in the table. 5. Be ca u s e the emissions from this u n it are calc ul a ted to b e over 99

. 9 % car bon di ox id e (C0 2 ), the r ema inin g pollutant em i ss ion s (C H 4 a nd N 2 0) are not presented in th e tab l e.Ca lpin e Corpo r ation, Deer Park E n e r gy Cen t er De er Park, TX ( H arr i s Coun t y)

Ta bl e 2 P h ase 2 Fac ilitv E mi ss ion Limits

Phase 2 o f Co n str uction

GHG Mass Ba sis

E mi ss i o n D es cription

U nit GHG Potentia l Output

- based Emiss ion s BA CT C0 2 (TPYl' 3 Limit 1

CO z 1
, 062
, 627 CO z 0.460

CTGS CTG5 / HRSG ton s /MW h
(F D3) I 5 A nnu a l RRSGS E mi ss ion s 7
, 730 C H 4 1 9.67 C H 4 Btu / KWh

N z O 1.97 N 2 0 Fugitive Na tur a l Gas emissions NG

- from piping CO z 0

. 11 C0 2 FUG co mpon e nt s ( in cluding valves & flanges) Cl-Lt 4 2

. 84 C H 4 4

SF6- SF 6 in s ul ated

FUG E l ect r ica l Equ ipm ent SF 6 0.000 1 8 SF 6 Page 9 of21 PSD-TX-979-GHG

BA CT

An nual Tons per B ACT

year Limit C0 1 e 1

' 3 ( TPY C0 2 e

2

' 3

)

1
, 062
, 627

1
, 063
, 650

4 1 3

6 10

0

. 11 60

59.69

4

. 3

4.3

I

. Co mplian ce wi th t h e output-based emi s sion lim i ts (o n a per h ou r basis) i s based o n a 30 -d ay rolling

ave ra ge. 2

. Comp li ance with the annual e mi ssion l imits (tons p er year) is based o n a 365 -d ay rolling average. 3

. T h e tpy em i ss i on limits spec ifie d in this table are not to be exceeded for thi s facility and includes em i ss i on s

on l y from the facility during nom1a l operat i on s a nd startup and sh utdo wn ac t ivitie s. 4

. Becaus e the em i ssio n s from t h is unit are ca l culated to be 96 % methane (CH 4 )
, the remaining pollutant

em i ssion ( C0 2 ) i s not presented in the table

. 5. Because th e emissions from thi s unit are calculated t o be over 99.9% carbon dioxide ( C0 2 ), th e r e m a inin g pollutant emi ss ion s (C H 4 a nd N 2 0) are not pre s e nted i n the t a bl e.Calpine Corporation
, neer Park Energy Center Deer Park
, TX (Harri s County)

B. Requirements for Combustion Turbine Page 10 of21 PSD-TX-979-GHG

1. Combustion Turbine Generator (CTG) BACT Emission Limits

a. Within 180 days of the date of initial startup of the FD2

- series combustion turbine generator , the Permittee shall perform an initial emission test for C0 2 and use emission f. :t ctors from 40 CFR Part 98. The Permittee shall ensure that GHG emissions from the Combustion Turbine Generator (CTG5) and heat recovery steam generator (HRSG5) into the atmosphere in e x cess of 0.460 tons C0 2 /MWh (net)
, not including duct firing, during the test. To determine this BACT emiss i on limit
, Permittee sha ll calculate the limit based on the measured net hourly energy output (MWh (net))
, the CTG is operating above 90% of its design capacity without duct burning firing and the results sha ll be corrected to ISO cond iti ons (59 ° F, 14.7 p s ia
, and 67% humidity). If the CTG does not meet the design emissions limit
, then the Permittee shall remedy the CTG ' s failure to meet the design emissions limit
, and shall not combust any fuel in the CTG until the Permittee has shown complianoe with that limit during a subsequent emission test

.

b. Upon demonstration that th e FD2-series combustion tmbine generator is in compliance with the design emissions limit via an emission test , the Permittee shall
not discha r ge or cause the discharge of emissions: from the Combustion Turbine Generator (CTG5) and heat recovery steam generator (HRSG5) into the atmosphere in excess of 0.460 ton C0 2 / MWh (net) on a 30-day rolling average and sha ll not discharge or cause the discharge of emissions into the atmosphere in excess 1
, 045
, 635 tons of C0 2 e on a 365-day rolling average. To determine this BACT emission Limits
, the Permittee shall calculate the limit based on the measured net homly energy output (MWh (net)) and the tons of C0 2 calculated from the equations provided in 40 CFR 75
, Appendix D and For th e C02 emissions CEMS data. T h e calculated hourly rate is averaged daily

.

c. Within 180 days of the date of initial startup of the FD3-series combustion turbine generator , the Permittee s h all perform an initial emission test for C0 2 and use emission factors from 40 CFR Part 98

. The Pemlittee shall ensure that GHG emissions from the Combustion Turbine Generator (CTG5) a nd heat recovery 

### steam generator (HRSG5) 

### into the atmosphere in excess of 0.460 tons**C0 ~.1\llh**  (net)
, not includin g duct burning firing, during the test. To determine this BACT emission limit
, Permittee shall calculate the limi

. t based on the measured net hourly energy output (MWh (net)), the CTG i s operating above 90% of its design capacity without duct burning and the results shall be corrected to ISO conditions (59op
, 14

. 7 psia, and 67% humidity). If the CTG does not meet the design emissions limit
, then the Permittee shall remedy the CTG ' s failure to meet the design emissions limit
,Calpine Co rporation
, Deer P a rk E ner gy Ce nter Deer Park
, T X ( H an- is County) Pag e 11 of21 PSD- TX-979-GHG

and s hall not co mbu s t any fuel in t he CTG until the P e rmitt ee ha s s ho w n**ro mn** **~nf'l>** u t ith**tl~at** li.nit rlnri..,n .:1 S "b S Pf"111P nt Prl"' ; ., s;o,.., t <>s t

.... ...... l"

....**~..~..............** .... .... ... .. ,.. _1

... ...... .. .... '""'""'"'""

.... 5

..... "" \,.;'"t""'"''•"' ""11..11..:> , .11 """ \

.

d

. Upon demon s tr a tion th a t the FD3-series co mbustion turbine ge nerator i s in

co mp l iance with th e d es i g n emis s ion s limit via an emission t es t , the Permitte e s hall
not dischar ge or cause th e di sc har ge of e mi ss ion s from the Co mbu s tion Turbine Generator (CTG5) and h ea t rec ove r y s te a m ge nerator (HRSG5) into th e atmo s pher e in excess of 0.460 ton C0 2 /MWh (ne t ) o n a 30-day rolling ave rage , and s hall n o t di sc harge or cause the di sc har ge of e mi ss ion s into th e atmosphere in exces s 1
, 063 ,65 0 t ons ofC0 2 e on a 365-day rollin g average. To determine thi s BA C T

e mis s ion limit s , the Permittee s hall calculate the limit b ase d on the measur e d n e t hourly ene1rgy output ( MWh ( net )) and the tons o f C0 2 ca lculated from the equations provid e d in 40 CF R 75, Appendix D and For th e C0 2 e mis s ion s CEMS data. The calculated hourl y rat e i s ave ra ge d daily

.

e. Modification of the pr o po se d FD2-series combustion turbin e generator, identified

as CTG5, to the FD3-series combu s tion turbine generator s hall commence within eighteen (18) month s of commencement of commercial operation of the initial project, or no lat e r than e i g hteen (18) m o nths after initial t es tin g is completed. Completion of th e initial proj ec t will occur th e date of the commercial operation of the F D 2-se ri es combustion turbin e.

f. Within 180 days of th e dat e of initia l s t ru tup of f o r both th e FD2 and FD3-series combustion turbin e ge nerator , the P e rmitt ee s hall not exceed a Co mbu s tion Turbine: Generator av e ra ge net heat rat e of 7, 730 Btu / kWh (HHV)
, not includin g duct burner firing
, durin g th e te s t for combustion turbine unit. To d e t e rmine this BA C T emission limit
, P er mitt ee s hall calculate the average n e t h ea t rate on a hourl y ba s i s consistent with e qu a tion F-20 and pr oced ur es pro v ided in 40 CF R Part 75
, Appendix F
, 

### § 5.5

. 2
, th e me as ur ed n e t hourl y heat rate (kWh), that the CTG i s operating above 90% of it s de s i g n capacity without duct burning and the results

s hall be co r r ecte d to ISO condition s (59 ° F
, 14

. 7 p s ia
, a nd 67% humidity). If the C TG doe s not meet th e e mi ss ions limit
, th e n the Permitte e s hall remedy th e CTG ' s f a ilure to me e t th e emissions limit
, a nd s hall not combu s t any fu e l in th e CTG until the P e rmitte e ha s s hown co mplian ce with that heat rate limit during a s ub se qu ent emission te s t.

g. Upon initi a l demon s tration that the FD2-series and FD3- s e ri es combustion turbine
ge n e rator complie s w ith the emissions limit v i a an emission t es t , the Permitt ee s h a ll
not excee d a Combustion Turbine Generator net h ea t rate of7
, 73 0 Btu / kWh (HHV)

on a 30- da y rollin g average , f o r both th e F D 2- or FD3-series combustion turbin e unit. To determine th i s limit
, Permittee s h a ll calculate th e average net h eat r ate on aCalpine Corporation,**D•~er** Park E nergy Center Deer Park
, TX (Harris County) Page 12 of21 PSD-TX-979-GHG

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

"7C A 

### --e-...1 :

.. C' 1: c c....,**~** •• A**+t..~ --** **e~~** 

### .. -e...l**-~• t..** **~** .. -1

..**o-~" ~**  .. +-

.. + / 1
, \1 / 1. \ Tl,o I J
, n.vp HUl A r , ':-J J .J ,.:., alJU lllv Ill a;:,uJ U llvl 11ULH lJ vllvl oJ UUlJ.lUL \1\. V> ll )• 111'- Calculated hourly he at rate is averaged daily.

h

. Permittee shall determine the hourly C0 2 emission rate from 40 CFR Part 75, Appendix G
, using 

### F e factors updated monthly from fuel analysis or, as an alternative, permittee may install and operate a volumetric stack gas flow monitor and associated data acquisition and handling syst,em in accordance with the C0 2 CEMS system provided in 40 CFR § 75.10(a)(3) and (a)(5).



### 2. Monitoring of C0 2 

### Emissions for CTG5/HRSG5

a

. The permittee shall determine the C0 2 hourly emission rate and C02 mass emissions for the combustion turbine generator and heat recovery steam generator, identified as CTG5 / HRSG5
, using an 0 2 monitor according to appendix F to 40 CFR Subpart 75. In accordance to 40 CFR Subpart 75.20(c)(4)
, the permittee shall determine hourly C0 2 concentration and mass emissions with a flow monitoring system; a continuous 0 2 concentration monitor ; fuel F and Fe factors; and, where 0 2 concentration is measured on a dry basis (or where Equation F

- 14b in appendix F
to 40 CFR Subpart 75 is used to determine C0 2 concentration), either
, a continuous moisture naonitoring system , as specified in §75. ll(b)(2), or a fuel-specific default moisture p e rcentage (if applicable), as defined in §75

. 11(b)(l) ; and by using the methods and procedures specified in appendix F to 40 CFR Subpart 75.

b. Permittee shall install
, calibrate, and operate a fud flow meter and perform periodic scheduled GCV fuel sampling for the combustion turbine generator and heat
recovery s team generator , identified as CTG511-fRSGS
, and shall meet the applicable requirements
, including certification**t~~sting,** of 40 CFR Part 75
, Appendix D and 40 CFR Part 60 to be used in conjunction with the Fe factor based

on the procedures to calculate the C0 2 emission rate in 40 CFR Part 75
, Appendix F

.

c. Oxygen analyzers s hall continuou s ly monitor and record oxygen concentration in the combustion turbine generator and heat recovery steam generator identified as**r""'T'~C TDCr!.t:.**  T

.. ,... 1-.

.... 11

........... ....l

.... ,..,,... +1...

...... ,.....,,. , ,....,... ..... ..... ..........**..-1~** .... ,.,.. .... t

...... ,...._**,...,. ,...** **,..n,.~nrr ._t::~o**  ..... ; ...... ,-1 "+t:.. \...; 1**UJ lT~**  . .::>UJ. H ;:,uaH JvUUvv w,.;**vAy ~;;u**  u; ;a utu 0 ;:, lUau avv1a 0 111 0 y,.;uuu u1 u minutes OJ! les s and record it at that frequency.

d

. The oxygen analyzers shall be quality-assured at least quarterly using c y linder gas audits (CG-As) in accordance with 40 CFR Part 60
, Appendix F, Procedure 1
, § 5.1

. 2
, with the following exception: a relative accuracy test audit i s not required

once every four quarters (i.e., two successive sem iannual CGAs may be conducted).Calpine Corporation, Deer Park E nergy Center Deer Park, TX (Harris County) Page 1 3 of21 PSD-TX-979-GHG

e.

.. A

.. s a..r1 alter11ative to 

### Special Condition II .B.2.a , the pertnittee n1ay**L~ ta11**  a r'Q 2 CEMS and volumetric s tack gas flow monitoring syste m with an automated data acquisition and handlin g system for m eas uring and recordin g C0 2 emissions discharged to the atmosphere.



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

s hall ensure that all required fuel flow m e t er i s in stalle d
, a periodic schedule for GCV fuel samp lin g i s initiated and all certification t es t s are completed on or be fo r e th e ea rlier of 90 unit operating days or 180 calendar days after th e date the unit

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

g. Permittee s hall ensure compliance with the specifications and test procedure s for fuel flow meter and/or C0 2 emission m o nit or ing sys tem at sta tionar y sources , 40 CF R Part 75 and 40 CFR Part 60.

h

. Permittee s hall meet the appropriate quality assurance requirements s pecified in 40 CFR Part 7'5, Appendix D and F and 40 CFR Part : 60 for the fuel flow m e t e r a nd / or C0 2 em iss i on monitoring sys tem.

