The URL can be used to link to this page

Browse Search

Home My WebLink About20100696.tiff Weld County Planning Department WELD COUNTY ATTORNEY'S OFFICE jteGREELEY OFFICE 915 TENTH STREET JUN 19 91109 P.O. BOX 758 GREELEY, CO 80632 RECEIVEDWEBSITE: www.co.weld.co.us e PHONE: (970) 336-7235 FAX: (970) 352-0242 COLORADO June 22, 2009 Ross Bachofer P.O. Box 652 La Salle, CO 80645 Re: Rocky Mountain Energy Center, LLC, Well Site Dear Mr. Bochofer: Enclosed is a copy of a plat entitled, "Partial Vacation of Permit Number USR-1339 Rocky Mountain Energy Center, LLC Power Generation Facility,"that was recorded in the office of the Weld County Clerk and Recorder on February 2, 2005. In our telephone conversation earlier this week,you inquired as to the reason that the well site located on property owned by Dale and Noreen Ewing was not required to be included in an amended USR-1339. I have confirmed with Kim Ogle of the Weld County Department of Planning Services that it was determined in 2004 and 2005 that the well site was a use-by-right in the A (Agricultural)Zone, pursuant to Section 23-3-20 of the Weld County Code. A copy of that Section is enclosed. If you should have questions regarding the enclosed, please feel free to call Mr. Ogle at (970) 353- 6100, ext. 3540. 'nc el ru T. Barker Weld County Attorney Kim Ogle Enc. 2010-0696 • e.,0-77/ (- UCKPZ-Zejn-d--2 Zoning—Procedures and Permits Div.9,Fees—Sec.23-2-940 Sec.23-2-940. General requirement for collateral. The policy on Collateral as outlined in Section 2-3-30 of this Code shall be followed. (Weld County Code Ordinance 2001-1) ARTICLE III Zone Districts Division I A (Agricultural)Zone District Sec.23-3-10. Intent. Agriculture in the COUNTY is considered a valuable resource which must be protected from adverse impacts resulting from uncontrolled and undirected business, industrial and residential land USES. The A (Agricultural) Zone District is established to maintain and promote agriculture as an essential feature of the COUNTY. The A (Agricultural) Zone District is intended to provide areas for the conduct of agricultural activities and activities related to agriculture and agricultural production without the interference of other, incompatible land USES. The A(Agricultural)Zone District is also intended to provide areas for the conduct of USES by Special Review which have been determined to be more intense or to have a potentially greater impact than USES Allowed by Right. The A(Agricultural)Zone District regulations are established to promote the health, safety and general welfare of the present and future residents of the COUNTY. (Weld County Codification Ordinance 2000-1) Sec.23-3-20. Uses allowed by right. No BUILDING, STRUCTURE or land shall be USED and no BUILDING or STRUCTURE shall hereafter be erected, structurally altered, enlarged or maintained in the A (Agricultural) Zone District except for one (1) or more of the following USES. Land in the A (Agricultural) Zone District is subject to the schedule of bulk requirements contained in Section 23-3-50 below. USES within the A (Agricultural) Zone District shall also be subject to the additional requirements contained in Articles IV and V of this Chapter. A. One(I) SINGLE-FAMILY DWELLING UNIT and AUXILIARY QUARTERS per LEGAL LOT. B. One (I) SINGLE-FAMILY DWELLING UNIT and AUXILIARY QUARTERS on a parcel of land created under the provisions of Chapter 24,Article VIII of this Code. C. FARMING,RANCHING and GARDENING. D. Cultivation, storage and sale of crops, vegetables, plants, flowers and nursery stock raised on the premises. E. TEMPORARY storage, in transit, of crops,vegetables, plants, flowers and nursery stock not raised on the premises and not for sale on said premises. F. Repealed. (Weld County Code Ordinance 2007-1) G. Grazing of LIVESTOCK. H. Feeding of LIVESTOCK within the limitations defined in Section 23-3-50 below and Section 23-4- 710. I. OIL AND GAS PRODUCTION FACILITIES. J. PUBLIC parks and PUBLIC recreation facilities. K. PUBLIC SCHOOLS and PUBLIC SCHOOL extension classes. 23-90 Supp. 12 Zoning—Zone Districts Div.1,A Agricultural Zone District—Sec.23-3-20 L. UTILITY SERVICE FACILITIES. M. Alcohol production which does not exceed ten thousand (10,000) gallons per year, provided that alcohol and by-products will be used primarily on the owner's or operator's land. N. TEMPORARY group assemblages(subject to Chapter 12,Article I, of this Code). O. Asphalt or concrete batch plant used temporarily and exclusively for the completion of a PUBLIC road improvements project. The six-month limitation for this TEMPORARY use may be extended in six-month increments at the discretion of the Director of Planning Services up to two (2) times, and thereafter by the Board of County Commissioners. P. MOBILE HOME subject to the additional requirements of Article IV,Division 3 of this Chapter. Q. Police and Fire Stations or Facilities. R. Borrow pits used TEMPORARILY and exclusively for the completion of a PUBLIC road improvement project. In addition, sand, soil and aggregate MINING, regardless of the use of the material, which qualifies for a single limited impact operation (a 110 permit) or is exempt from any permits from the Division of Minerals and Geology, generates no more than five thousand (5,000) cubic yards of material per year for off- site use and does not involve crushing, screening or other processing. An Improvements Agreement, as determined by the Department of Public Works,may be required prior to commencement of operations. S. MANUFACTURED HOME subject to the additional requirements of Section 23-4-700 of this Chapter. T. ANIMAL BOARDING and animal TRAINING FACILITIES where the maximum number of ANIMAL UNITS permitted in Section 23-3-50.D below is not exceeded. U. Commercial towers subject to the provisions of Article IV, Division 9 of this Chapter. However, one (1) amateur (HAM) radio operator's crank-up antenna may be extended to a maximum of one hundred fifty (150)feet in height,provided that its resting or"down"position does not exceed seventy(70)feet in height. V. Disposal of domestic sewage sludge subject to the additional requirements of Article IV, Division 6 of this Chapter. W. Disposal of DOMESTIC SEPTIC SLUDGE subject to the additional requirements of Article IV, Division 7 of this Chapter. X. TEMPORARY facilities for the sale of fireworks and Christmas trees. Y. GROUP HOME FACILITY. Z. FOSTER CARE HOME. (Weld County Codification Ordinance 2000-1; Weld County Code Ordinance 2001-1; Weld County Code Ordinance 2002-9; Weld County Code Ordinance 2007-1; Weld County Code Ordinance 2007-14) Sec.23-3-30. Accessory uses. The following BUILDINGS, STRUCTURES and USES shall be allowed in the A(Agricultural) Zone District so long as they are clearly incidental and ACCESSORY to the Uses Allowed By Right in the A (Agricultural) Zone District. Such BUILDINGS, STRUCTURES and USES must be designed, constructed and operated in conformance with the bulk requirements contained in Section 23-3-50 below. ACCESSORY USES within the A (Agricultural) Zone District shall also be subject to the additional requirements contained in Articles IV and V of this Chapter. Note: The combined GROSS FLOOR AREA of all ACCESSORY BUILDINGS constructed after the original effective date of this Chapter(August 25, 1981) on LOTS in an approved or recorded subdivision plat or LOTS part of a map or plan filed prior to adoption of any regulations 23-90a Supp. 14 Kim Ogle From: Bruce Barker Sent: Thursday, June 18, 2009 1:36 PM To: David Bauer; Clayton D. Kimmi; Kim Ogle Cc: Thomas Honn; Pat Persichino Subject: Ross Bachofer Attachments: Calpine USR 1339.pdf; Calpine Vacation Plat.pdf; Ewing ROW Calpine.pdf 411 roi psi Calpine USR Calpine Vacation Ewing RRROW 1339.pdf(2 MB) Plat.pdf(3 M... alpine.pdf(100 KB). Dave, Clay and Kim: I was contacted about 2 weeks ago by Ross Bachofer regarding the Calpine water well facility located next to the South Platte. The water wells were originally in the plat for USR-1339 in 2002 . See the attached. They were vacated from the plat in 2005. As I recall, we decided in 2005 that the wells were a use-by-right in the Ag Zone, and therefore there was no need to include them in the USR. The wells appear to be on property owned by the Ewings with a Parcel # of 130930000039. Bachofer has Parcel # 130930000048. From the aerial map at the Assessor's website, it looks like the well facility includes a building and berm on the very northern edge of the Ewing's parcel. The Ewings granted Calpine the right to place the facility there through an agreement, a copy of which is attached. Bachofer complained about the fact that Calpine did not need to amend USR-1339 to include the new wells. I told him that it was determined to be a use-by-right, but that does not seem to have made him happy. He also complained that the building and berm have caused flooding of his property. David and Clay: Do you know if the facility received a FHDP? Has Bachofer talked to you guys about his flooding concerns? Kim: Am I right that we determined in 2005 that the new wells were a use-by-right? Bruce. 1 111111111111111111111111 IIII 11111111111 III IIIII IIII IIII 757 3077757 06/2612003 05:07P Weld County, CO 1 of 5 R 26.00 0 0.00 Steve Moreno Clerk& Recorder RECORDING REQUESTED BY And WHEN RECORDED MAIL TO NAME Calpine Corporation MAILING PD.Box 11749 ADDRESS CITY, Pleasanton,CA 94588-1749 STATE ZIP CODE (925)479-6600 (SPACE ABOVE RESERVED FOR RECORDER'S USE ONLY) PPC No: 558-75 MN: 1309-30-0-00-007 & 1309-30-0-00-039 SHORT FORM OF RIGHT OF WAY AND EASEMENT THIS SHORT FORM OF RIGHT OF WAY AND EASEMENT is entered into this `k day of V��, 2003, by and between Rocky Mountain Energy Center, LLC, ("Grantee"), d'itd Dale W. Ewing and Noreen M. Ewing(collectively,"Grantors"). 1. Grantors and Grantee are parties to that certain Right of Way Option and Agreement dated August 13, 2002, and Amendment to Right of Way Option and Agreement dated March 14, 2003 (collectively "Agreement"), the terms and conditions of which are hereby incorporated by reference. 2. Pursuant to the Agreement, Grantors have granted to Grantee a right of way and easement to, among other things, drill, install, lay, construct, operate, maintain, repair, and replace water wells, pipelines, and related structures, all as more particularly described in the Agreement, on, over, across and through certain lands situated in Weld County, Colorado, being more particularly described in Exhibit A attached hereto and incorporated herein. IN WITNESS WHEREOF, the parties have executed this Short Form of Right of Way and Easement. See Signature Page Attached Hereto and Made a Part Hereof: • 1111111 11111 1)111111111 III 1101 IIII IIII 3077757 06/26/2003 05:07P Weld County, CO 2 of 5 R 26.00 D 0.00 Steve Moreno Clerk& Recorder SIGNATURE PAGE GRANTORS: GRANTEE: ROCKY MOUNTAIN ENERGY CENTER,LLC Dale W. Ewing r/ Name; RichRichard Thomas Title. Vice Presider* ` gym Noreen M. Ewing EXHIBIT A . 11111111111111111111111 �� 11111111111 III 3077757 06/26/2003 05:07P Weld County, CO 3 of 5 R 26.00 D 0.00 Steve Moreno Clerk& Recorder LEGAL DESCRIPTION TOWNSHIP 2 NORTH,RANGE 66 WEST,6TH PRINCIPAL MERIDIAN Real estate described as the southeast quarter (SE '/) and a tract of land located in the southwest quarter (SW '/<) of Section 30, Township 2 North, Range 66 West of the 6'h P.M., more particularly described as follows, to-wit: Beginning at a point 350 feet south of the northwest corner of the SE '/a of said Section 30; thence south 69° west 416 feet; thence south 28° 45' west 550 feet; thence south 11° west 992 feet; thence south 66° 24' east 920 feet; thence due north 1970 feet to the place of beginning. Except a tract of land in the SE / more particularly described as follows, to-wit: Beginning at the southeast corner of said SE /; thence north 1082 feet; thence south 60° 45' west 372 feet; thence south 55° west 428 feet; thence due west 348 feet; thence south 52° west 675 feet; thence due south 298 feet; thence due east 1460 feet to the place of beginning. Also excepting a tract of land situated in SE '/ of said Section 30 more particularly described as follows, to-wit: Beginning at the southwest corner of said SE /; thence due east 720 feet; thence north 66° 24' west 810 feet; thence south 320 feet to the place of beginning. Also excepting a tract of land more particularly described as follows, to-wit: Beginning at a point on the north line of the SE 1< from which point the northeast corner of Section 30 bears north 2° 26' east, a distance of 2640.6 feet; thence south 0° 05' east, a distance of 1619.0 feet to a point on the south property line; thence north 60° 40' east, a distance of 137.5 feet to a point on the east line of Section 30; thence along the east line of Section 30, north 0° 5' west a distance of 1551.8 feet to the northeast corner of the SE '/ of said Section 30; thence along the north line of the SE '/ south 89° 55' 30" west, a distance of 120.0 feet, more or less, to the point of beginning. Also excepting that parcel conveyed in Deed recorded July 11, 2001 at Reception No. 2865029. 11101 11111 MUMUM I I 1111111111 III I 3077757 06/26/2003 05:07P Weld County, CO 4 of 5 R 26.00 D 0.00 Steve Moreno Clerk 8 Recorder STATE OF COLORADO ) ) ss: COUNTY OF WELD ) The foregoing instrument was acknowledged before me this 12th day of June, 20034 by Dale W. Ewing. ,c°rj ;. Wrtness my hand and official seal. Q � ' `My Commission expires: 7-30-05 \'Y\01Q ��\I • Notary Public I Mari S. Gillman STATE OF COLORADO ) ) ss: COUNTY OF WELD ) The foregoing instrument was acknowledged before me this 12th day of June, 2003, by Noreen M. Ewing. Witness my hand and official seal. -My Cdtnmission expires: 7-30-05 \NCOS 611 Onoll Notary Public Mari S. Gillman STATE OF CALIFORNIA ) ss. COUNTY OF ALAMEDA ) On June 17, 2003 , before me, Phyllis Branle, Notary Public , personally appeared Richard L. Thomas , personally known to me (or proved to me on the basis of satisfactory evidence) to be the person(s) whose name(s) (is/ere) subscribed to the within instrument and acknowledged to me that (he/she/they) executed the same in (his/her/their) authorized capacity(ies), and that by (his/her/their) signature(s) on the instrument the person(s), or the entity upon behalf of which the person(s) acted, executed the instrument. WITNESS MY HAND AND OFFICIAL SEAL �/�y[ •,, -,,`. PHYLU88RANLE \J OL�l ie LeJ - COMMISSION 1248974 0 �'. ,. '�' NOTARY PUBUC•CAUFORNIR `� ALAMEDA COUNTY Notary Public ► . *maw ono Jon t I 111111111(11111111 IIIII 1111111111111 III 11111 Illl IIII 3077757 0612612003 05:07P Weld County, CO 5 0l 5 R 26.00 D 0.00 Steve Moreno Clerk& Recorder fff111 dwrax /fans 14”at =n aam g//oor m -- '{q Ixiae o sN I,$i9 a itti n lma d cte BCESOlD!MUM 013A {O pc�ad •SHOASAS S•SH3NONIAN3 NIL? b saoxenans•saaaNIoNg OOVtlOIOO'AINIIOJ Ol3M '!`/ g N. w.'I L�SN�'l ��;�ITnT 311'tl31N33 AOtl3N3 NiViN110W AN3Otl (_'E 3 j ' 'h g§ v ✓ 4t 1'�' e `asge"t §i = d p kbk ;1 O;W tc g„¢ C-,' „, tdh , "sae£g.Y,:� .,-,„A .4 ago g§s'8 §Yagc 4: _00.440% ye ?gig 6602I ayh Q�A_a„ ' etl � !ubi MYk kb�� i g. gear' ea'-g g₹d q,5 no. a g₹ ,,pa.�g. §4'$e agga F MI lit ai ,;W y5bo96€60k a gy§Y Mg s I, .aI f₹g i eengeF^g 1,.₹=@a e60;aI II a "Ic,gaaiga2ag12�' 0 II:".§ ma g$el I'. pE ' aaaaa9°� e : "j"aa' gas 9 ; 4q 28i bk $"a�� ` � @ �ga� a! Illg = �1 el ' i $A:;§pa.d@sE @ $°e 89 q.cY cA9ae t8is 'g'e. r A . at i pC—,aa .. O 0 J J U @ & @ @g � W H .2' ' 8 At et ₹ ei ;4 a @o o " o . 2 a gg p I (h W V E O B a e Se 3@ Y .� a ex g e - Fa i� Cq LigW W 128 p s 5 —.`.—' M Q m.5 .- �J `g, n •.. W 2 W H �P d a k M cr 03 W / SIP- 2V/ /�L�?� p Z , wd m \ �'-ffl /i:F Jj l�� t. lit a F ₹I iii--0 Lu F CC O W Op w�/ P1� I �F� S.$ ✓'�� sa l A ,_t a �I I ©— a !� \ p .- .._fin „§�*-_ > rea₹! � E.. N/ `, O N ' . V ' i s U i- f f j �. g1I` "g. 513 n a. o , §Is a ca a ₹n3 b gg Cs 5 g g § @ § g g ss a 9i § ;Ye! a3'_ Wg i i.i¢ ©tif IA i " gi!'ei i iiii Al_ a .. A t ₹$h 5 g Y g $§e g u'g�y 5g c¢X35 '$ pgega h$ t k €h3: g gtg i s e k a q t ato spg vo& g gl g yga pg og rg€;e§z gig q'• 3 `€ JJ g ₹ 0 a ₹ t _ ' e" 9 idii Y 1 is eta gp- 1$$g. i a d � Yn �ie 5g h� N y V 4se H Oct g; b g a Y ; it Y �a 44a "' : 3Stl �,.w FYI la 52 ®s'o 5& a €#a . g 5 v e 5 sg ai l p c - - Ggg ₹a p„bp 5yv pa:.:tl'6 44 'smdq 45 5 4, P•e ₹§d 5 hg€ Nt f :y ° o 5 : s" e6" a be a s 58 ap 50X k e aig;,lf "5` Tanwq 9 sg h o §g gg.-= ' i5, h a p" : '&5 66 a % g " z"2k Y:. g g p;y ge-r ^kb . X fl p5aaaas t hi iii i ge 55 3 E v a2 gg 15€ . a e ,ea , his f f:Yf g e=5gp g5g e g 8 2 2V ax"y ":u: g §s$2 g03 " ay5 A as @ YY g 3q IA S t AV q Y@ "g e.g iq d'}aa =g kg,f'k. pstt IYpgi '.`L q s u Y5g ₹9955 YE `ig ] : . j ii £ I4 § ₹t t b`i 3 hp; r I bnh 'daft " g "3= ay s lds 3fsgpsgt ! 6sa in i gig g 'i; : k 2,n „£ a a' 1 a ;p gg§ g@ @Fg$ '1ne ! gity !ge I= 9q al `E" 2,.,_ pgc "4asa s ₹5₹gg ''m1 v ge of a §$ aaa n; a e' . °e in XI p� n5a1 x "rgs"e5 pA itit, °s` '1�' ° =.qs ion 'ee�gas S gig k ft g ; 3§ "„e 5 v -h . I! a ,o eo Er?„, Y aa.aa. teo €a.! "a o d q y g ggyy �2 020 Ogg! Agg .ii "a " "@e @ a € 3� . f & § gr gr g e EV i.kE §q@- Wig" et e- P 190"8 Sp 0 mn: e- - 7Q }. r y s }'p` )m g uh g; agpq .g =" t3 f..c.s'c g^ ; as b Sae' 82g Yggy bz2 :tl Y I`�g S iN g tl g gc 139 ]3 dg I i5 Y Et L- Agt qa $ I Fyn"e °`ysYb, iiit 2AI20 �g Ea i m s 1g agaasa@ ht 41 lug it a 4 r ° ga b0 ¢q¢'" §i § §§§ a e§ a5 ! s ag he'h! 5009 ii ii, •wu§4 gh§Y: , C3C„ ill: b C tl-A 'A 'h h 5Rg Y y do f' a Y 4 g e Y9 Y a '5 ib Lk I i P 8 559 pi.. g3 i"3hY of L �3; "s [ xig „ 4 '' a 'A= s :t i as 4 gh k e bg ' eA e5 5 ' 4 115,1 it § 5" s III! tg "ga' £g 'g `E —"' a �$z {� i "s $g y @ q £ i' # § @ ., .: pop c v IX .YE ..Y.yyfL AA .abk ..s§ a a; . .t 5 4 " "g :dg 4 ` .o . . RF rei F@ .^.l`e5: ai'. gie4 5 Atet t - k,.`a 4a R.g al---- Y^ wmw Ilex //^IPV DOG-we/cot r w^.o-sslcac r - BCCk asf tl38WON 11Wtl3d in ed I00 V ]'ualapr9 0 No AN 8 2LtB 4 IS1 'l $1511N 31JS'ItllN3WNdN1/,N'3 }l OO Ytl OIO'� 11NAO0 Ol3M `� ,' b m" •Stl'A3lnNl1S•$M 33N1'JN2 "' oLIONIy�SN�Qat/I �I O1lN31N3O A'Jtl3N3 NItl1Nf1OW ANJOtl i i`t I C N ; o iSV n 6 2 g Y <k7 4 �'9 8^ 8 8 yi asp aks 2 , 1r�_` 2825.1 .:.:.9 ,... 2 5522,92, w W§ .k 3§iW,W x,X,M4333 ₹₹333g'o3.LX r 8-926 ER t Le-L6tSttttttt.tttttttttttEstttttEst o ;S a s_"a" _ ri og"s-"oa"- 2222-aSsoSo�-"e "aog'"-a""' 4 J 5 z. > �a: S's 8682^r:R_ '"S:p:pe'""sgt,a n o 488.8.8 e°- FW S m Fmms°SA:gggSSgSrn^om SgflgSS€Sts If J' w tp „ sssssssssssssssssssssk= €t€" W H :esssssssssssssssssssass=: 's €k:8t O) � < Sao Pa Yaw=: = ar T.4,wwwr lln-1 sW`g co Z J i .3Y m, €`aaz%€€ aa €€saa€€€aaa€€ s€es -r W U U < io CC L.L. .a a¢ 7 m Z yo W Z O o 0 000 W M 4o w �wr k i s 5,£- f t Z Q W m co El e eat _� g a s : ac6a ,.tgo' - „'a=� n'' o d s -:� s a oa €m&�a*i�.o k = ate€ f5852 - Z 8 Sg24 2 526,1 84528 <x m ≥!Ft �i a E a x 'inn .wge k E.=�3 Lr O W o g 8kr g Lg s2. ='Im„ 3Ya.Y g%;as W Y 92O Sop S' ssgg, € € LL O 52.2 w sg 8,2. 9.2.42 - H ilk no �Coa 3 m t -8 „S3 dtr 84.-gg €_..8 a iNC . wI a 28€ - "m-` o s . ` x d_`ttti,!3m p£iS;: !9YoY O i - Nt:,zr, €3s= 8 -. H t ^s2¢'.'. mE $ Yg3Q '8e,„a ,',8 3 w 3''o tVoa `t . W S,:It'g3 "s -q- e: €t CC P d e2vYo L.3�`,.5 3 5o Y}+ i' txOeZ:§d ; [tg'?3t �£5 2 a °3 3 wabmb .t"wb .2 22 g: t°y and p`eX€o¢ao. S 5402 t1. o d ,:p, 's.:88 3: 2. 3- 83: 2 6 U` th i b 688-5888 5 o2 `e : 58:8€=se .8 =s" pm t5§;g _ =YS2g121H8 'Yt 8 2, 3: Na363aa"da ge 256488 42d"` Yn - c z ni,".^ 9 ; ' 52'.^2265 52 Y,5` 2 '"•_w' a s=280„2.„.3 2 sz a g k€ 8="- --gZ"¢ 5. Fw2g„g 'o. . -°..8'.0.0 6t O !€" " 22 $2;2182 i68 o% 254222 ¢gaffs 2�a 58 jgm8856$$5m g2 2. of : Sk •g:2 t t"£.8W: 23 8d�-g w =‹C T6 °« €€€€€pat> € . !§ 9 4 'sm3=8W�€t £g :d":as g8o"€ k: "do�385:�:`y„ S't 56 g 1 4 ":wtao9a 2S "te«tl8 s20 �.8:y� 6 a 5.9 N21-.6665.=85 8- ' €y 2'ss5a24.82 82 agu .8 agg„e ® c 62Y n"�,.s€.3-i1„. .. at 2 . ... 5 om ELi! $t sizo xhe =3d • NI w03aavnNVII 4.h"nv oam PIUfaf 1 0(50-PaUPot BEET-tl50 M39WON AIWtl3d f)IOP ayeiolo] 3S ] fl 4°aN a�e,l A)f]P i I� ' suuNMOS lvxN3wNoamNg pI; OCWW100'A1N000 013M 4J �a 51? •saoxanHAS•saaaNr'JN r3 i i e .... 5 WaaJNLL'If1SN03 4uVI{NV 311'tl31N30 AOtl3M3 NIVLNf1011 ANOOtl i i i i i v co g b - t m "2g g E pap $s TN Igi a 9gir b [•�h mkt 2.2 51i-e„ a? .,`,e - bA t an2"' °"-i yy3 §yy£ 522..2 8 §32.1Ii. bb3-tg9F3' w2A. 4. .,$5E, v aly Y. e ci tagE 5$:3p;g ;a: h`-' i th d�a - aReii' "a_ ��gAzRe ffiey₹$a Via ym mbg gg z-€n' 3 a P$'ff.h gF"m,qq» ii [ ill s ze=$ -A p^pA' E S g968d: giE! ! ip h !xi₹r-z Xtlt e. 'it -i s 4 a i d t”, 244g = %It! .1V!.. o pbht En�P3 S M3 $ ''1.6‘;',..58P". get- ----9-z 2 ea• tlliy Ma . a8 § ,w. S` ;Na pl5P, h dude h. E Sego a_r �tap.ey ! € ' �!Ai i$5ha h 8nri i ii Oh if Y h;'21, S `=§$'bA. ' ' Y !ill a mt:Zaa„` " a§'5=i hi g s$th :1 $'thtam e 6 !ill I :pizP$'i :bas§ hi I g lid `p°'d pp �I, t �g I 6 da dE �E` UW le�am um i \111i u J e eh;= ��k �� edpi 1 9itA y iii, w rapeii •a, l I�E i$i I / i igi i �" i 17 iii dllA ie to I I rit$ BIB r il W fi w. ' �' r i C tle AEI IE� !9:IE '� U Q °ag i i Li. .0 l r Ii i I ;t 6 i I 's 8 y CO �z O)- - Id e A ICI . �� hi - ---ItI W < h°° -I i E ; i4i W — i o LL �� r 1sT•' i� -- ZQ � � s LLI CC w 3 w . \ \ Ee d V id £Ai aid k N ., ,, q �a c Aa A� = E is i a �_ Q W lek \3a Ilr _e. H H C'J .e Z o ` kk € d /A / \ II r ( rr i.m it r •, A A .F ,ii,47: 0 AA s •I'! ki fO II' I AA �I ;�i I E } 15- 0s ii idAd E Y o �hll-' A� ii', mil py k il �id�337 r y il O Yz A /9gy a¢ :It+.5 I it I. i ffii ai@' '$ it ,4 ill Qy a o// ps�k i I �} 5 dp4r IA2 �e a�,ii cc 0.o pp,�,sPg5k_*yyy?'(, G • A I it is ,i let. i� a �W{a 9 Bi \� iv I i s �ap \ I iIIi0E �iia a 5 a a p i a YY Ssi 2a"!a at %V,, iii. .al@ . El-' ; 1 I I.I6I•la>ae>a.. gg ESA , = a 1 uw• mKev•••//din.iwo fitL/mf .I GM 00,/vnv PI — BfOI•NSO tl39WON 11Wtl3d is INN °R UN*U'ualopyul / yv+l1 wud el dl.)0 syslyN3iJS 9VyN3WNoamNGi] !,7/j F OOvwolOO'AINOOO Ol3M "E E --- - YOA3AxinS•SN33NION'� �f- - t r.. -- _ .I 'alaNII11IISN03 QI'I'INVT4J ,{ '311'N31N3O AOH3N3 NIVINNON ANOON I I l I i! E t @ d 6P N P q p } I ! ill ;lie :Y 'iY : e l t ;IY FY!` exg ,� J 3> @ I F. Y tY„ . gE7 ID ' Ylge -YeYl rEY�. gK3r ; F YYYY Y=YF_F+ geg gg e il;;y Y¢q iig!li Y'qj$' F € iiiii t..x tiih!.}i{i4 :; i 7I°eV pe„S gt�3!g.6"t�pF'yYYF34 F yg§ �I U g!' .03 tl F6EIi.k r51.Fy'F"3i i763 [!.NIht4 71.;'s9' edig' ;l5;if; ygiR E ¢e,e, ,ggCYy !I6 . Q Vat y .8E 411'4 L'EVIE ' EVEEEg E 6 �, pp eCi:e EY1g Y'E EE -111E EIgYY93&EW?nEFF 9$4F Di-4q iirYr yih ip" .d:i¢e3.r- c l9gi ¢ rq 61 9 . gY p s 7e , i [ f� LL 1 Fe95➢dA,,„ ::l $FC. :,... $6. Y$Ya[123�Y@Ni l��Ff@Yi..F�z114@�, e4ae€@s�fi45i. „, , ,I; „,„t VI @Min -..•..............v..ezzARCPve:..".caap;Fs9-""•:ac9:AZAtEE,ggfEa:::68:Y0e::.}flE4cA WS:ea Iw Z tE o Z1* 2, r 'r Q i pi r CC o Yll I- Zw W ry; II \, iii II e .A.0=sue — I W 0 wn cow .3 Jun rs3 V LL a Cr)C'/ W er I.:ZZ2y ?=! .. ref'% r}a«c--.s--Z-% t lll' IAA i 1Ce)— a `IN I I $ Iii 4lI;Iili o� =o •D. II)6 •IIhIII J 3 0 \'� ti I Y I?IIII„YI cc o 'y' - I�i�dl U.! J i-=o I I ^1r • CC g p00 w 1V q ,1 h LE —JL Y �Ip41 Z 2 LL A wc-E -''-� ' V a 4 yv HW o u - fir -_ _ • U a ✓H t# s �.__� tsss� .sr ` �tA "# { E I .«,;,� �. \\\ p \ Id II w U 11 ly r a F . - i -eL ' CL cc o i F I It t l� w � woe., Iyq II ' 0 n i •' o rI i O 8- e I - ii 4UI ₹ 4 k 4 II -- , - AID+ a Z J � , @ b ° 9 a rh oE e, IIa,II g I Ell aJ I 41 II Y V V Z a I h ll 1� - N:I I • g yIl , I-- II j f 8 II n ' � w --�_ I;I ' 4h �i • _Ii�IM11 7 rr°t • Lam' ■■ ' ^y. n of ,II r =3,II p i ;a a =:1 }xssssT: r 13_ ass z_ s�. E - f �Iapc .-.� 3, • -ig'• s.4,- , s i 9P N1�rAt u..^ __49,03N,0 __ _.and I{r RY n I h 1,! #R i� _� N' Wit, / -flaws 3��'w 1411 n 3ui u3. �? �4 �"� ^a_ +: si aa``u:. _ ! 3.IL t iid� .t—'' _ N00'N� _ a1 • OllWlIM.-//' 4 EOM-9MifOf AU OOSO-Yh,/iltPI• e .- nos ^a.'°I J'>'m.fnn +9""9..ft++.a'a MN Octi-vsn tawnaN maid to :, $J$Ia lal 1vLN3aWoafnN3 OGY1aOlO3'A.N003 CUM Oi' L —' .sxoxanunS•SS:MOONSils � _- ' ''""0M1.L1f1SH0J(DIVIII VJ4 _ Or'auN30 ADU3Ni NIViP1 OM ANON' i i I 1 i I t V 03610.11 0 el. 1.4irt Ma so) i o� Pt ^o, — — — — — — — — — — -�i-- —, yam„— • Id )W 1.1. 8" nr _ ^n a R= r v N 9 -Ate, +gF N� :T. N ai e9 ke.ba • : 4. z ti ,$ U './-* f I N el i is y .o9'�cr 3.K.fl[9 S t1 init L ,.�—A \ •/ .11°'' I1a., F 9 �. �o J / lie., ii • r = r...... 3'c,r?�r RI. to �°s ,..,; a LL r a �� CO la rW h r • 111 WP4 2P" cci U W,o 2 e. r \ �\ •b'- ga: 2 4 \} . LLwd g \ N zOao ik V) , '^�1—Up 3 ce V j r LL QOw20 WI O le"z W rzw0 LL -4 \ f A ,W s: 03 Z JT,pw O � \ ql g m W W W etZ LL L#`F OJ 10 ` \\• ` • iri 1'I a w h w JIL¢rp t 2 >s i.i 8 Z .... wog#z . èkk� ¢ _� �..�( � � P� N I- e\\ CC tII>" ii \ \\ o 1 \\ ` a le Z sC II n I Qz `"CC I W co i ' r rk b k il � H e g a La IA i { { I N y / -m„'f.u�6 — ~fit ik YY ,19'f19 0129 n -------- L..64 . sVag 5 * Lo- w N.yfpf.L9 11 tl aalMg i n i i 'I,I bit°: 1i r g$ Ut : !3.....i. C�tle! iiiid gC �¢3 = 3 }r, Qff�� eay Mil w as.4.w.w......wMe.................v.,....•,..ec ....