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

a. Permittee s hall calculate the amount of C0 2 emitted for both the FD2- and FD3-

ser i es CTG from combustion in ton s per hour (tonslhr) on a 365- day rollin g

ave rage , and converted to tons per year ( tpy) ba se d on equation G-4 of 40 CFR Part 75 and the average net heat rate on an hourl y ba s is ba se d on the heat input calculation procedures contained in 40 CFR Part 75, Appendix F, equation F-20.

b

. The calculated C0 2 e mi ss ion s from Special Condition Il .B.3.a s hall b e compared to the measured C02 emissions from th e 02 emission monitor
, required in Special Co ndition II .B.2.a , a nd ifthe Permittee is using the C02 monitor (CEMS) methodolo gy , then t he calculated hourl y stac k gas volwnetric flow rate, required in Special Condition Il.B.l
, on a daily basis. If the mean diff ere n ce between the calculated and m eas ured**C~** emiss ion monitor r esu lt i s g reater than 10 % of measured C0 2 concentration, the permittee s h a li review the e mi ss ion unit s and monitoring in str um e ntation operational perfmmance. From thi s review
, any corrective measures taken are to be id e ntified
, rec:orded, including th e reason for the C02 emissiions difference and corrective mea s ur es completed within 48 hour s of the corrective measures being tak e n. lf the pe1mittee chooses to install and operate a C0 2 CEMS eq uipped with a vo lum e tric stack gas monitoring syste m , th en th e C0 2Calpine Corporat ion
,**er** Park Energy Center Deer Park
, TX (Harris County) Page 14 of21 PSD- TX-979-GHG

emission calculation from Special Cond ition II.B.3

. a and the mean difference

"'" '......,.- '""...,.;,..."_ ; l"' ....,"**l"'\.'t'\I'Y.0. 11** **~** n**..,.o,.,n~** ... .a...-o ...... + +h .a - t-1-,.a. -·a•.....-vt.;t+a o. ,... h,,....ll

... al, r """ +1"\ o rlf"ltf"' YVULpa.tJ.;)Vltl t.;) llV tVHOVJ a 1\,.;\..fUll\.;Jlt\...JtL , LLI\,..11 UL\,...1--'\,.;lUULL\,.;\...**ua u**  tt,.,l J v11 ut""" ualu. from the C0 2 CEMS for compliance purposes.

c. Permittee shall ca lculate the CH 4 and N 2 0 emissions on a 365- da y rolling average

. Permittee s hall determine compliance with the C H 4 and N 2 0 emissions limits contained i in this section using th e de fa ult CH 4 and N 2 0 emission factors contained in Table C-2 of 40 CFR Part 98 and the measured ac tual hourl y heat input (HriV).

d

. Permittee shall calculate the C0 2 e emissions on a 365-day rolling average , based on the procedure s and Global Warming Potentials (GWP) contained in Greenhouse Gas Re gu l at ion s, 40 CFR Part 98, Subpart A
, Table A-1.

e

. Fuel for the FD2 or FD3 Combustion Turbines shall be limited to natural gas with a fuel s ulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S / 1 00 dscf)

. The gross calorific value of the fuel sha ll be d e termined monthly by the procedures contained in 40 CFR Part 75, Appendix F
, §5.5 .2 and record s s hall be maintained of the monthly fuel gross calorific vall ue for a period of five years. U pon request , Permitte e shall provide a sample and / or analysis of the fuel-fired in the Combustion Turbines or shall allow a sample to be taken by EPA for analysis.

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

as CTG5, :s hall be measured and recorded using an operational non-resettable elapsed flow meter.

g

. Permittee s hall mea s ure and record the new energy output (MWh (net)) on an hourly ba s i s.

h

. On or before the date of initial performanc e t est required by 40 CFR 60.8
, and thereafter
, Permittee shall install
, and continuously operate, and maintain the HRSG5 equipped with a SCR so emissions are a1 t or below the emissions limit s specified in this permit and TCEQ permit No. 45642/PSD-TX-979M2/N036M2.

1. On or after initial performance te s ting
, permittee s hall use the combustion turbine
, Heat Rec overy Steam Generator, Steam Turbine and Plant-wide energy efficiency
processes , work practices and designs as represented in the permit application

.Ca lpin e Co rp orat i on , De e r P ark Energy Ce nter Deer Par k, TX (Harris County) Page 1 5 of2 1 PSD- TX-979

- GHG



### 4. R e quirements during FD2/FD3 Combustion Turbine (CTGS) Startup and Shutdown

a. Permittee s hall minimize e mi ss ion s durin g s t art-Ul p a nd s hutd own activities by
opera tin g a nd m a int aining the faci li ty and associated a ir pollution contro l equipme nt in accordance w ith good air pollution control practices
, safe operat in g practices, an d protect ion of the facility.

b. Emiss i o n s during startup a nd shutdown ac ti vities shall be minimized by limitin g the dw-ation of opera ti on in startup a nd sh utd own mode as follows:

1. A start up of CTG5 is defined as the period th at begins w h en th ere i s measw-eable fuel flow to the CTG5 and e nd s when th e CTG5 load reaches 60 percent. A startup for each CTG5 is limited to 480 minutes.

11. A s hutd own of eac h C TG 5 i s defined as the period that begins when CTG5 lo a d fa ll s below 60 p e rcent an d e nd s when th e r e is n o long e r m eas ur ea bl e f u e l fl ow t o CTG5. A s hutdown for CTG5 i s limit ed t o 180 minute s.

c. Permittee must record the time, date
, fue l h eat i nput (HHV) in mmBtu/hr and duration of eac h s t ar tup and s hutd own event in order t o ca l cu l ate total C0 2 e

em i ssio n s. The r ecords must include hourly C0 2 emission levels as measured by the fuel flo w m eter and/o r 0 2 e mi ssio n m o nitor (or C0 2 CEMS with volumetric

s t ack gas fllowrate) a nd the ca lcul atio n s based on the ac tu a l h ea t input for th e C0 2 , C02e, 0 2 ,**l~'hO,** and C H 4 e mi ss i ons during eac h s tartup and shu tdown eve nt based

o n the e qu ations represented in th e permit app li ca ti on. These records must be kept for five (5) years following th e date of s u c h eve nt

.

d

. Du rin g sta1 1up and s hutdown
, CTGS and HRSGS emissions s h a ll comply w ith a ll provisions of BACT emiss ion limit a ti ons in Special Cond ition II .B. l

.



### C. Fugitive Emission Sources



### 1. F ugitive Emission Sources Emission Limits

At a ll times
, includin g e quipm e nt start up a nd s hutd own, P e rmitt ee s h a ll n o t discharge
, or ca u se th e di sc h arge of e mi ss ion s from eac h unit into th e atmosphe r e, in excess of the following:Calpi ne Corporation, Deer Park Energy Center Deer Park, TX (Harris County) Page 16 of2 1 PSD-TX-97 9 -GHG

Tabie 3 Fugitive Em i ssion Sources Emission Limits

ID No.

NG-FUG

SF6-FUG

I. GHG P o llut a nt s Fugitive Sources Em i ssio n s D esc ripti o n Limit

Pollutant Mass Basis C02e Ba sis C0 2 e TPY Tota l C0 2 e TPY TPY TPY

Fug i tive Natural Gas CH4 1 emissions from 2.84 59.69 59.69
pipin g compone-nts ( in c l uding**va lv~:** **s** & 

## co z flang es) 0

. 1 1 0.1 J 0.11

SF 6 lnsulated Electrical SF 6 0.000 1 8 4.30 4.30 Equipment

Because the emiSS I Ons from this umt are ca l c ul ated to be 94.44% methane (CH 4 ) from natura l gas

ana l ysis
, th e remai n ing po llu tant emissions are n ot pre se nted in the t a bl e.



### 2. Fugitive Emission Sources Work Practice and Operational Requirements 60

4.30

a. For e m iss i on unit NG -FUG
, CH 4 emissions shall be calculated annually (calendar year). P ermittee s h a ll n ot exceed 2.84 tons per year of methane (e qui va l e nt to 59.69 to ns of C0 2 ) f rom a ll pipi n g compone nt s including va l ves and flanges and

a n ove rall emissions limit of 60 tons per year of C0 2 e. Emissions s h a ll be calc ul ate d annually based on th e em i ssio n factors from Ta bl e W

- 1 A of 40 CFR Part 98
, Subpart W
, P e tr o l e um and Na tur al Gas Systems using the reducti o n c r edit from 28LAER and calc ul at i ons g i ven in the TCEQ Technical Guidance D oc ument fo r Equip m ent Leak Fugit iv es, dated October 2000.

b. The permittee s hall implement an as-observed auditory, visual and olfactory (AVO) method for d etecti n g leaking from natural gas piping components

c

. For emi ss ion unit SF6

- FUG
, SF 6e missions shall be calculated annually (ca lendar year) in accordance w ith the mass balance approach provided in equation DD-1 of the Mandato r y Greenho u se Gas Repo rtin g rules for Electrica l T r ansmission and Distribution Equipmen t Use
, 40 CFR Part 98, Subpart DD. Permittee s hall not exceed one (1) 72 lb SF 6 circuit breakers with l eak detection.

d. Permittee sha ll maintain a file of all records
, data mea s urements , reports and document s related to the fugitiv e emission so urce s including
, but not Limited to, the followin g: a ll records o r report s pertaining to maintenance performed
, a llCa lpine Co rporati o n , D eer Park Energy Ce nter Deer Park
, TX ( H a rri s Co unt y) Page 17 of21 PSD-TX -979-G HG

r eco rd s r e latin g t o co mpliance with the Monitoring and Quality Assurance and**nn <:~** **\1** {'nt1trr.J rn f'1 f nr'\ n rt"\f'P rl11l' PC l"\11tJin P rl ;1"1 LJ.() rJ:;""Q QQ 1() LJ. '< \.A.II..4-..&.I.\. ) '- J \J.I.J.\..LVI \'<_ -' )J '<. '-" } 1-'.I.UV'VUU.J.VU V \AL...l.l.l.lV'-4 l.ll**'-' ~""-'-**  ./ Uo ...J V I •

III. Recordkeeping Requirements

A. In order to demonstrate compliance w ith the GHG e mi ss i o n rat es for both the FD2- and FD3-series CT G
, th e permittee w ill m o nitor the following parameters and s ummari ze th e data on a calendar month basi s.

a. Operatin g hours for all air emission so urce s; b. The natural gas fuel usag e for all combustion so ur ces , usin g co ntinuou s fuel flow

m o nitor s (a group of equipment can utilize a common fu e l flow meter , as long as actual fuel usage is allocated to the indi v idual equ i pment ba se d upon actual operating hour s and ma x imum firing r a te );

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

. Record th e number and dur a tion of shutdowns for each engine.

B. Petmittee will maintain s it e-s pecific procedures for b es t / optimum maintenance practice s and vendor-recommended operating proc e dures and O&M manual s. These manual s mu s t be maintained with the permit and loc a ted onsite.

C. Permittee s hall maintain records that include the followin g: the occunence and duration of any startup, shutdown, or malfuncti o n , p er formance t es tin g , calibrations, c heck s, GHG

em i ssion units and C 0 2 emission CEMS maintenance (if a C0 2 CE MS i s pr ese nt)
, duration of any period s during which a monitoring device i s inoperative
, and corresponding emission mea s urement s

.

D

. Permitt ee shall r:naintain records for fi ve (5) years from th e date of any ofthe following : the duration of startup , s hutdown
, the initial st mtup period as defined in Section IV for the emission unit s, pollutio n control units and CEMS ( if a C 0 2 CEMS is present)
, malfunctions
, performance testing
, calibrations, c heck s, maintenance and duration of an inoperative monitoring d evi ce and emission unit s with the required conesponding emission data

.

E. P ermittee shall maintain record s o f all GHG emission unit s and C0 2 emission CEMS certification tests (if a C0 2 CEMS is pre s ent ) and monitoring and comp i ianc e information required by this permit.

F. P er mitt ee will implem e nt th e AVO program and keep 1 r eco rd s of the monitoring r e s ult s,

as well as the re pa ir and maintenance records.Ca lpin e Corpo ration
, Deer Park Energy Ce nt er De e r Park
, TX (Harris Co unty ) Page18of21 PSD- TX -9 79 -GHG

G. At l eas t once per year , the permittee w ill obtain a n upd a ted anal ys is of the inl et gas t o doc utne11t 

### the C <) 2 

### and 

### m e tl1an e co nt ent of 

### the gas strea..'Tis.

H. Permittee s hall maintain r ecor d s a nd s ubmit a written n e

port of all exce ss em i ss ion s to EPA s emi-rumuall y , except when: more frequent reportin g i s specifically r eq uir e d by an app lic ab l e s ubp a rt ; or th e Admini s trator or authori z ed repre se ntative, on a case -b y -c ase basis
, det e rmine s that more frequent reporting i s n ecessa ry to accurate l y a ssess the compliance s tatu s of the so urce . T h e report i s due on t he thirtieth (30 111 ) da y follow in g the

e nd of each sem i- a nnual period and s h a ll includ e the following:

1

. Time intervals
, d a t a and magnitud e of th e excess emission s, the n a ture and cause ( if known)
, correct i ve ac tion s take n and pre v entive mea s ure s adopted ;

2

. Applicable time and d ate of eac h period during which the monitorin g equipment

was inoperati ve ( monit ori n g down-time) ;

3. A s tatement in the report of a n ega ti ve declaration ; that i s ; a s t ate m e nt when no

excess em i ss i ons occurred o r when the monitorin g eq uipment ha s n o t b ee n inoperat iv e, repair ed or a dju s ted ;

4

. Any failure t o co nduct any required so ur ce te sti n g, monitorin g, or ot h er compliance activities ; and

5. An y v iolation of limita t ion s on operation
, includin g but not limit ed to restriction s

o n hours of operation of the e mer ge n cy ge nera t or or fire pump

.

I. Ex ce ss e mi ssio n s s hall b e d efi ned a s any period in w hich the fac ilit y e mi ss ion s exceed a

m ax imum emission limit set forth in th i s permit.

J. Ex cess emissions indic a ted by GHG emission so urc e c ert ifi cat ion testing or compliance monitorin g s hall be co nsider e d vio l a ti o n s of the applicab l e emission limit for the p urpo se of thi s permit.

K. All records r e q u ired by this PSD P e rmit s hall be retained for not l ess thru1 5 yea r s following th e dat e of s u c h measur e ments , maint e n ance , and reports.

IV. Shakedown Periods

The comb u s tion turbin e emis s ion limit s and requirem e nt s in conditions I I. A and II.B s h a ll not apply durin g combustion s hak e d own p e ri ods. S h ake down is defined as the p er iod beginning with initial st artup a nd e ndin g n o l ate r th a n initi a l performance te s tin g, durin g whi c h th e PermitteeCalp in e Corpo r ation
, D< ;:e r Park Energy Ce n ter Deer P ark
, TX (HarTis Cou nt y) Page 19 of2 1 PSD- TX-979

- GHG

co n ducts ope r atio n al ar1d contractua l tes tin g a n d tuning t o ensure the safe, effic ient and reliable
opera ti o n 

### of th e plan t. 

### The s hak e d own 

### period s h a ll not 

### exceed the t i me p er i od for performar1ce
te s ting as specified in 40 CF R § 60 .8

. T h e r eq uirement s of Special Con diti o n I.C of th i s permit sha ll app l y at a ll times.

V

. P e rformance Testing Requirements:

A. Upon completion of the firs t ph ase of co n s tru c ti o n , the hold e r of this p er mit sha ll perform an initi a l stack te s t for the F D 2

- series co mbu st i on tur bine t o establ i sh th e ac tual quant i ties of air contaminants being e mitted into the atmosphere from e mi ss ion unit CTG5/HRSG5 and to determine the initial comp li ance w ith the C0 2 emis s i on li mits established in this permit. Sampling sha ll be conducted in accor dar1 ce with 40 CFR § 60.8 and E PA Method 3a or 3 b for the co n cent r ation of C0 2 f o r th e CTGs.



### B

. Upo n co mpl etio n of th e second phase of const ructi o n , the holder of th i s permit s h a ll p e r form

a n initial s t ack t est for t h e FD3 series comb u s tion turbin e t o esta bli s h th e actual qu a ntitie s of

a ir con t a min a nt s bein g e mitt ed in to th e atmosp h ere fro m emiss i o n unit CTG5 / HRSG5 and to d e t er min e the initial comp lianc e w i t h the C0 2 emis s i on li mits established in thi s permit. Sampling s hall be conducted in acco rdan ce w ith 40 CFR § 60.8 and EPA Method 3a or 3b for th e concentra tion of C0 2 for the CTGs

.

C. Within sixty (60) d ays afte r achieving the ma x imum production r ate at which t he F2

- series CTG w ill be opera ted
, but not l a t e r than one hundred and eig h ty ( 1 80) days after initial
start up of the fac ilit y , perfo nn ance t ests(s) mu s t b e co ndu cted and a written report of the performance testing r es ult s furnished to th e E PA. Addit i onal samp lin g may be required by TCEQ or EPA

.

D. Within six t y (60) d ays after achieving the maximum produ
, ction rate at which the FD

- 3 series CTG will be ope r a t e d
, but not l ater than o n e hundr ed and eig h ty (180) days after initi a l startup of the facility
, p erfo rm a nc e t ests(s) must b e con du cted and a written report of the performance tes tin g res ult s furnished to the E P A. Additional sam plin g ma y be required by TCEQ or EPA.

E. P e r mittee s hall su bmit a pe rf ormance test protocol to E PA no later than thirty (30) da ys prior
to the t est to allow review of the test plan a nd t o arrange for an observer to be pr ese nt at th e 

### te st fo r 

### bo th the FD2- an d FD 3-series combus ti o n turbine gene r ator. T he perfom1ance tes t

s h all be co ndu cte d in accor dance with the subm itt e d protoc ol, and any c h anges requ ir ed by EPA.

F

. The h o l de r of thi s p e rm it s hall perform stac k samp lin g and other testing as required to

e sta blish th e ac tual quantitie s of C0 2 emi ss i ons bein g emitted into the atmosphere fromCalpine Cor porat i on, Deer Park Energy Ce nter Deer Park
, TX (Harris County) Page 20 of21 PSD- TX-979-GHG

emission unit CTG5 / HRSG5 and to determine the initial compliance with aJJ emission limits**~nf.n l-.l:** **hed** ;

.. ;.1-.:n

..**,.~.~:** ..**~,...** .. h nf. h tho "Cn'l a'"'d**Fn~** sor;o s f"Tr. <;: <>.,.., nlincr ch<>ll h P**~;::)laUll** 111 UUI:> jJ'woliJ.llL .lUl UVU.l \..11\.o 1 J....Jk -. .JI JJJ • "-'lJ."" '-' ..l '-...lo U U...lU

. jJ1. , LU,6

... HU.4U V V conducted in accordance with EPA Methods l-4 and 3 b fo r the conce ntration of C0 2 for the CTGs.

G. Fuel sampling for emission unit CTG5/HRSG5 s hall be conducted in accordance with 40 CFR Part 75 and Pa1t 98.

H. The turbine shall be tested at or above ninet y percent (90%) of maximum load operations for the atmospheric conditions which exist during testing. The duct burners s hall be tested at its maximum firing rate while the turbine is operating as close to ba se load as po ss ible. The tested turbine load shall be identified in the sampling rep01t. The permit ho l der shal l pre se nt at th e pretest meeting the manner in which stack sampling will be executed in order to demonstrate compliance with the emission s l imit s contained in Section II and the emission

s tandards found in NSPS
, Subpart K.KKK.

I. Air emissions from each HRSG exhaust stack shall be tested while firing at the minimum load in the normal operating range. The normal operating range consistent with emission limits is to be determined during stack testing

. Air emission s wi l l be sampled and analyzed while at a the minimum l oad include (but not limited to) VOC and 0 2

.

J

. Performance tests must be conducted under such conditions to ensure representative performance of the affected facility. The owner or operator mu st make available to the EPA such records as may be necessary to determine the condition s of the performance tests.

K. The owner or operator must provide the EPA at least thirt y (30) days' prior notice of any performance test , except as s pecified under other subparts

. to afford the EPA the opportunity
to have an observer present and/or to attend a pre-test meetin g. If there i s a delay in the original test date, the faci l ity mu st provide at lea st seven (7) days prior notice of the rescheduled date of the performance test.

L. The owner or operator shall provide
, or cau se to be provid e d
, performance testing facilities as follows:

1. Samp l ing p011s adequate for test methods applicable to thi s facility, 2. Safe sampling platform(s)
, 3. Safe access to sa mpl i ng platform(s)
, and 4. Uti l ities fo:r sampling and testing equipment.

M. Unless otherwise specified, each performanc e test shall consist of three separate runs u si ng the applicable test method. Each run shall be conducted for the time and under the conditionsCa lpin e Co rp o ration
, De e r Park E n e rg y Center D ee r Park
, TX (Harris County) Pa ge 2 1 of2 1 PSD- TX-979-GHG

s p ec ified in th e applicable s tandard

. For purposes of determining comp lianc e with a n applicab l e sta ndard. th e ar ithm etic mean of th e r es ult s of the three run s shall apply

.

VI. Agency Notifications

Permittee s h a ll s ubmit GHG permit applications
, p e rmit a mendm e nt s , a nd other app li cable
p er mit inform at i o n to:

Multi Media P l anning and Permitting Di vis i o n E PA Region 6 144 5 Ross Avenue (6 PD-R ) Dalla s, TX 75202 Emai l : Group R6AirPermit s @ EP A.gov

Permitt ee s hall s ubmit a copy of a ll c om pliance and e nf orce m e nt correspondence as requir e d b y thi s Approval to Co n s truct to :

Co mpliance and E nforcement Division E PA Re g ion 6 144 5 Ross Avenue (6EN) DalJa s, TX 752 0 2

### Statement of Basis Greenhouse Gas Prevention of Significant Deterioration Preconstruction Permit for the Calpine Corporation, Deer Park Energy Center (DPEC) , LLC

Permit Number: PSD

- TX -979- GHG

August 2012

This document serves as the S tatement of Basis required by 40 CFR 124.7. This document sets forth the legal and factual basis for the draft permit conditions and provides references to the statutory or regulatory provisions, including provisions under 40 CFR 52.21, that would apply if the permit is finalized

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

I. Executive Summary

On September 1 , 2011, the Calpine Corporation, Deer Park Energy Center (DPEC), LLC
, submitted to EPA Region 6 a Prevention of Significant Deterioration (PSD) permit application for Greenhouse Gas (GHG) emissions from proposed construction of a natural gas- fired combined -cycle combustion turbine generator (CTG) at the existing DPEC fa cility

. In connection with the same proposed project, Calpine Corporation submitted a PSD permit application for non-GHG pollutants to the Texas Commission on Environmental Quality (TCEQ) on September 1 , 2011. On December 11, 2011, February 7, 2012 , April 2, 2012, April 30, 2012 and June 22, 2012, Calpine submitted additional information to amend their permit application s to both EPA and TCEQ, revising the permit application s to incorporate a multiphase construction of the proposed CTG. The revised project at the DPEC p lant proposes phased construction of the n atural gas -fired combined- cycle CTG with a generating capacity of approximately 180 megawatts that will be completed in two stages of construction. In the in itial phase, Calpine intends to construct a Siemens Model FD2 combustion turbine that will be subsequently be upgraded in perform ance as a FD3

- series combustion turbine in the second stage of construction. Modification of the FD2 combustion turbine to the FD3

- series would commence within eighteen (18) months of completion of construction or beginning of commercial operation of the initial project. Afterreviewing the application, EPA Region 6 has prepared the following Statement of Basis (SOB) and draft air permit to authorize phased construction of air emission sources at DPEC

.

This SOB documents the information and analysis EPA used to support the decisions EPA made in drafting the air permit. It includes a description of the proposed facility, the applicable air permit requirements, and an analysis showing how the applicant complied with the requirements.

EPA Region 6 concludes that Calpine’s application is complete and provides the necessary information to demonstrate that the proposed project meets the applicable air permit regulations. EPA's conclusions rely upon information provided in the permit application, supplemental information EPA requested and provided by Calpine Corporation, and EPA's own technical analysis . EPA is making all this information available as part of the public record

.Calpine Corporation, Deer Park Energy Center Page 2 of 38 Deer Park, Texas (Harris County)



### II. Applicant

Calpine Corporation 717 Texas, Suite 1000 Houston , TX 7 7002

Physical Address: 5665 Highway 225 Deer Park , TX 77536

Contact: Patrick Blanchard Director of Environmental, Health and Services Deer Park Energy Center LLC 717 Texas, Suite 1000 Houston, TX 77002

III. Permitting Authority

On May 3, 2011, EPA published a federal implementation plan that makes EPA Region 6 the PSD permitting authority for the p ollutant GHGs. 75 FR 25178 (promulgating 40 CFR § 52.2305) . Texas still retains approval of its plan and PSD program for pollutants that were subject to regulation before January 2, 2011, i.e., regulated NSR pollutants other than GHGs.

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

EPA, Region 6 1445 Ross Avenue Dallas, TX 75202

The EPA, Region 6 Permit Writer is: Alfred C. Dumaual, Ph.D. Air Permitting Section (6PD

- R) (214) 665-6613

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

Air Permits Division (MC -163) TCEQ P.O. Box 13087 Austin, TX 78711-3087Calpine Corporation, Deer Park Energy Center Page 3 of 38 Deer Park, Texas (Harris County)



### IV. Facility Location

The Calpine Corporation, DPEC plant is located in Harris County, Texas, and this area is currently considered to be in attainment for all NAAQS with the exception of the 8 hour Ozone standard, for which it is classified as a marginal non

- attainment area as of April 2012. The geographic coordinates for this facility are as follows:

Latitude: 29 o 42 ’ 43.6 ” North (29.712111) Longitude: 95o 08’ 7.8” West (-95.135511)

The figures below illustrate the facility location for this draft permit in city of Deer Park, Harris County, Texas.Calpine Corporation, Deer Park Energy Center Page 4 of 38 Deer Park, Texas (Harris County)



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

EPA concludes Calpine ’s proposed modification is subject to PSD review for the pollutant GHG, because the project would lead to an emissions increase of GHGs for a facility as described at 40 CFR §§ 52.21(b) (23) and (49)(iv). Under the project, GHG emissions are calculated to increase over zero tons per year (tpy) on a mass basis and well exceed the applicability threshold of 75,000 tpy CO 2 

### e. ( EPA calculates CO 2 

### e emissions of 1,045,635 tpy in the initial phase of construction which is increased to 1,060,783 tpy after the final phase of construction ). EPA Region 6 implements a GHG PSD FIP for Texas under the provisions of 40 CFR § 52.21 (except paragraph (a)(1)). See 40 CFR § 52.2305.

As the permitting authority for regulated NSR pollutants other than GHGs, TCEQ has determined the modification is subj ec t to PSD review for non -GHG pollutants. Accordingly, under the circumstances of this project, the State will issue the non

- GHG portion of the permit and EPA will issue the GHG portion. 1



### EPA Region 6 applies the policies and practices reflected in the EPA document entitled “PSD and Title V Permitting Guidance for Greenhouse Gases” (March 2011) . C onsistent with that guidance, we have not required the applicant to model or conduct ambient monitoring for GHGs, and EPA Region 6 has not required any assessment of impacts of GHGs in the context of the additional impacts analys is or Class I area provisions. Instead, EPA has determined that compliance with the BACT analysis is the best technique that can be employed at present to satisfy the additional i mpacts analysis and Class I area requirements of the rules related to GHGs. We note again , however, that the project has triggered review for regulated NSR pollutants that are non- GHG pollutants under the PSD permit sought from TCEQ.

VI. Project Description

The proposed GHG PSD permit, if finalized, will allow DPEC to initiate a multi phase construction of a new 180 MW natural gas- fired Siemens 501 F- series combined- cycle combustion turbine generator, identified as CTG5, with a plant

- wide generating capacity of 1230-1300 MW , depending on ambient conditions. The phased construction for this project will be carried out in two stages. In the initial stage , Calpine proposes to construct a 168 MW natural gas- fired Siemens Model 501 FD2 combined- cycle combustion turbine as described above upon issuance of the PSD GHG permit. In the final stage, the FD2 combustion turbine will be upgraded to a 180 MW FD3 combustion turbine , this involves replacement of a limited number of internal compone nts of the turbine which will be accomplished in the timeframe of a routine outage. The modification includes improvements to the turbine blades, vanes and improved compressors seals that allow the turbine to regain generation capacity that is lost in the summer months due to hot ambient conditions. Calpine plans to install the turbine using the FD2 configuration to ensure the project is online and available to supply needed power to the Electric Reliability Council of Texas (ERCOT) grid for the summer of 2014 peak season. Additional time may be required to install the parts required for an FD3 configuration, and hence a two

-

1 U.S. Environmental Protection Agency, Question and Answer Document: Issuing Permits for Sources with Dual PSD Permitting Authorities , April 19, 2011,< http://www.epa.gov/nsr/ghgdocs/ghgissuedualpermitting.pdf > (April 2011)

.Calpine Corporation, Deer Park Energy Center Page 5 of 38 Deer Park, Texas (Harris County)


### phased construction period is required to avoid compromising the scheduled construction and installation of the combustion turbine.

Calpine intends to begin the upgrade of the Siemens 501 FD2

- series engine to the FD3

- series within an eighteen (18) month period following commercial operation of the FD2 series unit. Completion of construction of the initial project will occur the date that commercial operation of the FD2 phase of the project begins, or no later than eighteen (18) months after initial testing is completed in order to account for any additional work that may take place during the “shakedown period” that immediately follows first fire of the proposed turbine. The increased changes in CO 2 

### emissions due to this modification are presented in the calculations of the original application as submitted on September 1 , 2011. I t is calculated that the proposed combustion turbine is an FD3

- series engine will generate more CO 2 

### emissions than the FD2

- series ; however, the heat rate (in Btu/kWh) for the combined cycle process is about the same for both configurations. S ome or all of the steam produced from the new combustion turbine will either exhaust to a dedicated Heat Recovery Steam Generator (HRSG) to produce steam or be sold to a neighboring facility. The steam produced f rom the HRSG is then routed to an existing shared 200 MW steam turbine unit to produce electricity for sale to the ERCOT power grid

. Listed in the table below is a summary of the emissions for this project, a detailed analysis of the calculations can be found in the Appendix, Tables 1 through 8:

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

Potential Emissions (Mass Basis) TPY CO 2 e Potential Emissions TPY

CO 2 1,044,629 CO 2 1,044,629
CH 4 19.34 CH 4 406

N 2 O 1.93 N 2 O 599

SF 6 0.00018 SF 6 4.3 Total Potential Emissions (Mass Basis) 1,044,651 Total CO 2 e 1,045,635

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

Potential Emissions (Mass Basis) TPY CO 2 e Potential Emissions TPY

CO 2 1, 062
, 62 7 CO 2 1, 062
, 627
CH 4 19.67 CH 4 413

N 2 O 1.97 N 2 O 610

SF 6 0.00018 SF 6 4.3 Total Potential Emissions (Mass Basis) 1, 062 , 652 Total CO 2 e 1,06 3 ,650Calpine Corporation, Deer Park Energy Center Page 6 of 38 Deer Park, Texas (Harris County)



### VII. General Format of t he BACT Analysis

The BACT analyses was conducted in accordance with the “Top -Down” Best Available Control Technology Guidance Document outlined in the 1990 draft U.S. EPA New Source Review Workshop Manual , which outlines the steps for conducting a top -down BACT analysis. Those steps are listed below.

(1) Identify all potentially available control options;

(2) Eliminate technically infeasible control options;

(3) Rank remaining control technologies;

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

(5) Select BACT.

Also in accordance with the top-down BACT guidance, the BACT analyses also takes into account the energy, environmental, and economic impacts of the control options during step 4. Emission reductions may be determined through the application of available control techniques, process design, and/or operational limitations. Such reductions are necessary to demonstrate that the emissions remaining after application of BACT will not cause adverse environm ental effects to public health and the environment.

Each of the emission unit submitted in the PSD GHG application was evaluated separately in the top-down 5- step BACT analysis.