-,.n w.. lets MEMORANDUM IL`PC TO: Ross Bachofer 2/18/2009 COLORADO FROM: Chris Gathman— Planner Ill SUBJECT: Calpine partial vacation & resolution & Pump Control Building for Calpine Mr. Bachofer, I have attached the plat maps and resolution partially vacating the Calpine USR. I have also found correspondence in the Calpine file indicating that the pump control building (under Building Permit# BCS-030285)to be located on the property at 7503 Highway 85 was not considered a substantial change by the Department of Planning Services in June of 2003. Therefore, an amended Use by Special Review Permit was not required. Let me know if you have any questions in this matter. I can be reached at(970)353-6100 ext. 3537 or at cgathman@co.weld.co.us. Mc4 tack Z 1 /2o0? C. Goodbye, So Long, Good Luck ` • Page 1 of 2 Kim Ogle From: Gary Aron [garon@calpine.com] Sent: Tuesday, May 29, 2007 3:22 PM To: Barry Boone (ppcland@pacbell.net); Bernie Pastorik (bernard.j.pastorik@xcelenergy.com); Bill Meier(billm@unitedpower.com); Bob Holland (rholland@nalco.com); Bob Schafish (RSchafish@RWBeck.com); Bob Stahl (bob.stahl@state.co.us); Brian Fitzpatrick(Brian Fitzpatrick); Brian McDonald (bmeieio@yahoo.com); Bruce Kroeker(bkroeker@tza4water.com); Chris Delaney; Chris Thorne (cthorne@hollandhart.com); Curtis Perry (Perry, Curtis); Cynthia Reynolds (reynolds.cynthia@epa.gov); Dana Echter (Dana.Echter@xcelenergy.com); Daniel C. Sampson (Daniel Sampson); Dave Adler(dadler@generalair.com); Dave Perkins (dperkins@rentk.com); Don Smith (donald.smith@xemkt.com); Donrich Ebuen (debuen@ciscocems.com); Ed Portaro (ed.portaro@harrisgrp.com); Elizabeth Mitchell (emitchell@hollandhart.com); Gary Grelli (gjg3@pge.com); Gregory S. Darvin (gdarvin@cox.net); Jack Ward (jward@dxgroup.com); Jackie Joyce (Jackie.Joyce@state.co.us); Jaclynn Peterson (jaclynnp@chemtreat.com); Jason Long; Jean Decker(Jean Decker); Jeff Haskins (Jeff.Haskins@xemkt.com); Jim Lynch (jim.lynch@xcelenergy.com); Aurora Water(JMurphy@ci.aurora.co.us); Kim Ogle; Lisa Darling (Lisa Darling [Idarling@ci.aurora.co.us]); Lloyd Land (land391957@aol.com); Mark Osterholt; Mark Safty (msafty@hollandhart.com); Mark Severts (marks@ttdusa.com); Matt Smith (msmith@interstatechemical.com); Mike Meyerkord (mmeyerkord@ondeo-nalco.com); Monica Mika; Randy Gotham (rgotham@nalco.com); Rich Chamberlain (rich.chamberlain@xcelenergy.com); Aurora Water (rmarsice@ci.aurora.co.us); Robert L. Hamilton (roberthamilton@aol.com); Sarah Gray (sgray@ciscocems.com); Scott Patefield (scott.patefield@state.co.us); Stephanie Edinger ('sedinger@hollandhart.com'); Thomas Lovell (thomas.lovell@state.co.us); Tom Dea (tdea@tza4water.com); Tom O'Donnell (Tom O'Donnell [TO'Donnell@hollandhart.com]); Walt Bastron (wbastron@ciscocems.com); Wayne Swafford (WSwafford@trigon-sheehan.com); William D Ward (Will) (Will.Ward@ElPaso.com); David Williams; Barbara McBride; Margie Hansen; Alan Roth; Robert Parker; Brian Fretwell; Brian Harenza; Aida Guloy; Anne Mastry; Barbara Flinn Hanna; Blake Stevens; Bob Fishman; Bob Matteis Bob Regan; Brad Richards; Courtney Layering; Darryl Nitschke; Dave Olsheski; Drew Metz; Gerard Murray; Ivan Kush; J. Steve Clark; Jackie Thomas; Jason Goodwin; Jay Creasy; Jay Dibble; Jeffry Sorenson; Jennifer Green; Jennifer Wagner; Jessica Fisher; Jim Shield; Keith Burrows; Kris Zadlo; Larry Vondrak; Lyle Fedje; Mark Osterholt; Marrianna Isaacs; Mayra Garcia-Lopez; Michael Dragoni; Mike Rogers; Nancy Murray; Nick Gaglia; Norma Miller; Patrick Doran; Paul Kraft; Paula Taylor; Peter So; Rosemary Antonopoulos; Ryan Bowles; Ryan Herrera; Ryan Wanner; Saul Rapkin; Scott Vickers; Sofya Ovcharenko; Timothy Dierauf; Tina Romero; Todd Thornton; Tom Long; William Valagura; Pam McPeck; Aurora Water(JMurphy@ci.aurora.co.us); Aurora Water (rmarsice@ci.aurora.co.us); Brian Fitzpatrick (Brian Fitzpatrick); Gary Aron; Bonnette Bachelor (bbachelor@interstatechemical.com); Matt Smith (msmith@interstatechemical.com); Sissy Ryan Cc: BSEC OPS; RMEC OPS Subject: Goodbye, So Long, Good Luck Dear Everyone: It's with a heavy heart, but fond memories that I say goodbye to Calpine Corporation, Rocky Mountain and Blue Spruce Energy Centers. It's been a good 6-1/2 years, both in California and Colorado, watching the fruits of our labor bringing RMEC out of the ground and into operation. My last day will be Friday, June 8th. I will be working for Merrick and Company, an AE firm here in the Denver area. My contact information is below. For all dealings with RMEC in the areas of Operations Management, Environmental Compliance, Plant Safety, Engineering related issues, Permitting, DOE Reporting, GADS Reporting, Water Reporting and Accounting, Billing Statements, Event Notifications and any other grunt work I used to do, please contact Mr. Jim Gooding, GeneralManagerat303-536-2550orviae-mailatjimg@calpine.com. r Iii 6O-1 r Goodbye, So Long, Good Luck - • Page 2 of 2 Gary Aron Mechanical Discipline Lead Facilities and Science Technologies Merrick and Company 2450 S. Peoria Street Aurora, CO 80014 303-353-3522 main 303-710-3363 cell gary.aron@merrick.com Gary M. Aron, PE Operations Manager Rocky Mountain Energy Center 6211 Weld County Road 51 Keenesburg, CO 80643 (303) 536-2518 (303) 536-2548 Fax (303) 710-3363 Cell (303) 536-2556 Control Room L:AL-fit IA t5Q-- Weld County Planning Department Wpl ( n 'i`Y Planning D pa13rtm nt J GREELEY OFFICE IT. WEST BUILDING OCT 1 2 2007 OCT 1 0 2007 UNITED STATES BANKRUPTCY COURT RECEIVED SOUTHERN DISTRICT OF NEW YORK r LThciVED In re ) Chapter 11 Calpine Corporation,et al., ) Case No. 05-60200(BRL) Debtors. ) Jointly Administered NOTICE OF(I)CONFIRMATION HEARING AND OBJECTION DEADLINE WITH RESPECT TO THE DEBTORS' PLAN, AND(II)SOLICITATION AND VOTING PROCEDURES TO ALL CREDITORS, EQUITY INTEREST HOLDERS AND PARTIES IN INTEREST: 1. Approval of Disclosure Statement and Solicitation Procedures. On September 26, 2007, the United States Bankruptcy Court for the Southern District of New York (the"Bankruptcy Court") entered an order (the "Solicitation Procedures Order") approving the Fourth Amended Disclosure Statement For Debtors' Fourth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code, (the "Disclosure Statement") for the Debtors'Fourth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code (as amended from time to time and including all exhibits and supplements, the "Plan"), as containing adequate information, as required under section 1125(a) of title 11 of the United States Code (the`Bankruptcy Code"),and authorized the Debtors to solicit votes with regard to the acceptance or rejection of the Plan. All capitalized terms used, but not defined herein, shall have the meanings ascribed to such terms in the Plan or the Disclosure Statement,as applicable. 2. Plan Supplement. The Debtors have filed certain portions of the supplement to the Plan (the "Plan Supplement"), and will file a complete version of the Plan Supplement on a date that is no later than fourteen days prior to November 30,2007 or such later date as may be approved by the Bankruptcy Court on notice to parties in interest(the"Plan Supplement Filing Date"). After the Plan Supplement Filing Date,the Plan Supplement will be available online at http://www.kccllc.net/calpine. If you would like to request a copy of the Plan Supplement,please write to Calpine Corporation,c/o Kurtzman Carson Consultants LLC, 2335 Alaska Avenue, El Segundo, California 90245,call(888)249-2792,or email calpineinfo@kccllc.com. 3. Confirmation Hearing. A hearing to confirm the Plan (the "Confirmation Hearing") will commence on December 18,2007 before the Honorable Burton R.Lifland,United States Bankruptcy Judge,located at One Bowling Green, New York, New York 10004. The Confirmation Hearing may be continued from time to time by announcing such continuance in open court or otherwise, without further notice to parties in interest. The Bankruptcy Court, in its discretion and prior to the Confirmation Hearing, may put in place additional procedures governing the Confirmation Hearing. The Plan may be modified, if necessary,prior to, during, or as a result of the Confirmation Hearing,without further notice to interested parties. 4. Record Date. The Record Date for purposes of determining which Holders of Claims and Interests are entitled to vote on the Plan is September 27,2007. 5. Voting Deadline. The Bankruptcy Court has established November 30, 2007, at 4:00 p.m. prevailing Pacific Time as the voting deadline (the "Voting Deadline"). If you hold a Claim or Interest against one of the Debtors as of the Record Date, and are entitled to vote to accept or reject the Plan,you have received a Ballot or Master Ballot and voting instructions appropriate for your Claim(s). For your vote to accept or reject the Plan to be counted, you must complete all required information on the Ballot, execute, and return the completed Ballot in accordance with the voting instructions. Any failure to follow the voting instructions included with the Ballot may disqualify your Ballot and your vote. 6. Objections to the Plan. The Bankruptcy Court has established November 30,2007, at 4:00 p.m. prevailing Eastern Time, as the last date and time for filing and serving objections to the Confirmation (the "Plan Objection Deadline"). Any objections to the Plan must be in writing; conform to the Bankruptcy Rules and the Local Rules;state the name and address of the objecting party and the amount and nature of the Claim or Interest of .. such Entity; state with particularity the basis and nature of any objection to the Plan and, if practicable, a proposed modification to the Plan that would resolve such objection; and be filed, together with proof of service, with the Bankruptcy Court and served so that they are actually received no later than the Plan Objection Deadline,by (a)the Clerk of the Bankruptcy Court, Judge Burton R. Lifland's Chambers, Room 517, One Bowling Green, New York, New York 10004; (b)counsel to the Debtors, Kirkland and Ellis LLP, Citigroup Center, 153 East 53rd Street, New York, New York 10022, Attn.: Richard M. Cieri, and Kirkland & Ellis LLP, 200 East Randolph Street, Chicago, Illinois 60601, Attn.: David R. Seligman; (c) the Office of the United States Trustee for the Southern District of New York, 33 Whitehall Street, 21" Floor,New York,New York 10004, Attn.: Paul Schwartzberg; (d) counsel to the Unofficial Committee of Second Lien Debtholders,Paul Weiss Rifkind Wharton&Garrison LLP, 1285 Avenue of the Americas, New York, NY 10019-6064, Attn.: Alan W. Komberg, Andrew N. Rosenberg, Elizabeth R. McColm; (e)counsel to the Official Committee of Unsecured Creditors,Akin Gump Strauss Hauer&Feld LLP, 590 Madison Avenue, New York, New York 10022-2524, Attn.: Michael S. Stamer, Philip C. Dublin,Alexis Freeman; (f) counsel to the Official Committee of Equity Security Holders, Fried, Frank, Harris, Shriver & Jacobson LLP, One New York Plaza,New York,New York 10004,Attn.: Brad E. Scheler, Gary Kaplan; and(g) counsel to Credit Suisse, as administrative agent under the debtor in possession financing facility, Simpson Thacher & Bartlett LLP, 425 Lexington Avenue,New York,New York 10017,Attn.: Peter V.Panteleo and Robert H.Trust. 7. Inquiries. The Debtors will serve either paper copies of, or a CD-ROM containing, the Solicitation Procedures Order, the Disclosure Statement, and all exhibits to the Disclosure Statement, including the Plan,on the Core Group,all parties in interest on the 2002 List as of the Record Date and all parties entitled to vote to accept or reject the Plan. Holders of Claims or Interests who are entitled to vote to accept or reject the Plan shall receive a Solicitation Package, containing paper copies of this Confirmation Hearing Notice, applicable Ballot(s) and/or Master Ballot(s),and the Solicitation Procedures. The Solicitation Package(except the Ballots)may also be obtained from Kurtzman Carson Consultants' (the "Claims and Solicitation Agent") website at www.kccllc.net/calpine or by writing to Calpine Corporation, do Kurtzman Carson Consultants LLC, 2335 Alaska Avenue, El Segundo, California 90245, Attention: Ballot Processing Center, by calling (888) 249-2792, or by emailing calpineinfo@kccllc.com. For Holders of Claims or Interests, the Claims and Solicitation Agent will answer questions regarding the procedures and requirements for voting to accept or reject the Plan and for objecting to the Plan, provide additional copies of all materials, and oversee the voting tabulation. The Claims and Solicitation Agent can be contacted by writing to Calpine Corporation,c/o Kurtzman Carson Consultants LLC,2335 Alaska Avenue, El Segundo, California 90245, Attention: Ballot Processing Center, by calling (888) 249-2792, or by emailing calpineinfo@kccllc.com. For Holders of Claims or Interests on account of publicly-traded securities, Financial Balloting Group LLC (the "Special Voting Agent") will also answer questions regarding the procedures and requirements for voting to accept or reject the Plan and for objecting to the Plan,provide additional copies of all materials, and oversee the voting tabulation. The Special Voting Agent can be contacted by writing to Calpine Corporation do Financial Balloting Group, LLC, 757 Third Avenue, 3rd Floor, New York, New York 10017, Attention:Ballot Processing Center or by calling(866)433-0895. 8. Temporary Allowance of Claims for Voting Purposes. Holders of Claims and Interests that are subject to a pending objection by the Debtors as of the Record Date cannot vote on the Plan;provided,however,that if the Debtors object to only a portion of a Claim or Interest, such Claim or Interest may be voted in the undisputed amount. Moreover, Holders of Claims and Interests cannot vote any disputed portion of its Claim or Interest unless one or more of the following has taken place at least five business days before the Voting Deadline: (a)an order of the Bankruptcy Court is entered allowing such Claim or Interest pursuant to section 502(b)of the Bankruptcy Code, after notice and a hearing; (b)an order of the Bankruptcy Court is entered temporarily allowing such Claim or Interest for voting purposes only pursuant to Bankruptcy Rule 3018(a),after notice and a hearing;(c)a stipulation or other agreement is executed between the Holder of such Claim or Interest and the Debtors resolving the objection and allowing such Claim or Interest in an agreed upon amount; (d)a stipulation or other agreement is executed between the Holder of the such Claim or Interest and the Debtors temporarily allowing the Holder of such Claim or Interest to vote its Claim or Interest in an agreed upon amount; or (e)the pending objection to the such Claim or Interest is voluntarily withdrawn by the Debtors (each, a"Resolution Event"). If an objection to a Disputed Claim or Interest is filed by the Debtors after the Record Date but before fifteen days prior to the Confirmation Hearing, the Debtors' notice of objection will inform such Holder of the rules applicable to Claims and Interests that have been objected to,and the procedures for seeking a Resolution Event. If an objection to Claim or Interest is filed on or after fifteen days before the Voting Deadline, such Claim or Interest shall be temporarily allowed for voting purposes only, without further action by the Holder of such Claim or Interest and without further order of the Bankruptcy Court. 9. Distribution Record Date. The Bankruptcy Court has approved the date that the Confirmation Order is entered on the docket in these Chapter 11 Cases as the Distribution Record Date for purposes of 2 determining which Creditors and Equity Interest Holders are entitled to receive distributions under the Plan, except with respect to Claims and Interests based on publicly-traded Securities (which are subject to the surrender provisions of Article VII.D.10 of the Plan. 10. Release, Exculpation, and Injunction Language in the Plan. Please be advised that the Plan contains certain release, exculpation, and injunction provisions. Holders of Claims and Interests (i) voting to accept the Plan or (ii) abstaining from voting on the Plan and electing not to reject the release provisions, shall be deemed to accept the release provisions in Article VIII of the Plan. Holders of Claims and Interests that abstain from voting on the Plan may accept or reject the release provisions in Article VIII of the Plan. A. Releases by Holders of Claims and Interests. Except as otherwise specifically provided in the Plan or Plan Supplement, on and after the Effective Date, Holders of Claims and Interests (a) voting to accept the Plan or(b) abstaining from voting on the Plan and electing not to opt out of the release contained in this paragraph (which by definition,does not include Holders of Claims and Interests who are not entitled to vote in favor of or against the Plan in fact do not so vote), shall be deemed to have conclusively, absolutely, unconditionally,irrevocably,and forever,released and discharged the Debtors,the Reorganized Debtors, and the Released Parties from any and all Claims, Interests, obligations, rights, suits, damages, Causes of Action, remedies,and liabilities whatsoever, including any derivative Claims asserted on behalf of a Debtor, whether known or unknown, foreseen or unforeseen, existing or hereafter arising, in law, equity or otherwise, that such Entity would have been legally entitled to assert (whether individually or collectively), based on or relating to, or in any manner arising from, in whole or in part, the Debtors, the Debtors' restructuring, the Debtors' Chapter 11 Cases, the purchase, sale, or rescission of the purchase or sale of any security of the Debtors, the subject matter of, or the transactions or events giving rise to, any Claim or Interest that is treated in the Plan, the business or contractual arrangements between any Debtor and any Released Party, the restructuring of Claims and Interests prior to or in the Chapter 11 Cases,the negotiation,formulation, or preparation of the Plan and Disclosure Statement, or related agreements, instruments, or other documents, upon any other act or omission,transaction, agreement, event,or other occurrence taking place on or before the Effective Date,other than Claims or liabilities arising out of or relating to any act or omission of a Debtor, a Reorganized Debtor, or a Released Party that constitutes a failure to perform the duty to act in good faith, with the care of an ordinarily prudent person and in a manner the Debtor, the Reorganized Debtor, or the Released Party reasonably believed to be in the best interests of the Debtors (to the extent such duty is imposed by applicable non-bankruptcy law) where such failure to perform constitutes willful misconduct or gross negligence. B. Injunction. Except as otherwise expressly provided in the Plan or for obligations issued pursuant to the Plan, all Entities who have held, hold, or may hold Claims against the Released Parties and Exculpated Parties, and all Entities holding Interests, are permanently enjoined, from and after the Effective Date, from: (1)commencing or continuing in any manner any action or other proceeding of any kind on account of or in connection with or with respect to any such Claims or Interests; (2)enforcing, attaching, collecting,or recovering by any manner or means any judgment, award,decree or order against such Entities on account of or in connection with or with respect to any such Claims or Interests; (3)creating, perfecting, or enforcing any encumbrance of any kind against such Entities or the property or estates of such Entities on account of or in connection with or with respect to any such Claims or Interests; (4)asserting any right of setoff, subrogation, or recoupment of any kind against any obligation due from such Entities or against the property or Estates of such Entities on account of or in connection with or with respect to any such Claims or Interests unless such Holder has Filed a motion requesting the right to perform such setoff on or before the Confirmation Date, and notwithstanding an indication in a Proof of Claim or Interest or otherwise that such Holder asserts, has,or intends to preserve any right of setoff pursuant to section 553 of the Bankruptcy Code or otherwise; and(5)commencing or continuing in any manner any action or other proceeding of any kind on account of or in connection with or with respect to any such Claims or Interests released or settled pursuant to the Plan. You are advised to carefully review and consider the Plan, including the release, exculpation, and injunction provisions,as your rights might be affected. Calpine Corporation 3 UNITED STATES BANKRUPTCY COURT Weld County Planning Department SOUTHERN DISTRICT OF NEW YORK GREELEY OFFICE OCT 1 1 2007 In re ) Chapter 11 RECEIVED Calpine Corporation, et al. ) Case No.05-60200(BRL) Debtors. ) Jointly Administered NOTICE OF(I)CONFIRMATION HEARING AND OBJECTION DEADLINE WITH RESPECT TO THE DEBTORS'PLAN, AND(II)SOLICITATION AND VOTING PROCEDURES TO ALL CREDITORS,EQUITY INTEREST HOLDERS AND PARTIES IN INTEREST: 1. Approval of Disclosure Statement and Solicitation Procedures. On September 26, 2007, the United States Bankruptcy Court for the Southern District of New York (the "Bankruptcy Court") entered an order (the "Solicitation Procedures Order") approving the Fourth Amended Disclosure Statement For Debtors' Fourth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code, (the "Disclosure Statement") for the Debtors'Fourth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code(as amended from time to time and including all exhibits and supplements, the "Plan"), as containing adequate information, as required under section 1125(a) of title 11 of the United States Code (the`Bankruptcy Code"),and authorized the Debtors to solicit votes with regard to the acceptance or rejection of the Plan. All capitalized terms used, but not defined herein, shall have the meanings ascribed to such terms in the Plan or the Disclosure Statement,as applicable. 2. Plan Supplement. The Debtors have filed certain portions of the supplement to the Plan (the "Plan Supplement"), and will file a complete version of the Plan Supplement on a date that is no later than fourteen days prior to November 30,2007 or such later date as may be approved by the Bankruptcy Court on notice to parties in interest(the"Plan Supplement Filing Date"). After the Plan Supplement Filing Date,the Plan Supplement will be available online at http://www.kccllc.net/calpine. If you would like to request a copy of the Plan Supplement,please write to Calpine Corporation,c/o Kurtzman Carson Consultants LLC, 2335 Alaska Avenue, El Segundo, California 90245,call(888)249-2792,or email calpineinfo@kccllc.com. 3. Confirmation Hearing. A hearing to confirm the Plan (the "Confirmation Hearing") will commence on December 18,2007 before the Honorable Burton R. Lifland,United States Bankruptcy Judge, located at One Bowling Green, New York, New York 10004. The Confirmation Hearing may be continued from time to time by announcing such continuance in open court or otherwise, without further notice to parties in interest. The Bankruptcy Court, in its discretion and prior to the Confirmation Hearing, may put in place additional procedures governing the Confirmation Hearing. The Plan may be modified, if necessary,prior to,during, or as a result of the Confirmation Hearing,without further notice to interested parties. 4. Record Date. The Record Date for purposes of determining which Holders of Claims and Interests are entitled to vote on the Plan is September 27,2007. 5. Voting Deadline. The Bankruptcy Court has established November 30, 2007, at 4:00 p.m. prevailing Pacific Time as the voting deadline (the "Voting Deadline"). If you hold a Claim or Interest against one of the Debtors as of the Record Date,and are entitled to vote to accept or reject the Plan,you have received a Ballot or Master Ballot and voting instructions appropriate for your Claim(s). For your vote to accept or reject the Plan to be counted, you must complete all required information on the Ballot, execute, and return the completed Ballot in accordance with the voting instructions. Any failure to follow the voting instructions included with the Ballot may disqualify your Ballot and your vote. 6. Objections to the Plan. The Bankruptcy Court has established November 30,2007,at 4:00 p.m. prevailing Eastern Time, as the last date and time for filing and serving objections to the Confirmation (the"Plan Objection Deadline"). Any objections to the Plan must be in writing; conform to the Bankruptcy Rules and the Local Rules;state the name and address of the objecting party and the amount and nature of the Claim or Interest of such Entity; state with particularity the basis and nature of any objection to the Plan and, if practicable, a proposed modification to the Plan that would resolve such objection; and be filed, together with proof of service, with the Bankruptcy Court and served so that they are actually received no later than the Plan Objection Deadline,by(a)the Clerk of the Bankruptcy Court, Judge Burton R. Lifland's Chambers, Room 517, One Bowling Green, New York, New York 10004; (b)counsel to the Debtors, Kirkland and Ellis LLP, Citigroup Center, 153 East 53rd Street, New York, New York 10022, Attn.: Richard M. Cieri, and Kirkland & Ellis LLP, 200 East Randolph Street, Chicago, Illinois 60601, Attn.: David R. Seligman; (c) the Office of the United States Trustee for the Southern District of New York, 33 Whitehall Street, 21" Floor,New York,New York 10004, Attn.: Paul Schwartzberg; (d) counsel to the Unofficial Committee of Second Lien Debtholders,Paul Weiss Rifkind Wharton&Garrison LLP, 1285 Avenue of the Americas, New York, NY 10019-6064, Attn.: Alan W. Kornberg, Andrew N. Rosenberg, Elizabeth R. McColm;(e)counsel to the Official Committee of Unsecured Creditors,Akin Gump Strauss Hauer&Feld LLP, 590 Madison Avenue,New York,New York 10022-2524, Attn.: Michael S. Stamer, Philip C. Dublin, Alexis Freeman; (1) counsel to the Official Committee of Equity Security Holders, Fried, Frank, Harris, Shriver & Jacobson LLP, One New York Plaza,New York,New York 10004, Attn.: Brad E. Scheler,Gary Kaplan; and(g) counsel to Credit Suisse, as administrative agent under the debtor in possession financing facility, Simpson Thacher & Bartlett LLP, 425 Lexington Avenue,New York,New York 10017,Attn.: Peter V.Panteleo and Robert H.Trust. 7. Inquiries. The Debtors will serve either paper copies of, or a CD-ROM containing, the Solicitation Procedures Order, the Disclosure Statement, and all exhibits to the Disclosure Statement, including the Plan,on the Core Group,all parties in interest on the 2002 List as of the Record Date and all parties entitled to vote to accept or reject the Plan. Holders of Claims or Interests who are entitled to vote to accept or reject the Plan shall receive a Solicitation Package, containing paper copies of this Confirmation Hearing Notice, applicable Ballot(s) and/or Master Ballot(s), and the Solicitation Procedures. The Solicitation Package(except the Ballots)may also be obtained from Kurtzman Carson Consultants' (the "Claims and Solicitation Agent") website at www.kccllc.net/calpine or by writing to Calpine Corporation, do Kurtzman Carson Consultants LLC, 2335 Alaska Avenue, El Segundo, California 90245, Attention: Ballot Processing Center, by calling (888) 249-2792, or by emailing calpineinfo@kccllc.com. For Holders of Claims or Interests, the Claims and Solicitation Agent will answer questions regarding the procedures and requirements for voting to accept or reject the Plan and for objecting to the Plan, provide additional copies of all materials, and oversee the voting tabulation. The Claims and Solicitation Agent can be contacted by writing to Calpine Corporation,do Kurtzman Carson Consultants LLC,2335 Alaska Avenue, El Segundo, California 90245, Attention: Ballot Processing Center, by calling (888) 249-2792, or by emailing calpineinfo@kccllc.com. For Holders of Claims or Interests on account of publicly-traded securities, Financial Balloting Group LLC (the "Special Voting Agent") will also answer questions regarding the procedures and requirements for voting to accept or reject the Plan and for objecting to the Plan,provide additional copies of all materials, and oversee the voting tabulation. The Special Voting Agent can be contacted by writing to Calpine Corporation c/o Financial Balloting Group, LLC, 757 Third Avenue, 3rd Floor, New York, New York 10017, Attention:Ballot Processing Center or by calling(866)433-0895. 