VIII. Applicable Emission Units S ubject to BACT

The following devices are subject to this GHG PSD permit:

• Natural Gas

- Fired Combined- cycle Combustion Turbine Generator ( CTG5) an d Heat Recovery Steam Generator (HRSG5)

• Fugitive Natural Gas emissions from piping components ( NG

- FUG )

• SF 6 

### Insulated Electrical Equipment (SF6

- FUG )Calpine Corporation, Deer Park Energy Center Page 7 of 38 Deer Park, Texas (Harris County)



### IX. GHG BACT for the Natural

- Gas Fired Combined -Cycle Combustion Turbine Generator (CTG5) and Heat Recovery System Generator (HRG5)

The new combined- cycle combustion turbine generator (CTG) is proposed to be as efficient, but with improved environmental controls compared to the other four existing CTG at the site. If approved, initially, a Siemens 501 FD2

- series combined- cycle combustion generator with a electrical generating capacity of approximately 168 MW will be constructed and will be upgraded to a FD3

- series with a electrical generating capacity of 180 MW within an 18-month period under terms of conditions of the permit. The FD3 upgrade includes improvements to the turbine blades and vanes and improved compr essor seals to allow the turbine to regain generation capacity that is lost during the summer months due to hot ambient conditions. The FD3

- series combustion turbine will generate more CO 2 

### emissions than the FD2

- series ; however the efficiency
, in terms of heat rate (in Btu/kWh) , is the same for both on a combined cycle basis. The CTG/HRSG unit will be fired exclusively with pipeline

- quality natural gas with a fuel sulfur content of up to 5 grains of sulfur per 100 dry standard cubic feet (gr S/100 dscf). For purposes of BACT, CTG5 and HRSG5 are treated as one emission unit.

EPA has reviewed Calpine ’s BACT analysis for the two -phase construction of a natural gas- fired combined- cycle combustion turbine generator and finds it sufficient in setting forth this proposed permit, as summarized below.

Step One: Identify All Potentially Available Control Technologies

As part of the PSD review, Calpine provides in the GHG permit application a 5

- step top -down BACT analysis for the new combustion turbine emission unit. In this analysis, the following technologies are identified in the BACT analysis: (A) the use of carbon capture and storage (CCS) including CO 2 

### capture/compression, CO 2 

### transport and CO 2 

### storage ; (B) Inherently lower -emitting processes, pra ctices, and designs which are further subdivided into: (1) Combustion turbine energy efficiency processes, practices and designs; (2) Heat recovery steam generator energy efficiency process, practices and designs; and (3) Plant

- wide energy efficiency processes, practices, and designs;

(A) Carbon Capture and Storage

For purposes of the BACT analysis, CCS is classified as an add -on pollution control technology for “ facilities emitting CO 2 

### in large concentrations, including fossil fuel- fired power plants, and for industrial facilities with high-purity CO 2 

### streams (e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement pro duction, and iron and steel manufacturing).” 2 

### CCS involves the separation and capture of CO 2 

### from the combustion process flue gas, the pressurizing of the captured CO 2 

### and then the transportation of the compressed CO 2 

### by pipeline or other means of transportation, if necessary, where it is injected into a long- term geological location.

2 U.S. Environmental Protection Agency, Office of Air Quality Planning and Standards, PSD and Title V Permitting Guidance for Greenhouse Gases , March 2011, < http:/www.epa.gov/nsr/ghgdocs/ghgpermittingguidance.pdf > (March 2011)Calpine Corporation, Deer Park Energy Center Page 8 of 38 Deer Park, Texas (Harris County)


### Several technologies are in various stages of development and are b eing considered for CO 2 

### separat ion and capture.

As it stands current ly, CCS technology and its components can be summarized in the table 3 

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

CCS Component CCS Technology

Capture Post

- combustion Pre

- combustion Oxy

- fuel combustion Industrial separation (natural gas processing, ammonia production)
Transportation Pipeline Shipping

Geological Storage Enhanced Oil Recovery (EOR) Gas or oil fields Saline formations Enhanced Coal Bed Methane Recovery (ECBM)
Ocean Storage Direct injection (dissolution type) Direct injection (lake type)

Mineral carbonation Natural silicate minerals Waste minerals CO 2 Utilization/Application Industrial Uses of CO 2 (e.g. carbonated products)



### For large, point sources, there are three types of capture configurations – pre-combustion capture, post-combustion capture, and oxy-combustion capture:

1) Pre -combustion capture implies as named, the capture of CO 2 

### prior to combustion. It is a technological option available to integrated coal gasification combined- cycle (IGCC) plants. In these plants, coal is gasified to form synthesis gas (syngas with key components of carbon monoxide and hydrogen). Carbon monoxide ( CO ) is reacted with steam to form CO 2 

### which is then removed and the hydrogen is then diluted with nitrogen and fed into the gas turbine combined- cycle

. 2) Post -combustion capture involves extracting CO 2 

### in a purified form from the flue gas following combustion of the fuel. Primarily for coal-fired power plants and electric generating units (EGU), other industries can benefit. Currently, all commercial postcombustion capture is via chemical absorption process using monoethanolamine (MEA) -based solvents. 4

3 Intergovernmental Panel on Climate Change (IPCC) Special Report, Bert Metz, Ogunlade Davidson, Heleen de Coninck, Manuela Loos and Leo Meye r (Eds.), Carbon Dioxide Capture and Storage (New York: Cambridge University Press, 2005), Table SPM.2, 8. < http://www.ipcc.ch/pdf/special -reports/srccs/srccs_wholereport.pdf > 4 Wes Hermann et al. An Assessment of Carbon Capture Technology and Research Opportunities - GCEP Energy Assessment Analysis, Spring 2005 . < http://gcep.stanford.edu/pdfs/assessments/carbon_capture_assessment.pdf >Calpine Corporation, Deer Park Energy Center Page 9 of 38 Deer Park, Texas (Harris County)


### 3) Oxy -combustion technology is primarily applied to coal-burning power plants where the capture of CO 2 

### is obtained from a pulverized coal oxy-fuel combustion in which fossil fuels are burned in a mixture of r ecirculated flue gas and oxygen rather than air. The remainder of the flue gas, that is not recirculated, is rich in carbon dioxide and water vapor, which is treated by condensation of the water vapor to capture the CO 2 

### . 5 

### When combusting coal with air (which is done in nearly all existing coal-burning power plants), nitrogen is formed as byproduct of the combustion and is present in high concentrations in the flue gas. Post- combustion capture of CO 2 

### is ess entially the separation of nitrogen and carbon dioxide, which can be done but at a high cost. However if there were no nitrogen present as in the case of oxy -combustion, then CO 2 

### capture from flue gas would be greatly simplified 6



### . It is implied that an optimized oxy-combustion power plant will have ultra- low CO 2 

### emissions as a result.

Once CO 2 

### is captured from the flue gas, CO 2 

### is compressed to 100 atmospheres (atm) or higher for ease of transport (usually by pip eline) into a storage area, in most cases, a geological storage area. It is also possible that CO 2 

### can be stored and shipped via all different modes of transportation via land, air and sea.

Geological storage of CO 2 

### involves the injection of compressed CO 2 

### into deep geologic formations (injection zones) overlain by competent sealing formations and geo logic traps that will prevent the CO 2 

### from escaping , there are five types of geologic formations that are considered : clastic formations; carbonate formations; deep, unmineable coal seams; organicrich shales; and basalt interflow zones

. There is a large b ody of ongoing research and field studies focused on developing better understanding of the science and technologies for CO 2 

### storage. 7



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

Methods techniques and systems to increase energy efficiency is the key GHG reducing direction that falls under “lower polluting processes/practices.” Use of inherently lower

emitting technologies, including energy efficiency measures, represents an opportunity for GHG reductions i n these types of BACT reviews. In some cases, a more energy efficient process or project design may be used effectively alone; where in other cases, energy efficient measure may be used effectively in tandem with end -of- stack controls to achieve additional control criteria p ollutants. Apply ing the most energy efficient technologies at a

source should in most cases translate into fewer overall emissions of all air pollutants per unit of energy produced. Selecting technologies, measures and options that are energy efficient translates not only in the reduction of emissions of the particular regulated NSR air pollutant undergoing BACT review, but it also may achieve collateral reductions of emissions of other pollutants, as well as GHGs.

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

- Fuel Combustion”, August 2008. < h ttp://www.netl.doe.gov/publications/factsheets/rd/R&D127.pdf > 6 Herzog et al., page 4-5
7 U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory Carbon Sequestration Program: Technology Program Plan
, , February 2011

< http://www.netl.doe.gov/technologies/carbon_seq/refshelf/2011_Sequestration_Program_Plan.pdf >Calpine Corporation, Deer Park Energy Center Page 10 of 38 Deer Park, Texas (Harris County)



### Inherently lowering emitting processes, practices, and designs is divided into two basic categories. The fir st category of energy efficient improvement options includes improvement options or processes that maximize the energy efficiency of the individual emissions unit. The second category of energy efficiency improvements includes options that could reduce emissions is more appropriate for new Greenfield facilities that includes equipment or processes that have the effect of lowering emissions by improving the utilization o f thermal energy and electricity that is generated and used on the site.

(1) In the case of combustion turbine energy efficiency processes, practices and designs
, one of the current efficient ways of generating electricity from a natural gas fuel source is t hrough a combined- cycle design. For fossil fuel technologies, efficiency ranges from 30 to 50 percent higher heating value (HHV). A typical coal- fired Rankine cycle power plant has a base load efficiency of approximately 30% HHV while a modern F- Class nat ural gas fired combined- cycle turbine generator operating under optimal conditions has a baseload efficiency of approximately 50% HHV.

The combined- cycle unit operates based on a combination of two thermodynamic cycles: the Brayton and Rankine cycles. The combustion turbine operates on the Brayton cycle while the HRSG and steam turbine operate on the Rankine cycle. The combination of both of these cycles contributes to the higher efficiency of the combined- cycle power plants.

While there are number of modifications to a combustion turbine generator that exist, Calpine has identified the following additional processes, practices and designs that are applicable for the combined combustion turbine generator: (a) Periodic Burner Tuning : The modern F-Class combustion turbines have a regularly scheduled maintenance program for optimal efficiency of the turbine. Three basic maintenance levels exist: combustion inspections, hot gas path inspections, and major overhauls with combustion inspections being the most common. As a part of the maintenance activity, combustors are tuned to restore the highly efficient low -emission operation.

(b) Reduction in Heat Loss: Use of insulation blankets help minimize heat loss at cooler temperatures , as well as protect personnel and nearby auxiliary equipment, insulation blankets will be deployed around the combustion turbine casing. Uses of the blankets immediately minimize any heat loss from the combustion turbine shell and increase the overall efficiency of the machine.

(c) Instrumentation and Controls : Operation of the combustion turbine is all under automatic control via the distributed control system (DCS) . DCS oversees all aspects of the operation including fuel feed and burner operations to achi eve efficient low -NOx combustion. The control system monitors the operational parameters of the unit and modulates the fuel flow and turbineCalpine Corporation, Deer Park Energy Center Page 11 of 38 Deer Park, Texas (Harris County)


### operations to achieve optimal high- efficiency low

- emission performance for full

- load and part -load conditions.

Calpine proposed the use of a new combined-cycle combustion turbine, which is more energy efficient compared with the emissions from a simple

- cycle gas turbine in table below.

GHG Control Technologies Emission Rate (lb CO 2 

### / MWh) New combined

- cycle gas CT G 774 Existing combined

- cycle CT G 824

- 996 Simple cycle CT

~ 1,319

Calpine has elected to construct the Siemens 501F CTG/HRSG with a CTG rated at 180 MW nominal and a duct burner- fired heat recovery s team generator (HRSG). The maximum design rated capacity of the duct burners will be 725 million British thermal units per hour (MMBtu/hr). The CTG will be fire d exclusively with pipeline

quality natural gas. The Si emens 501F turbine was chosen for DPEC because it has the appropriate size needed for this facility
, DP EC is already equipped with four (4) operating Siemens 501F turbines , and several Siemens 501F turbines are ready for use in Calpine’s fleet . In comparison with other turbines, EPA has identified the several high energy efficient models commercially av ailable around the 180 MW range. For a CTG, efficiency can be determined by the heat rate, which can be expressed as Btu of the fuel combusted divided by kWh of electricity produced (Btu/kWh). The lower the overall numbers, the less heat needed to produce a unit of electricity. Using data provided by the manufacturer for CTG under ISO test conditions, EPA identified the following models:

Manufacturer Model Net Plant Output (kW) 8 LHV 9 ISO Heat Rate (Btu/kWh) % Net ISO Plant Efficiency (ISO) Rolls

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

- Royce 2 x Trent 60 WLE ISI 153 7,281 44.5 Mitsubishi MPCP1 (M501) 167 7,000 46.3

Siemens SCC6

- 2000F 1x1 (FD2/FD3) 171 7,007 46.2

Hitachi 206FA 215 6,800 47.7



### As listed in the table above, the Siemens 501F- series turbine has a calculated efficiency of 46.2 % which is as efficient as or more efficient than the other listed natural gas-fired combined- cycle combustion turbines (efficiencies tend to range from 40 % to 60% with larger kW -producing turbines typically having the highest

8 Net plant output is calculated using specific design (i .e., ISO) test criteria
9 Lower heat rate is determined by subtracting the heat of vaporization of water from the higher heating value.Calpine Corporation, Deer Park Energy Center Page 12 of 38 Deer Park, Texas (Harris County)


### efficiencies) 10 

### . Since age and ambient and operating conditions will affect efficiency, the heat rate numbers presented above are used to compare efficiency between turbine models and do not translate directly into permit limitations.

(2) For the h eat recovery steam generator , energy efficien t process es , practices and design include :
a. Heat Exchanger Des ign : Heat exchanger design is optimized to provide maximum heat exchange transfer from the waste heat of the combustion turbine exhaust using multiple thin

- walled tubes filled with fluid and at the same time minimizing the overall size of the HRSG.

b. Insulation : Similar to the combustion turbine practic e, use of insulation to min imize heat loss to the surroundings is used to help improve the overall efficiency of the HRSG. Insulation is applied to the HRSG panels that make up the shell of the unit, to the high- temperature steam and water lines, and typically to the bottom portion of the stack.

c. Minimizing Fouling of Heat Exchange Surfaces : Since HRSGs are made u p of numerous tubes within the sh ell of the unit are used to generate steam from the combustion t urbine, the tubes and their extended surfaces must be kept as clean as possible to maximize heat transfer. Fouling occurs from the constituents within the exhaust gas stream. To minimize fouling, filtration of the inlet air to the combustion turbine is per formed . Additionally, cleaning of the tubes is performed during periodic outages.

d. Minimized Vented Steam and Repair of Steam Leaks : Routine maintenance checks will include inspection of valves and pipes for steam leaks and re

ducting steam escaping which would result in large losses in efficiency in power generation.

(3) Plant -wide energy efficient processes include fuel gas preheating, drain operation, multiple combustion/HRSG trains and boiler feed pump fluid drivers.

a. Fuel gas preheating : The overall efficiency is increased with increased fuel inlet temperatures . F or the F

- class combusti on turbine, the fuel gas is heated with high temperature water from the HRSG.

b. Drain operation : Drains are required to allow for draining the equipment for maintenance (maintenance drains) and allow condensate to be removed from the steam piping and drains for operation (operation drains) and prevent loss of energy from the cycle.