8. Temporary Allowance of Claims for Voting Purposes. Holders of Claims and Interests that are subject to a pending objection by the Debtors as of the Record Date cannot vote on the Plan;provided,however,that if the Debtors object to only a portion of a Claim or Interest. such Claim or Interest may be voted in the undisputed amount. Moreover,Holders of Claims and Interests cannot vote any disputed portion of its Claim or Interest unless one or more of the following has taken place at least five business days before the Voting Deadline: (a)an order of the Bankruptcy Court is entered allowing such Claim or Interest pursuant to section 502(b)of the Bankruptcy Code, after notice and a hearing; (b)an order of the Bankruptcy Court is entered temporarily allowing such Claim or Interest for voting purposes only pursuant to Bankruptcy Rule 3018(a),after notice and a hearing;(c)a stipulation or other agreement is executed between the Holder of such Claim or Interest and the Debtors resolving the objection and allowing such Claim or Interest in an agreed upon amount; (d)a stipulation or other agreement is executed between the Holder of the such Claim or Interest and the Debtors temporarily allowing the Holder of such Claim or Interest to vote its Claim or Interest in an agreed upon amount; or (e)the pending objection to the such Claim or Interest is voluntarily withdrawn by the Debtors(each, a"Resolution Event"). If an objection to a Disputed Claim. or Interest is filed by the Debtors after the Record Date but before fifteen days prior to the Confirmation Hearing, the Debtors' notice of objection will inform such Holder of the rules applicable to Claims and Interests that have been objected to,and the procedures for seeking a Resolution Event. If an objection to Claim or Interest is filed on or after fifteen days before the Voting Deadline, such Claim or Interest shall be temporarily allowed for voting purposes only, without further action by the Holder of such Claim or Interest and without further order of the Bankruptcy Court. 9. Distribution Record Date. The Bankruptcy Court has approved the date that the Confirmation Order is entered on the docket in these Chapter 11 Cases as the Distribution Record Date for purposes of 2 determining which Creditors and Equity Interest Holders are entitled to receive distributions under the Plan, except with respect to Claims and Interests based on publicly-traded Securities (which are subject to the surrender provisions of Article V II.D.10 of the Plan. 10. Release, Exculpation, and Injunction Language in the Plan. Please be advised that the Plan contains certain release,exculpation, and injunction provisions. Holders of Claims and Interests (i)voting to accept the Plan or (ii) abstaining from voting on the Plan and electing not to reject the release provisions, shall be deemed to accept the release provisions in Article VIII of the Plan. Holders of Claims and Interests that abstain from voting on the Plan may accept or reject the release provisions in Article VIII of the Plan. A. Releases by Holders of Claims and Interests. Except as otherwise specifically provided in the Plan or Plan Supplement, on and after the Effective Date, Holders of Claims and Interests (a) voting to accept the Plan or(b) abstaining from voting on the Plan and electing not to opt out of the release contained in this paragraph (which by definition, does not include Holders of Claims and Interests who are not entitled to vote in favor of or against the Plan in fact do not so vote),shall be deemed to have conclusively,absolutely, unconditionally, irrevocably, and forever,released and discharged the Debtors,the Reorganized Debtors,and the Released Parties from any and all Claims, Interests, obligations, rights, suits, damages, Causes of Action, remedies, and liabilities whatsoever, including any derivative Claims asserted on behalf of a Debtor,whether known or unknown, foreseen or unforeseen, existing or hereafter arising, in law, equity or otherwise, that such Entity would have been legally entitled to assert (whether individually or collectively), based on or relating to, or in any manner arising from, in whole or in part, the Debtors, the Debtors' restructuring, the Debtors' Chapter 11 Cases, the purchase, sale, or rescission of the purchase or sale of any security of the Debtors, the subject matter of, or the transactions or events giving rise to, any Claim or Interest that is treated in the Plan, the business or contractual arrangements between any Debtor and any Released Party, the restructuring of Claims and Interests prior to or in the Chapter 11 Cases,the negotiation, formulation,or preparation of the Plan and Disclosure Statement, or related agreements, instruments, or other documents, upon any other act or omission, transaction, agreement, event, or other occurrence taking place on or before the Effective Date,other than Claims or liabilities arising out of or relating to any act or omission of a Debtor, a Reorganized Debtor, or a Released Party that constitutes a failure to perform the duty to act in good faith, with the care of an ordinarily prudent person and in a manner the Debtor, the Reorganized Debtor, or the Released Party reasonably believed to be in the best interests of the Debtors (to the extent such duty is imposed by applicable non-bankruptcy law) where such failure to perform constitutes willful misconduct or gross negligence. B. Injunction. Except as otherwise expressly provided in the Plan or for obligations issued pursuant to the Plan, all Entities who have held, hold, or may hold Claims against the Released Parties and Exculpated Parties, and all Entities holding Interests, are permanently enjoined,from and after the Effective Date, from: (1)commencing or continuing in any manner any action or other proceeding of any kind on account of or in connection with or with respect to any such Claims or Interests; (2)enforcing, attaching, collecting,or recovering by any manner or means any judgment,award,decree or order against such Entities on account of or in connection with or with respect to any such Claims or Interests; (3)creating, perfecting, or enforcing any encumbrance of any kind against such Entities or the property or estates of such Entities on account of or in connection with or with respect to any such Claims or Interests; (4)asserting any right of setoff, subrogation, or recoupment of any kind against any obligation due from such Entities or against the property or Estates of such Entities on account of or in connection with or with respect to any such Claims or Interests unless such Holder has Filed a motion requesting the right to perform such setoff on or before the Confirmation Date, and notwithstanding an indication in a Proof of Claim or Interest or otherwise that such Holder asserts, has,or intends to preserve any right of setoff pursuant to section 553 of the Bankruptcy Code or otherwise; and(5) commencing or continuing in any manner any action or other proceeding of any kind on account of or in connection with or with respect to any such Claims or Interests released or settled pursuant to the Plan. You are advised to carefully review and consider the Plan, including the release,exculpation, and injunction provisions,as your rights might be affected. Calpine Corporation 3 KIRICLAND&ELLIS LLP Hearing Date: August 8,2007 at 10:00 a.m.(ET) Citigroup Center Objection Deadline:July 30,2007 at 5:00 p.m.(El) 153 East 53`d Street New York,New York 10022-4611 Telephone: (212)446-4800 U/eld Ceu,-i Department Facsimile: (212)446-4900 G2FFLFY OFFICE Richard M. Cieri(RC 6062) JL J 9 00 Marc Kieselstein(admitted pro hac vice) David R. Seligman(admitted pro hac vice) Edward O. Sassower(ES 5823) RECEIVED Counsel for the Debtors UNITED STATES BANKRUPTCY COURT SOUTHERN DISTRICT OF NEW YORK In re: ) Chapter 11 Calpine Corporation, et al.. ) Case No. 05-60200(BRL) Debtors. ) Jointly Administered ) NOTICE OF DEBTORS' MOTION FOR ENTRY OF AN ORDER(A)APPROVING THE ADEQUACY OF THE DEBTORS'DISCLOSURE STATEMENT; (B)APPROVING SOLICITATION AND NOTICE PROCEDURES WITH RESPECT TO CONFIRMATION OF THE DEBTORS' PROPOSED PLAN OF REORGANIZATION; (C)APPROVING THE FORM OF VARIOUS BALLOTS AND NOTICES IN CONNECTION THEREWITH; AND (D)SCHEDULING CERTAIN DATES WITH RESPECT THERETO PLEASE TAKE NOTICE that at 10:00 a.m. (ET) on August 8, 2007, the Debtors, by their counsel, shall appear before the Honorable Judge Burton R. Lifland, at the United States Bankruptcy Court for the Southern District of New York, Alexander Hamilton Custom House, One Bowling Green, New York,New York 10004-1408, Room 623, or as soon thereafter as counsel may be heard, and present the Debtors' motion for entry of an order (the "Solicitation Procedures Order"): (a)approving the adequacy of the Debtors' disclosure statement (as may be amended from time to time and including all supplements, the "Disclosure Statement"); (b)approving solicitation and notice procedures with respect to confirmation of the Debtors' proposed plan of reorganization (as may be amended from time to time and including all supplements, the "Plan"); (c)approving the forms of various ballots and notices in connection therewith; and(d)scheduling certain dates with respect thereto(the"Motion"). PLEASE TAKE FURTHER NOTICE that copies of the Disclosure Statement, the Plan, the Motion, and related documents can be obtained by accessing the Bankruptcy Court's website at http://www.nysb.uscourts.gov, by accessing the Claims and Solicitation Agent's website at http://www.kccllc.net/calpine,by writing to Calpine Corporation, c/o Kurtzman Carson Consultants LLC, K&E 11935727.1 2335 Alaska Avenue, El Segundo, California 90245, by calling (888) 249-2792, or by emailing calpineinfo@kccllc.com. PLEASE TAKE FURTHER NOTICE that the Motion requests the Bankruptcy Court to establish the date that is two business days after entry of the Solicitation Procedures Order as the record date for determining which creditors and shareholders are entitled to vote to accept the Plan. PLEASE TAKE FURTHER NOTICE that the hearing on the Motion may be adjourned thereafter from time to time without further notice. PLEASE TAKE FURTHER NOTICE that objections to the Motion, if any, must be in writing, shall conform to the Federal Rules of Bankruptcy Procedure and the Local Rules of the Bankruptcy Court and shall be filed with the Bankruptcy Court electronically by registered users of the Bankruptcy Court's case filing system (the User's Manual for the Electronic Case Filing System can be found at http://www.nysb.uscourts.gov, the official website for the Bankruptcy Court) and, by all other parties in interest, on a 3.5 inch disk, preferably in Portable Document Format (PDF), WordPerfect or any other Windows-based word processing format(in either case, with a hard copy delivered directly to Chambers) and shall be served upon: (a)counsel to the Debtors,Kirkland and Ellis LLP, Citigroup Center, 153 East 53rd Street, New York, New York 10022, Attn.: Richard M. Cieri, Edward O. Sassower, and Kirkland & Ellis LLP, 200 East Randolph Street, Chicago,Illinois 60601, Attn.: David R. Seligman; (b)the Office of the United States Trustee for the Southern District of New York, 33 Whitehall Street, 2O Floor, New York, New York 10004, Attn.: Paul Schwartzberg; (c)counsel to the Unofficial Committee of Second Lien Debt holders, Paul Weiss Rifkind Wharton & Garrison LLP, 1285 Avenue of the Americas, New York, NY 10019-6064, Attn.: Alan W. Kornberg, Andrew N. Rosenberg, Elizabeth R. McColm; (d)counsel to the Official Committee of Unsecured Creditors, Akin Gump Strauss Hauer & Feld LLP, 590 Madison Avenue, New York, New York 10022-2524, Attn.: Michael S. Stamer, Philip C. Dublin, Alexis Freeman; (e)counsel to the Official Committee of Equity Security Holders, Fried, Frank Harris, Shriver & Jacobson LLP, One New York Plaza, New York, New York 10004, Atha.: Brad E. Scheler, Gary Kaplan; and (0 counsel to Credit Suisse, as administrative agent under the debtor in possession financing facility, Simpson Thacher & Bartlett LLP, 425 Lexington Avenue, New York, New York 10017, Attn.: Peter V. Panteleo, Robert H. Trust, so as to be received by no later than July 30, 2007 at 5:00 p.m. (ET). PLEASE TAKE FURTHER NOTICE that objections to the Motion, if any, should state with particularity the basis and nature of the objection and should propose an insert for or modification to the Disclosure Statement that would resolve such objection. Dated: July 2,2007 Respectfully submitted, Calpine Corporation 2 K&E 11935727.1 taw , Weld County Planning Department UNITED STATES BANKRUPTCY COURT SOUTHWEST BUILDING SOUTHERN DISTRICT OF NEW YORK MAY 1 8 ZOOS ) RECEIVED In re: ) Chapter 11 Calpine Corporation, et al., ) Case No. 05-60200 (BRL) Debtors. ) Jointly Administered NOTICE OF DEADLINE REQUIRING FILING OF PROOFS OF CLAIM ON OR BEFORE AUGUST 1, 2006 TO ALL PERSONS AND ENTITIES WITH CLAIMS AGAINST ANY OF THE 273 DEBTOR ENTITIES LISTED ON APPENDIX A ATTACHED HERETO: The United States Bankruptcy Court for the Southern District of New York has entered an Order establishing August 1, 2006 at 5:00 p.m. (prevailing Eastern time) (the "Bar Date") as the last date for each person or entity (including individuals, partnerships, corporations, joint ventures, trusts and governmental units) to file a proof of claim against any of the Debtors listed on Appendix A to this Notice(the "Debtors"). The Bar Date and the procedures set forth below for filing proofs of claim apply to all claims against the Debtors that arose prior to December 20, 2005, the date on which the Debtors commenced cases under Chapter 11 of the United States Bankruptcy Code, except for those holders of the claims listed in Section 4 below that are specifically excluded from the Bar Date filing requirement. 1. WHO MUST FILE A PROOF OF CLAIM You MUST timely file a proof of claim to vote on a Chapter 11 plan filed by the Debtors or to share in distributions from the Debtors' bankruptcy estates if you have a claim that arose prior to December 20, 2005 (the "Filing Date"), and it is not one of the types of claims described in Section 4 below. Claims based on acts or omissions of the Debtors that occurred before the Filing Date, must be filed on or prior to the Bar Date, even if such claims are not now fixed, liquidated or certain or did not mature or become fixed, liquidated or certain before the Filing Date. Under section 101(5) of the Bankruptcy Code and as used in this Notice, the word "claim" means: (a) a right to payment, whether or not such right is reduced to judgment, liquidated, unliquidated, fixed, contingent, matured, unmatured, disputed, undisputed, legal, equitable, secured, or unsecured; or (b) a right to an equitable remedy for breach of performance if such breach gives rise to a right to payment, whether or not such right to an equitable remedy is reduced to judgment, fixed, contingent, matured, unmatured, disputed, undisputed, secured, or unsecured. 2. WHAT TO FILE Your filed proof of claim must conform substantially to Official Form No. 10. A case- specific proof of claim form accompanies this Notice. The Debtors are enclosing a proof of claim form for use in these cases. If your claim is scheduled by the Debtors, the form also sets forth the amount of your claim as scheduled by the Debtors, the specific Debtors against which the claim is scheduled and whether the claim is scheduled as disputed, contingent or unliquidated. You will receive a different proof of claim form for each claim scheduled in your name by the Debtors. You may utilize the proof of claim form(s) provided by the Debtors to file your claim. Additional proof of claim forms may be obtained at www.uscourts.gov/bankform and at www.kccllc.net/calpine. All proof of claim forms must be signed by the claimant or, if the claimant is not an individual, by an authorized agent of the claimant. It must be written in English and be denominated in United States dollars. You should attach to your completed proof of claim any documents on which the claim is based (if voluminous, attach a summary) or an explanation as to why the documents are not available. Any holder of a claim against more than one Debtor must file a separate proof of claim with respect to each such Debtor and all holders of claims must identify on their proof of claim the specific Debtor against which their claim is asserted and the case number of that Debtor's bankruptcy case. A list of the names of the Debtors and their case numbers is attached to this notice as Appendix A. 3. WHEN AND WHERE TO FILE Except as provided for herein, all original proofs of claim must be filed so as to be received on or before August 1, 2006, at 5:00 p.m. (prevailing Eastern time), at the following address: If sent by mail: If sent by messenger or overnight courier: United States Bankruptcy Court United States Bankruptcy Court Southern District of New York Southern District of New York Calpine Corporation Claims Docketing Center Calpine Corporation Claims Docketing Center Bowling Green Station One Bowling Green P.O. Box 5040 Room 534 New York, New York 10274-5040 New York, New York, 10004-1408 Proofs of claim will be deemed timely filed only if actually received by the Bankruptcy Court on or before the Bar Date. Proofs of claim may not be delivered by facsimile, telecopy, or electronic mail transmission. 2 4. WHO NEED NOT FILE A PROOF OF CLAIM You do not need to file a proof of claim on or prior to the Bar Date if you are: (a) any person or entity that has already filed a proof of claim against the Debtors with the Clerk of the Bankruptcy Court for the Southern District of New York in a form substantially similar to Official Bankruptcy Form No. 10; (b) any person or entity whose claim is listed on the Schedules filed by the Debtors; provided, however,that: (i)the claim is not scheduled as"disputed,""contingent" or"unliquidated";; (ii)the claimant does not disagree with the amount, nature and priority of the claim as set forth in the Schedules; and(iii)the claimant does not dispute that the claim is an obligation of the specific Debtor against which the claim is listed in the Schedules; (c) any holder of a claim that heretofore has been allowed by order of this Court; (d) any person or entity whose claim has been paid in full by any of the Debtors; (e) any holder of a claim for which specific deadlines have previously been fixed by this Court; (f) any Debtor having a claim against another Debtor or any of the nondebtor direct or indirect, wholly-owned subsidiaries of Calpine Corporation having a claim against any of the Debtors, provided, however, that any foreign entity or deconsolidated subsidiary that is no longer related to the Company is required to file a proof of claim by the Bar Date, including 1066917 Ontario Inc., 3094479 Nova Scotia Company, Basento Energia S.r.1., Calgary Energy Centre ULC, Calpine (Jersey) Holdings Limited, Calpine (Jersey) Limited, Calpine Canada Energy Finance ULC, Calpine Canada Energy Finance 11 ULC, Calpine Canada Energy Ltd., Calpine Canada Natural Gas Partnership, Calpine Canada Power Ltd., Calpine Canada Power Services, Ltd., Calpine Canada Resources Company, Calpine Canada Whitby Holdings Company, Calpine Canadian Saltend L.P., Calpine Energy Finance Luxembourg S.a.r.l., Calpine Energy Services Canada Ltd., Calpine Energy Services Canada Partnership, Calpine European Finance LLC, Calpine European Funding (Jersey) Holdings Limited, Calpine European Funding (Jersey) Limited, Calpine Finance (Jersey) Limited, Calpine Global Investments, S.L., Calpine Greenfield Limited Partnership, Calpine Greenfield Ltd., Calpine International Holdings, Inc., Calpine International Indonesia B.V., Calpine International Investment B.V., Calpine Island Cogeneration Limited Partnership, Calpine Island Cogeneration Project, Inc., Calpine Natural Gas Services Limited, Calpine Power, L.P., Calpine UK Holdings Limited, 3 CM Greenfield Power Corp., Compania de Generacion Valladolid S. de R.L. de C.V., Fergas S.r.L., Greenfield Energy Centre, LP, Polsky SCQ Services, Inc., Thomassen Services Gulf LLC, Thomassen Turbine Systems B.V., Valladolid International Investments, S. de R.L. de C.V., and Whitby Cogeneration Limited Partnership. (g) any person or entity whose claim is limited exclusively to the repayment of principal, interest, and/or other applicable fees and charges (a "Debt Claim") on or under any bond or note issued or guaranteed by the Debtors pursuant to an indenture (the "Debt Instruments"): provided, however, that: (i) the foregoing exclusion in this subparagraph shall not apply to the indenture trustee under the applicable Debt Instruments (the "Indenture Trustee"); (ii) the Indenture Trustee nevertheless shall be required to file one Proof of Claim, on or before the Bar Date, with respect to all of the Debt Claims on or under each of the Debt Instruments; and (iii) any holder of a Debt Claim wishing to assert a claim, other than a Debt Claim, arising out of or relating to a Debt Instrument shall be required to file a Proof of Claim on or before the Bar Date, unless another exception in this paragraph applies; and (h) any holder of a claim allowable under § 503(b) and § 507(a) of the Bankruptcy Code as an expense of administration. If you are a holder of an equity interest in the Debtors, you need not file a proof of interest with respect to the ownership of such equity interest at this time. However, if you assert a claim against the Debtors, including a claim relating to such equity interest or the purchase or sale of such interest, a proof of such claim must he filed on or prior to the Bar Date pursuant to procedures set forth in this Notice. This Notice is being sent to many persons and entities that have had some relationship with or have done business with the Debtors but may not have an unpaid claim against the Debtors. The fact that you have received this Notice does not mean that you have a claim or that the Debtors or the Court believe that you have a claim against the Debtors. 5. EXECUTORY CONTRACTS AND UNEXPIRED LEASES If you have a claim arising out of the rejection of an executory contract or unexpired lease as to which the order authorizing such rejection is dated on or before April 26, 2006, the date of entry of the Bar Order, you must file a proof of claim by the Bar Date. Any person or entity that has a claim arising from the rejection of an executory contract or unexpired lease, as to which the order is dated after the date of entry of the Bar Order, you must file a proof of claim with respect to such claim by the date fixed by the Court in the applicable order authorizing rejection of such contract or lease. Any person or entity that holds a claim that arises from the rejection of an executory contract or unexpired lease pursuant to the Order Pursuant to Sections 365 and 554 of the Bankruptcy Code Authorizing and Approving Expedited Procedures for the Rejection of Executory Contracts and Unexpired Leases of Personal and Non-Residential Real 4 Property, dated December 21, 2005 (ECF Docket No. 31), must file a proof of claim on or before the later of(i)the Bar Date or(ii)thirty(30)days after the effective date of the rejection notice. 6. CONSEQUENCES OF FAILURE TO FILE A PROOF OF CLAIM BY THE BAR DATE ANY HOLDER OF A CLAIM THAT IS NOT EXCEPTED FROM THE REQUIREMENTS OF THIS ORDER, AS SET FORTH IN SECTION 4 ABOVE, AND THAT FAILS TO TIMELY FILE A PROOF OF CLAIM IN THE APPROPRIATE FORM WILL BE BARRED FROM ASSERTING SUCH CLAIM AGAINST THE DEBTORS AND THEIR CHAPTER 11 ESTATES, FROM VOTING ON ANY PLAN OF REORGANIZATION FILED IN THESE CASES, AND FROM PARTICIPATING IN ANY DISTRIBUTION IN THE DEBTORS' CASES ON ACCOUNT OF SUCH CLAIM. 