10 United States Environmental Protection Agency, Combined Heat and Power Partnership, Technology Characterization: Steam Turbines , December 2008, p.8

- 9

< http://www.epa.gov/chp/documents/catalog_chptech_steam_turbines.pdf >Calpine Corporation, Deer Park Energy Center Page 13 of 38 Deer Park, Texas (Harris County)



### c. Multiple combustion turbine/HRSG trains : Multiple combustion turbine/HRSG tra ins help with part-load operation and allow for higher overall plant part-load efficiency by shutting down trains operating at less efficienc y part -load conditions and ramping up the remaining train(s) to highefficiency full -load operations.

d. Boiler feed pump fluid drivers : Boiler feed pumps are used as a means to impart high pressure on the working fluid. The pumps require considerable power and to minimize the power consumption at part- loads, fluid drives are being used to minimize power consumption at p art -load at part-load, improving the facility’s overall efficiency.

Step Two: Eliminate Technically Infeasible Control Options Based on the information reviewed for this BACT analysis, while there are some portions of CCS that are technically infeasible, EPA has determined that overall Carbon Capture and Storage (C C S) technology is technologically feasible at this source . Listed below is a summary of those CCS components that are technically feasible and those CCS components that ar e not technically feasible for DPEC

. Step Two Summary for CCS for Calpine DPEC CCS Component CCS Technology Technical Feasibility

Capture Post

- combustion Y Pre

- combustion N Oxy

- fuel combustion N Industrial separation (natural

gas processing, ammonia production) N

Transportation Pipeline Y Shipping Y

Geological Storage Enhanced Oil Recovery (EOR) Y

Gas or oil fields N * Saline formations N* Enhanced Coal Bed Methane Recovery (ECBM) N*

Ocean Storage Direct injection (dissolution type) N*

Direct injection (lake type) N*

Mineral carbonation Natural silicate minerals N* Waste minerals N* Large scale CO 2 

### Utilization/Application N*Calpine Corporation, Deer Park Energy Center Page 14 of 38 Deer Park, Texas (Harris County)

* Both geologic storage and large scale CO 2 utilization technologies are in the research and development phase in the United States and currently commercially unavailable. 11



### Step Three: Rank Remaining Control Technologies by Control Effectiveness

The remaining technically feasible options for controlling CO 2 

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

1) Carbon Capture and Storage (CCS)

CCS could enable large (> 85%) reduction of CO 2 

### emissions from fossil fuel combustion in power generation, industrial processes and synthetic fuel production 12 

### and is the best known method of reducing CO 2 

### e emissions into the atmosphere.

2) Inherently lower

- emitting processes, practices, and designs which are further subdivided into:

a. Combustion turbine energy efficiency processes, practices and designs; b. Heat recovery steam generator energy efficiency process, practices and designs; and

c. Plant

- wide energy efficiency processes, practices, and designs;

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

Company /

Location Process Description Control Device BACT Emission Limit / Requirements Year Issued Reference

Lower Colorado River Authority (LCRA), Thomas C. Ferguson Plant

Horseshoe Bay, TX combined

cycle combustion turbine and heat recovery steam generator Energy Efficiency/ Good Design & Combustion Practices Combustion turbine annual net heat rate limited to 7,720 Btu/kWh (HHV)

GHG BACT limit of 0.459 tons CO 2 /MWh (net)

365

- day average, rolling daily for the combustion turbine unit

Fugitive methane emissions and SF6 emissions are monitored and maintained using 2011 PSD

- TX -1244- GHG

11 U.S. Department of Energy, Carbon Sequestration Program: Technology Pr ogram Plan
, page 20

- 23
12 I EA Energy Technology Essentials, “ CO2 Capture and Storage ,” December 2006 < http://www.iea.org/techno/essentials1.pdf > (December 2006)Calpine Corporation, Deer Park Energy Center Page 15 of 38 Deer Park, Texas (Harris County)
best practice standards.

Palmdale Hybrid Power Plant Project

Palmdale, CA combined

cycle combustion turbine and heat recovery steam generator , plus a 50 MW solar array* Energy Efficiency/ Good Design & Combustion Practices , and use of the solar array Combustion turbine annual net heat rate limited to 7,319 Btu/kWh (HHV)

GHG BACT limit of 0.387 tons CO 2 /MWh (net)

365

- day average, rolling daily for the combustion turbine unit

Auxiliary boiler and heater heat input limit of 110 MMBtu/hr and 500 hours operation on 365

- day rolling total

SF6 Circuit Breakers BACT limit of 9.56 tpy CO 2 e 2011 SE 09

- 01

Calpine Russell City Energy

Hayward, CA 600 MW combined

cycle power plant Energy Efficiency/ Good Design & Combustion Practices Combustion t urbine Operational limit of 2,038.6 MMBtu/kWh

Fire Pump Diesel Engine GHG BACT limit of 7.6 tpy CO 2 e

SF6 Circuit Breaker annual limit of 39.3 tpy 

### CO 2 e 2011 15487

PacifiCorp Energy

Lakeside, UT combined

cycle turbine Energy Efficiency/ Good Design & Combustion Practices C ombustion turbine BACT limit of 950 lb CO 2 e/ MWh 2011 DAQE

I N0130310010

- 11Calpine Corporation, Deer Park Energy Center Page 16 of 38 Deer Park, Texas (Harris County)

Kennecott Utah Copper Repowering

South Jordan, UT 275 MW combined combustion Energy Efficiency/ Good Design & Combustion Practices Combustion turbine BACT limit of 1,162,552 tpy CO 2 e rolling 12

- month period 2011 DAQE

IN105720026-11

*Palmdale is unique as the applicant proposed to include, and thus the BACT analysis and eventual limit i ncluded, use of a solar component that includes up to 50 MW of potential solar thermal power generation, which represents an inherently lower

- emitting technology for th at proposed facility.


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

EPA Region 6 reviewed Calpine ’s CCS cost estimate and believes the overall cost estimation is financially prohibitive due to the overall cost of GHG control strategies. CCS costs include install ation and operation of carbon capture controls and construction of a new pipeline to transport the CO 2 

### approximately 1 5 miles 13 

### (24 kilometers) to the closest site with recognized potential for geological storage of CO 2 

### , which is the enhanced oil recovery (EOR) operations located at the Hastings oil field, southwest of Houston, Texas.

The bulk of the cost for CCS is attributable to the post -combustion capture and compression system , and the additional operating cost estimates are listed in detail in Table 9 of the Appendix. As it stands , the estimated cost to construct and install a CCS system to the turbin e is approximately $113 million 14 

### , around 50% of the cost of the of a typical gas-fired combined cycle turbine without CCS. Additionally Calpine , using EPA guidance documents, has provided

an estimation that the overall average operating cost s for the entire CCS system could add approximately $ 80 million 

### annually (See Appendix, Table 9)

. While Calpine has provided information suggesting that annual operating costs for CCS could increase overall costs by as little as 20% 15



### , EPA notes that Calpine arrives at this figure by including the lowest estimated cost for each and every step of the CCS process. Calpine’s analysis also included an estimate of the annual operating costs for CCS if the highest costs were needed for each and every step of the CCS process, and estimated the annual operating cost increase to be approximately 58%. Since it is unlikely that either the lowest costs or the highest costs could be achieved for each and every step of the process, EPA has instead relied upon the average c osts and determined that the average combined costs of installation and operation of a CCS system still makes CCS economically infeasible for this project

.
In addition, EPA notes that implementing CCS would result in energy penalty simply because the CCS process will use energy produced by the plant. This may , in turn , potentially increase s the natural gas fuel use of the plant, with resulting increases in emissions of non -GHG pollutants,
to overco me these efficiency losses , or would result in less energy being produced for use on the

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

< http://www.beg.utexas.edu/gccc/miocene/ > 14 Natural Gas Combined

- Cycle Plants With and Without Carbon Capture & Sequestration , DOE

< http://www.netl.doe.gov/energy

- analyses/pubs/deskreference/B_NGCC_051507.pdf > 15 The minimum cost factor found for implementation/operation of the CO2 capture systems within the cost

- related information reviewed for CCS technology was found from the “Properties” section of the Greenhouse Gas Mitigation Strategies Database ( last accessed April 2010) (< http:/ghg.ie.unc.edu:8080/GHGMD B/#data > ), which was obtained through the EPA GHG web site (< http://www.epa.gov/nsr/ghgpermitting.html > ).Calpine Corporation, Deer Park Energy Center Page 17 of 38 Deer Park, Texas (Harris County)


### grid . The Report of the Interagency Task Force on Carbon Capture and Storage has estimated that an energy penalty of as much as 15% would result from inclusion of CO 2 

### capture ( Reference 4, page A-14) and an overall loss of energy efficiency of approximately 7% 16 

### . It was concluded in the same report 17 

### that while CCS is technically feasible at this time
, the costs for the capture and compression of CO 2 

### remains the biggest barrier to widesp read commercialization of CCS.

Therefore, CCS has been eliminated as BACT for this particular project based upon research and analysis showing that there is a significant negative economic impact due to the additional projected capital costs of implementing and operating CCS as the control technology at the proposed combustion turbine. In addition, the potential negative environmental and energy impacts of increased non -GHG pollutant emissions, the overall loss in energy efficiency , and/or decreased energy produced for use on the grid also provide a basis for excluding CCS as BACT for this facility.

Step Five: Select BACT Calpine intends to initially construct and install a n FD2 -series combustion turbine with plans to modify it within an eighteen (18) month period to the FD3-series combustion turbine. The proposed BACT limits are in terms of efficiency measured in units of Btu of fuel energy consumed in order to generate a kilo watt of electric energy (Btu/ kWh). S ince CCS has been eliminated as BACT for CTG5, then BACT for the new combined-c ycle combustion turbine is the high efficiency processes, practices and designs which are made enforceable by output- based and annual BACT limits. The average heat rate in terms of Btu/ kWh (HHV) will be the same for the FD2 configuration as the FD3 configuration when in continuous operation, since the FD2- series and FD3 -series combustion tur bines have the same efficiency. However, the FD3 configuration provides greater output at high ambient temperatures during base load periods. Therefore, for the FD3, the potential annual electric generation ( MWh ) and fuel usage, as well as corresponding GHG emissions, will be higher on an annual basis, maximum CO 2 

### e potential emissions will increase by only two percent ( 2 %) from 1,045,635 tons for the FD2- series to 1,063,650 tons of CO 2 

### e for the FD3 -series combustion turbine (see Appendix Calculations, Tables 1 and 2).

a) Degradation Consideration for combined

- cycle combustion turbine generator efficiency

To establish an enforceable BACT condition that can be achieved over the life of the facility, it is important that the permit limit accounts for the anticipated degradation of the equipment over time between regular maintenance cycle s. A 48,000-operating-hour degradation curve provided by the manufacturer, Siemens , reflect s anticipated recoverable and non-recoverable degradation in heat rate between major maintenance overhauls of approximately five percent (5 %). The results of the degradation curves differentiate between “recoverable” and “non

- recoverable” degradation. Components of the turbine and combustion system subject to high thermal and mechanical stress are designed for periodic refurbishment or replacement. The turbine components most affected by the combustion process include combustion liners, fuel nozzle assemblies, transition pieces, turbine nozzles, stationary shrouds, and turbine buckets. These components are often referred to as “hot gas path” components. “Recoverabl e” degradation is

16 IPCC Special Report of the Interagency Task Force on Carbon Capture and Storage (August 2010)
17 Ibid. , p. 33

- 51Calpine Corporation, Deer Park Energy Center Page 18 of 38 Deer Park, Texas (Harris County)


### mostly attributable to turbine blade fouling due to impurities in intake air and fuel. This type of degradation can be mitigated through inspection programs, on- line turbine water washes, instrument calibration, and other maintenance acti vities. “Non

- recoverable” degradation is mainly attributed to blade surface roughness, erosion and blade tip rubs and cannot be restored upon a maintenance overhaul.

The manufacturer’s degradation results only account for the anticipated degradation within the first 48,000 hours of the gas turbine’s useful life; they do not reflect any potential increase in this
rate of degradation which might be expected after the first major overhaul and/or as the equipment approaches the end of its useful life. Furth er, the projected 5% degradation rate represents the average, and not the maximum or guaranteed rate of degradation for the turbines. Therefore, Calpine DPEC proposes that, for the purposes of deriving an enforceable BACT limit on the proposed facility’s heat rate, gas turbine degradation may be reasonably be estimated at six percent (6%) of the facility’s heat rate.

Finally, in addition to the heat rate degradation from normal wear and tear on the turbines, DPEC also suggested a compliance margin based on potential degradation in other elements of the combined- cycle plant that would cause the overall plant heat rate to rise (i.e., cause efficiency to fall). DPEC proposed a 3% degradation rate to account for these factors. The other elements of the combined- cycle plant include the following:

• Degradation in Turbine Exhaust Flow: The gas turbine manufacturer’s degradation curves predict potential recoverable and non- recoverable degradation in gas turbine exhaust flow over the 48,000- maintenance cycle . This degradation in exhaust flow could result in a direct reduction in the ability of the steam turbine to generate power, which could further degrade the plant’s overall efficiency. While degradation in the exhaust flow is expected to be partially offset by degradation in exhaust temperature (which raises over the maintenance cycle), this offset is not expected to make up for anticipated degradation in the reduction in steam turbine power as a result of reduced exhaust flow.

• Degradation in Performance of Steam Turbine and Other Equipment: Degradation in the performance of the heat recovery steam generator, steam turbine, heat transfer, cooling tower, and ancillary equipment such as pumps and motors is also expected to occur over the course of a major maintenance cycle.

b) BACT Limit:

By establishing th e energy efficiency for the combined- cycle turbine as BACT, permit conditions must be developed to ensure that Calpine DPEC installs and operate an energy efficient tu rbine in an energy efficient manner.

EPA has developed an emission limit in tons of GHG per MWh produced that must be met during the in i tial and periodic stack test ing. Since ambient conditions can affect the efficiency during a stack test and cannot be predicted at this time, the emission limit is being set using International Organization for Standardization (ISO) conditions. ISO 3977- 2 is corrected for the following conditions:Calpine Corporation, Deer Park Energy Center Page 19 of 38 Deer Park, Texas (Harris County)



### • Ambient Dry Bulb Temperature: 59 o 

### F

• Ambient Relative Humidity: 60%

• Baromet ric Pressure: 14.69 psia

• Fuel Lower Heating Value: 20,647 Btu/lb

• Fuel HHV/LHV Ratio: 1.1086

1) BACT Limit for the Combined

- Cycle Combustion Turbine Generator To ensure Calpine DPEC operates its facility to minimize greenhouse gases, EPA proposes to
esta blish an CO 2 

### emission limit/MWh

. To determine an appropriate heat rate limit for continuous operations, the baseline annual average heat rate (HHV) of 6 ,852 Btu/kWh is used with the 3.3% design margin taken into account followed by a six percent (6%) performance margin reflecting effi ci ency losses due to equipment degradation prior to maintenance overhauls, and then a three percent (3%) degradation margin reflecting the variability in operation in auxiliary plant equipment due to use over time , resulting in the annual average heat rate (HHV) of 7,728 Btu/kWh (See Appendix, Table 4). Additionally, t o determine the heat input limit for this facility, the heat rate is calculated assuming that all steam generated in the heat recovery steam generator is used to generate electricity in the exi sting on-site steam turbine even though there are periods when some or all of the generated steam is sold to a neighboring facility rather than sent to the on- site steam turbine.

The proposed GHG PSD pe rmit, if approved , requires an output-based BACT limit of 0.460 tons CO 2 

### /MWh (net) for both the FD2 and FD3 engines on a 30-day rolling average and an annual GHG BACT limit of 1,045,635 tons CO 2 

### e per year for the FD2 series engine and 1,063,650 tons of CO 2 

### e per year for the FD3 series engine on a 365-day rolling average. This is with the understanding that the FD2 series will be upgraded to the FD3 series within a statutory timeframe of 18 months under the conditions of this permit. In establishing an enforceable BACT limit over the lifetime of the turbine, Calpine accounted for the anticipated degradation of the equipment over time between regular maintenance cycles , as discussed in this section

. (See Appendix, Table 4 for calculations)

c) Operating Conditions

Listed below are the operating conditions and work practice for the heat recovery steam generator and the plant- wide operations that ensure that CTG5 is operating at the highest possible efficiency.

1) HRSG 5 Unit Operating Conditio ns The Heat Recovery Steam Generator (HRSG 5 ) energy efficiency processes, practices and designs considered include: i. Energy efficient heat exchanger design. In this design, each pressure level incorporates an economizer section(s), evaporator section, and superheater section(s);

ii. Addition of insulation to the HRSG5 panels, high- temperature steam and water lines and to the bottom portion of the stack;Calpine Corporation, Deer Park Energy Center Page 20 of 38 Deer Park, Texas (Harris County)



### iii. Filtration of the inlet air to the combustion turbine and periodic cleaning of the tubes (performed at leas t every 18 months) is performed to minimize fouling; and

iv. Minimization of steam vents and repairs of steam leaks.

2) Plant Wide Operating Conditions Within the combined- cycle power plant, several plant- wide , overall energy efficiency processes, practices and designs are included as BACT requirements because the a dditional operating conditions /practices help maintain the efficiency of the turbine

. The requirements include: i. Fuel gas preheating. For the F- class combusti on turbine based combined- cycle , the fuel gas is pre

- heated to temperature of approximately 300 o 

### F with high temperature water from the HRSG;

ii. Drain operation. Operation drains are controlled to minimize the loss of energy from the cycle but closing the dra ins as soon as the appropriate steam conditions are achieved;

iii. Multiple combustion turbine/HRSG trains. Multiple combustion turbine/HRSH trains help with part-load operation. A higher overall plant part- load efficiency is achieved by shutting down trains o perating at less efficient part -load conditions and ramping up the remaining train(s) to high- efficiency full -load operation;

iv. Boiler feed pump fluid drives. To minimize the power consumption at part- loads, the use of fluid drives or variable-frequency dri ves are used to minimize the power consumption at part-load conditions;

d) BACT Compliance: For both the FD2 and FD3

- series , the combined- cycle combustion turbine unit is designed with a number of features to improve the overall efficiency. The additional combustion turbine design features include:

1. Inlet evaporative cooling to utilize water to cool the inlet air and thereby increasing the turbine’s efficiency ;

2. Periodic burner tuning as part of a regularly scheduled maintenance program to help ensure a more reliable operation of the unit and maintain optimal efficiency ;

3. Insulation blankets are utilized to minimize the heat loss through the combustion turbine shell and help improve the overall efficiency of the machine; and

4. Hydrogen will be used to cool the generators resulting in a lower electrical loss and higher unit efficiency.Calpine Corporation, Deer Park Energy Center Page 21 of 38 Deer Park, Texas (Harris County)


### Calpine DPEC’s proposed method to demonstrate compliance w ith the CO 2 

### emission limit of 0.421 tons of CO2 per MWh (net) 18 

### established as BACT by using fuel flow meters to monitor the quantity of fuel combusted in the electric generating unit and performing periodic scheduled fuel sampling pursuant to 40 CFR 75.10( 3)(ii) and the procedures listed in 40 CFR 75, Appendix G. Results of the fuel sampling will be used to calculate a site

- specific Fc factor, and that factor will be used in the equation below to calculated CO 2 

### mass emissions. In conjunction with the flow metermethodology , Calp ine will determine the CO 2 

### hourly emission rate and CO 2 

### mass emissions using an O 2 

### monitor pursuant to 40 CFR Subpart 75 and appendix F of 40 CFR Subpart 75. The proposed permit also includes an alternative compliance demonstration method in which Calpine DPEC may install, calibrate, and operate a CO 2 

### CEMS and volumetric stack gas flow monitoring system with an automated data acquisition and handling system for measuring and recording CO 2 

### emissions. To demonstrate compliance with the CO 2 

### BACT limit of 0.460 tons of CO 2 

### per MWh (net) using CO 2 

### CEMS, the measured hourly CO 2 

### emissions are divided by the net hourly energy output and averaged daily.

Currently, the four existing natural gas- fired turbines at Deer Park utilize fuel flow m eters and monthly GCV (Gross Calorific Value) sampling in order to comply with the Acid Rain quality assurance and monitoring requirements of 40 CFR 75, Appendix D and G. The proposed natural gas- fired turbine identified as CTG5/HRSG5 will also comply wit h the fuel flow metering andGCV sampling requirements listed in Appendix D. Calpine DPEC proposes to determine a sitespecific Fc factor using the ultimate analysis and GCV in equation F -7b of 40 CFR 75, Appendix F. The site

- specific Fc factor will be r e-determined annually in according to 40 CFR 75, Appendix F, §3.3.6.

The equation for estimating CO 2 

### emissions as specified in 40 CFR 75.10(3)(ii) is as follows:



### W CO 2 

### = ( Fc × H × Uf × MW CO 2 

### )/2000

Where: W CO2 = CO 2 emitted from combustion, tons/hour MW CO2 = molecular weight of CO 2 , 44.0 lbs/mole Fc = Carbon

- based Fc

- Factor, 1040 scf/MMBtu for natural gas or site

- specific Fc factor H = hourly heat input in MMBtu, as calculated using the procedure in 40 CFR 75, Append ix F, §5 Uf = 1/385 scf CO 2 /lb

- mole at 14.7 psia and 68 °F


### Calpine DPEC is subject to all applicable requirements for fuel flow monitoring and quality assurance pursuant to 40 CFR 75, Appendix D, which includes:

• Fuel flow meter - meets an accuracy of 2.0%, required to be tested once each calendar quarter pursuant to 40 CFR 75, Appendix D, §2.1.5 and §2.1.6(a))

• Gross Calorific Value (GCV) - determine the GCV of pipeline natural gas at least once per calendar month pursuant to 40 CFR 75, Appendix D, §2.3.4.1

Additionally, this approach is consistent with the CO 2 

### reporting requirements of 40 CFR 98, Subpart D- GHG Mandatory Reporting Rule for Electricity Generation. Furthermore, Calpine DPEC proposed CO 2 

### monitoring method is consistent with the recently proposed New Source

18 Output- based limits will be based on ton of CO 2 versus ton of CO 2 e because all emissions determined by monitoring methodology in accordance to 40 CFR Part 75 are done in lbs of CO 2 as opposed to lbs of CO 2 e.Calpine Corporation, Deer Park Energy Center Page 22 of 38 Deer Park, Texas (Harris County)


### Performance Standards, Subpart TTTT- Standards of Performance for Greenhouse Gas Emissions for Electric Utility Generating Units (40 CFR 60.5535(c)) which allows for electric generating units firing gaseous fuel to determine CO 2 

### mass emis sions by monitoring fuel combusted in the affected electric generating unit and using a site specific Fc factor determined in accordance to 40 CFR 75, Appendix F.

The calculated hourly CO 2 

### concentration result for emission point, CTG5/HRSG5 , is required to be compared to the measured hourly CO 2 

### concentration from the CO 2 

### emission monitor. If the mean difference between the calculated and measured CO 2 

### concentration result is greater than 10%, Calpine shall review the emission units and monito ring instrumentation operational performance. This comparison is generally similar to the Relative Accuracy Test Audit (RATA) trial run standards provided in 40 CFR Part 75(E)(2). From this review, any corrective measures taken are to be identified, recorded, including the reason for the CO 2 

### emissions difference and corrective measures completed within 48 hours of the corrective measures being taken. If Calpine DPEC chooses to install a nd operate the CO 2 

### CEMS equipped with a volumetric stack gas monitoring system, the CO 2 

### concentration calculation and mean difference comparison is no longer a requirement and the applicant shall rely on the data from the CO 2 

### CEMS for compliance purposes.

The emission limits associated with CH 4 

### and N 2 

### O are calculated based on emission factors provided in 40 CFR Part 98, Table C- 2 and the actual heat input (HHV). Comparatively, the emissions from CO 2 

### contribute the most (greater than 99%) to the overall emissions from the CTGs and; therefore, additional analysis is not required for CH 4 

### and N 2 

### O. To calculate the CO 2 

### e emissions, the draft permit requires calculation of the emissions based on the procedures and Global Warming Potentials (GWP) contained in the Greenhouse Gas Regulations, 40 CFR Part 98, Subpart A, Table A-1. Records of the calculations would be required to be kept to demonstrate compliance with the emission limits on a 365- day average, rolling daily.

An initial stack test demonstration will be required for CO 2 

### emissions from emission unit. An initial stack test de monstration for CH 4 

### and N 2 

### O emissions are not required because the CH 4 

### and N 2 

### O emission are approximately 0.09% of the total CO 2 

### e emissions from the CTGs and are considered a de minimis level in comparison to the CO 2 

### emissions.

For s tartup and shutdown operating scenario s for the proposed CTG, BACT will be achieved by minimizing the duration of the start -up and shutdown events, consistent with market demands, and by engaging the pollution control equipment (e.g., the SCR system in combined- cycle ) as soon as practicable, based on vendor recommendations and guarantees. During periods of startup and shutdown, the permittee must record the time, date, fuel heat input (HHV) in MMBtu/hr and the duration of each startup and shutdown event. All emissions during startup and shutdown are minimized by limiting the durati on of operation. The estimated 70 tons/hour (See calculations in Table 5 of the Appendix) illustrate that startup and shu td own emissions are lower than “normal” emissions and are accounted fo r in the Annual Facility Emissions (Table 1 of Appendix). To demonstrate compliance with the startup and shutdown emissions, Calpine shall record the time, date, fuel heat input and duration of each startup and shutdown event. The duration of operation during startup and shutdown are defined as follows:Calpine Corporation, Deer Park Energy Center Page 23 of 38 Deer Park, Texas (Harris County)



### 1. A startup of CTG5 is defined as the period that begins when there is measureable fuel flow to the CTG5 and ends when the CTG5 load reaches 6 0 percent. A startup for each CTG5 is limited to 480 minutes. 2. A sh utdown of each CTG5 is defined as the period that begins when CTG5 load falls below 60 percent and ends when there is no longer measureable fuel flow to CTG5. A shutdown for CTG5 is limited to 180 minutes.

Under draft terms, records of all emission s calcu lations for startup and shutdown events shall be kept on-site for a period of 5- years. After review of the submitted materials, EPA agrees with and adopts Calpine’s BACT analysis for the natural gas- fired combined- cycle combustion turbines.

X. GHG BACT for the Fugitive Emission Sources (NG

- FUG)

Step One: Identify All Potentially Available Control Technologies The control technology for process fugitive emissions of GHGs are :

• Leakless Technology

• Instrument L eak detection and repair (LDAR) programs

• Remote Sensing

• Auditory, Visual, and Olfactory (AVO) Monitoring

Step Two: Eliminate Technically Infeasible Control Options

• Leakless Technology – Leakless technology valves may be incorporated in situations where highly toxic or otherwise hazardous materials are present. Likewise, some technologies, such as bellows valves, cannot be repaired without a unit shutdown. Because natural gas is not considered highly toxic nor a hazardous material, th is gas do es not warrant the risk of unit shutdown for repair, and there fore leakless valve technology for fuel lines is considered technically impracticable.

• Instrument LDAR Programs – Is considered technically feasible

.

• Remote Sensing – Is considered technically feasible

.

• AVO Monitoring – Is considered technically feasible.
Step Three: Rank Remaining Control Technologies by Control Effectiveness Instrument LDAR programs and the alternative work practice of remote sensing using an infrared camera have been determined by EPA to be equivalent methods of piping fugitive controls. 19 

### The most stringent LDAR program, 28LAER, provides for 97% control credit for valves, flanges, and connectors.

As

- observed AVO methods are generally somewhat less effective than instrument LDAR and remote sensing, since they are not conducted at specific intervals. However, since pipeline natural gas is odorized with very small quantities of mercaptan, as-observed olfactory observation is a very effective method for identifying and correcting leaks in natural gas systems.

19 73 FR 78199

- 78219, December 22, 2008.Calpine Corporation, Deer Park Energy Center Page 24 of 38 Deer Park, Texas (Harris County)


### Due to the pressure and other physical properties of plant fuel gas, as-observed audio and visual observations of potential fugitive leaks are likewise moderately effective.

Step Four: Evaluate Top Control Alternatives Although instrument LDAR and/or remote sensing of piping fug itive emissions in natural gas lines may be somewhat more effective than as -observed AVO methods, these methods are not economically practicable for GHG control from components in fuel gas service. The incremental GHGs controlled by implementation of the 28LAER or a comparable remote sensing program is less than 60 tons CO 2 

### e per year, or less than 0.0001% of the total project’s proposed CO 2 

### e emissions.

Step Five: Select BACT EPA has reviewed and Calpine’s Fugitive Emission Sources top -down BACT analysis. Based on the economic impracticability of instrument monitoring and remote sensing for fuel gas piping components, EPA proposes to incorporate as- observed AVO as BAC T for the piping components in new combustion turbine generator and heat recovery steam gen erator and proposes an annual BACT emission limit of 60 tons per year CO 2 

### e . Calpine also identified and adopted the use of dry compressor seals, use of rod packing for reciprocating compressors, and the use of low-bleed gas- driven pneumatic controllers or air

- driven pneumatic controllers as BACT for fugitives. EPA determines tha t the AVO program for fugitives for control of CH 4 

### emissions is BACT.

XI. GHG BACT for the SF6 Insulated Electrical Equipment (SF6

- FUG)

Step One: Identify All Potentially Available Control Technologies Several control options can be used to help minimize GHG emissions for the SF6 circuit breakers which include:

• Use of dielectric oil or compressed air circuit breakers – these types of circuit breakers do not contain any GHG pollutants and serve as a substitute for SF6 circuit breakers

. Potential alternatives to SF6 circuit breakers are addressed in the National Institute of Standards and Technology (NTIS) Technical Note 1425, Gases for Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure SF6 20



### • Totally enclosed SF6 circ uit breakers with leak detection system - Modern SF6 circuit breakers , as opposed to the older SF6 circuit breakers, are designed as a totally enclosed

pressure system which reduces the potential for SF6 emissions. These systems are equipped with a density alarm that provides a warning when 10% of the SF6 (by weight) has escaped. This identifies potent ial leak problems before the bulk of the SF6 can escape

20 Christophorous, L.G., J.K. Olthoff, and D.S. Green, Gases for Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure SF6 , NIST Tech ni cal Note 1425, Nov. 19 97, < http://www.epa.gov/electricpower

sf6/documents/new_report_final.pdf >Calpine Corporation, Deer Park Energy Center Page 25 of 38 Deer Park, Texas (Harris County)


### Step Two: Eliminate Technically Infeasible Control Options At this time, sulfur hexafluoride (SF6)

- containing circuit breakers are the only commercially available circuit breakers. While there are other potential dielectric, non

- greenhouse gas substances such as oil and air that could be used, these types of circuit breakers are all in the

resear ch stage and thus are not technically feasible for use at the DPEC

. 21



### Step Three: Rank Remaining Control Technologies by Control Effectiveness The only remaining technically feasible options for insulating electrical equipment associated with the combustion turbine process are t otally enclosed SF6 circuit breakers with a leak detection system

. Step Four: Evaluate Top Control Alternatives There no other control alternatives available at this time as stated in Step 2 , therefore SF6 circuit breakers will o nly be considered.