7. THE DEBTORS' SCHEDULES AND ACCESS THERETO You may be listed as the holder of a claim against one or more of the Debtors in the Debtors' Schedules of Assets and Liabilities and/or Schedules of Executory Contracts and Unexpired Leases(collectively, the"Schedules"). To determine if and how you are listed on the Schedules, please refer to the descriptions set forth on the enclosed proof of claim forms regarding the nature, amount, and status of your claim(s). If you received postpetition payments from the Debtors (as authorized by the Court) on account of your claim, the enclosed proof of claim form will reflect the net amount of your claim. If the Debtors believe that you hold claims against more than one Debtor, you will receive multiple proof of claim forms, each of which will reflect the nature and amount of your claim against one Debtor, as listed in the Schedules. If you rely on the Schedules (or enclosed proof of claim forms), it is your responsibility to determine that the claim is accurately listed in the Schedules however, you may rely on the enclosed form, which lists your claim as scheduled, identifies the Debtor against which it is scheduled, and specifies whether the claim is disputed, contingent or unliquidated. As set forth above, if you agree with the nature, amount and status of your claim as listed in the Debtors' Schedules, and if you do not dispute that your claim is only against the Debtor specified by the Debtors, and if your claim is not described as "disputed," "contingent," or "unliquidated," you need not file a proof of claim. Otherwise, if you decide to file a proof of claim, you must do so before the Bar Date in accordance with the procedures set forth in this Notice. Copies of the Debtors' Schedules are available for inspection on KCC's website at www.kccllc.net/calpine or the Court's Internet Website at http://www.nysb.uscourts.gov. A login and password to the Court's Public Access to Electronic Court Records ("PACER") are required to access this information and can be obtained through the PACER Service Center at http:/,/www.pacer.psc.uscourts.gov. Copies of the Schedules may also be examined between the hours of 9:00 a.m. and 4:30 p.m., Monday through Friday, at the Office of the Clerk of the Bankruptcy Court, One Bowling Green, Room 511, New York, New York 10004-1408. Copies 5 of the Debtors' Schedules may also be obtained by written request to Debtors' Claims Agent at the following address and telephone number: Kurtzman Carson Consultants LLC 12910 Culver Blvd. Suite I Los Angeles, California 90066 Tel. No.: 1-888-249-2792 A holder of a possible claim against the Debtors should consult an attorney regarding any matters not covered by this notice, such as whether the holder should file a proof of claim. Dated: April 26 , 2006 BY ORDER OF THE COURT New York, New York KIRKLAND & ELLIS LLP Citigroup Center 153 East 53rd Street New York, New York 10022-4611 (212) 446-4800 Counsel for the Debtors 6 APPENDIX A Name Tax ID No. Case No. Date Filed Calpine Kennedy Operators,Inc. 77-0572141 05-60199 12/20/2005 Calpine Corporation 77-0212977 05-60200 12/20/2005 Calpine Administrative Services Company,Inc. 77-0556638 05-60201 12/20/2005 Calpine Power Company 77-0211570 05-60202 12/20/2005 Calpine Fuels Corporation 77-0399211 05-60203 12/20/2005 Calpine Finance Company 56-2395088 05-60204 12/20/2005 Calpine International Holdings,Inc. 77-0547250 05-60205 12/20/2005 Calpine Operations Management Company,Inc. 77-0558496 05-60206 12/20/2005 Calpine Energy Holdings,Inc. N/A 05-60207 12/20/2005 Calpine Energy Services Holdings,Inc. 77-0504648 05-60208 12/20/2005 CPN Energy Services GP,Inc. 77-0495420 05-60209 12/20/2005 CPN Energy Services LP,Inc. 77-0572147 05-60210 12/20/2005 Calpine PowerAmerica,Inc. 77-0564589 05-60211 12/20/2005 Calpine PowerAmerica,LP 57-1205489 05-60212 12/21/2005 Calpine PowerAmerica-CA,LLC 56-2304827 05-60213 12/21/2005 Calpine PowerAmerica-CT,LLC 77-0645731 05-60214 12/21/2005 Calpine PowerAmerica-MA,LLC 54-2122394 05-60215 12/21/2005 Calpine PowerAmerica-ME,LLC 54-2122391 05-60216 12/21/2005 Calpine Producer Services,LP 75-2198121 05-60217 12/21/2005 CES GP,J.1 P 36-4512517 05-60218 12/21/2005 Calpine Capital Trust V 10-6002907 05-60221 12/21/2005 Calpine Energy Services,LP 77-0526913 05-60222 12/21/2005 Amelia Energy Center,LP 77-0574035 05-60223 12/21/2005 Bellingham Cogen,Inc. 77-0276359 05-60224 12/21/2005 Bethpage Energy Center 3,LLC 61-1431273 05-60225 12/21/2005 Anacapa Land Company,LLC 77-0530349 05-60226 12/21/2005 Calpine Freestone Energy GP,LLC 86-1056713 05-60227 12/21/2005 Bethpage Fuel Management Inc. 11-2949037 05-60228 12/21/2005 CalGen Finance Corp. 20-1162632 05-60229 12/21/2005 Calpine Freestone Energy,LP 86-1056720 05-60230 12/21/2005 Calpine Freestone,LLC 77-0546242 05-60231 12/21/2005 Anderson Springs Energy Company 77-0276355 05-60232 12/21/2005 Calpine Cogeneration Corporation 59-2076187 05-60233 12/21/2005 Calpine Gas Holdings LLC 20-2943018 05-60234 12/21/2005 Blue Heron Energy Center LLC 77-0559134 05-60235 12/21/2005 CalGen Project Equipment Finance Company One,LLC 77-0556245 05-60236 12/21/2005 Calpine Generating Company, LLC 77-0555128 05-60237 12/21/2005 Blue Spruce Holdings,LLC 55-0908052 05-60238 12/21/2005 Androscoggin Energy,Inc. 36-4131773 05-60239 12/21/2005 Calpine Gilroy 1,Inc. 77-0436505 05-60240 12/21/2005 Calpine Gilroy 2,Inc. 77-0436507 05-60241 12/21/2005 Broad River Energy LLC 36-4311004 05-60242 12/21/2005 Calpine Gilroy Cogen,L.P. 77-0436504 05-60243 12/21/2005 Auburndale Peaker Energy Center,LLC 77-0575652 05-60244 12/21/2005 Broad River Holdings,LLC 56-2503253 05-60245 12/21/2005 Calpine Global Services Company,Inc. 77-0522836 05-60246 12/21/2005 Calpine Corpus Christi Energy GP,LLC 86-1056770 05-60247 12/21/2005 Augusta Development Company,LLC 77-0585885 05-60248 12/21/2005 CalGen Equipment Finance Company,LLC 77-0555523 05-60249 12/21/2005 Calpine c*Power,Inc. 20-1162721 05-60250 12/21/2005 CalGen Equipment Finance Holdings,LLC 77-0555519 05-60251 12/21/2005 Aviation Funding Corp. 11-3145216 05-60252 12/21/2005 CalGen Expension Company,LLC 77-0555127 05-60253 12/21/2005 Calpine Decatur Pipeline,L.P. 77-0530346 05-60254 12/21/2005 Baytown Energy Center,LP 77-0555135 05-60255 12/21/2005 Baytown Power GP,LLC 86-1056699 05-60256 12/21/2005 Calpine East Fuels, Inc. 77-0522835 05-60257 12/21/2005 Baytown Power,LP 86-1056708 05-60258 12/21/2005 CalGen Project Equipment Finance Company Three,LLC 10-0008436 05-60259 12/21/2005 Calpine Construction Management Company,Inc. 77-0555084 05-60260 12/21/2005 Calpine Corpus Christi Energy LP 86-1056497 05-60261 12/21/2005 CalGen Project Equipment Finance Company Two,LLC 77-0585399 05-60262 12/21/2005 Calpine Decatur Pipeline,Inc. 77-0530347 05-60263 12/21/2005 Calpine Dighton,Inc. 77-0467581 05-60264 12/21/2005 Calpine Acadia Holdings,LLC 77-0534545 05-60265 12/21/2005 Calpine Eastern Corporation 77-0472431 05-60266 12/21/2005 CCFC Development Company,LLC 77-0566178 05-60267 12/21/2005 Calpine Agnews,Inc. 77-0269484 05-60268 12/21/2005 CCFC Equipment Finance Company,LLC 77-0566184 05-60269 12/21/2005 Calpine Amelia Energy Center GP,LLC 77-0574025 05-60270 12/21/2005 CCFC Project Equipment Finance Company One,LLC 56-2500167 05-60271 12/21/2005 Calpine Amelia Energy Center LP,LLC 77-0574024 05-60272 12/21/2005 Celtic Power Corporation 77-0572133 05-60273 12/21/2005 CGC Dighton,LLC N/A 05-60274 12/21/2005 Channel Energy Center,LP 77-0555137 05-60275 12/21/2005 Channel Power GP,LLC 86-1056758 05-60276 12/21/2005 Channel Power LP 86-1056755 05-60277 12/21/2005 Clear Lake Cogeneration Limited Partnership 76-0252373 05-60278 12/21/2005 Calpine Gordonsville GP Holdings,LLC 77-0580854 05-60281 12/21/2005 Calpine Gordonsville LP Holdings,LLC 77-0580855 05-60282 12/21/2005 Calpine Gordonsville,LLC 77-0472433 05-60283 12/21/2005 Calpine Greenleaf Holdings,Inc. 77-0495371 05-60284 12/21/2005 Calpine Greenleaf,Inc. 77-0495373 05-60285 12/21/2005 Calpine Northbrook Holdings Corporation N/A 05-60286 12/21/2005 CPN Clear Lake,Inc. 47-0667302 05-60287 12/21/2005 Calpine International,LLC 74-3130779 05-60288 12/21/2005 Calpine Investment Holdings,LLC 55-0883680 05-60289 12/21/2005 CPN Decatur Pipeline,Inc. 77-0530348 05-60290 12/21/2005 Calpine Northbrook Investors,LLC 36-4233245 05-60291 12/21/2005 CPN Power Services,LP 86-1055932 05-60292 12/21/2005 CPN Freestone,LLC 77-0545937 05-60293 12/21/2005 Calpine Kennedy Airport,Inc. 77-0572139 05-60294 12/21/2005 2 Calpine Northbrook Project Holdings,LLC 52-2218699 05-60295 12/21/2005 CPN Funding,Inc. 41-1892779 05-60296 12/21/2005 Calpine Leasing,Inc. 77-0527925 05-60297 12/21/2005 Calpine Long Island, Inc. 77-0572140 05-60298 12/21/2005 Calpine Northbrook Services LLC 36-4271051 05-60299 12/21/2005 CPN Pryor Funding Corporation 41-1852241 05-60300 12/21/2005 CPN Morris,Inc. 41-1884586 05-60301 12/21/2005 Calpine Pastoria Holdings,LLC 77-0559247 05-60302 12/21/2005 CPN Oxford,Inc. 77-0520677 05-60303 12/21/2005 Calpine Northbrook Southcoast Investors, 1. LC 36-4337045 05-60304 12/21/2005 Calpine Philadelphia,Inc. 23-2547038 05-60305 12/21/2005 CPN Telephone Flat,Inc. 77-0321522 05-60306 12/21/2005 Calpine Pittsburg,LLC 77-0524474 05-60307 12/21/2005 Calpine NTC,LP N/A 05-60308 12/21/2005 CPN Pipeline Company 77-0489460 05-60309 12/21/2005 Calpine Power Equipment,LP 77-0555123 05-60310 12/21/2005 Calpine Oneta Power 1, LLC 75-2815390 05-60311 12/21/2005 CPN Pleasant Hill Operating,LLC 77-0559395 05-60312 12/21/2005 Decatur Energy Center,LLC 77-0555708 05-60313 12/21/2005 Calpine Lost Pines Operations, Inc. 77-0520359 05-60314 12/21/2005 Calpine Oneta Power II, LLC 75-2815394 05-60315 12/21/2005 Calpine Power Inc. 51-0352026 05-60316 12/21/2005 CPN Pleasant Hill,LLC 77-0530350 05-60317 12/21/2005 Calpine Oneta Power,LP 75-2815392 05-60318 12/21/2005 Calpine Power Management,Inc. 94-3408181 05-60319 12/21/2005 Calpine Baytown Energy Center LP, LLC 77-0555138 05-60320 12/21/2005 CPN Power Services GP,LLC 86-1056015 05-60321 12/21/2005 Calpine Operating Services Company,Inc. 71-0887428 05-60322 12/21/2005 Calpine Power Services, Inc. I I-3642873 05-60323 12/21/2005 Calpine Project Holdings, Inc. 77-0572149 05-60324 12/21/2005 Calpine Capital Trust 77-6180054 05-60325 12/21/2005 Calpine Pryor, Inc. 74-2893556 05-60326 12/21/2005 Calpine Rumford 1,Inc. 77-0495621 05-60327 12/21/2005 Calpine Louisiana Pipeline Company 77-0582977 05-60328 12/21/2005 Calpine Central Texas GP,Inc. 68-0510163 05-60329 12/21/2005 Calpine Bethpage 3 Pipeline Construction Company,Inc. 20-1561373 05-60330 12/21/2005 Calpine Magic Valley Pipeline, Inc. 77-0507851 05-60331 12/21/2005 Magic Valley Pipeline,LP 77-0507850 05-60332 12/21/2005 Calpine Central,Inc. 77-0498817 05-60333 12/21/2005 MEP Pleasant Hill,LLC 77-0552138 05-60334 12/21/2005 Fontana Energy Center, LLC 77-0578294 05-60335 12/21/2005 Northwest Cogeneration, Inc. 77-0276357 05-60336 12/21/2005 MOAPA Energy Center, LLC 77-0566241 05-60337 12/21/2005 Calpine Central-Texas, Inc. 77-0498819 05-60338 12/21/2005 Freestone Power Generation, LP 76-0608559 05-60339 12/21/2005 Calpine Channel Energy Center GP,LLC 77-0555139 05-60340 12/21/2005 Calpine Monterey Cogeneration, Inc. 77-0397024 05-60341 12/21/2005 Calpine Bethpage 3,LLC 83-0418045 05-60342 12/21/2005 3 Calpine Channel Energy Center LP,LLC 77-0555140 05-60343 12/21/2005 Mobile Energy LLC 36-4097615 05-60344 12/21/2005 Calpine Clear Lake Energy GP,LLC 86-1056773 05-60345 12/21/2005 Modoc Power,Inc. 77-0397028 05-60346 12/21/2005 GEC Bethpage Inc. 06-1220854 05-60347 12/21/2005 Calpine MVP,Inc. 77-0507852 05-60348 12/21/2005 Calpine Clear Lake Energy,LP 86-1056509 05-60349 12/21/2005 NTC GP,LLC 54-2185596 05-60350 12/21/2005 Calpine Central,LP 77-0498817 05-60351 12/21/2005 Calpine CalGen Holdings,Inc. 77-0555131 05-60352 12/21/2005 Morgan Energy Center,LLC 77-0555141 05-60353 12/21/2005 Thomassen Turbine Systems America,Inc. 34-2043722 05-60354 12/21/2005 Calpine California Development Company,LLC 77-0572905 05-60355 12/21/2005 Nueces Bay Energy,LLC 36-4216016 05-60356 12/21/2005 Tiverton Power Associates,LP 77-0404269 05-60357 12/21/2005 Geysers Power Company II LLC 77-0503976 05-60358 12/21/2005 Calpine NCTP GP,LLC 86-1056771 05-60359 12/21/2005 Calpine California Energy Finance,LLC 77-0572901 05-60360 12/21/2005 Mount Hoffman Geothermal Company,LP 77-0397032 05-60361 12/21/2005 JMC Bethpage,Inc. 04-2980589 05-60362 12/21/2005 Deer Park Power GP,LLC 86-1056752 05-60363 12/21/2005 Towantic Energy,LLC 06-1531404 05-60364 12/21/2005 VEC Holdings,LLC 51-0557228 05-60365 12/21/2005 MAC Partners 11-3036753 05-60366 12/21/2005 Odyssey Land Acquisition Company 77-0546712 05-60367 12/21/2005 Venture Acquisition Company 77-0557971 05-60368 12/21/2005 Lake Wales Energy Center,LLC 77-0580173 05-60369 12/21/2005 Deer Park Power,LP 86-1056744 05-60370 12/21/2005 Lawrence Energy Center,LLC 77-0565531 05-60371 12/21/2005 Cogenamerica Asia,Inc. 23-2677506 05-60372 12/21/2005 Vineyard Energy Center,LLC N/A 05-60373 12/21/2005 O.L.S.Energy-Agnews,Inc. 77-0572145 05-60374 12/21/2005 Delta Energy Center,LLC 95-4812214 05-60375 12/21/2005 Mt.Vernon Energy LLC 36-4343950 05-60376 12/21/2005 Calpine Calistoga Holdings,LLC 77-0524471 05-60377 12/21/2005 Wawayanda Energy Center,LLC 77-0565516 05-60378 12/21/2005 Calpine Capital Trust II 77-0532910 05-60379 12/21/2005 Zion Energy LLC 36-4330312 05-60380 12/21/2005 Newsouth Energy LLC 83-0413417 05-60381 12/21/2005 Dighton Power Associates,LP N/A 05-60382 12/21/2005 Cogenamerica Parlin Supply Corporation 23-2485662 05-60383 12/21/2005 Calpine Capital Trust III 77-6194923 05-60384 12/21/2005 Pajaro Energy Center,LLC 77-0580174 05-60385 12/21/2005 East Altamont Energy Center,LLC 77-0566240 05-60386 12/21/2005 Pastoria Energy Center,LLC 77-0582975 05-60387 12/21/2005 Nissequogue Cogen Partners 22-3056034 05-60388 12/21/2005 Geysers Power I Company 77-0503975 05-60389 12/21/2005 Goldendale Energy Center,LLC 75-3132706 05-60390 12/21/2005 4 Calpine Capital Trust IV 10-6002905 05-60391 12/21/2005 Hammond Energy LLC 36-4348163 05-60393 12/21/2005 Hillabee Energy Center,LLC 83-0360324 05-60394 12/21/2005 Phipps Bend Energy Center,LLC 45-0475412 05-60395 12/21/2005 Pine Bluff Energy,LLC 364132992 05-60396 12/21/2005 Idlewild Fuel Management Corp. 11-3061354 05-60397 12/21/2005 Power Investors,LLC 36-4047074 05-60398 12/21/2005 Power Systems Mfg.LLC 65-0945128 05-60399 12/21/2005 Quintana Canada Holdings,LLC 77-0571374 05-60400 12/21/2005 Rockgen Energy LLC 36-4348406 05-60401 12/21/2005 Lone Oak Energy Center,LLC 77-0565384 05-60403 12/21/2005 Los Esteros Critical Energy Facility,LLC 77-0583736 05-60404 12/21/2005 Los Medanos Energy Center,LLC 77-0553164 05-60405 12/21/2005 Calpine NCTP,LP 86-1056506 05-60406 12/21/2005 Magic Valley Gas Pipeline GP,LLC 86-1055920 05-60407 12/21/2005 Magic Valley Gas Pipeline LP 86-1055914 05-60408 12/21/2005 Calpine Northbrook Corporation of Maine,Inc. 77-0572148 05-60409 12/21/2005 Pastoria Energy Facility,LLC 77-0581976 05-60410 12/21/2005 Russell City Energy Center,LLC 80-0045453 05-60411 12/21/2005 Fond Du Lac Energy Center,LLC 77-0567247 05-60412 12/21/2005 San Joaquin Valley Energy Center,LLC 77-0578295 05-60413 12/21/2005 Calpine Rumford,Inc. 77-0495622 05-60414 12/21/2005 Skipanon Natural Gas,LLC 77-0557968 05-60415 12/21/2005 Calpine Schuylkill,Inc. 23-2613016 05-60416 12/21/2005 South Point Energy Center,LLC 77-0579923 05-60417 12/21/2005 Calpine Northbrook Energy Holdings,LLC 36-3790556 05-60418 12/21/2005 South Point Holdings,LLC 80-0129192 05-60419 12/21/2005 Calpine Siskiyou Geothermal Partners,L.P. 77-0397029 05-60420 12/21/2005 Philadelphia Biogas Supply Inc. 23-2486177 05-60421 12/21/2005 Stony Brook Cogeneration,Inc. 77-0472431 05-60422 12/21/2005 Calpine Sonoran Pipeline,LLC 77-0572907 05-60423 12/21/2005 Calpine Stony Brook Operators,Inc. 77-0572142 05-60424 12/21/2005 Calpine Stony Brook Power Marketing,LLC 59-3821206 05-60425 12/21/2005 Calpine Stony Brook, Inc. 77-0572143 05-60426 12/21/2005 Calpine Sumas,Inc. 77-0295731 05-60427 12/21/2005 Stony Brook Fuel Management Corp. 11-3187764 05-60428 12/21/2005 Calpine TCCL Holdings,Inc. 77-0486738 05-60429 12/21/2005 Sutter Dryers, Inc. 77-0419274 05-60430 12/21/2005 Calpine Northbrook Energy,LLC 36-4235799 05-60431 12/21/2005 TBG Cogen Partners 04-3057472 05-60432 12/21/2005 Calpine Texas Pipeline GP,Inc. 77-0550650 05-60433 12/21/2005 Texas City Cogeneration,LP 77-0507664 05-60434 12/21/2005 Texas Cogeneration Company 76-0212244 05-60435 12/21/2005 Texas Cogeneration Five,Inc. 77-0506546 05-60436 12/21/2005 Texas Cogeneration One Company 47-0669902 05-60437 12/21/2005 Thermal Power Company 77-0031605 05-60438 12/21/2005 Calpine Texas Pipeline LP,Inc. 77-0550642 05-60439 12/21/2005 Columbia Energy LLC 36-4380154 05-60440 12/21/2005 5 Corpus Christi Cogeneration,LP 36-4337040 05-60441 12/21/2005 CPN 3rd Turbine,Inc. 77-0576424 05-60443 12/21/2005 CPN Acadia,Inc. 77-0534543 05-60444 12/21/2005 CPN Berks Generation,Inc. 77-0513298 05-60445 12/21/2005 CPN Berks 111' 77-0513022 05-60446 12/21/2005 Calpine Texas Pipeline,L.P. 77-0550749 05-60447 12/21/2005 CPN Bethpage 3rd Turbine Inc. 77-0583485 05-60448 12/21/2005 CPN Cascade,Inc. 33-0534297 05-60449 12/21/2005 Calpine Tiverton I,Inc. 77-0494269 05-60450 12/21/2005 Calpine Tiverton,Inc. 77-0494266 05-60451 12/21/2005 Calpine Auburndale Holdings,LLC 77-0547002 05-60452 12/21/2005 Calpine Baytown Energy Center GP,LLC 77-0555133 05-60453 12/21/2005 Calpine ULC I Holding,LLC 55-0907827 05-60454 12/21/2005 Calpine University Power,Inc. 77-0572144 05-60455 12/21/2005 Calpine Unrestricted Funding,LLC 56-2483129 05-60456 12/21/2005 Calpine Unrestricted Holdings,LLC 55-0883677 05-60458 12/21/2005 Calpine Vapor,Inc. 77-0448936 05-60459 12/21/2005 Carville Energy LLC 36-4309608 05-60460 12/21/2005 NTC Five,Inc. 16-1684059 05-60463 12/21/2005 Calpine California Equipment Finance Company,LLC 10-0006591 05-60464 12/27/2005 Calpine KIA,Inc. 77-0572134 05-60465 12/27/2005 Calpine Power Management,LP 94-3708181 05-60466 12/27/2005 Rumford Power Associates,LP 04-3373838 05-60467 12/27/2005 Whatcom Cogeneration Partners,LP 77-0295732 05-60468 12/27/2005 Calpine East Fuels,LLC N/A 05-60476 12/29/2005 Geothermal Energy Partners,LLC N/A 05-60477 12/29/2005 Calpine Hidalgo,Inc. 76-0573524 06-10026 1/8/2006 Calpine Hidalgo Holdings,Inc. 56-2158381 06-10027 1/8/2006 Calpine Hidalgo Power,LP 86-1056740 06-10028 1/8/2006 Calpine Hidalgo Energy Center,L.P. 76-0573523 06-10029 1/8/2006 Calpine Hidalgo Power GP,LLC 86-1056735 06-10030 1/8/2006 Calpine PowerAmerica-NY,LLC 74-3130329 06-10031 1/8/2006 Calpine PowerAmerica-NH,LLC 37-1496040 06-10032 1/8/2006 Calpine PowerAmerica-OR,LLC 56-2304825 06-10034 1/9/2006 Calpine Hidalgo Design,L.P. 76-0607388 06-10039 1/9/2006 Geysers Power Company,LLC 77-0503977 06-10197 2/3/2006 Silverado Geothermal Resources,Inc. 95-3153574 06-10198 2/3/2006 6 UNITED STATES BANKRUPTCY COURT SOUTHERN DISTRICT OF NEW YORK PROOF OF CLAIM Debtor and Case Number(Select One) This Space For Court Use Only NOTE:This form should not be used to make a claim for an administrative expense arising after the commencement of the case.A"request"for payment of an administrative expense may be filed pursuant to 11 U.S.C.§503. Name of Creditor(The person or other entity to whom the debtor owes money or ❑ Check box if you are aware property): that anyone else has filed a Sw Weld County Planning Offices proof of claim relating to your Name and Address where notices should be sent: claim.Attach copy of statement giving particulars. ❑ Check box if you have never Sw Weld County Planning Offices received any notices from the 4209 Cr 24 1 2 bankruptcy court in this case. Longmont CO 80504 ❑ Check box if the address differs from the address on the envelope sent to you by the Telephone Number: court. This Space For Court Use Only Last four digits of account or other number by which creditor identifies Check here 0 replaces debtor: if this claim ❑ amends a previously filed claim dated: 1.Basis for Claim ❑ Goods sold 0 Retiree benefits as defined in 11 U.S.C. §1114(a) ❑ Services performed ❑ Wages,salaries,and compensation(fill out below) ❑ Money loaned Last four digits of your SS#: ❑ Personal injury/wrongful death Unpaid compensation for services performed ❑ Taxes from to ❑ Other (date) (date) 2.Date debt was incurred: 3.If court Judgment, date obtained: 4.Classification of Claim.Check the appropriate box or boxes that best describe your claim and state the amount of the claim at the time case filed. See reverse side for important explanations. Unsecured Nonpriority Claim $ Secured Claim. ❑ Check this box if a)there is no collateral or lien securing your ❑ Check this box if your claim is secured by collateral(including a right of claim,orb)your claim exceeds the value of the property securing setoff). it,or if c)none or only part of your claim is entitled to priority. Brief Description of Collateral: Unsecured Priority Claim. ❑ Real Estate ❑ Motor Vehicle ❑ Other ❑ Check this box if you have an unsecured claim,all or part of which is Value of Collateral$ entitled to priority Amount of arrearage and other charges at time case filed included in Amount entitled to priority$ _ secured claim,if any: $ Specify the priority of the claim: ❑ Domestic support obligations under II U.S.C. §507(a)(l)(A)or 0 Up to$2,225*of deposits toward purchase,lease,or rental of property or services (a)(I)(B). for personal,family,or household use- 11 U.S.C. §507(aX7). ❑ Wages,salaries,or commissions(up to$10,000),*earned within 180 ❑ Taxes or penalties owed to governmental units-11 U.S.C.§507(a)(8). days before filing of the bankruptcy petition or cessation of the debtor's ❑ Other-Specify applicable paragraph of 11 U.S.C. §507(a)( ). business,whichever is earlier- 11 U.S.C.§507(a)(4). *Amounts are subject to adjustment on 4/1/07 and every 3 years thereafter ❑ Contributions to an employee benefit plan- 11 U.S.C. §507(a)(5). with respect to cases commenced on or after the date of adjustment. 5. Total Amount of Claim at Time Case Filed: $ (Unsecured) (Secured) (Priority) (Total) El Check this box if claim includes interest or other charges in addition to the principal amount of the claim.Attach itemized statement of all interest or additional charges. 6.Credits:The amount of all payments on this claim has been credited and deducted for the purpose of making this proof of claim. This Space For Court Use Only 7.Supporting Documents:Attach copies of supporting documents, such as promissory notes,purchase orders,invoices,itemized statements of running accounts,contracts,court judgments,mortgages,security agreements,and evidence of perfection of lien. DO NOT SEND ORIGINAL DOCUMENTS.If the documents are not available,explain.If the documents are voluminous, attach a summary. S.Date-Stamped Copy:To receive an acknowledgment of the filing of your claim,enclose a stamped,self-addressed envelope and copy of this proof of claim Date: Sign and print the name and title,if any,of the creditor or other person authorized to file this claim(attach copy of power of attorney,if any): Penalty for presenting fraudulent claim:Fine up to$500,000 or imprisonment for up to 5 years,or both. 18 U.S.C. §§152 and 3571 IIIIIII IIIIIIIIIII 1 111 1111 111 III I II III I IIII' it Ill UNITED STATES BANKRUPTCY COURT SOUTHERN DISTRICT OF NEW YORK In re Chapter 11 Calpine Corporation, et al., Case No.: 05-60200 (BRL) Debtors. (Jointly Administered) NOTICE OF COMMENCEMENT OF CHAPTER 11 BANKRUPTCY CASES AND MEETING OF CREDITORS Beginning on December 20, 2005, and continuing on subsequent days, the debtors and debtors-in-possession in the above-captioned cases (collectively, the "Debtors,") filed voluntary petitions for relief under chapter 11 of the Bankruptcy Code. The Debtors and their federal tax identification numbers are attached hereto as Exhibit A. COUNSEL FOR THE DEBTORS. Richard M. Cieri Matthew A. Cantor Robert G. Bums Edward O. Sassower KIRKLAND & ELLIS LLP Citigroup Center 153 East 53rd Street New York, New York 10022-4611 Telephone: (212) 446-4800 Facsimile: (212)446-4900 COMMENCEMENT OF CASES. Petitions for relief under chapter 11 of the Bankruptcy Code have been filed in this Court by the Debtors listed above, and orders for relief have been entered. You will not receive notice of all documents filed in this case. All documents filed with the Court, including lists of the Debtors' property and debts, will be available for inspection at the Office of the Clerk of the Bankruptcy Court. In addition, such documents may be available at http://www.kccllc.net/calpine or the Court's website, http://www.nvsb.uscourts.2ov, and can be viewed with a PACER password (to obtain a PACER password, go to the PACER website, http://pacer.psc.uscourts.Qov). K&E 10919105.5 PURPOSE OF CHAPTER 11 FILING. Chapter 11 of the U.S. Bankruptcy Code enables a debtor to reorganize pursuant to a plan. A plan is not effective unless approved by the court at a confirmation hearing. Creditors will be given notice concerning any plan, or in the event the case is dismissed or converted to another chapter of the Bankruptcy Code. The Debtors will remain in possession of their property and will continue to operate any business unless a trustee is appointed. DATE, TIME AND LOCATION OF SECTION 341 MEETING OF CREDITORS. March 21, 2006, at 2 p.m., Prevailing Eastern Time, at 80 Broad Street, 2n° Floor, New York, New York 10004. SECTION 341 MEETING OF CREDITORS. The Debtors' representative, as specified in Rule 9001(5) of the Federal Rules of Bankruptcy Procedure (the "Bankruptcy Rules"), is required to appear at the meeting of creditors on the date and at the place set forth above for the purpose of being examined under oath. Attendance by creditors at the meeting is welcomed, but not required. At the meeting, the creditors may examine the Debtors and transact such other business as may properly come before the meeting. The meeting may be continued or adjourned from time to time by notice at the meeting, without further written notice to the creditors. CREDITORS MAY NOT TAKE CERTAIN ACTIONS. A creditor is anyone to whom a debtor owes money or property. Under the Bankruptcy Code, a debtor is granted certain protection against creditors. Common examples of prohibited actions by creditors are contacting a debtor to demand repayment, taking action against a debtor to collect money owed to creditors or to take property of a debtor, and starting or continuing foreclosure actions or repossessions. If unauthorized actions are taken by a creditor against a debtor, the Court may penalize that creditor. A creditor who is considering taking action against a debtor or the property of a debtor -2- K&E 10419105.5 should review section 362 of the Bankruptcy Code and may wish to seek legal advice. The staff of the Clerk of the Bankruptcy Court are not permitted to give legal advice. CLAIMS. Schedules of creditors will be filed pursuant to Bankruptcy Rule 1007. Any creditor holding a scheduled claim which is not listed as disputed, contingent, or unliquidated as to amount may, but is not required to, file a proof of claim in these cases. Creditors whose claims are not scheduled or whose claims are listed as disputed, contingent, or unliquidated as to amount and who desire to participate in the cases or share in any distribution must file their proofs of claim. A creditor who desires to rely on the schedule of creditors has the responsibility for determining that the claim is listed accurately. Separate notice of the deadlines to file proofs of claim and proof of claim forms will be provided to the Debtors' known creditors. Proof of claim forms also are available in the clerk's office of any bankruptcy court. Proof of claim forms are also available at http://www.kccllc.net/calpine or from the Court's web site at http://www.nysb.uscourts.gov. Proof of claim forms may be filed at the following addresses: United States Bankruptcy Court By hand or overnight courier: Southern District of New York United States Bankruptcy Court Calpine Corporation Claims Docketing Southern District of New York P.O. Box 5040 One Bowling Green Bowling Green Station Room 534 New York, New York 10274-5040 New York,New York 10004-1408 DISCHARGE OF DEBTS. Confirmation of chapter 11 plan may result in a discharge of debts, which may include all or part of your debt. See section 1141(d) of the Bankruptcy Code. A discharge means that you may never try to collect the debt from the debtor, except as provided in the plan. For the Court: Kathleen Farrell-Willoughby Dated: January 26, 2006 Clerk of Court United States Bankruptcy Court for the Southern District of New York -3- K&E 109191115 5 Debtor Tax ID# Amelia Energy Center, LP 77-0574035 Anacapa Land Company, LLC 77-0530349 Anderson Springs Energy Company 77-0276355 Androscoggin Energy, Inc. 36-4131773 Auburndale Peaker Energy Center, LLC 77-0575652 Augusta Development Company, LLC 77-0585885 Aviation Funding Corp. 11-3145216 Baytown Energy Center, LP 77-0555135 Baytown Power GP, LLC 86-1056699 Baytown Power, LP 86-1056708 Bellingham Cogen,Inc. 77-0276359 Bethpage Energy Center 3, LLC 61-1431273 Bethpage Fuel Management Inc. 11-2949037 Blue Heron Energy Center, LLC 77-0559134 Blue Spruce Holdings, LLC 55-0908052 Broad River Energy LLC 36-4311004 Broad River Holdings, LLC 56-2503253 CalGen Equipment Finance Company, LLC 77-0555523 CalGen Equipment Finance Holdings, LLC 77-0555519 CalGen Expansion Company, LLC 77-0555127 CalGen Finance Corp. 20-1162632 CalGen Project Equipment Finance Company One, LLC 77-0556245 CalGen Project Equipment Finance Company Three, LLC 10-0008436 CalGen Project Equipment Finance Company Two, LLC 77-0585399 Calpine Acadia Holdings, LLC 77-0534545 Calpine Administrative Services Company, Inc. 77-0556638 Calpine Agnews, Inc. 77-0269484 Calpine Amelia Energy Center GP, LLC 77-0574025 Calpine Amelia Energy Center LP, LLC 77-0574024 Calpine Auburndale Holdings, LLC 77-0547002 Calpine Baytown Energy Center GP, LLC 77-0555133 Calpine Baytown Energy Center LP, LLC 77-0555138 Calpine Bethpage 3 Pipeline Construction Company, Inc. 20-1561373 Calpine Bethpage 3, LLC 83-0418045 Calpine c*Power, Inc. 20-1162721 Calpine CalGen Holdings, Inc. 77-0555131 Calpine California Development Company, LLC 77-0572905 Calpine California Energy Finance, LLC 77-0572901 Calpine California Equipment Finance Company, LLC 10-0006591 Calpine Calistoga Holdings, LLC 77-0524471 Calpine Capital Trust 77-6180054 Calpine Capital Trust II 77-0532910 Calpine Capital Trust III 77-6194923 Calpine Capital Trust IV 10-6002905 Calpine Capital Trust V 10-6002907 Calpine Central Texas GP, Inc. 68-0510163 K&E 10919105.5 Debtor Tax ID# Calpine Central, Inc. 77-0498817 Calpine Central, L.P. 77-0498817 Calpine Central-Texas, Inc. 77-0498819 Calpine Channel Energy Center GP, LLC 77-0555139 Calpine Channel Energy Center LP, LLC 77-0555140 Calpine Clear Lake Energy GP, LLC 86-1056773 Calpine Clear Lake Energy, LP 86-1056509 Calpine Cogeneration Corporation 59-2076187 Calpine Construction Management Company, Inc. 77-0555084 Calpine Corporation 77-0212977 Calpine Corpus Christi Energy GP, LLC 86-1056770 Calpine Corpus Christi Energy LP 86-1056497 Calpine Decatur Pipeline Inc. 77-0530347 Calpine Decatur Pipeline, L.P. 77-0530346 Calpine Development Holdings, Inc. 83-0360325 Calpine Dighton, Inc. 77-0467581 Calpine East Fuels, Inc. 77-0522835 Calpine Eastern Corporation 77-0472431 Calpine Edinburg, Inc. 56-2088366 Calpine Energy Services, LP 77-0526913 Calpine Finance Company 56-2395088 Calpine Freestone Energy GP, LLC 86-1056713 Calpine Freestone Energy, LP 86-1056720 Calpine Freestone, LLC 77-0546242 Calpine Fuels Corporation 77-0399211 Calpine Gas Holdings, LLC 20-2943018 Calpine Generating Company, LLC 77-0555128 Calpine Gilroy 1, Inc. 77-0436505 Calpine Gilroy 2, Inc. 77-0436507 Calpine Gilroy Cogen, L.P. 77-0436504 Calpine Global Services Company, Inc. 77-0522836 Calpine Gordonsville GP Holdings, LLC 77-0580854 Calpine Gordonsville LP Holdings, LLC 77-0580855 Calpine Gordonsville, LLC 77-0472433 Calpine Greenleaf Holdings, Inc. 77-0495371 Calpine Greenleaf, Inc. 77-0495373 Calpine Hidalgo Design, L.P. 76-0607388 Calpine Hidalgo Energy Center, L.P. 76-0573523 Calpine Hidalgo Holdings, Inc. 56-2158381 Calpine Hidalgo Power GP, LLC 86-1056735 Calpine Hidalgo Power, LP 86-1056740 Calpine Hidalgo, Inc. 76-0573524 Calpine International Holdings, Inc. 77-0547250 Calpine International, LLC 74-3130779 Calpine Investment Holdings, LLC 55-0883680 Calpine Kennedy Airport, Inc. 77-0572139 -5- K&E 10919105.5 • r _, Debtor Tax ID# Calpine Kennedy Operators, Inc. 77-0572141 Calpine MA, Inc. 77-0572134 Calpine Leasing, Inc. 77-0527925 Calpine Long Island, Inc. 77-0572140 Calpine Lost Pines Operations, Inc. 77-0520359 Calpine Louisiana Pipeline Company 77-0582977 Calpine Magic Valley Pipeline,Inc. 77-0507851 Calpine Marketing, LLC 04-3436393 Calpine Monterey Cogeneration, Inc. 77-0397024 Calpine MVP, Inc. 77-0507852 Calpine NCTP GP, LLC 86-1056771 Calpine NCTP, LP 86-1056506 Calpine Northbrook Corporation of Maine, Inc. 77-0572148 Calpine Northbrook Energy Holdings, LLC 36-3790556 Calpine Northbrook Energy, LLC 36-4235799 Calpine Northbrook Investors, LLC 36-4233245 Calpine Northbrook Project Holdings, LLC 52-2218699 Calpine Northbrook Services, LLC 36-4271051 Calpine Northbrook Southcoast Investors, LLC 36-4337045 Calpine NTC, LP NA Calpine Oneta Power I, LLC 75-2815390 Calpine Oneta Power II, LLC 75-2815394 Calpine Oneta Power, L.P. 75-2815392 Calpine Operating Services Company, Inc. 71-0887428 Calpine Operations Management Company, Inc. 77-0558496 Calpine Pastoria Holdings, LLC 77-0559247 Calpine Philadelphia, Inc. 23-2547038 Calpine Pittsburg, LLC 77-0524474 Calpine Power Company 77-0211570 Calpine Power Equipment LP 77-0555123 Calpine Power Management, Inc. 94-3408181 Calpine Power Management, LP 94-3708181 Calpine Power Services, Inc. 11-3642873 Calpine Power, Inc. 51-0352026 Calpine PowerAmerica- CA, LLC 56-2304827 Calpine PowerAmerica - CT, LLC 77-0645731 Calpine PowerAmerica- MA, LLC 54-2122394 Calpine PowerAmerica- ME, LLC 54-2122391 Calpine PowerAmerica -NH, LLC 37-1496040 Calpine PowerAmerica-NY, LLC 74-3130329 Calpine PowerAmerica-OR, LLC 56-2304825 Calpine PowerAmerica, Inc. 77-0564589 Calpine PowerAmerica, LP 57-1205489 Calpine Producer Services, L.P. 75-2198121 Calpine Project Holdings, Inc. 77-0572149 Calpine Pryor, Inc. 74-2893556 -6- K&E 10919105.5 Debtor Tax ID# Calpine Rumford I, Inc. 77-0495621 Calpine Rumford, Inc. 77-0495622 Calpine Schuylkill, Inc. 23-2613016 Calpine Siskiyou Geothermal Partners, L.P. 77-0397029 Calpine Sonoran Pipeline, LLC 77-0572907 Calpine Stony Brook Operators, Inc. 77-0572142 Calpine Stony Brook Power Marketing, LLC 59-3821206 Calpine Stony Brook, Inc. 77-0572143 Calpine Sumas, Inc. 77-0295731 Calpine TCCL Holdings, Inc. 77-0486738 Calpine Texas Pipeline, GP, Inc. 77-0550650 Calpine Texas Pipeline, L.P. 77-0550749 Calpine Texas Pipeline, LP, Inc. 77-0550642 Calpine Tiverton I, Inc. 77-0494269 Calpine Tiverton, Inc. 77-0494266 Calpine ULC I Holding, LLC 55-0907827 Calpine University Power, Inc. 77-0572144 Calpine Unrestricted Fundings, LLC 56-2483129 Calpine Unrestricted Holdings, LLC 55-0883677 Calpine Vapor, Inc. 77-0448936 Carville Energy LLC 36-4309608 CCFC Development Company, LLC 77-0566178 CCFC Equipment Finance Company, LLC 77-0566184 CCFC Project Equipment Finance Company One, LLC 56-2500167 Celtic Power Corporation 77-0572133 CES GP, LLC 36-4512517 CES Marketing VII, LLC 20-3403057 Channel Energy Center, LP 77-0555137 Channel Power GP, LLC 86-1056758 Channel Power, LP 86-1056755 Clear Lake Cogeneration Limited Partnership 76-0252373 CNEM Holdings, LLC 32-0158075 CogenAmerica Asia, Inc. 23-2677506 CogenAmerica Parlin Supply Corporation 23-2485662 Columbia Energy LLC 36-4380154 Corpus Christi Cogeneration L.P. 36-4337040 CPN 3rd Turbine, Inc. 77-0576424 CPN Acadia, Inc. 77-0534543 CPN Berks Generation, Inc. 77-0513298 CPN Berks, LLC 77-0513022 CPN Bethpage 3rd Turbine, Inc. 77-0583485 CPN Cascade, Inc. 33-0534297 CPN Clear Lake, Inc. 47-0667302 CPN Decatur Pipeline, Inc. 77-0530348 CPN Energy Services GP, Inc. 77-0495420 CPN Energy Services LP, Inc. 77-0572147 -7- K&E 10919105.5 r Debtor Tax ID# CPN Freestone, LLC 77-0545937 CPN Funding, Inc. 41-1892779 CPN Morris, Inc. 41-1884586 CPN Oxford, Inc. 77-0520677 CPN Pipeline Company 77-0489460 CPN Pleasant Hill Operating, LLC 77-0559395 CPN Pleasant Hill,LLC 77-0530350 CPN Power Services GP, LLC 86-1056015 CPN Power Services, LP 86-1055932 CPN Pryor Funding Corporation 41-1852241 CPN Telephone Flat, Inc. 77-0321522 Decatur Energy Center, LLC 77-0555708 Deer Park Power GP, LLC 86-1056752 Deer Park Power, LP 86-1056744 Delta Energy Center, LLC 95-4812214 Dighton Power Associates Limited Partnership NA East Altamont Energy Center,LLC 77-0566240 Fond du Lac Energy Center, LLC 77-0567247 Fontana Energy Center, LLC 77-0578294 Freestone Power Equipment, LP 76-0608559 Freestone Power Generation, LP 76-0608559 GEC Bethpage Inc. 06-1220854 GEC Holdings, LLC 81-0626508 Geysers Power Company II, LLC 77-0503976 Geysers Power I Company 77-0503975 Gloverdale Geothermal Partners LLC 33-0315616 Goldendale Energy Center, LLC 75-3132706 Hammond Energy LLC 36-4348163 Hillabee Energy Center, LLC 83-0360324 Idlewild Fuel Management Corp. 11-3061354 JMC Bethpage, Inc. 04-2980589 KIAC Partners 11-3036753 Lake Wales Energy Center, LLC 77-0580173 Lawrence Energy Center, LLC 77-0565531 Lone Oak Energy Center, LLC 77-0565384 Los Esteros Critical Energy Facility, LLC 77-0583736 Los Medanos Energy Center, LLC 77-0553164 Magic Valley Gas Pipeline GP, LLC 86-1055920 Magic Valley Gas Pipeline, LP 86-1055914 Magic Valley Pipeline,L.P. 77-0507850 MEP Pleasant Hill, LLC 77-0552138 Moapa Energy Center,LLC 77-0566241 Mobile Energy LLC 36-4097615 Modoc Power, Inc. 77-0397028 Morgan Energy Center, LLC 77-0555141 Mount Hoffman Geothermal Company, L.P. 77-0397032 -8- K&E 109191055 Debtor Tax ID# Mt. Vernon Energy LLC 36-4343950 NewSouth Energy LLC 83-0413417 Nissequogue Cogen Partners 22-3056034 Northwest Cogeneration, Inc. 77-0276357 NTC Five, Inc. 16-1684059 NTC GP, LLC 54-2185596 Nueces Bay Energy LLC 36-4216016 O.L.S. Energy-Agnews, Inc. 77-0572145 Odyssey Land Acquisition Company 77-0546712 Pajaro Energy Center, LLC 77-0580174 Pastoria Energy Center, LLC 77-0582975 Pastoria Energy Facility, L.L.C. 77-0581976 Philadelphia Biogas Supply, Inc. 23-2486177 Phipps Bend Energy Center, LLC 45-0475412 Pine Bluff Energy, LLC 36-4132992 Power Investors, LLC 36-4047074 Power Systems MFG., LLC 65-0945128 Quintana Canada Holdings, LLC 77-0571374 RockGen Energy LLC 36-4348406 Rumford Power Associates Limited Partnership 04-3373838 Russell City Energy Center, LLC 80-0045453 San Joaquin Valley Energy Center,LLC 77-0578295 Skipanon Natural Gas, LLC 77-0557968 South Point Energy Center, LLC 77-0579923 South Point Holdings, LLC 80-0129192 Stony Brook Cogeneration, Inc. 77-0472431 Stony Brook Fuel Management Corp. 11-3187764 Sutter Dryers, Inc. 77-0419274 TBG Cogen Partners 04-3057472 Texas City Cogeneration, LP 77-0507664 Texas Cogeneration Company 76-0212244 Texas Cogeneration Five, Inc. 77-0506546 Texas Cogeneration One Company 47-0669902 Thermal Power Company 77-0031605 Thomassen Turbine Systems America, Inc. 34-2043722 Tiverton Power Associates Limited Partnership 77-0404269 Towantic Energy, L.L.C. 06-1 53 1404 VEC Holdings, LLC 51-0557228 Venture Acquisition Company 77-0557971 Wawayanda Energy Center, LLC 77-0565516 Westbrook, L.L.C. 77-0521787 Whatcom Cogeneration Partners, L.P. 77-0295732 Zion Energy LLC 36-4330312 -9- K&E 109'9105.5 r UNITED STATES BANKRUPTCY COURT SOUTHERN DISTRICT OF NEW YORK In re: ) Chapter 11 Calpine Corporation, et al., ) ) Case No. 05-60200 (BRL) Debtors. ) Jointly Administered INTERIM ORDER UNDER SECTIONS 327(a)AND 328(a) OF THE BANKRUPTCY CODE AUTHORIZING THE EMPLOYMENT AND RETENTION OF AP SERVICES,LLC AS CRISIS MANAGERS TO THE DEBTORS Upon the motion (the "Application")' of the above-captioned debtors (collectively, the "Debtors") for an order authorizing the employment and retention of AP Services, LLC ("APS") as crisis managers to the Debtors and upon the Declaration of Lisa J. Donahue (the "Donahue Declaration") in support of the Application; it appearing that the relief requested is in the best interest of the Debtors' estates, their creditors and other parties in interest; it appearing that the Court has jurisdiction over this matter pursuant to 28 U.S.C. §§ 157 and 1334; it appearing that this proceeding is a core proceeding pursuant to 28 U.S.C. § 157(b)(2); it appearing that venue of this proceeding and this Application in this District is proper pursuant to 28 U.S.C. §§ 1408 and 1409; notice of this Application and the opportunity for a hearing on this Application was appropriate under the particular circumstances and that no other or further notice need by given; and after due deliberation and sufficient cause appearing therefor, it is hereby ORDERED 1. The Application is approved on an interim basis until such time as the Court conducts a final hearing on this matter(the"Final Hearing"). Capitalized terms used but not otherwise defined herein shall have the meanings set forth in the Application. K&E 10884331.6 2. A Final Hearing on this Application shall take place before this Court at 10:00 a.m. (prevailing Eastern Time)on March 22, 2006. 3. The Debtors shall serve a copy of this Interim Order and notice of the Final Hearing on all creditors and parties in interest within five (5) days of the entry of this Interim Order. 4. Any objections to the relief requested by the Application on a final basis must be filed with the Court and served on the Office of the United States Trustee, 33 Whitehall Street, 21st Floor, New York, New York 10004, Attention: Paul Kenan Schwartzberg and Kirkland & Ellis LLP, attorneys for the Debtors, Matthew Cantor, Esq., Kirkland & Ellis LLP, 153 East 53rd Street, New York, NY 10022 so as to be actually received by no later than March 17, 2006 at 4:00 p.m.,prevailing Eastern Time. 5. APS is found to be a "disinterested person" within the meaning of 11 U.S.C. § 101(14). 6. The Debtors are hereby authorized, pursuant to sections 327(a) and 328(a) of the Bankruptcy Code, to employ and retain, under a general retainer, upon the terms and for the purposes set forth in the Application and the First Amended Engagement Letter, APS as crisis managers to the Debtors in these Chapter 11 Cases on an interim basis effective as of the Petition Date. 7. APS shall be compensated in accordance with the Application, the First Amended Engagement Letter, and this Interim Order, in accordance with the procedures set forth in sections 330 and 331 of the Bankruptcy Code, the Bankruptcy Rules, the Local Rules, guidelines established by this Court,the United States Trustee Guidelines, and the orders of this Court. 2 K&E 10884331 6 8. Notwithstanding anything to the contrary in the Bankruptcy Code, the Bankruptcy Rules, the Local Rules of this Court, any orders of this Court or any guidelines regarding submission and approval of fee applications, APS and its professionals shall only be required to maintain time records for services rendered postpetition in half-hour(.5) increments. 9. The United States Trustee and the Official Committee of Unsecured Creditors retain all rights to object to APS's interim and fmal fee applications (including expense reimbursement) on all grounds including but not limited to the reasonableness standard provided for in Section 330 of the Bankruptcy Code. 10. All requests of APS for payment of indemnity pursuant to the Engagement Letter .shall be made by means of an application (interim or final as the cace may be) and shall be subject to review by the Court to ensure that payment of such indemnity conforms to the terms of the Engagement Letter and is reasonable based upon the circumstances of the litigation or settlement in respect of which indemnity is sought, provided, however, that in no event shall APS be indemnified in the case of its own bad-faith, self-dealing, breach of fiduciary duty (if any),gross negligence or willful misconduct. 11. In no event shall APS be indemnified if the Debtor or a representative of the estate, asserts a claim for, and a court determines by final order that such claim arose out of, APS's own bad-faith, self-dealing, breach of fiduciary duty (if any), gross negligence, or willful misconduct. 12. In the event that APS seeks reimbursement for attorneys' fees from the Debtors pursuant to the Engagement Letter, the invoices and supporting time records from such attorneys shall be included in APS's own applications (both interim and final) and such invoices and time records shall be subject to the United States Trustee's guidelines for compensation and 3 K&E 10814331 6 reimbursement of expenses and the approval of the Bankruptcy Court under the standards of §§ 330 and 331 of the Bankruptcy Code without regard to whether such attorney has been retained under § 327 of the Bankruptcy Code and without regard to whether such attorneys' services satisfy Section 330(a)(3)(C)of the Bankruptcy Code. 13. APS shall make an additional disclosure in the form of a supplemental affidavit, to the extent such disclosure has not been previously made, no later than five (5) days prior to the Final Hearing date of any APS clients identified as either (a) Interested Parties as set forth in the Donahue Declaration or (b) the Debtors' top 100 unsecured creditors, representing equal to or greater than 1%of APS and AlixPartners's consolidated annual revenues. 14. The Debtors are authorized to take all actions necessary to effectuate the relief granted pursuant to this Interim Order in accordance with the Application. 15. The terms and conditions of this Interim Order shall be immediately effective and enforceable upon its entry. 16. To the extent that any term of this Interim Order is inconsistent with the Engagement Letter or Application,the terms of this Interim Order shall govern. 17. The requirement set forth in Rule 9013-1(b) of the Local Bankruptcy Rules for the Southern District of New York that any motion or other request for relief be accompanied by a memorandum of law is hereby deemed satisfied by the contents of the Application or otherwise waived. 18. The Court retains jurisdiction with respect to all matters arising from or related to the implementation of this Interim Order. 4 K&E 10884331 6 19. To the extent that this Interim Order is inconsistent with any prior order or pleading with respect to the Application in these cases or the Engagement Letter, the terms of this Interim Order shall govern. Dated: January 26, 2006 New York,New York /s/Burton R. Lifland United States Banlcruptcy Judge 5 K&E 10880331.6 UNITED STATES BANKRUPTCY COURT SOUTHERN DISTRICT OF NEW YORK In re: ) Chapter 11 Calpine Corporation, et al., ) Case No. 05-60200 (BRL) Debtors. ) Jointly Administered INTERIM ORDER AUTHORIZING RETENTION OF MILLER BUCKFIRE& CO., LLC AS FINANCIAL ADVISORS AND INVESTMENT BANKERS FOR THE DEBTORS Upon the application (the "Application")I of the above-captioned debtors (collectively, the"Debtors") pursuant to Fed. R. Bankr. P. 2014(a) for an interim order under section 327(a) and 328(a) of the Bankruptcy Code authorizing the employment and retention of Miller Buckfire & Co., LLC as financial advisors and investment bankers of the Debtors; and upon the Affidavit of Kenneth A. Buckfire in support of the Application; and it appearing that Miller Buckfire neither holds nor represents any interest adverse to the Debtors' estates; and it appearing that Miller Buckfire is "disinterested," as that term is defined in section 101(14) of the Bankruptcy Code; and it appearing that the relief requested is in the best interest of the Debtors' estates, their creditors and other parties in interest; it appearing that this Court has jurisdiction over this matter pursuant to 28 U.S.C. §§ 157 and 1334; it appearing that this proceeding is a core proceeding pursuant to 28 U.S.C. §157(b)(2); it appearing that venue of this proceeding and this Application in this District is proper pursuant to 28 U.S.C. §§ 1408 and 1409; notice of this Application and the opportunity for a hearing on this Application was appropriate under the particular Capitalized terms used but not otherwise defined herein shall have the meanings set forth in the Application. 1 K&E l 0sS4327.I I circumstances and that no other or further notice need be given; and after due deliberation and sufficient cause appearing therefor, it is hereby ORDERED 1. The Application is approved on an interim basis until such time as the Court conducts a final hearing on this matter(the"Final Hearing"). 2. The Final Hearing shall take place before this Court at 10:00 a.m. (prevailing Eastern Time) on March 22, 2006. 3. The Debtors shall serve a copy of this Interim Order and notice of the Fin! Hearing on all creditors and parties in interest within five (5) days of the entry of this Interim Order. 4. Any objections to the relief requested by the Application on a fmal basis must be filed with the Court and served on the Office of the United States Trustee, 33 Whitehall Street, 21st Floor, New York, New York 10004, Attention: Paul Kenan Schwartzberg and Kirkland & Ellis LLP, attorneys for the Debtors, Matthew Cantor, Esq., Kirkland & Ellis LLP, 153 Fast 53rd Street, New York, NY 10022 so as to be actually received by no later than March 17, 2006, at 4:00 pm,prevailing Eastern Time. 5. Miller Buckfire is found to be a "disinterested person" within the meaning of 11 U.S.C. § 101O4). 6. In accordance with sections 327(a), 328(a) and 1107(a) of the Bankruptcy Code, the Debtors are authorized to employ and retain Miller Buckfire as their financial advisors and investment bankers in these Chapter 11 Cases on an interim basis effective as of the Petition Date,pursuant to the terms set forth in the Application and the Engagement Letter. 7. The Engagement Letter, as modified by this Interim Order, is approved pursuant to 11 U.S.C. § 328(a) and the Debtors are authorized to pay, reimburse and indemnify Miller 2 K&E 101184327 I I Buckfire according to the terms and at the times specified in the Engagement Letter, as modified by this Interim Order. 8. Miller Buckfire shall be compensated in accordance with the procedures set forth in sections 330 and 331 of the Bankruptcy Code, the Bankruptcy Rules, the Local Rules and such procedures as may be fixed by order of this Court; provided, however, that Miller Buckfire shall not receive any payments from the Debtors on account of any monthly fee statement until the occurrence of the Final Hearing and the entry of a final order approving Miller Buckfire's retention it being understood that such Final Hearing shall occur no later than sixty (60) days after the mailing of the notice of the Final Hearing. 9. Notwithstanding the foregoing, fee applications filed by Miller Bucic ire shall be subject to review only pursuant to the standards set forth in section 328(a) of the Bankruptcy Code and not subject to the standard of review set forth in section 330 of the Bankruptcy Code. 10. The first sentence of Paragraph 7 of the Engagement Letter shall be deleted and replaced by the following: "Miller Buckfire has been retained under this agreement as an independent contractor with no agency relation to the Company or to any other party, it being understood that Miller Buckfire shall have no authority to bind, represent or otherwise acct as an agent, executor, administrator, trustee, lawyer or guardian for the Company, nor shall Miller Buckfire have the authority to manage money or property of the Company." 11. Notwithstanding anything to the contrary in the Bankruptcy Code, the Bankruptcy Rules, the Local Rules of this Court, any orders of this Court or any guidelines regarding submission and approval of fee applications, Miller Buckfire and its professionals (i) shall only be required to maintain time records for services rendered postpetition, in half-hour (.5) increments and(U) shall not be required to provide or conform to any schedule of hourly rates. 3 K&E 10884327.11 12. The United States Trustee retains all rights to object to Miller Buckfire's interim and final fee applications (including expense reimbursement) on all grounds including but not limited to the reasonableness standard provided for in Section 330 of the Bankruptcy Code. 13. All requests of Miller Buckfire for payment of indemnity pursuant to the Engagement Letter shall be made by means of an application (interim or final as the case may be) and shall be subject to review by the Court to ensure that payment of such indemnity conforms to the terms of the Engagement Letter and is reasonable based upon the circumstances of the litigation or settlement in respect of which indemnity is sought, provided, however, that in no event shall Miller Buckfire be indemnified in the case of its own bad-faith, self-dealing, breach of fiduciary duty(if any),gross negligence or willful misconduct. 14. In no event shall Miller Buckfire be indemnified if the Debtor or a representative of the estate, asserts a claim for, and a court determines by final order that such claim arose out of, Miller Buckfire's own bad-faith, self-dealing, breach of fiduciary duty (if any), gross negligence,or willful misconduct. 15. In the event that Miller Buckfire seeks reimbursement for attorneys' fees from the Debtors pursuant to the Engagement Letter, the invoices and supporting time records from such attorneys shall be included in Miller Buckfire's own applications (both interim and final) and such invoices and time records shall be subject to the United States Trustee's guidelines for compensation and reimbursement of expenses and the approval of the Bankruptcy Court under the standards of sections 330 and 331 of the Bankruptcy Code without regard to whether such attorney has been retained under section 327 of the Bankruptcy Code and without regard to whether such attorneys' services satisfy section 330(a)(3)(C)of the Bankruptcy Code. 4 K&E 10884327.11 16. The Retainer shall constitute a general security retainer for postpetition services and expenses until the conclusion of these Chapter 11 Cases, at which point Miller Buckfire will apply the Retainer against its then-unpaid Completion Fee and any other unpaid fees and expenses in respect of Miller Buckfire's fee applications filed and approved in accordance with applicable provisions of the Bankruptcy Code; provided, however, that the Official Committee of Unsecured Creditors retains all rights to object to the nature of the Retainer prior to the Final Hearing. Notwithstanding the foregoing, any party in interest shall have the right to raise before the Court the application of Miller Buckfire's Retainer, if any, to administrative expenses of the estates at any time, and Miller Buckfire reserves the right to contest any such matters. 17. Miller Buckfire shall make an additional disclosure in the form of a supplemental affidavit, to the extent such disclosure has not been previously made, no later than five (5) days prior to the Final Hearing date of any Miller Buckfire clients identified as creditors of the Debtors representing equal to or greater than I%of Miller Buckfire's annual revenues. 18. The Debtors are authorized to take all actions necessary to effectuate the relief granted pursuant to this Interim Order in accordance with the Application. 19. The terms and conditions of this Interim Order shall be immediately effective and enforceable upon its entry. 20. The requirement set forth in Rule 9013-1(b) of the Local Bankruptcy Rules for the Southern District of New York that any motion or other request for relief be accompanied by a memorandum of law is hereby deemed satisfied by the contents of the Application or otherwise waived. 5 K&E 10884327.11 21. To the extent that this Interim Order is inconsistent with any prior order or pleading with respect to the Application in these cases or the Engagement Letter, the terms of this Interim Order shall govern. 