Step Five: Select BACT Based on Calpine’s top-down BACT analysis for fugitive emissions, Calpine concludes that using state- of -the- art enclosed

- pressure SF 6 

### circuit breakers with leak detection is the appropriate BACT control technology option. The proposed GHG PSD permit, if approved, is comprised of a 72 pound SF 6 

### insulated circuit breaker. Calpine will monitor the SF 6 

### emissions annually in accordance with the requirements of the Mandatory Greenhouse Gas Reporting rules for Electrical Transmission and Distribution Equipment Use. The annual SF 6 

### emissions will be calculated according to the mass balance approach in Equation DD-1 of Subpart DD. EPA concurs with and adopts Calpine’s best work practice standards for control of SF 6 

### emissions and the state -of- the

- art enclosed

- pressure SF 6 

### circuit breakers with leak detection for fugitive SF 6 

### emissions as BACT.

XII. Threatened and Endangered Species

Pursuant to Sectio n 7(a)(2) of the Endangered Species Act (ESA) (16 U.S.C. 1536 ) and its implementing regulations at 50 CFR Part 402, EPA is required to insure that any action authorized, funded, or carried out by EPA is not likely to jeopardize the continued existence of any federally

- listed endangered or threatened species or result in the destruction or adverse modification of such species’ designated critical habitat.

To meet the requirements of Section 7, EPA is relying on a Biological Assessment (BA) prepared by the applicant and reviewed by EPA. Further, EPA designated Calpine as its non-federal representative for purposes of preparation of the BA and for conducting informal consultation.

A draft BA has identified twelve (12) species as federally endangered or threatened in Harris County by the U.S. Fish and Wildlife Service (USFWS), National Marine Fisheries Service (NMFS) and the Texas Parks and Wildlife Department (TPWD).

21 Christophorous, L.G. et al., pp. 28 -29Calpine Corporation, Deer Park Energy Center Page 26 of 38 Deer Park, Texas (Harris County)



### EPA has determined that issuance of the proposed permit to Calpine for construction of the combustion turbine generator/heat recovery steam generator will have no effect on five (5) of these listed species, specifically the smalltooth sawfish ( Pristis pectinata ), the red -cockaded woodpecker ( Picoides borealis ), the whooping cr ane ( Grus americana) , the Louisiana black bear ( Ursus americanus luteolus ), and the red wolf ( Canis rufus ). These species are either thought to be extirpated from the county or Texas or are not present in the action area.

The remaining seven (7) species identified are species that ma y be present in the action area in certain circumstances. As a result of this potential occurrence and based on the information provided in the draft BA, the issuance of the permit may affect, but is not likely to adversely af

fect the following species. As a result, EPA will submit the final draft BA to the Southwest Region, Clear Lake, Texas Ecological Services Field Office of the USFWS for its concurrence that issuance of the permit may affect, but is not likely to adversely affect the following species:

• Houston toad ( Bufo houstonensis ).

• Texas prairie dawn

- flower ( Hymenoxys texana ).

EPA will also submit the final draft BA to the NOAA Southeast Regional Office, Protected Resources Division of NMFS for its concurrence that issuance of the permit may affect, but is not likely to adversely affect the following species:

• leatherback sea turtle ( Dermochelys coriacea )

• green sea turtle ( Chelonia mydas )

• Kemp’s ridley sea turtle ( Lepidochelys kempii )

• loggerhead sea turtle ( Caretta caretta )

• West Indian manatee ( Trichechus manatus )

Any interested party is welcome to bring particular concerns or information to our attention regarding this project’s potential effect on endangered species. The final draft biological
assessment c an be found at EPA’s Region 6 Air Permits website at http://yosemite.epa.gov/r6/Apermit.nsf/AirP

.

XIII. Magnusson- Stevens Act

The 1996 Essential Fish Habitat (EFH) amendments to the Magnuson- Stevens Fi shery Conservation and Management Act (Magnuson- Stevens Act) set forth a mandate for NOAA’s National Marine Fisheries Service (NMFS), regional fishery management councils (FMC), and other federal agencies to identify and protect important marine and anadromous fish habitat.

To meet the requirements of the Magnuson- Stevens Act , EPA is relying on an EFH Assessment prepared by the applicant and reviewed by EPA.

The action area of the project site affects tidally influenced portions of the Buffalo Bayou (Houston Ship Channel) which connects to Upper Galveston Bay. The se tidally influenced portions have been identified as potential habitats of postlarval, juvenile, and subadult red drumCalpine Corporation, Deer Park Energy Center Page 27 of 38 Deer Park, Texas (Harris County)


### ( Sciaenops ocellatus ), Spanish mackerel ( Scomberomorus maculatus ), pink shrimp ( Penaeus duorarum ), white shrimp ( Penaeus setiferus ) and brown shrimp ( Farfantepenaeus aztecus ). The EFH Amendment information was obtained from the Gulf of Mexico Fishery Management Council ( http://www.gu lfcouncil.org/ ).

Based on the information provided in the EFH Assessment, EPA concludes that the proposed PSD permit allowing Calpine DPEC to construct the combustion turbine generator/heat recovery generator, identified as CTG5/HRSG5, will have no advers e impacts on EFH.

XIV. National Historic Preservation Act (NHPA)

Section 106 of the NHPA requires EPA to consider the effects of this permit action on properties eligible for inclusion in the National Register of Historic Places. To make this determination, EPA relied on a cultural resource report prepared by Blanton an d Associates, Inc. (“Blanton”), Calpine’s consultant, submitted on May 4, 2012.

Blanton conducted an a cultural resource survey within a 1,000-meter radius of the construction site which included a review of the Texas Historical Commission’s online Texas Archaeological Site Atlas (TASA) and a pedestrian survey. B ased on the information provided in the cultural resources report, no archaeological resources or historic structures were found. The site is located in a modern industrial facility in a highly developed, industrialized zone surrounded by oil and gas refineries.

Upon receipt of the report, EPA sent letters to Indian tribes identified by the Texas Historical Commission as having historical interests in Texas to inquire if any of the tribes have historical interest in the particular location of the project and to inquire whether any of the tribes wished to consult with EPA in the Section 106 process. EPA received no tribal requests for participation as a consulting party or comments about the pr oject.

After considering a report submitted by the applicant, EPA Region 6 determines that because the report indicated that no archaeological resources or historic properties are located within the construction area of the project and that a potential for the lo cation of archaeological resources is low, issuance of the permit to Calpine will not affect properties potentially eligible for listing on the National Register.

EPA will provide a copy of this report to the State Historic Preservation Officer for consultation and concurrence with this determination. Any interested party is welcome to bring particular concerns or information to our attention regarding this project’s potential effect on historic properties.Calpine Corporation, Deer Park Energy Center Page 28 of 38 Deer Park, Texas (Harris County)



### XV. Environmental Justice (EJ)

Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes federal executive branch policy on environmental justice. Based on this Executive Order, the EPA’s Environmental Appeals Board (EAB) has held that environmental justice issues must be considered in

conne ction with the issuance of federal Prevention of Significant Deterioration (PSD) permits issued by EPA Regional Offices [ See, e.g., In re Prairie State Generating Company , 13 E.A.D. 1, 123 (EAB 2006); In re Knauf Fiber Glass , Gmbh, 8 E.A.D. 121, 174-75 (EAB 1999 )]. This permitting action, if finalized, authorizes emissions of GHG, controlled by what we have determined is the Best Available Control Technology for those emissions. It does not select environmental controls for any other pollutants. Unlike the criteria pollutants for which EPA has historically issued PSD permits, there is no National Ambient Air Quality Standard (NAAQS) for GHG emissions . The global climate-change inducing effects of GHG emissions, according to the “Endangerment and Cause or Contribute Finding”, are far- reaching and multi -dimensional (75 FR 66497). Climate change modeling and evaluations of risks and impacts are typically conducted for changes in emissions that are orders of magnitude larger than the emissions from individual pr ojects that might be analyzed in PSD permit reviews. Quantifying the exact impacts attributable to a specific GHG source obtaining a permit in specific places and points would not be possible [PSD and Title V Permitting Guidance for GHGS at 48]. Thus, we conclude it would not be meaningful to evaluate impacts of GHG emissions on a local community in the context of a single permit. Accordingly, we have determined an environmental justice analysis is not necessary for the permitting record.

XVI. Conclusion and P roposed Action

Based on the information supplied by Calpine, our review of the analyses contained the TCEQ PSD Permit Application and the GHG PSD Permit Application, and our independent evaluation of the information contained in our Administrative Record, it is our determination that the proposed facility would employ BACT for GHGs under the terms contained in the draft permit

. Therefore, EPA is proposing to issue Calpine a PSD permit for GHGs for the facility, subject to the PSD permit conditions specified therein. This permit is subject to review and comments. A final decision on issuance of the permit will be made by EPA after considering comments received during the public comment period.Calpine Corporation, Deer Park Energy Center Page 29 of 38 Deer Park, Texas (Harris County)



### Statement of Basis

Appendix

for

Calpine Corporation, Deer Park Energy Center (DPEC), LLC Greenhouse Gas Prevention of Significant Deterioration Preconstruction Permit

Permit Number: PSD

- TX

- 979

- GHGCalpine Corporation, Deer Park Energy Center Page 30 of 38 Deer Park, Texas (Harris County)



### Table 1. Annual Facility Emi ssions
Output- based emissions limit, in tons per megawat t-hour (tons/MWh) on a 30-day rolling average , and annual emissions, in tons per year (TPY) on a 365-day rolling average basis shall not exceed the following:

Phase 1 of Construction

Emission Unit Description GHG Mass Basis BACT

GHG Potential Emissions

( TPY ) 2,3 Output

- based BACT CO 2 Limit 1 Tons per year CO 2 e 2,3 Annual BACT Limit (T PY CO 2 e 2,3 )

CTG5 (FD2) / HRSG5 CTG5/HRSG5 Annual Emissions CO 2 1,044,629 CO 2 0.460 tons/MWh

7,730 Btu/KWh 1,044,629

1,045,635

CH 4 19.34 CH 4 406

N 2 O 1.93 N 2 O 599

NG

FUG Fugitive Natural Gas emissions from piping components (including valves & flanges) CO 2 0.11 CO 2 0.11 60

CH 4 4 2.84 CH 4 4 59.69

SF6- FUG SF 6 Insulated Electrical Equipment SF 6 0.00 018 SF 6 4.3 4.3

1. Compliance with the output

- based emission limits ( on a per hour basis ) is based on a 30

- day rolling average

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

- day rolling average

. 3. The tpy emission limits specified in this table are not to be exceeded for this facility and includes emissions only from the facility during normal operations and startup and shutdown activities. 4. Because the emissions from this unit are calculate d to be 96% methane (CH 4 ), the remaining pollutant emission ( CO 2 ) is not presented in the table. 5. Because the emissions from this unit are calculated to be over 99.9% carbon dioxide ( CO 2 ), the remaining pollutant emissions (CH 4 and N 2 O) are not presented in the table.Calpine Corporation, Deer Park Energy Center Page 31 of 38 Deer Park, Texas (Harris County)

Phase 2 of Construction

Emission Unit Description GHG Mass Basis BACT

GHG Potential Emissions

( TPY ) 2,3 Output

- based BACT CO 2 Limit 1 Tons per year CO 2 e 2,3 Annual BACT Limit (T PY CO 2 e 2,3 )

CTG5 (FD2) / HRSG5 CTG5/HRSG 5 Annual Emissions CO 2 1, 062
, 627 CO 2 0.460 tons/MWh

7,730 Btu/KWh 1, 062
, 627

1,06 3 ,650

CH 4 19.67 CH 4 413

N 2 O 1.97 N 2 O 610

NG

FUG Fugitive Natural Gas emissions from piping components (including valves & flanges) CO 2 0.11 CO 2 0.11 60

CH 4 4 2.84 CH 4 4 59.69

SF6- FUG SF 6 Insulated Electrical Equipment SF 6 0.00 018 SF 6 4.3 4.3

1. Compliance with the output

- based emission limits ( on a per hour basis ) is based on a 30

- day rolling average

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

- day rolling average

. 3. The tpy emission limits specified in this table are not to be exceeded for this facility and includes emissions only from the facility during normal operations and startup and shutdown activities. 4. Because the emissions from this unit are calculate d to be 96% methane (CH 4 ), the remaining pollutant emission ( CO 2 ) is not presented in the table. 5. Because the emissions from this unit are calculated to be over 99.9% carbon dioxide ( CO 2 ), the remaining pollutant emissions (CH 4 and N 2 O) are not presented in the table.Calpine Corporation, Deer Park Energy Center Page 32 of 38 Deer Park, Texas (Harris County)

Table 2: Annual Emissions for the FD2 Combined

- cycle Combustion Turbine and Steam Generator (CTG5/HRSG5)

–
Phase 1 of Construction Total Heat Input Capacity (MMBtu/yr) 1 = 17,577,900 Greenhouse Gas
CO 2 CH 4 N 2 O Emission Factor 2 (kg/MMBtu) 1.00E

- 03 1.00E

- 04 Global Warming Potential 3 (GWP) 1 21 310 GHG Potential Emissions 4,5 (tpy) 1,044,629 19.34 1.93 Total GHG Potential Emissions (tpy) 1,044,651 CO 2 e 6 (tpy) 1,044,629 406 599
Total CO 2 e 7 (tpy) 1,045,635 Methodologies and Assumptions

1 Total Heat Input Capacity was determined from the projected annual firing rate information provided by Calpine and reviewed b y the EPA

Operating Mode Annual Operating Hours (hr/yr) Turbine Heat Input (MMBtu/hr) Duct Burner Heat Input (MMBtu/hr) Total Hourly Heat Input (MMBtu/hr) Total Annual Heat Input (MMBtu/hr) Base Load, 70 o F Ambient, Avg Duct Burner Firing 6,760 1,827.5 110 1937.5 13,097,500 Base Load, 90 o F Ambient, Peak Duct Burner Firing 1,500 1602.8 595 2,197.8 3,296,700

Base Load, 90 o F Ambient, Peak Duct Firing, Power Augmentation 500 1,712.4 655 2,367.4 1,183,700

8,760 17,577,900

2 CH4 and N2O GHG factors are based on Table C

- 2 of 40 CFR 98

3 Greenhouse Warming Potentials (GWP) are from Table A

- 1 of 40 CFR Part 98, Subpart A. Mandatory Greenhouse Gas Reporting

4 CO 2 emissions is based on Equation G

- 4, Appendix G, 40 CFR Part 75, Appendix G where the yearly emission was calculated instead of hourly
W CO2 = (Fc x H x Uf x MW CO2 )/2000
where: WCO 2 = CO 2 emitted (tons/yr) H = Heat Input (MMBtu/yr) MW CO2 = Molecular Weight of CO 2 = 44.0 lbs/mole
Fc = Carbon

- base F factor, 1040 scf/MMBtu Uf = 1/385 scf CO 2 /lb

- mole 5 Greenhouse Warming Potentials (GWP) are from Table A

- 1 of 40 CFR Part 98, Subpart A and GHG Potential Emissions (tons/year) = Throughput (MMBtu/yr) x Emission Factor (kg/MMBtu) x (2.2 lbs/kg) x (1 ton/2000 lbs)