22. The Court retains jurisdiction with respect to all matters arising from or related to the implementation of this Interim Order. Dated: January 26, 2006 New York, New York /s/Burton R. Lifland United States Bankruptcy Judge 6 K&E 10884327.11 UNITED STATES BANKRUPTCY COURT SOUTHERN DISTRICT OF NEW YORK In re: ) ) Chapter 11 Calpine Corporation, et al., ) ) Case No. 05-60200 (BRL) Debtors. ) Jointly Administered NOTICE OF HEARING ON APPLICATION OF THE DEBTORS PURSUANT TO SECTIONS 327(a) AND 328(a) OF THE BANKRUPTCY CODE FOR AUTHORIZATION TO EMPLOY AP SERVICES, LLC AS CRISIS MANAGERS TO THE DEBTORS TO ALL CREDITORS AND PARTIES IN INTEREST: PLEASE TAKE NOTICE that Calpine Corporation and its debtor affiliates (the "Debtors")I seek a final order approving their Application Pursuant To Fed. R. Bankr. P. 2014(a) for an Interim Order Under Sections 327(a) and 328(a) of the Bankruptcy Code Authorizing the Employment and Retention of AP Services, LLC ("APS") as Crisis Managers to the Debtors as filed on December 21, 2005 (the "Application"). PLEASE TAKE FURTHER NOTICE that the Honorable Burton R. Lifland of the United States Bankruptcy Court for the Southern District of New York (the "Bankruptcy Court") approved an Interim Order Under Sections 327(a) and 328(a) of the Bankruptcy Code Authorizing the Employment and Retention of AP Services, LLC as Crisis Managers to the Debtors (the "Interim Order") on an interim basis pending a final hearing on the Application. PLEASE TAKE FURTHER NOTICE that the final hearing on the Application is scheduled for March 22, 2006 at 10:00 a.m. prevailing Eastern Time at the United States Capitalized terms used but not otherwise defined herein shall have the meanings set forth m the Application. Bankruptcy Court, Room 621, United States Customs House, One Bowling Green, New York, New York 10004. PLEASE TAKE FURTHER NOTICE that objections, if any, to the Application must be filed with the Court and served no later than March 17, 2006 at 4:00 p.m. prevailing Eastern Time on the Office of the United States Trustee, 33 Whitehall Street, 21st Floor, New York, New York 10004, Attn: Paul Kenan Schwartzberg; attorneys for the Debtors, Ann: Matthew Cantor, Esq., Kirkland & Ellis LLP, 153 East 53rd Street, New York, NY 10022; and attorneys for APS, Law Office of Sheldon S. Toll, PLLC, 2000 Town Center, Suite 2550, Southfield, MI 48075. PLEASE TAKE FURTHER NOTICE that any objections to the Application must be in writing, shall conform to the Federal Rules of Bankruptcy Procedure and the Local Rules of the Bankruptcy Court, and shall be filed with the Bankruptcy Court electronically in accordance with General Order M182 (General Order M-182 and the User's Manual for the Electronic Case Filing System can be found at www.nysb.ucourts.gov, the official website for the Bankruptcy Court), by registered users of the Bankruptcy Court's case filing system and, by all other parties in interest, on a 3.5 inch disk, preferably in Portable Document Format (PDF), Wordperfect or any other Windows-based word processing format (with a hard-copy delivered directly to Chambers). PLEASE TAKE FURTHER NOTICE that pursuant to the Application, Debtors seek to retain APS to assist the Debtors in their operations and restructuring efforts, with an objective of developing a short-term cash flow forecasting tool, restructuring the Debtors, and managing the Debtors' restructuring efforts, including negotiating with parties in interest and coordinating the 2 "working group" of the Debtors' employees and external professionals who are assisting the Debtors in the restructuring process. PLEASE TAKE FURTHER NOTICE that, if its retention is approved, MS will, unless such terms prove to have been improvident in light of developments not capable of being anticipated at the time of the hearing, be entitled to receive the following compensation: (a) MS will be compensated at the following hourly rates and will bill the Debtors on a monthly basis for any fees incurred in connection with services provided to the Debtors: Managing Directors $570-690 Directors $430-530 Vice Presidents $320-410 Associates $250-280 Analysts $180-200 Paraprofessionals $150 (b) Debtors also have agreed to consider paying APS a contingent success fee (the "Contingent Success Fee") in the event that the Debtors complete a successful restructuring or sale of the Company. As set forth in the Engagement Letter, not less than 90 days following the beginning of the engagement, the parties will determine the terms of the Contingent Success Fee. PLEASE TAKE FURTHER NOTICE that if the Application is granted, the Debtors will indemnify and hold APS harmless against liabilities arising out of or in connection with its retention by Debtors, provided, however, in no event shall APS be indemnified if the Debtors or representatives of their estates assert a claim for, and a Court of competent jurisdiction determines by a final order that such claim arose out of, APS's own bad faith, self-dealing, breach of fiduciary duty (if any), gross negligence or willful misconduct. PLEASE TAKE FURTHER NOTICE that the foregoing summary of certain elements of the retention is not complete and that the full terms of the retention are contained in the Application and the Engagement Letter, which are available for inspection at the clerk's office for the Bankruptcy Court, on the Bankruptcy Court's Internet site at www.nysb.uscourts.gov, 3 and on the website of the Debtors' notice and claims agent, Kurtzman Carson Consultants LLC, at http://www.kccllc.net/calpine. To the extent that the summary of the retention terms set forth in this notice conflict with the terms of the Engagement Letter, the terms of the Engagement Letter control. Dated: January 26, 2006 Respectfully submitted, New York, New York /s/ Matthew A. Cantor Richard M. Cieri (RC 6062) Matthew A. Cantor(MC 7727) Edward Sassower (ES 5823) Robert G. Bums (RB 0970) KIRKLAND & ELLIS LLP 153 East 53`d Street New York, New York 10022-4611 Telephone: (212)446-4800 Facsimile: (212) 446-4900 Counsel for the Debtors 4 • UNITED STATES BANKRUPTCY COURT SOUTHERN DISTRICT OF NEW YORK In re: Chapter I1 Calpine Corporation, et al., Case No. 05-60200 (BRL) Debtors. ) Jointly Administered NOTICE OF HEARING ON APPLICATION OF THE DEBTORS PURSUANT TO SECTIONS 327(a) AND 328(a) OF THE BANKRUPTCY CODE FOR AUTHORIZATION TO EMPLOY MILLER BUCKFIRE & CO., LLC AS FINANCIAL ADVISORS AND INVESTMENT BANKERS TO THE DEBTORS TO ALL CREDITORS AND PARTIES IN INTEREST: PLEASE TAKE NOTICE that Calpine Corporation and its debtor affiliates (the "Debtors")I seek a final order approving their Application Pursuant To Fed. R. Bankr. P. 2014(a) for an Order Under Sections 327(a) and 328(a) of the Bankruptcy Code Authorizing the Employment and Retention of Miller Buckfire & Co., LLC ("Miller Buckfire") as Financial Advisors and Investment Bankers to the Debtors as filed on December 22, 2005 (the "Application"). PLEASE TAKE FURTHER NOTICE that the Honorable Burton R. Lifland of the United States Bankruptcy Court for the Southern District of New York (the "Bankruptcy Court") approved an Interim Order Under Sections 327(a) and 328(a) of the Bankruptcy Code Authorizing the Employment and Retention of Miller Buckfire & Co., LLC as Financial Advisors and Investment Bankers to the Debtors (the "Interim Order") on an interim basis pending a final hearing on the Application. Capitalized terms used hut not otherwise dermal herein shall have the meanings set torah in the Application. PLEASE TAKE FURTHER NOTICE that the final hearing on the Application is scheduled for March 22, 2006 at 10:00 a.m. prevailing Eastern Time at the United States Bankruptcy Court, Room 621, United States Customs House, One Bowling Green, New York, New York 10004. PLEASE TAKE FURTHER NOTICE that objections, if any, to the Application must be filed with the Court and served no later than March 17, 2006 at 4:00 p.m. prevailing Eastern Time on the Office of the United States Trustee, 33 Whitehall Street, 21st Floor, New York, New York 10004, Attention: Paul Kenan Schwartzberg and Kirkland & Ellis LLP, attorneys for the Debtors, Matthew Cantor, Esq., Kirkland & Ellis LLP, 153 Fast 53rd Street, New York, NY 10022. PLEASE TAKE FURTHER NOTICE that any objections to the Application must be in writing, shall conform to the Federal Rules of Bankruptcy Procedure and the Local Rules of the Bankruptcy Court, and shall be filed with the Bankruptcy Court electronically in accordance with General Order M-182 (General Order M-182 and the User's Manual for the Electronic Case Filing System can be found at www.nysb.ucourts.gov, the official website for the Bankruptcy Court), by registered users of the Bankruptcy Court's case filing system and, by all other parties in interest, on a 3.5 inch disk, preferably in Portable Document Format (PDF), Wordperfect or any other Windows-based word processing format (with a hard-copy delivered directly to Chambers). PLEASE TAKE FURTHER NOTICE that pursuant to the Application, Debtors seek to retain Miller Buckfire under the terms of the Engagement Letter to provide a broad range of necessary financial advisory and investment banking services as Miller Buckfire and the Debtors 2 shall deem appropriate and feasible in order to advise the Debtors in the course of these Chapter 11 cases. PLEASE TAKE FURTHER NOTICE that, if its retention is approved, Miller Buckfire will, unless such terms prove to have been improvident in light of developments not capable of being anticipated at the time of the hearing, be entitled to receive the following compensation: (a) Monthly Fees: A Monthly Advisory Fee of$250,000. (b) DIP Financing Fee: Upon obtaining a written commitment for a DIP financing facility, a fee of$2,000,000. (c) Completion Fee: If the Debtors consummate a Transaction then upon closing of such Transaction and the effective date of a plan of reorganization approved by the Court, a Completion Fee equal to $17,000,000. (d) Retainer: A Retainer of $2,000,000, to be credited in full against the Completion Fee. (e) In addition to the fees described above, and regardless of whether any transaction occurs, the Debtors shall promptly reimburse Miller Buckfire, upon request from time to time, for all: (i) reasonable out-of-pocket expenses (including travel and lodging, data processing and communications charges, courier services and other appropriate expenses) and (ii) other reasonable fees and expenses, including expenses of counsel retained with the Debtors' consent (which shall not be unreasonably withheld). PLEASE TAKE FURTHER NOTICE that if the Application is granted, the Debtors will indemnify and hold Miller Buckfire harmless against liabilities arising out of or in connection with its retention by Debtors, provided, however, in no event shall Miller Buckfire be indemnified if the Debtors or representatives of their estates assert a claim for, and a Court of competent jurisdiction determines by a final order that such claim arose out of, Miller Buckfire 's own bad faith, self-dealing, breach of fiduciary duty (if any), gross negligence or willful misconduct. PLEASE TAKE FURTHER NOTICE that the foregoing summary of certain elements of the retention is not complete and that the full terms of the retention are contained in the 3 Application and the Engagement Letter, which are available for inspection at the clerk's office for the Bankruptcy Court, on the Bankruptcy Court's Internet site at www.nysb.uscourts.gov, and on the website of the 12ebtors' notice and claims agent, Kurtzman Carson Consultants LLC, at http://www.kcclIc.net/calpine. To the extent that the summary of the retention terms set forth in this notice conflict with the terms of the Engagement Letter, the terms of the Engagemert Letter control. Dated: January 26, 2006 Respectfully submitted, New York, New York /s/ Matthew A. Cantor Richard M. Cieri (RC 6062) Matthew A. Cantor(MC 7727) Edward Sassower (ES 5823) Robert G. Burns (RB 0970) KIRKLAND & ELLIS LLP 153 East 53rd Street New York, New York 10022-4611 Telephone: (212) 446-4800 Facsimile: (212) 446-4900 Counsel for the Debtors 4 , 'g! 3f,f UNITED STATES BANKRUPTCY COURT SOUTHERN DISTRICT OF NEW YORK Weld County Planning Department GREELEY OFFICE In re: ) FEB 0 1 2006 ) Cha)Jter 11 Calpine Corporation,et al., > IZ E C E I Vr E D Case No.05-60200(BRL) Debtors. ) Jointly Administered NOTICE OF(A)NOTIFICATION PROCEDURES APPLICABLE TO SUBSTANTIAL HOLDERS OF EQUITY SECURITIES,(B)NOTIFICATION AND HEARING PROCEDURES FOR TRADING IN EQUITY SECURITIES,AND (C)ALLOWING A HEARING ON THE PROSPECTIVE APPLICATION THEREOF TO ALL PERSONS OR ENTITIES WITH EQUITY INTERESTS IN THE DEBTORS: PLEASE TAKE NOTICE THAT on December 20, 2005 (the"Petition Date"),Calpine Corporation("Calpine") and certain of its subsidiaries and affiliates (the "Affiliate Debtors," and together with Calpine, the "Debtors"), commenced cases under ci.apter 11 of title 11 of the United States Code, 11 U.S.C. §§ 101-1330, as amended by the Bankruptcy Abuse Prevention and Consumer Protection Act of 2005 (the `Bankruptcy Code"). Subject to certain exceptions, section 362 of the Bankruptcy Code operates as a stay of any act to obtain possession of property of the Debtors' estates or property from the Debtors' estates or to exercise control over property of the Debtors' estates. PLEASE TAKE FURTHER NOTICE THAT on December 21, 2005, the Debtors filed a motion seeking entry of an order pursuant to sections 105, 362 and 541 of the Bankruptcy Code establishing notification procedures and approving restrictions on certain transfers of Calpine equity securities(the"Motion")(see Docket No. 5). PLEASE TAKE FURTHER NOTICE THAT on December 21, 2005, the United States Bankruptcy Court for the Southern District of New York(the"Bankruptcy Court")entered an order approving the Motion and the procedures set forth below in order to preserve the Debtors' net operating losses and certain other tax attributes (collectively, the "Tax Attributes") pursuant to sections 105,362 and 541 of the Bankruptcy Code(the"Order")(see Docket No. 37). Any sale or transfer of equity securities in the Debtors in violation of the procedures set forth below shall be null and void ab initio as an act violating the automatic stay provisions of section 362 of the Bankruptcy Code.l PLEASE TAKE FURTHER NOTICE THAT, pursuant to the Order, the following procedures shall apply to holding and trading in EQUITY SECURITIES OF CALPINE: (a) Any person2 or entity who currently is or becomes a Substantial Shareholder (as defined in paragraph (e) below) must file with the Court, and serve upon the Debtors and attorneys for the Debtors, a notice of such status ("Notice of Status as a Sabstan= al Shareholder") on or before the later of(A) 40 days after the effective date of the notice of entry of the Order or (B) 10 :'"ys after becoming a Substantial Shareholder. (b) Prior to effectuating any transfer of equity securities (including options to acquire stock, as defined in paragraph (e) below) that would result in an increase in the amount of common stock of Calpine beneficially owned by a Substantial Shareholder or would result in a person or entity becoming a Substantial Shareholder, such Substantial Shareholder must file with the Bankruptcy Court and serve on the Debtors and attorneys for the Debtors an advance written notice ("Notice of Intent to Purchase, Acquire or Otherwise Accumulate"),of the intended transfer of equity securities. (c)Prior to effectuating any transfer of equity securities(including options to acquire stock) that would result in a decrease in the 2mount of common stock of Calpine beneficially owned by a Substantial Shareholder or would result in a person or entity I PLi.,,SE TAKE FURTHER NOTICE THAT on January 5,2006,pursuant to Paragraph 4 of the Order,the Debtors amended Paragraph 3(e)of the Order to exclude the pl. asc"convertible debt"and filed with the Bankruptcy Court a notification regarding the same(see Docket No.346). 2 References to"person"herein are made in accordance with the definition of"person"in section 101(41)of the Bankruptcy Code. ceasing to be a Substantial Shareholder,such Substantial Shareholder must file with the Court,and serve on the Debtors and counsel to the Debtors, advance written notice ("Notice of Intent to Sell, Trade, or Otherwise Transfer")3, of the intended transfer of equity securities. (d)The Debtors shall have 30 calendar days after receipt of a Notice of Proposed Transfer to file with the Bankruptcy Court and serve on such Substantial Shareholder an objection to any proposed transfer of equity securities described in the Notice of Proposed Transfer on the grounds that such transfer may adversely affect the Debtors' ability to utilize the Tax Attributes. If the Debtors file an objection, such transfer shall not be effective unless approved by a final and nonappealable order of the Bankruptcy Court. If the Debtors do not object within such 30-day period,such transfer may proceed solely as set forth in the Notice of Proposed Transfer. Further transactions within the scope of this paragraph must be the subject of additional notices as set forth herein with an additional 30-day waiting period. (e) For purposes of this Notice, (A) a "Substantial Shareholder" is any person or entity that beneficially owns at least 25,600,000 shares of the common stock of Calpine, (B) "beneficial ownership" of equity securities includes direct and indirect ownership (i.e., a holding company would be considered to beneficially own all shares owned or acquired by its subsidiaries), ownership by such holder's family members and persons acting in concert with such holder to make a coordinated acquisition of stock, and ownership of shares which such holder has an option to acquire, and (C) an "option" to acquire stock includes any contingent purchase, warrant, put, stock subject to risk of forfeiture, contract to acquire stock or similar interest, regardless of w?.; •er it is contingent or otherwise not currently exercisable, but shall not include any debt instrument that is convertible into PLEASE TAKE FURTHER NOTICE THAT, upon the request of any person, attorneys for the Debtors, Kirkland & Ellis LLP, 153 East 53rd Street, New York, New York 10022, Attn.: Richard M. Cieri, Esq., will provide a form of each of the required notices described above. PLEASE TAKE FURTHER NOTICE THAT, upon the request of any person, Kurtzman Carson Consultants LLC (the "Official Copy Service"), 12910 Culver Boulevard, Suite I, Los Angeles, California, (310) 823-9000 (telephone), (310) 823-9133 (facsimile), shall supply a copy of the Order. The Official Copy Service shall supply a copy of the Order at a cost to be paid by the person requesting it at the prevailing fee being charged by the Official Copy Service. The Official Copy Service shall accommodate document requests during normal business hours,Monday to Friday(excluding recognized holidays).4 FAILURE TO FOLLOW THE PROCEDURES SET FORTH IN THIS NOTICE SHALL CONSTITUTE A VIOLATION OF THE AUTOMATIC STAY PROVISIONS OF SECTION 362 OF THE BANKRUPTCY CODE. ANY PROHIBITED PURCHASE, SALE, TRADE OR OTHER TRANSFER OF EQUITY SECURITIES IN THE DEBTORS IN VIOLATION OF THE ORDER SHALL BE NULL AND VOID AB INITID AND MAY BE PUNISHED BY CONTEMPT OR OTHER SANCTIONS IMPOSED BY THE BANKRUPTCY COURT. PLEASE TAKE FURTHER NOTICE THAT the requirements set forth in this Notice are in addition to the requirements of Rule 3002 of the Federal Rules of Bankruptcy Procedure and applicable securities, corporate and other laws, and do not excuse compliance therewith. Dated: January 20,2006 Calpine Corporation 50 West San Fernando Street, San Jose,California 95113 Attn.: General Counsel Kirkland&Ellis LLP Citigroup Center, 153 East 53rd Street,New York 10022 Attn.: Richard M. Cieri,Esq. 3 A Notice of Intent to Sell,Trade or Otherwise Transfer,together with a Notice of Intent to Purchase,Acquire or Accumulate,is hereinafter collectively referred to as a"Notice of Proposed Transfer." 4 Normal business hours for the Official Copy Service arc from 9:00 a.m.to 6:00 p.m.(prevailing Pacific Time). 2 Anacapa Land Company, LLC P.O. Box 11749 Pleasanton, CA 94588-1749 Phone: 925-479-6664 Toll Free: 877-446-4406 Fax: 925-479-7309 December 1 , 2005 Commissioner Robert Masden Weld County Board of Commissioners 915 10`h Street Greeley, Colorado 80631 Re: Rocky Mountain Energy Center Conservation Easement Dear Commissioner Masden; Enclosed per your request are copies of various correspondence relating to Anacapa Land Company, LLC ("Anacapa") efforts to place the property into a conservation easement. As of September 28, 2005, the Colorado Cattlemen's Agricultural Land Trust has expressed interest in the property, and Anacapa is proceeding to work through the issues with them. Please contact me at 925-479-6664 should you have any questions. Best Regards, J mes Hines, CC1M irector, Land Cc: J. Gooding \ I / , / anti COLORADO CATTLEMEN'S AGRICULTURAL ,AND TRUST rig ------- r \-"- PROTECTING OPEN SPACE BY PRESERVING AGRICULYURE September 28, 2005 Jim Hines Calpine Director, Land 4160 Dublin Blvd. Dublin, California 94.68-3139 Dear Jim, On September 7, 2005 The Colorado Cattlemen's Agricultural Land Trust's Board of Directors accepted the project called the Calpine Property, owned by Calpine/Rocky Mountain Energy Center in consideration of holding a conservation easement on 400 acres of this property north of the town of Hudson in Weld County, Colorado. It will be the responsibility of each party to keep their individual organizations informed regarding progress of the project and easement negotiations. Both parties agree to keep the other informed of any changes in the project details in as timely a fashion possible. Both Parties have agreed to work together to complete this project in the manner set forth and agreed upon. jute Date CCALT Project Manager Calpine Project Manager 8533 Ralston Road • Arvada,Colorado 80002 • 303-431-6422 • Fax 3034214316 • info@ccalt.org • www.ccalt.org OckANDis STATE OF COLO Bill Owens,Governor Douglas H.Benevento,Executive Director � o4'coc„ ��,.c7..e,.3 Dedicated to protecting and improving the health and environment of the pw�l aof0 1.000ty Colorado p' 4300 Cherry Creek Dr.S. Laboratory Services Division Planning Department I x14.; **+`) Denver,Colorado 80246-1530 8100 Lowry Blvd. GREELEY OFFICE Phone(303)692-2000 Denver,Colorado 80230-6928 TDD Line(303)691-7700 (303)692-3090 JUL 2 5 2005 Colorado Department Located in Glendale,Colorado of Public Health http://www.cdphe.state.co.us RECEIVED and Environment July 20, 2005 U.S.EPA-Region 8 U.S. Forest Service Attn.: Mr.Hans Buenning Attn.: Mr. Jeff Sorkin 999 18th St Ste 500 P.O.Box 25127 AP-AR LAKEWOOD CO 80225 DENVER CO 80202 ��r/ National Park Service-Air Resources Division "nty Clerk, Weld County Attn.: Mr.John Notar/Ms.Liana Reilly s`►T/lease make the attached submittal available for P.O.Box 25287 DENVER CO 80225-0287 public review. Re: Rocky Mountain Energy Center, LLC PSD Application for major modification. Ladies/Gentlemen: Rocky Mountain Energy Center,LLC has submitted an application under the Prevention of Significant Deterioration (PSD) provisions for the installation of a natural gas fired combustion turbine for power generation. Enclosed is a copy of the application. If you have any questions on this, please feel free to contact me at 303-692-3198. Please send in your comments at your earliest convenience. CCM Sinc rely, ,CORam N. Seetharam lK Professional Engineer Construction onary Permitsuc s Unit ( J� Stationary Sources Program Air Pollution Control Division ` APCD-SS-B1 ,3uG R-1-1/a0 : F a- .s-7_ , AC APPLICATION FOR MODIFICATION OF ANces EXISTING MAJOR SOURCE t' W ah eke, toes go For the: Rocky Mountain Energy Center Submitted on behalf of Rocky Mountain Energy Center,LLC Calpine Corporation 6211 Weld County Road 51 Keenesburg,CO 80643 Prepared by 06P CS, METEOROLOGICAL AND AIR QUALITY MODELING Atmospheric Dynamics,Inc. 2925 Puesta del Sol Rd. Santa Barbara,CA 93105 July 2005 APPLICATION FOR MODIFICATION OF AN EXISTING MAJOR SOURCE For the: ,act w a Rocky Mountain Energy Center Satonrl °;yes' So Submitted on behalf of Rocky Mountain Energy Center,LLC Calpine Corporation 6211 Weld County Road 51 Keenesburg, CO 80643 Prepared by ter' .A!l VIOSPHE rI • CS METEOROLOGICAL AND AR QUALITY MODELING Atmospheric Dynamics,Inc. 2925 Puesta del Sol Rd. Santa Barbara, CA 93105 July 2005 Table of Contents Page 1.0 Introduction 1 1.1 Project Schedule 1 1.2 Application Organization 2 2.0 Existing Facility and Proposed Project Descriptions 4 2.1 Existing Equipment and Processes 4 2.1.1 Existing Project Emissions 5 2.2 Proposed Project and Modifications 8 2.3 Proposed Modification Project Emissions 8 2.3.1 Criteria Pollutant Emissions 9 2.3.2 Hazardous Pollutant Emissions 11 2.4 Proposed Exhaust Stacks and Emissions Points 13 2.5 Emissions Impacts from Proposed Modification 13 3.0 Regulatory Analysis 14 3.1 Prevention of Significant Deterioration (PSD) 14 3.2 Emission Standards 14 3.2.1 New Source Performance Standards 14 3.2.1.1 Subpart GG and KKKK 14 3.2.1.2 Subpart Da 15 3.2.2 Title 4 Acid Rain Provisions 15 3.2.3 Applicable Colorado Regulations 15 4.0 Regional and Site Description 17 4.1 Project Location 17 4.2 Population and Land Use 17 4.3 Existing Climate 17 4.4 Existing Air Quality 18 4.5 Existing Soils and Vegetation 18 5.0 Analysis of BACT for NOx, PM10, CO, VOC and SO2 21 5.1 BACT Analysis for the Combined Cycle Unit 22 5.1.1 Analysis of Control Requirements for Nitrogen Oxides 22 5.1.2 Evaluation of Achieved in Practice 30 5.1.2.1 Achieved in Practice Criteria Evaluation for SCR 31 5.1.2.2 Achieved in Practice Criteria Evaluation for SCONOx 32 5.1.3 Evaluation of Ammonia Emissions 36 5.1.4 Analysis of Control Requirements for Carbon Monoxide 39 5.1.5 Analysis of Control Requirements for PM to 41 5.1.6 Analysis of Control Requirements for VOC 44 5.1.7 Analysis of Control Requirements for SO2 45 6.0 Evaluated Operational Scenarios 46 7.0 Air Quality Modeling Analysis 47 7.1 Overview of the Modeling Process 47 7.2 Goals of the Air Quality Modeling Analysis 47 i r v1 7.3 Existing Meteorology and Air Quality 48 7.4 Site Representation 49 7.5 Background Air Quality 50 7.6 Auer Land Use Analysis 50 7.7 Air Quality Dispersion Models 51 7.8 Analysis Scenarios 55 7.9 Class I and Class II Area Impacts 58 8.0 Air Quality Impact Analysis 70 8.1 Impacts on Existing Ambient Air Quality Standards 70 8.2 Impacts on Class I Areas 75 8.3 Impacts on Class II Areas 81 9.0 Socioeconomic and Growth Impacts 84 9.1 Socioeconomic Impacts 84 9.2 Growth Inducing Impacts 84 10.0 Summary and Conclusions 85 References APPENDICES Appendix A APEN Forms Appendix B Emissions Calculations and Data Sheets Appendix C Modeling Input/Output files on CD Appendix D Miscellaneous Support Data FIGURES Figure 1-1: General Site Location Map Figure 2-1: Existing Facility Plot Plan Figure 2-2: New Equipment Location(Plot Plan) Figure 2-3: Simplified Process Flow Diagram Figure 7-1: Surrounding Terrain Figure 7-2 Wind Rose Summary Figure 7-3: Building Configuration for Modeling Analysis Figure 7-4: Coarse Receptor Grid Figure 7-5: Downwash/Fenceline Receptor Grid Figure 7-6: Fine Receptor Grid Figure 7-7: Calpuff Class I Receptor Rings Figure 7-8: Annual Precipitation Colorado TABLES Table 2-1: Combustion Turbine Short Term Emission Rates Table 2-2: Turbine/HRSG Short Term Emission Rates Table 2-3: Aux Boiler Short Term Emission Rates Table 2-4: Emergency Generator Short Term Emission Rates Table 2-5: Fire Pump Short Term Emission Rates ii Table 2-6: Existing Device Heat Rates Table 2-7: Existing Facility Start-up Emission Rates Table 2-8: Existing Facility Emissions Table 2-9 Proposed Turbine Short Term Emission Rates Table 2-10 Proposed Turbine/HRSG Short Term Emission Rates Table 2-11 Proposed Device Heat Rates Table 2-12 Proposed Equipment Start-up Emission Rates Table 2-13 Proposed New Equipment Emissions Table 2-14 Proposed New Equipment HAP Emissions Table 2-15 Typical Natural Gas Analysis Data Table 4-1: Background Air Quality Values Table 4-2: Summary of Soils in the Project Area Table 5-1: NOx Control Technologies Ranked by Effectiveness Table 5-2: Comparison of SCR and SCONOx Removal Technologies Table 5-3: NOx Control Technologies Ranked by Ammonia Emissions Table 5-4A: SCR Costs (Per Gas Turbine/HRSG) Table 5-4B: SCONOx Cost and Incremental Cost(Per Gas Turbine/HRSG) Table 5-4C: SCONOx Incremental Cost(Per Gas Turbine/HRSG) Table 5-5: Summary of CO BACT Evaluation Results Table 5-6: Oxidation Catalyst Costs (per Gas Turbine/HRSG) Table 7-1: Modeling Criteria Summary Table 7-2: Significance Values for Class MI Areas Table 7-3: Building Dimensions for RMEC Table 7-4: Land Use Parameters Table 7-5: Distances and Elevations of Class I Receptor Rings Table 8-1: Load Screening results for RMEC Table 8-2: ISCST3 Source Emissions for Modeling Table 8-3: Modeled Emission Rates and Stack Data for Turbine Startup Table 8-4: PSD Monitoring Exemption Levels Table 8-5: Projecflmpact Summary Table 8-6: Proposed Emissions vs. PSD Significant Emission Rate Thresholds Table 8-7: PSD Significant Impact Levels and Increments Table 8-8: Maximum Modeled Impacts vs. PSD Significance Thresholds Table 8-9: Preconstruction Monitoring Requirements Table 8-10: Summary of Class I Concentration Impacts Table 8-11: Summary of Class I Visibility Impacts(Regional Haze) Table 8-12: Summary of Class I/II Deposition Analysis Table 8-13: ANC Calculations Including Sensitive Class II Areas iii 1.0 INTRODUCTION Rocky Mountain Energy Center,LLC(RMEC)currently operates a 600 MW power generating facility near the town of Hudson, Colorado. The plant site is located just east of the town of Hudson and is bounded by CR 49 to the west, CR 16 to the north, and CR 51 to the east. The site location in Universal Transverse Mercator (UTM) coordinates is 534491 meters casting, 4437767 meters northing. Figure 1-1 shows the general regional and local site locations of the power plant. The power plant site is zoned "agricultural" with a"Use by Special Review Permit",and is located adjacent to an existing commercial/industrial area in the town of Hudson,which lies to the west,and agricultural land uses with scattered residences to the east and west. The RMEC has the capacity to generate a nominal 600 megawatts (MW) of electrical power,with a peak capacity up to 630 MW. The facility is a major source of oxides of nitrogen(NOx),carbon monoxide(CO), particulate matter with an aerodynamic diameter of 10 microns or less (PM1o), and volatile organic compounds (VOCs), and a minor emissions source of sulfur dioxide (SO2). The facility was originally subject to Colorado State Regulation No. 3,Part B IV.D.3 and 40 CFR Part 52,because the emission rates triggered the requirements of the Prevention of Significant Deterioration (PSD)permit program. The current facility is comprised of two (2)Westinghouse 501FD combustion turbine(CT)units,two(2) heat recovery steam generators(HRSG),a twelve(12)cell cooling tower,one(1)condensing steam turbine generator (CSTG), a 129 MMBtu/hr(HI-1V)natural gas fired auxiliary boiler, a diesel fueled emergency generator, and a diesel fueled emergency fire pump. Except for the emergency equipment, the facility is fueled exclusively by natural gas. Each CT/HRSG has the capacity to fire up to 2311 MMBtu/hr(HHV)of natural gas. Each of the two(2) combustion turbines incorporate dry low-NOx combustion systems that limit NOx emissions to 25 ppmv. Each HRSG incorporates low NOx burners and a Selective Catalytic Reduction(SCR) system to further control NOx down to 3.0 ppm,,. Each turbine/HRSG combination also incorporates a CO catalyst that limits CO emissions to 9 ppm,,. The auxiliary boiler incorporates low NOx burners to limit emissions of NOx to 30 ppm,,. Steam produced in the HRSGs is used to drive the CSTG, which produces additional electric generation. RMEC is proposing to modify the existing power plant facility through the expansion of the existing 2X1 combined cycle facility to a 3X 1 configuration.The expansion would consist of the addition of a single F- class combustion turbine and associated HRSG. Sections 2.2 through 2.5 present detailed data on the proposed expansion. 1.1 Modification Project Schedule The modification project will be implemented in the following phases: • Permitting Application Submittal (July, 2005) • Engineering and Procurement(January, 2006) • Construction(August, 2006) • Startup/Testing (approximately a 2 month period following completion of construction) • Commercial Operation (immediately following the Startup/Testing phase March, 2008) To support the above noted schedule,as well as expeditious approval,RMEC will provide technical support to the staff by making technical staff available on an as-needed basis from the following companies: 1 sl • ..... P m \ L y I _ cn, Cel 3 Oro � ``_ __ •o CIO I ~ d a r el'J I - e e L. J �/ m Ii 'O CU I 3k o a 41 Eld \ g �. CC 3 O i •• �� `��? . — - V \_��`\ ` ��!£`` vita\ /d �.J� w T i. I !-4cn_r ' Ira .. - U� `yi1 i .. 4 ' t0 S J U 3 `1 L — J v L � - Ss 0, - v o A, O .. . .. ^J .Z d J..I �N� tO �•Q.r� r- .. _ s W u Q) w v I—, ' v Y C �•� v L La E r• 2,rrtldo.: 1 'O 44" n c 3 -. u G — z ' c v, •U o o E woo, ° Tp' . - cL, N � I In` kOi �CCL N ^ro y Z. I j ij, Up cou G v O1 c ' O __I yaw o ' cn,x� 1"a „7,• , ; •Y ci •-4 U - - w w z w c.:-" h"l 0 �, o a O= .a - o > .n o f w a ct pa . 0 P Q a ‘'" � SAC cuJ ° � M. iz : j-ti zC. 3 $ _ co-W ''''In 5• N N � .. 1-.cc: v J C\ v G L gyp) { • '�` fC9Q.1 t[t N v Siemens Westinghouse -- Combustion Turbine Technology Calpine -- Overall Project Design Atmospheric Dynamics, Inc. -- Environmental Technology and Air Quality Analysis ENV Environmental -- Environmental Technology and Air Quality Analysis 1.2 Application Organization This application is organized into 10 sections and applicable appendices: Section 1.0 Introduction provides a basic introduction to the existing facility, modification project schedule, and the organization of this document. Section 2.0 Existing and Proposed Project Description describes the existing facility and the proposed modifications and associated equipment. Section 3.0 Regulatory Analysis contains discussions of the applicability of new source review(NSR)rules,and new source performance standards(NSPS). This section also discusses the applicability of tribal, state and local air quality regulations. Section 4.0 Regional and Site Description contains information pertaining to the proposed modification project including geographic information; site location and topographic maps; and plot plans indicating the locations of existing and proposed facilities and units. Section 5.0 Analysis of Best Available Control Technologies for NOx, PM1a, CO,VOC and SO2 presents the analysis of control requirements conducted to determine best available control technology (BACT) for the proposed modifications. Section 6.0 Emissions Inventory presents pollutant specific emission rates and stack parameters of each proposed new source and the basis for the values presented. Section 7.0 Air Quality Modeling Analysis describes the air quality dispersion modeling analysis conducted to demonstrate that the impacts associated with the proposed modifications will not adversely impact existing air quality or exceed the available increment(s). This section includes a discussion of model selection,methodology,and inputs,as well as results of the analysis. Section 8.0 Air Quality Impact Analysis describes the assessment of the impacts of air,ground,and water pollution on soils,vegetation,and visibility caused from the proposed modifications and any project-associated growth. Impacts to Class I areas were also assessed as part of this section. Section 9.0 Socioeconomic and Growth Impacts describes the impacts of the proposed modifications on local infrastructure and economics. 2 Section 10.0 Summary and Conclusions Appendix A contains APENS for each piece of combustion equipment. Appendix B contains emission calculation information and data sheets. Appendix C contains the modeling input/output files on Compact Disk. Appendix D contains all other miscellaneous support data. This document was prepared for RMEC by: Gregory Darvin Atmospheric Dynamics, Inc. 2925 Puesta del Sol Santa Barbara, CA 93105 (805) 569-6555 Questions pertaining to this document should be directed to Gregory Darvin at Atmospheric Dynamics. 3 2.0 EXISTING AND PROPOSED PROJECT DESCRIPTIONS 2.1 Existing Facility Description Data presented in this section has been updated per the Title V application dated March 2005.The energy facility currently consists of two (2) Westinghouse 501FD natural gas combustion turbines(CT),two (2) supplementary fired heat recovery steam generators(HRSG)each equipped with duct burners(DB),one(1) condensing steam turbine generator(CSTG),a twelve(12)cell cooling tower, a diesel emergency backup generator, and a diesel fired fire pump. The CTs are operated in a combined cycle configuration. The combustion turbines and duct burners are fueled exclusively by natural gas. Steam produced by the three HRSGs is directed to the CSTG. The RMEC facility has a gross electric generating capacity of up to 630 MW. Electricity generated by the combustion turbines and the CSTG is distributed to the local utility electric power grid. A diesel fuel-fired 1800 horsepower emergency backup generator is used to maintain power to the facility during utility outages. A small, 182 horsepower, diesel fuel-fired fire pump is also located on site and is deployed only in case of a fire at the facility.The emergency generator and fire pump are"readiness"tested at least one hour per week. The existing facility plot plan is shown in Figure 2-1. See comments on Figure 2-2 with respect to the new aux boiler location.Equipment not shown in detail on the plot plan but included in the project is the electrical switchyard and electrical equipment such as transformers,transmission lines,and switchyard interconnections,and other miscellaneous equipment and facilities. Combustion Turbine/Heat Recovery Steam Generator The two (2) existing CTs are Siemens Westinghouse 501FD gas turbines equipped with dry low-NOx combustion systems. The hot CT exhaust is ducted to the associated HRSG,where the exhaust heat is used to generate up to 2,300 psia steam for electric power generation via the CSTG. Auxiliary or supplemental duct firing is included as a part of each HRSG. The rated heat input capacity of each turbine and duct burner system is 2311 MMBtu/hr(HHV). Auxiliary duct firing is used to increase electric power production during periods of peak electric demand. Based on operational information, the total steam production from each HRSG is estimated at 1,600,000 and 760,000 lbs/hr for operation with and without duct firing,respectively, with the CTs operating at average ambient conditions. Selective catalytic reduction(SCR)systems and CO catalysts are used to control emissions from the combustion turbines and duct burners. Cooling Tower A cooling water system provides cooling to condense the steam coming from the steam turbine. The cooling water system uses a 12 cell, induced draft cooling tower with a circulating water flowrate of approximately 166,166 gpm, operating at up to 10 cycles of concentration. The water that is circulated through the cooling tower is considered non-contact cooling water. A high efficiency mist eliminator with a typical drift rate of 0.0005 percent of the water circulation rate is used to limit emissions of PKo. Steam Condensing Turbine A condensing steam turbine/electric generator(CSTG)rated at 326 MW is included as an integral part of the existing combined cycle facility. Steam produced by the HRSGs is used to drive the CSTG. • Ancillary Equipment In addition to the above devices, the following ancillary equipment is also located at the existing facility: Emergency Backup Generator One(1) 1800 horsepower diesel fuel-fired generator is used to provide on-site power to the facility during 4 L. d C • ad f ya,� sa Q' + } 7 i V. O 1 • et N rr� i f w ° aztu O• (� C i .y t ....`. ^, rh r§r. ' i moCd o/ i 14 t �i'�:'L{. .F:� `,'y.` Y'r' + .`';r' I :s'ubd .......1,•9' � t "P,�'y" {` ^.i w'wi , 1 1 I+r r r ftl A l ¢ m� : •e i r ` ' k II r' f f f ' ___•! ri 1 i 111 I .• 1 ` t r { I k III ti....: rLi-.L. _724 ! .I. '— 0t.f�'J�MIl7 a og.,:' o 1 g ' i : i i 1 c 0 i ..4r •-4.4E.-0,j i'1r C!�.. . .,!�� 1 , i I a 0f " x __ — ` ! o hi` i 11 E ;1. i m : i6 � V‘easo-a3 Viii I L C1 J / i . • j utility outages. This unit is only operated when both (2) CTs are not operating and there is no power available from the grid, and during periods of periodic testing. Firepump One (1) 182 hp diesel fuel-fired firepump is used in the event of an on-site fire when there is no power available from the grid, and during periods of periodic testing. Auxiliary Boiler One(1) 129 MMBtu/hr(HHV)natural gas-fired auxiliary boiler. The auxiliary boiler is only used when one or more of the CT/HRSGs are not operating. The auxiliary boiler is used to maintain temperature in the steam condensing turbine, HRSGs, and vacuum in the condenser, thus allowing the facility to be started quickly. Ammonia Storage Two anhydrous ammonia tanks with a maximum capacity of 12,000 gallons each are located on site. 2.1.1 Existing Facility Emissions The existing facility emissions as derived from the PSD application document dated February 2002 are given in Tables 2-1 to 2-8. These tables have been revised pursuant to the Title V application dated March 2005. Table 2-1 Maximum short term pollutant emission rates—each gas turbine'. Pollutant ppmvd @ 15% 02 Ib/MMBtue Ib/hr NOx 3.06 0.0134 24.0 CO 9.00b 0.0241 43.0 VOC 2.00 0.0025 4.5' PMlod - 0.0062 11.0 5O/ 0.120 0.0007 1.3 Basis: "Emission rates shown reflect the highest value with no power augmentation,and no duct burners at any operating load except startup and shutdown. 'RMEC design criteria. `Pounds per hour provided by vendor;ppm and Ib/MMBtu calculated from lb/hr. °100 percent of particulate matter emissions assumed to be emitted as PM RI;PM,0 emissions include both front and back half as those terms are used in USEPA Method 5. `Based on maximum fuel sulfur content of 0.25 grains/I 00 SCF. 5 Table 2-2 Maximum short term pollutant emission rates—each turbine with duct burner in power augmentation mode. Pollutant ppmvd @ 15% O2 lb/MMBtu` lb/hr NOx 3.0e 0.0108 25.0 CO 9.0' 0.0199 46.0 VOC 2.0 0.0025 5.813 PMIo` 0.0076 17.6 SO2d 0.12 0.0006 1.4 Basis: 'RMEC design criteria. "Pounds per hour provided by vendor;ppm and lb/MMBtu calculated from lb/hr. `100 percent of particulate matter emissions assumed to be emitted as PM,0;PM,o emissions include both front and back half as those terms are used in USEPA Method 5. dBased on maximum fuel sulfur content of 0.25 grains/100 SCF. Table 2-3 Maximum Pollutant Emission Rates Auxiliary Boiler' Pollutant ppmvd @ 3% O2 lb/MMBtu lb/hr NOx 30b 0.0380 4.9 CO 50e 0.0388 5.0 VOC 106 0.0047 0.6 PMlod N/A 0.0186 2.4 SO2e 0.359e 0.0007 0.09 Notes: 'Emission rates shown reflect the highest value at any operating load,excluding startup°Vendor guarantee. `MEC specification. d100 percent of particulate matter emissions were assumed to be emitted as PM pp;PM,,)emissions include both front and back half as those terms are used in USEPA Method 5. Based on maximum fuel sulfur content of 0.25 grains/100 SCF. Table 2-4 Maximum pollutant emission rates—emergency generator set (1800 hp). Pollutant g/bhp-hr lb/hr tons/yr NOx 6.9 31.7 0.75 CO 8.5 39.05 2.75 VOC 1.0 4.59 0.12 PMIo 0.40 1.84 0.044 SO2 Neg 0.654 0.05 Notes: Emission rates shown reflect the highest value at any operating load per vendor guarantee. Tons/yr based on max operation hours of 30 minute tests at 50%load and 200 tests/yr. 100 percent of particulate matter emissions were assumed to be emitted as PM,o;PM,o emissions include both front and back half as those terms are used in USEPA Method 5. EPA AP-42,Table 3.2-2. SO,emissions based on maximum fuel sulfur content of 0.05%wt. 6 Table 2-5 Maximum pollutant emission rates—fire pump engine(182 hp). Pollutant g/bhp-hr lb/hr tons/yr NOx 5.89 2.36 0.236 CO 3.55 1.42 0.142 POC 0.73 0.29 0.0290 PM10 0.25 0.10 0.010 SO2 neg 0.063 0.0063 Notes: Emission rates shown reflect the highest value at any operating load per vendor guarantee. Tons/yr based on max operation of 200 hrs/yr. 100 percent of particulate matter emissions were assumed to be emitted as PM io;PMia emissions include both front and back half as those terms are used in USEPA Method 5. SOt based on maximum fuel sulfur content of 0.05%wt. Table 2-6 Maximum device heat input rates (HHV) (MMBtu), existing equipment. Period Gas Turbines w/ Gas Turbines w/o Emergency Emergency Fire Duct Burners' Duct Burnersb Generator Set Pump Per Hour 2311 1785 —6.514 —1.26 Per Year` 10,630,600 6,611,640 —1301d —252 Notes: 'Based on maximum heat input for full load operation at 90 deg. F plus duct burner with power augmentation. °Based on maximum heat input for full load turbine operation at 3 deg. F. 'Daily and annual heat input rates are highly variable due to the wide capability of the turbines and duct burners to operate at various loads on a daily and annual basis. d Emergency generator limited to 30 minute tests. Natural gas @ 1057 btu/scf(HHV),#2 diesel fuel @ 137,000 btu/gal(EPA AP-42). Table 2-7 Combustion turbine startup emission ratesa(existing turbines). NO„ CO POC Cold Start, lb/hour 80 838 16 Cold Start, lb/startb 240 2,514 48 Hot Start, lbs/start` 80 902 16 °Estimated based on vendor data and source test data. °Maximum of three hours per cold start. `Maximum of one hour per hot start. rt f L / 7 Table 2-8 Potential Emissions from Existing Equipment' Maximum Annual Emissions, NO, SO2 CO VOC PMta (tPY) Turbines and Duct Burnersb 240.4 11.80 782.2 50.6 126.8 Cooling Tower - - - - 19.1 Auxiliary Boiler 4.7 0.05 2.75 0.57 2.28 Emergency Generator 0.75 0.05 2.75 0.12 0.044 Fire Pump Engine 0.236 0.0063 0.142 0.029 0.01 Total Project (tons/yr`) 246.1 11.9 787.8 51.3 148.2 Notes: 'See Title V application dated March 2005 for derivation of current PTE values. 'Includes startup emissions. `Numbers may not add directly due to rounding. 2.2 Proposed Project and Modifications The proposed modifications at the RMEC are as follows: • Expansion of the existing 2x 1 combined cycle facility to a 3x1 configuration.The expansion would consist of the addition of a single F-class combustion turbine and associated HRSG. The combustion turbine would be a Siemens Westinghouse 501 FD gas turbine equipped with dry low-NOx combustion system,with a rated heat input at ISO conditions is approximately 1785 MMBtu/hr(HHV).The new turbine will be exclusively fired on natural gas.The hot CT exhaust will be ducted to the new HRSG, where the exhaust heat will be used to generate up to 2,300 psia steam for electric power generation via the CSTG. Auxiliary or supplemental duct firing is included as a part of the HRSG design. The rated heat input capacity of the HRSG duct burner is 659 MMBtu/hr (HHV). Auxiliary duct firing is used to increase electric power production during periods of peak electric demand. Based on operational information, the total steam production from the new HRSG is estimated at 1,600,000 and 760,000 lbs/hr for operation with and without duct firing,respectively,with the CT operating at average ambient conditions.Figure 2-2 shows the new equipment location on the facility plot plan. It should be noted that the existing aux boiler has been moved to accommodate the installation of the new turbine/HRSG which will be placed just west of the existing turbines/HRSGs. The new location for the aux boiler is shown on Figure 2-2. Figure 2-3 shows a simplified process flow diagram for a single combined cycle unit. Installation of the new CT/HRSG is not expected to result in the need for modifications to the cooling tower, and cooling and steam makeup water requirements are sufficient at present to accommodate the proposed modification. It is expected that the modification will cause an increase in cooling tower blowdown (wastewater) discharges, which will require that the present facility NPDES permit be modified. 2.3 Proposed Modification Project Emissions Emissions of all of the criteria and hazardous air pollutants have been characterized and quantified in this application. 8 O R N a O O " p . U a,n t 0I) : e t ti, N C '\ WC m u • o a E t,.e i--• r = iz - .17t71 W ._..-_._.._. a z 8 . • \ I O i r.r...,.�.... p; i ry . '1't.• �.... III , , ,..... ,..... „ , i ,yy�w• �:�f�� i I ' Wt k • s 1 41... 1.. . IP. t ;`... ....,., 1 a L c;;;41. ' Jet i w� . •ri- � J4�. 9 ,y•OG tj Bali �r 7�� I C • ICI i s : ICI .; 10 : v 4, 1 1 ----....k. r 0 | ClU 21 E] ! 2 $ a ) rn ` } . ! ) 2/ k _ « ± ( 7 $ § . " ± E - Cu I 7 & . o co § I--u) 0 & a 0 a { }_ E kJ co \ 0 00 I / 2 . ° t a ) �) ) m CD 0 k 0 $ ) k k m.15 \. V E ti o # I § a 2.3.1 Criteria Pollutant Emissions The new emissions sources at the RMEC include one gas turbine with a heat recovery steam generator equipped with supplemental burners(duct burners).The actual operation of the turbine will range between 70 percent and 100 percent of their maximum rated output. Supplemental firing will be provided by the duct burners as needed to achieve the required power generation level. Steam injection into the combustion turbines(power augmentation,or PAG)will also be used to increase power output under certain conditions. Emission control systems will be fully operational during all operations except during startups and shutdowns. Maximum annual emissions are based on operation of the new systems at maximum firing rates and include the expected maximum number of startups that may occur in a year. Each turbine startup will result in transient emission rates until steady-state operation for the gas turbine and emission control systems is achieved. An ambient air quality impact analysis for the new system has been conducted to satisfy the Air Pollution Control Division (APCD) requirements for criteria pollutants (NO2, CO, VOC, PM10, and SO2) on a pollutant-specific basis. It should be noted that the operational scenarios having the highest emissions rates do not necessarily produce the highest ambient impacts. The gas turbine and duct burner emission rates have been estimated from vendor data, RMEC design criteria, and established emission calculation procedures. The emission rates for the combustion turbine alone,the combustion turbine and duct burner with power augmentation,are shown in the following Tables 2-9 through 2-14. Table 2-9 Maximum short term pollutant emission rates—proposed gas turbine'. Pollutant ppmvd @ 15% 02 lb/MMBtue lb/hr NO„ 3.0b 0.0106 19.0 CO 9.06 0.0196 35.0 VOC 2.0 0.0025 4.5` PMI° - 0.0062 11.0 5O2e 0.12 0.00062 1.1 NH3 10 0.0133 23.7 Basis: 'Emission rates shown reflect the highest value with no power augmentation,and no duct burners at any operating load except startup and shutdown. bl MEC design criteria. `Pounds per hour provided by vendor;ppm and Ib/MMBtu calculated from lb/hr. 4100 percent of particulate matter emissions assumed to be emitted as PM,o;PM,a emissions include both front and back half as those terms are used in USEPA Method 5. 'Based on maximum fuel sulfur content of 0.25 grains/100 SCF. 9 Table 2-10 Maximum short term pollutant emission rates—proposed turbine/duct burner with power augmentation. Pollutant ppmvd @ 15% O2 lb/MMBtue lb/hr NOx 3.0a 0.0108 25.0 CO 9.Oa 0.0199 46.0 VOC 2.0 0.0025 b e 5.8 PM10 - 0.0080 18.6 SO2d 0.12 0.00061 1.4 NH3 10 0.0134 Basis: 30.9 °RMEC design criteria. bPounds per hour provided by vendor;ppm and lb/MMBtu calculated from lb/hr. '100 percent of particulate matter emissions assumed to be emitted as PMia;PM io emissions include both front and back half as those terms are used in USEPA Method 5. °Based on maximum fuel sulfur content of 0.25 grains/100 SCF. Table 2-11 Maximum device heat input rates (HHV) (MMBtu), proposed equipment. Period Gas Turbine w/Duct Burner' Gas Turbine w/o Duct Burnerb Per Hour 2,311 1,785 Per Year` 10,630,600 6,611 640 Notes: 'Based on maximum heat input for full load operation at 90 deg. F plus duct burner with power augmentation. b Based on maximum heat input for full load turbine operation at 3 deg. F. `Daily and annual heat input rates are highly variable due to the wide capability of the turbines and duct burners to operate at various loads on a daily and annual basis. °Emergency generator limited to 30 minute tests. Natural gas @ 1057 btu/scf(HHV) Maximum emission rates from the new CT/HRSG are expected to occur during a startup or shutdown are shown in Table 2-12. PM10 and SO2 emissions have not been included in this table because emissions of these pollutants will be lower during a startup period than during base load facility operation. Up to 456 turbine startup hours are expected to occur on an annual basis. This includes 52 cold starts, which are a three-hour event,and 300 warm starts,which are 1-hour events. Thus,the short-term and annual emissions profile for the turbine/HRSG includes these cold/warm starts and were included in the modeling analysis. Table 2-12 Maximum turbine startup emission rates'(proposed equipment). NOx CO VOC Cold Start, lb/hour 80 902 16 Cold Start, lb/startb 240 2,706 48 Hot Start, lbs/start` 80 902 16 'Estimated based on vendor data and source test data. See Appendix B bMaximum of three hours per cold start. `Maximum of one hour per hot start. The analysis of maximum facility emission levels was based on the pollutant emission factors shown in Tables 2-9,2-10;the RMEC operating envelope shown in Table 2-11;and the RMEC startup emission rates shown in Table 2-12. The annual emissions for the turbines were calculated based on a turbine capacity factor of 100 percent, with 456 hours in startup mode. For some pollutants, turbine emissions vary based on ambient temperatures. Annual emissions have been calculated assuming an average ambient temperature of 50 degrees Fahrenheit for 5,360. It was assumed that up to 4,600 hours of duct burner and power augmentation would 10 occur and this is typically associated with high temperature conditions. In addition, up to 456 turbine start hours (52 cold starts and 300 warm starts) were included in the annual emissions profile. Base mode operation (no power augmentation and duct burner operation) would occur for 5,360 hours per year. The maximum annual and hourly emissions for the proposed modifications are shown in Table 2-13. Detailed emission calculations appear in Appendix B. Table 2-13 Emissions from Proposed New Equipment' Maximum Hourly Emissions NO, SO2 CO VOC PMto (lb/hr) Turbine and Duct Burnerb 80.0 1.4 902.0 16.0 18.6 Maximum Annual Emissions, (tPY) Turbine and Duct Burner" 113.0 5.7 378.8 25.7 70.8 Notes: 'See Appendix B for expansion project emissions calculations. "Includes startup emissions. 