6 CO 2 e (tpy) = GHG Potential Emissions x G WP for each pollutant

7 Total CO 2 e (tpy) = (CO 2 Potential Emissions x CO 2 GWP) + CH 4 Potential Emissions x CH 4 GWP) + (N 2 O Potential Emissions x N 2 O GWP)Calpine Corporation, Deer Park Energy Center Page 33 of 38 Deer Park, Texas (Harris County)

Table 3: Annual Emissions for the FD3 Combined -C ycle Combustion Turbine and Steam Generator (CTG5/HRSG5)

Phase 2 of Construction Total Heat Input Capacity (MMBtu/yr) 1 17
, 880
, 750 Greenhouse Gas
CO 2 CH 4 N 2 O Emission Factor 2 (kg/MMBtu) 1.00E

- 03 1.00E

- 04 Global Warming Potential 3 (GWP) 1 21 310 GHG Potential Emissions b (tpy) 1, 062
, 627 19.67 1.97 Total GHG Potential Emissions (tpy) 1,080,728 CO 2 e 6 (tpy) 1, 062
, 627 413 610
Total CO 2 e 7 (tpy) 1, 063
, 650 Methodologies and Assumptions

1 Total Heat Input Capacity was determined from the projected annual firing rate information provided by Calpine and reviewed b y the EPA

Operating Mode Annual Operating Hours (hr/yr) Turbine Heat Input (MMBtu/hr) Duct Burner Heat Input (MMBtu/hr) Total Hourly Heat Input (MMBtu/hr) Total Annual Heat Input (MMBtu/hr)
Base Load, 70 o F Ambient, Avg Duct Burner Firing 6,760 1,873 110 1,983 13,097,500
Base Load, 90 o F Ambient, Peak Duct Burner Firing 1,500 1,752 595 2,347 3,520,050

Base Load, 90 o F Ambient, Peak Duct Firing, Power Augmentation 500 1,871 655 2,526 1,263,200

8,760 17
, 880
, 750

2 CH 4 and N 2 O GHG factors are based on Table C

- 2 of 40 CFR 98

3 Greenhouse Warming Potentials (GWP) are from Table A

- 1 of 40 CFR Part 98, Subpart A. Mandatory Greenhouse Gas Reporting

4 CO2 emissions is based on Equation G

- 4, Appendix G, 40 CFR Part 75, Appendix G where the yearly emission was calculated instead of hourly
W CO2 = (Fc x H x Uf x MW CO2 )/2000
where: W CO2 = CO 2 emitted (tons/yr) H = Heat Input (MMBtu/yr) MW CO2 = Molecular Weight of CO 2 = 44.0 lbs/mole
Fc = Carbon

- base F factor, 1040 scf/MMBtu Uf = 1/385 scf CO2/lb

- mole 5 Greenhouse Warming Potentials (GWP) are from Table A

- 1 of 40 CFR Part 98, Subpart A and GHG Potential Emissions (tons/year) = Throughput (MMBtu/yr) x Emission Factor (kg/MMBtu) x (2.2 lbs/kg) x (1 ton/2000 lbs)

6 CO 2 e (tpy) = GHG Potential Emissions x G WP for each pollutant

7 Total CO 2 e (tpy) = (CO 2 Potential Emissions x CO 2 GWP) + CH 4 Potential Emissions x CH 4 GWP) + (N 2 O Potential Emissions x N 2 O GWP)Calpine Corporation, Deer Park Energy Center Page 34 of 38 Deer Park, Texas (Harris County)

Table 4 : Output

- Based BACT Limits for FD2 and FD3 Combined -C ycle Combustion Turbine and Steam Generator (CTG5/HRSG5)

Base Net Heat Rate in Btu/ kWh (HHV) (without duct firing) 6,852.0

+ 3.30% Design Margin Heat Rate due to Design Margin ( Btu/ kWh (HHV) 1 7,078.1

+ 6.00% Performance Margin Heat Rate due to Performance Margin and Design Margin ( Btu/ kWh (HHV) ) 7,502.8

+ 3.00% Degradation Margin Calculated Base Net Heat Rate with Compliance Margins ( Btu/ kWh (HHV)) 7,727.9

Calculation of Output

- Based BACT Limit (ton CO 2 /MWh ) for CTG5/HRSG5 5

EPN Base Heat Rate (Btu/kWh ) 6 Heat Input Re quired to Produce 1 MW (MMBtu/h ) 2 tons CO2e per

year 3 Total Heat Input Capacity (MMBtu/yr) 3 tons CO 2 e /MWh 4

CTG5/ HRSG5 7727.9 7.73 1,063,650 17,880,750 0.460

1 Base Heat Rate was calculated accounting for a 3.3% margin of error in design and construction of the new turbine

2 Heat Input was calculated by dividing the Base Heat Rate by a factor of 1000

3 Values obtained from Table 2 for the FD2 series and Table 3 for the FD3 series of the SOB Appendix 4 tons CO 2 e/MWh = ((tons CO 2 e per year)/(total heat input capacity/Heat Input Required to produce 1 MW))

. Output- based limits will be based on CO2 versus CO2e because all emissions determined by monitoring methodology in accordance to 40 CFR Part 75 are in lbs of CO 2 as opposed to lbs of CO 2 e.

5 Ongoing Output

- based BACT limit averaged over each 30

- day consecutive period 6 Base Heat Rate was calculated accounting for 3.3% design margin, 6.0% performance margin and a 3.0% degradation margin (See SOB, Step 5 discussion of GHG BACT for the Combined- cycle Combustion Turbine Generator)Calpine Corporation, Deer Park Energy Center Page 35 of 38 Deer Park, Texas (Harris County)



### Table 5 . Startup and Shutdown Hourly Emissions Calculations

Total Heat Input Capacity (MMBtu/ hr ) 1 1,164

Greenhouse Gas

CO 2 CH 4 N 2 O
Emission Factor 2 (kg/MMBtu) 1.00E

- 03 1.00E

- 04 Global Warming Potential 3 (GWP) 1 21 310
GHG Potential Emissions 4,5 (tons per hour ) 69 1.28E

- 03 1.28E

- 04 Total GHG Potential Emissions ( tons per hour ) 69
CO 2 e 6 (tons per hour ) 69 2.69E

- 02 3.97E

- 02

Total CO 2 e b ( tons per hour ) 69

Methodologies and Assumptions
1 Total Heat Input Capacity was determined from the hourly firing rate information provided by Calpine and reviewed by the EPA

. Startup Emission Basis – A startup period begins when an initial flame detection signal is recorded in the plant’s Data Acquisiti on and Handling System (DAHS) and ends when combustion tubine output reaches 60% load. Since GHG emissions are proportional to fuel consumption, high GHG emissions during a startup occurs at the point of highest fuel consumption (approximately 60% load).

Operating Mode Turbine Heat Input (MMBtu/hr) Duct Burner Heat Input (MMBtu/hr) Total Hourly Heat Input (MMBtu/hr)

Maximum Hourly Heat Input Base Load, 20 o F Ambient, Max Duct Burner Firing 2,017 452 2, 469

Maximum Hourly Heat Input during Startup 60% Load, 90 o F Ambient, no Duct

Burner Firing 1,164 0 1,164

2 CH4 and N2O GHG factors are based on Table C

- 2 of 40 CFR 98 3 Greenhouse Warming Potentials (GWP) are from Table A

- 1 of 40 CFR Part 98, Subpart A. Mandatory Greenhouse Gas Reporting 4 CO 2 emissions is based on Equation G

- 4, Appendix G, 40 CFR Part 75, Appendix G where the yearly emission was calculated instead of hourly
W CO2 = (Fc x H x Uf x MW CO2 )/2000
where: W CO2 = CO 2 emitted (tons/yr) H = Heat Input (MMBtu/yr) MW CO2 = Molecular Weight of CO 2 = 44.0 lbs/mole Fc = Carbon

- base F factor, 1040 scf/MMBtu Uf = 1/385 scf CO2/lb

- mole 5 Greenhouse Warming Potentials (GWP) are from Table A

- 1 of 40 CFR Part 98, Subpart A and GHG Potential Emissions (tons/year) = Throughput (MMBtu/yr) x Emission Factor (kg/MMBtu) x (2.2 lbs/kg) x (1 ton/2000 lbs)

6 CO 2 e (tpy) = GHG Potential Emissions x GWP for each pollutant 7 Total CO 2 e (tpy) = (CO 2 Potential Emissions x CO 2 GWP) + CH 4 Potential Emissions x CH 4 GWP) + (N 2 O Potential Emissions x N 2 O GWP)Calpine Corporation, Deer Park Energy Center Page 36 of 38 Deer Park, Texas (Harris County)



### Table 6. Fugitive Emissions (Valves)

Source Types Fluid State Count Emission Factor 1 (scf/hr/comp) Greenhouse Gas

CO 2 2 CH 4 3

NG

- FUG Valves Gas/vapor 60 0.123 0.05 1.27

Flanges Gas/vapor 240 0.017 0.03 0.70
Relief Valves Gas/vapor 8 0.196 0.01 0.27

Sampling Collections Gas/vapor 18 0.1 23 0.0 1 0.38

Global Warming Potential 3 (GWP) 1 21 GHG Potential Emissions 4 (tpy) 0.1 0 2. 62 Total GHG Potential Emissions (tpy) 2. 7 2 CO 2 e 5 (tpy) 0.1 0 5 4

. 95
Annual CO 2 e BACT Limit (tpy) 5 5. 05

Methodologies and Assumptions

1 Emission factors from Table W

- 1A of 40 CFR 98 Mandatory Greenhouse Gas Reporting

2 CO 2 emissions based on vol% of CO 2 in natural gas (1.33% from Natural Gas Analysis)

3 CH 4 emissions based on vol% of CH 4 in natural gas (94.44% from natural gas analysis)

4 Greenhouse Warming Potentials (GWP) are from Table A

- 1 of 40 CFR Part 98, Subpart A

5 CO 2 e (tpy) = GHG Potential Emissions x GWP for each pollutant

6 Total CO 2 e (tpy) = (CO 2 Potential Emissions x C O 2 GWP) + CH 4 Potential Emissions x CH 4 GWP) + (N 2 O Potential Emissions x N 2 O GWP)

sample calc %CO 2

60 valves 0.123 scf 0.0133 lb

- mole 44.01 lb CO 2 8760 hr ton hr*valve 385.5 scf lb

- mole yr 2000 lbCalpine Corporation, Deer Park Energy Center Page 37 of 38 Deer Park, Texas (Harris County)



### Table 7

. Miscellaneous Fugitive Emissions from Small Equipment & Component Repair/Replacement
Initial Conditions Final conditions CO 2 3 CH 4 4

Location Volume 1 (ft) Pressure (psig) Temp ( o F) Pressure (psig) Temp ( o F) Volume 2 (scf) Annual (tpy) Annual (tpy) Total (tpy)

Turbine Fuel Line Shutdown/Maintenance 955 50 50 0 68 4397 0.0033 0.0861 Small Equipment/Fugitive Component Repair/Replacement 6.7 50 50 0 68 31 0.00002 0.0006

Total GHG Potential Emissions 0.0034 0.0867 0.0901
Global Warming Potential 1 21

CO 2 e Emissions 0.0034 1.8216 1.8250
1. Initial volume was calculated by multiplying the cross sectional area by the l ength of the pipe using the following formula: V i = { π * [(diameter(inches)/12)/2] 2 * length(ft)}

2 . Final volume was 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 the compressibility factor, Z, is estimated as the following equation:

Z n = 0.9994

- 0.0002P n + 3e

- 08P n 2

3. CO 2 emissions is based on % vol ume of CO 2 in Natural gas = 1.33% from natural gas analysis
4. CH 4 emissions is based on % volume of CH 4 in natural gas = 94.4% from natural gas analysis
5. Global Warming Potential factors are based on Table A

- 1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting Example Calculation: 4,397 scf Nat Gas 0.0133 scf CO 2 lbmole 44.01 lb CO 2 ton = 0.0033 tons CO 2 year scf Nat Gas 385.5 scf lbmole 2000 lb yr


### Table 8 . Fugitive Emissions from Electrical Equipment Insulated with SF 6 Assumptions: New insulated circuit breaker SF6 capacity 72 lbs
Estimated annual SF6 leak rate 0.50% weight
Estimated annual SF6 mass emission rate 0.00018 tons/year Global Warming Potential 23,900
Estimated annual CO 2 e emission rate 4.302 ton/year

1 . Global Warming Potential factors based on Table A

- 1 of 40 CFR 98 Mandatory Greenhouse Gas Reporting
2 . Estimated annual CO2e emissions was calculated using the following equation:

72 lbs 0.005 (%weight) ton (GWP) 23,900 = 

### 4.3 Tons/year year 2000 lbsCalpine Corporation, Deer Park Energy Center Page 38 of 38 Deer Park, Texas (Harris County)



### Table 9 . Financial Assessment for Imple ment ation of a Carbon Capture and Storage System at the Calpine DPEC Facility

Carbon Capture and Storage (CCS) Components Annual System CO 2 Throughput (tons of CO 2 captured, transported, and stored) Pipeline Length for CO 2 Transport System (km) 5 Range of Approximate Annual Costs for CCS System (in USD) 6
Post

- Combustion CO2 Capture and Compression System 1 Average Cost 2,3,4 956,349 $70,544,632

CO2 Transport System Average Cost 2,3,4 956,349 

### 24 $419,123 CO2 Storage System Average Cost 2,3,4 956,349 $8,918,776
Total Annual Cost s for CO2 Capture, Transport and Storage Systems Average Cost 2,3,4 956,349 $79,882,531

Assumptions: 1. Assume that the capture systems is able to capture 90% of the total CO2 emissions generated by the power plant’s gas turbines 2. Th e minimum cost factor found for implementation/operation of the CO2 capture systems within the cost

- related information reviewed for CCS technology is found from the “Properties” section of the Greenhouse Gas Mitigation Strategies Database ( last accessed April 2010) ( http:/ghg.ie.unc.edu:8080/GHGMDB/#data ), which was obtained through the EPA GHG web site ( http://www.epa.gov/nsr/ghgpermitting.html ). The factor is based on the increased cost of electricity (COE; in $/MW

- h) resulting from the implementation and operation at a CO2 capture system on a natural gas

- fired combined- cycle power plant. The factor accounts for annualized capital costs, fixed operating costs, variable operating costs, and fuel costs. 3. Maximum costs are from the Report of the Interagency Task Force on Carbon Capture and Storage, pp 33, 34, 37 and 44 (August 2010) ( http://www.epa.gov/climatechange/policy/ccs_task_force.html ). The facto r s from the report are in dollar s (USD) per tonne of CO2 processed, transported or stored and have been converted to dollars per ton. Per the report, the factors are based on the increased cost of electricity (COE; in $/kW

- h) of an “energy

- generating system, including all the costs over its lifetime; initial investment, operations, and maintenance, cost of fuel and cost of capital.” 4. The average costs factors were calculated as the arithmetic mean of the minimum and maximum factors for each of the CCS component system and for all 5. The length of the pipeline was the assumed distance to the closest potential geologic storage site, as identified by the University of Texas at Austin, Bureau of Economic Geology, Gulf Coast Carbon Center, available at

< http://www.beg.utexas.edu/gccc/miocene/ >. 6. Cost estimates (for geologic storage of CO2) are limited to capital and operational costs, and do not include potential costs associated with long

- term liability from Intergovernmental Panel on Climate Change (IPCC) Special Report, Carbon Dioxide Capture and Storage (New York: Cambridge University Press, 2005), p.44

< http://www.ipcc.ch/pdf/special -reports/srccs/srccs_wholereport.pdf >