2.3.2 Hazardous Pollutant Emissions Hazardous air pollutants (HAPs) are compounds that have been identified as pollutants that pose a significant health hazard. Nine of these pollutants are regulated under the federal New Source Review program; they are lead, asbestos,beryllium,mercury, fluorides, sulfuric acid mist,hydrogen sulfide,total reduced sulfur,and reduced sulfur compounds.' In addition to these nine compounds,the federal Clean Air Act lists 189 substances as potential HAPs(Clean Air Act Sec. 112(b)(1)). The APCD has also published a list of compounds it defines as potential HAPs reportable air pollutant emissions.Any pollutant that maybe emitted from RMEC and is on the federal New Source Review list,the federal Clean Air Act list,and/or the APCD HAPs list has been included in the emissions inventory. Emission factors were determined by reviewing the available technical data, determining the products of combustion, and/or using material balance calculations. HAPs emission factors were taken from data compiled from the California Air Toxics Emission Factors (CATEF)database. The HAPs' that may be emitted from RMEC, and their respective emission factors, are shown in Table 2- 10. Appendix B also provides the detailed emission calculations for hazardous pollutants. 'These pollutants are regulated under federal and state air quality programs 11 Table 2-14 HAP emissions for the Proposed New CT/HRSG Emission Factor I Emissions Pollutant (Ib/MMscf) I lb/hr I ton/yr Gas Turbine with Duct Burner Acetaldehyde 6.86x10"2 0.15 0.56 Acrolein 6.43x10"3 0.01 0.05 Ammonia a 30.90 114.96 Benzene 1.36x10-2 0.03 0.11 1,3-Butadiene 1.27x1O 2.78E-04 1.04E-03 Ethylbenzene 1.79x10.2 0.04 0.15 Formaldehyde 1.10x10"1 0.24 0.90 Hexane 2.59x10.1 0.57 2.11 Naphthalene 1.66x10"3 3.63E-03 1.35E-02 Polycyclic 2.23x10"3 Aromatics 1.44E-03 5.38E-03 Propylene 7.70x10-1 1.68 6.28 Propylene 4.78x10-2 Oxide 0.10 0.39 Toluene 7.10x10"2 0.16 0.58 Xylene 2.61x10"2 0.06 0.21 °Ammonia emissions calculated from ammonia slip rate. See Appendix B. A typical natural gas analysis is given in Table 2-15. Table 2-15 Typical Chemical Characteristics and Heating Value of Natural Gas Constituent Mole % Nitrogen 0.857 CO2 1.98 Methane 89.6 Ethane 5.857 Propane 1.14 n-Butane 0.19 Isobutane 0.146 n-Pentane 0.042 Isopentane 0.057 n-Hexane 0.057 BTU/SCF 1057 12 2.4 Proposed Stacks and Emissions Points The new turbine and HRSG will exhaust through a single stack with the following physical characteristics: • Stack height- 175 ft. agl • Stack diameter— 18.5 ft. • Stack temperature— 158 up to 170 deg F(dependent upon turbine load and duct burner use) • Stack exit velocity—54 up to 71 ft/sec (dependent upon turbine load and duct burner use) 2.5 Emissions Impacts from Proposed Modification Addition of the new combustion turbine and HRSG will result in the following emissions increases as derived from Table 2-13. • NOx- 113.0 tons per year • CO—378.8 tons per year • VOC—25.7 tons per year • SOx—5.7 tons per year • PMio—70.8 tons per year • H2504-4.38 tons per year Emissions of NOx, CO, and PKo are above the significant emissions threshold values for PSD review as delineated in Section 3.1,as such,the proposed modification is subject to PSD review for these pollutants. The emissions of PMio include both the front half and back half condensables. Emissions of hydrogen sulfide mist(H2SO4)were also included in the total PMio emission calculations and were based on a 1 lb/hr emission rate. 13 3.0 REGULATORY ANALYSIS This section presents the identification of applicable regulations that will affect the proposed modifications, with respect to air quality issues. Each regulation is briefly explained and the compliance methods proposed to be used by the facility are delineated. Because the proposed project will be located within the State of Colorado, the Colorado Department of Public Health and Environment,Air Pollution Control Division (APCD)has the regulatory jurisdiction. 3.1 Prevention of Significant Deterioration (PSD) If a source emits, or has the potential to emit, more than 100/250 tons per year of any pollutant subject to regulation under the Clean Air Act(CAA), and if it can be classified as one of the 28 specific source types listed in 40 CFR Part 52.21, then the source is considered to be a major source [40 CFR Part 52.21(b)(23)(i)] subject to PSD review. PSD review applies to sources located in an attainment area(an area considered by the regulatory authority as meeting ambient air quality standards)or in an area designated as unclassifiable. EPA Region VIII and the APCD have designated Weld County as being in attainment for all regulated pollutants. Therefore, the existing project was subject to PSD review. In addition,the EPA has classified natural gas-fired combined cycle electrical generating facilities as fossil fuel fired steam electric plants. The existing facility was therefore,subject to the 100 ton per year emission level threshold at which PSD review is required. The current facility permitted annual emissions of NOR, CO, VOC, SO,, and PKo are delineated in Section 2. Modifications of existing major sources will be subject to PSD review if the actual or potential emissions increases exceed the following threshold levels: • NOR,VOC, or SO,,—40 tons per year • CO— 100 tons per year • PMio— 15 tons per year • PM2.5— 15 tons per year 3.2 Emissions Standards 3.2.1 New Source Performance Standards EPA has established performance standards for a number of air pollution sources in 40 CFR Part 60. These "new source performance standards" (NSPS)usually represent a minimum level of control that is required on a new source. 3.2.1.1 Subpart GG and ICKICK EPA regulates stationary gas turbines in 40 CFR Part 60, Chapter 1 subpart GG. The final rule for the so- called "New Source Performance Standards" (NSPS) was originally promulgated September 10, 1979. Subpart GG was recently revised and amended by EPA by direct final rulemaking procedures(4/14/03). The revisions to Subpart GG generally address alternative testing and monitoring procedures, as well as reflecting references to NOx control technologies and turbine design since the original standards were adopted in 1979. The existing turbines are subject to the revised regulation, and can now take advantage of several provisions of the revised regulation with respect to monitoring and reporting. 14 EPA has recently proposed Subpart KKKK which will be applicable to the proposed new turbine. Subpart KKKK also addresses alternative testing and monitoring procedures, as well as reflecting updated references to NOx control technologies. Turbines associated with RMEC would be considered"electric utility stationary gas turbines"because more than one-third of their potential electric output capacity will be supplied to a utility power distribution system.In addition,the provisions of Subpart KKKK also apply to the HRSG/duct burners. Subpart KKKK NOx limits for the turbine/HRSG would be 0.39 lb/Mw-hr. SOx compliance with Subpart KKKK can be achieved in two ways, i.e., compliance with a fuel sulfur limit of 0.05%by weight(500 ppmw),or compliance with a total emissions factor of 0.58 lbs/MW-hr.In most cases,the BACT requirements and monitoring requirements resulting from a NSR or PSD review process are far more stringent than even the new NSPS, as such, compliance with current BACT and monitoring requirements will insure compliance with the provisions of Subpart KKKK (upon final promulgation). 3.2.1.2 Subpart Da Subpart Da will not apply to the new HRSG-duct burners per the provisions of Subpart KKKK discussed above. Because the proposed emission rates for the new CT and HRSG duct burners reflect BACT (which is usually more stringent than NSPS limits), the emission rates proposed for the RMEC modification are below those allowed by NSPS. Consistent with NSPS requirements,RMEC will also notify APCD of the anticipated initial startup date, the actual startup date, any changes in the facility that affect emissions, compliance sources tests, and certification tests for continuous emission monitors. RMEC also will maintain records of startups and shutdowns, malfunctions of control equipment or periods of excess emissions if they occur, and periods when continuous emission monitoring equipment is inoperative. 3.2.2 Title 4 (Acid Rain)Provisions Title 4 of the Clean Air Act Amendments of 1990 provide a strategy for reducing national emissions of nitrogen and sulfur oxides as part of a comprehensive plan for reducing acid deposition.Part 75 requires any gas turbine larger than 25 MW that provides more than one-third of its potential electric output capacity to a utility power distribution system to monitor flow rate, oxygen, and nitrogen and sulfur oxides. The proposed modification (new CT/HRSG)would be subject to these regulations. Monitoring may take the form of continuous emission monitors or calculations based on fuel sulfur monitoring or similar techniques. The requirements for continuous emission monitors are similar to those required under NSPS except that CEMs for sources subject to Part 75 must meet more stringent accuracy limits during annual relative accuracy test audits. 3.2.3 Applicable Colorado Regulations The following regulations apply to the proposed new turbines: Regulation 1 —Particulate Rules:The opacity provisions of Subpart II,A, 1 apply at a level of 20%.Method 9 will be used to evaluate opacity.The opacity provisions of Subpart II,A,4 also apply to turbine startups at a level of 30%. Operation of the turbines on natural gas is not expected to result in opacities in excess of these provisions.The emissions provisions of Subpart III,A, 1,cat a level of 0.1 lbs/mmbtu of particulate matter from fuel burning equipment apply to the turbines. The proposed emission rates for PM/PMto from the combustion turbines are well below this limit.The provisions of Subpart III,D, 1,b with respect to the preparation of fugitive dust control plans also applies. RMEC will update the plan used for the original facility construction project and will implement the revised plan for the installation of the new turbines. 15 Regulation 1 —Subpart IV (Monitoring Requirements): This provision applies only to "fossil fuel fired steam generators", since RMEC is a combined cycle turbine facility, the monitoring requirements do apply. In addition,the turbine exhaust stacks will incorporate a continuous emissions monitoring system for NOx, CO, and O2. The CEMS will be similar in design and operation as the existing CEMS on the existing turbine exhaust stacks. Regulation 1 —Subpart VI, B, 4 (SO2 Emissions Regulations): Combustion turbines with heat input rates greater than or equal to 250 mmbtu/hr are limited to an SO2 emission rate not to exceed 0.35 lbs SO2/mmbtu. Use of natural gas will result in emissions of SO2 well below this limit. Appendix E contains a copy of the applicable regulation listing which applies to the existing combustion turbines. This same list is applicable to the proposed new turbine/HRSG, with the exception of the NSPS Subpart GG requirements and the listings referring to Permit 02WE0228. Other regulations which do not appear at this time to contain any specific applicable provisions are as follows. These rules may contain general applicable provisions for which the proposed new turbines will comply with upon finalization of construction. 1. Procedural Rules 2. Common Provisions Regulations 3. Reg 2—Odor Provisions 4. Reg 4—Woodstove Provisions 5. Reg 5 —Emissions Banking and Trading Provisions 6. Reg 6—NSPS (see Subpart KKKK discussion above) 7. Reg 8—Control of HAPs 8. Reg 9—Reduction of Automotive Emissions 9. Reg 10—Criteria for Analysis of Conformity 10. Reg 11 —Motor Vehicle IM Program 11. Reg 12—Reduction of Diesel Vehicle Emissions 12. Reg 13 —Oxygenated Fuels Program 13. Reg 14—Motor Vehicle Emissions Reduction Program/Alternative Fuel Vehicles 14. Reg 15—Control of ODCs 15. Reg 16—Street Sanding Emissions Program 16. Reg 17—Clean Fuel Fleet Program 17. Reg 18—Control of Acid Deposition Precursors 18. Reg 19—Lead Based Paint Abatement Program 16 4.0 REGIONAL AND SITE DESCRIPTION This section describes the project location,the land use and population of the surrounding area,the existing climate, air quality, soils, and vegetation. 4.1 Proiect Location Figure 1 (presented previously) shows the general location of the Rocky Mountain Energy Center. The facility lies approximately 47 km northeast of downtown Denver (assuming the center of the Denver downtown area is at the intersection of Broadway and Colfax) off of Interstate 76, 18 km north of the Denver International Airport complex,and 38 km south of Greeley,Colorado.Based on data derived from existing USGS maps, the facility is located inside the boundaries of Weld County. The RMEC UTM coordinates are 534491 meters Basting,4437767 meters northing(Zone 13). The facility elevation is 1508 meters (4941 ft.) above mean sea level (MSL). 4.2 Population and Land Use The population of Weld County,per updates to the 2000 census(2003 estimates)is approximately 211,272 individuals. The county covers an area of 3,992 square miles, resulting in a population density of 52.9 persons/square mile. See updated census data in Appendix E. Much of the land use in Weld County is agriculturally oriented. 4.3 Existing Climate The climate of the project area prevails over much of the central Rocky Mountain region, without the extremely cold mornings of the high elevations during winter, or the hot afternoons of summer at lower altitudes. Extremely warm or cold weather in Denver is usually of short duration. Situated long distances from any moisture source, and separated from the Pacific Ocean by several high mountain barriers,the area enjoys low relative humidity, light precipitation, and abundant sunshine. Air masses from four different sources influence the area weather. These include arctic air from Canada and Alaska,warm moist air from the Gulf of Mexico,warm dry air from Mexico and the southwestern deserts, and Pacific air modified by its passage over mountains to the west. In winter, the high altitude and mountains to the west combine to moderate temperatures in the area. Invasions of cold air from the north, intensified by the high altitude can be abrupt and severe. However, most of the cold air masses that spread southward out of Canada never reach the altitude of the project area, but move off over the lower plains to the east. Surges of air from the west are moderated in their decent down the east face of the Rockies,and reach the project area in the form of chinook winds that often raise temperatures into the 60s, even in midwinter. In the spring, polar air often collides with warm moist air from the Gulf of Mexico and these collisions result in frequent,rapid and drastic weather changes. Spring is the cloudiest,windiest,and wettest season in the project area. Much of the precipitation falls as snow, especially in March and early April. Stormy periods are interspersed with stretches of mild, sunny weather that quickly melt previous snow cover. Summer precipitation falls mainly from scattered thunderstorms during the afternoon and evening. 17 Mornings are usually clear and sunny with clouds forming during early afternoon to cut off the sunshine at what would otherwise be the hottest part of the day. Severe thunderstorms,with large hail and heavy rain occasionally occur in the area,but these conditions are more common on the plains to the east. Autumn is the most pleasant season. Few thunderstorms occur and invasions of cold are infrequent. As a result,there is more sunshine and less severe weather than at any other time of the year. Based on observations in Denver for the 1951-1980 period, the average first occurrence of 32 degree Fahrenheit in the fall is October 8 and the average last occurrence in the spring is May 3. 4.4 Existing Air Quality Existing air quality data was derived from the Air Division annual reports (North Range Front region)for the most recent three (3) year period (2001-02 through 2003-04). Table 4-1 summarizes this data by pollutant. Table 4-1 Summary of Back ound Air Quality Pollutant Avg. Time Applicable High Value for Avg Of Annual Standard Last 3 Yrs High Values for Last 3 Yrs NO2 Annual 0.053 ppm 0.0121 0.0121 Ozone 8 Hr(4t'max) 0.08 ppm 0.069 0.069 1 Hr(1s`max) 0.12 ppm 0.095 0.095 CO 8 Hr 9 ppm 5 5 1 Hr 35 ppm 3 3 SO2 Annual 0.03 ppm 0.002 0.002 24 Hr 0.14 ppm 0.036 0.036 3 H 0.5 ppm 0.011 0.011 PM10 Annual Mean 50 ug/m3 33 33 24 Hr 150 ug/m3 83 83 PM2.5 Annual Mean 15 ug/m3 10.1 9.4 24 Hr 65 ug/m3 50.8 36.5 Recommended values derived from May 16,2005 APCD Memo.Nancy Chick-APCD. As shown above, air quality in the region is in attainment for all pollutants and for all averaging periods, with the exception of 8-hour ozone which is being treated as attainment. 4.5 Existing Soils and Vegetation The location and properties of the soil types in the project area were identified from maps of the area prepared by the U.S. Soil Conservation Service(now called Natural Resources Conservation Service).These soil maps and properties were obtained from the Soil Survey of Weld County, Colorado - Southern Part (U.S. Department of Agriculture, 1980). Weld County has the highest number of prime farmland acres in Colorado (365,000 acres). No impacts will occur to prime farmland from the RMEC project, as all reasonable efforts were made to avoid prime farmland in siting the facilities. The present parcel size is approximately 633 acres. The existing plant site covers approximately 88 acres.A temporary construction laydown area will be used and then reclaimed(probably less than 1 acre).Impacts to 18 soils will be mitigated through preservation of existing agricultural uses on the remainder of the parcel.No prime farmland will be impacted. Table 4-2 summarizes the soil types in the project area. Table 4-2 Summary of Soil Types Found in the Power Plant Regional Area Soil Type Descriptions Prime RMEC Power Plant Region 10—Bankard sandy This is a deep,somewhat excessively drained soil on floodplains* at N loam 0-3%slopes elevations of 4,450-5,000 feet. Permeability is moderately rapid. Available water capacity is low.This soil is used as pasture and limited cropping. 15—Colby loam This is a steep well-drained soil on uplands at elevations of 4,850-5,050 Y 1-3 %slopes feet.Permeability is moderate. Available water capacity is high. Surface runoff is medium, and erosion hazard is moderate.In irrigated areas,this soil is suited to all crops commonly grown in the area.In nonirrigated areas this soil is soil is suited to winter wheat,barley,and sorghum. Windbreaks and environmental plantings of trees and shrubs are generally well suited to this soil. 18—Colby Adena These gently to moderately sloping soils are located on plains,hills and N loams 3-9%slopes ridges at elevations of 4,750-4,900 feet.The Colby soil is deep and well- drained with moderate permeability,high water capacity,rapid runoff, and high erosion hazard. The Adena soils are deep and well-drained with slow permeability,high water capacity,medium runoff,and moderate erosion hazard. 47—Olney fine This is a deep and well-drained soil located on plains at elevations of Y sandy loam 1-3% 4,600-5,200 feet.The permeability and available water capacity are slopes moderate permeability,high water capacity. Surface runoff is medium, and erosion hazard is low. In irrigated areas,this soil is suited to all crops commonly grown in the area.In nonirrigated areas this soil is soil is suited to winter wheat, barley,and sorghum.Windbreaks and environmental plantings of trees and shrubs are generally well suited to this soil. 60- Shingle- This gently to moderately sloping soil complex is located on plains,hills N Renohill complex 3- and ridges at elevations of 4,600-4,750 feet.The permeability is slow to 9%slopes moderate and available water capacity ranges from low to moderate. Surface runoff is medium to rapid,and erosion hazard is moderate. This soil is used as rangeland and wildlife habitat. 79—Weld loam I- This is a deep,well drained soil on smooth plains at elevations of 4,850- Y 3%slopes 5,000 feet.Permeability is slow.Available water capacity is high. Surface runoff is slow,and erosion hazard is low.In irrigated areas,this soil is suited to all crops commonly grown in the area.The soil is well suited to winter wheat,barley,and sorghum.Windbreaks and environmental plantings of trees and shrubs are generally well suited to this soil. Weld County's economy is heavily dependent on agriculture. Crops produced in the county include onions, sugar beets, pinto beans, potatoes, corn, alfalfa, wheat, carrots, barley, and sorghum, in addition to other specialty crops. Many of the feed crops are used locally by the livestock industry.For example,most of the 19 corn grown in the area, both silage and grain, is used for feed at commercial feedlots, farm feedlots, and dairies.Significant numbers of sheep,swine,and turkeys also use the feed crops from the area. Croplands in the agricultural district also provide natural open space areas. None of these soils or vegetation types have been identified as having any particular sensitivity to air pollutants such as those emitted from the proposed facility or anticipated to be emitted from the proposed facilities. In addition,the secondary air quality standards are designed to be protective of cash crops,but are not designed to be protective of sensitive plant and animal species. No sensitive species were identified. 20 5.0 ANALYSIS OF BEST AVAILABLE CONTROL TECHNOLOGY FOR NOx, CO, PM1o,VOC, and SO2 The proposed modification project was evaluated under federal PSD provisions in 40 CFR Part 52.21 and Regulation 3 of the APCD rules,and it was concluded that the new combined cycle unit will be subject to PSD review requirements for NO2, CO, and PM/PM10. VOC and SO2 are not subject to PSD review for the proposed modification. Subsequent to completion of the modification,the facility will continue to be a major source for NOR,CO,VOC,and PM 1o.The facility will remain a minor source for SO2.However,the plant will apply BACT to SO2, and the proposed CO catalyst is also considered as BACT for VOC. The applicable air quality permitting requirements in the APCD regulations are delineated by air quality areas which correspond to established attainment and non-attainment areas within the county. The Weld county region is a PSD area for all pollutants per Regulation 3,consequently,the project must incorporate controls that are designed to meet Best Available Control Technology(BACT)requirements. This section presents the BACT analyses,with proposed emission controls and limits for the project's new emission units. The emissions units covered by the BACT control technology review is the combustion turbine and associated duct burner. BACT is defined in the regulations as follows: ...an emissions limitation(including a visible emission standard)based on the maximum degree of reduction for each pollutant subject to regulation under the Clean Air Act which would be emitted from any proposed stationary source or modification which the Control Officer,on a case-by-case basis, taking into account energy, environmental, and economic impacts and other costs, determines is achievable for such source or modification through application of production processes or available methods,systems, and techniques, including fuel cleaning or treatment or innovative fuel combustion techniques for control of such pollutant. In no event shall application of best available control technology result in emissions of any pollutant which would exceed the emissions allowed by any applicable standard under 40 CFR Parts 60 and 61. If the Control Officer determines that technological or economic limitations on the application of measurement methodology to a particular emissions unit would make the imposition of an emissions standard infeasible, a design,equipment,work practice,operational standard,or combination thereof,may be prescribed instead to satisfy the requirement for the application of best available control technology. Such standard shall, to the degree possible, set forth the emissions reduction achievable by implementation of such design, equipment, work practice or operation, and shall provide for compliance by means which achieve equivalent results. EPA recommends using a"top-down"approach for determining BACT. This approach essentially ranks potential control technologies in order of effectiveness and ensures that the best technically and economically feasible option is chosen. As described in EPA's New Source Review Workshop Manual, draft, October 1990,the general methodology of this approach is as follows: 1. Identify potential control technologies, including combinations of control technologies, for each pollutant subject to PSD review. 2. Evaluate each control technology for technical feasibility; eliminate those determined to be technically infeasible. 3. Rank the remaining technically feasible control technologies in order of control effectiveness. 4. Assume the highest-ranking technically feasible control represents BACT, unless it can be shown to result in adverse environmental, energy, or economic impacts. 21 5. Select BACT. EPA's RACT/BACT/LAER Clearinghouse (RBLC) is considered a principal reference for identifying potential control technologies and emission rates used in past permitting of similar sources. The database was queried for entries since January 2000 involving combustion turbines and duct burners. In addition, BACT decisions for similar equipment and systems made by other agencies were also reviewed and included in the final BACT decision. Literature searches were also completed for various control technologies and incorporated into this analysis. The emission rates proposed in this permit application apply with and without duct firing. Also,the duct burner and combustion turbine have a common release point and the duct burner will never operate independent of the turbine, thus, the BACT analyses are conducted for the combined emission rates of the combustion turbine and duct burner. The emission rates proposed are consistent with the entries in the RBLC, other agency recent BACT evaluations, and literature search results, especially those for sources with similar MMBtu/hr and MW ratings. The"top-down"procedure is followed for the BACT analyses for the pollutants evaluated in this analysis, with a focus on identifying emission limitations or control technologies that are achieved in practice and technically feasible. The sections following present the BACT analyses and proposed NOx,CO,PM/PMio, VOC, and SO2 limits and controls for the combined cycle unit. 5.1 BACT Analysis for the Combined Cycle Unit 5.1.1 Analysis of Control Requirements for Nitrogen Oxides 1. Identify Potential Control Technologies The baseline NOR emission rates for this analysis are considered to be 15 ppmvd @15% O2 (at 48% efficiency) for the combustion turbines and 0.11 lb/MMBtu for the duct burners, based on the applicable New Source Performance Standards (40 CFR Part 60, Subparts Da and KICKK). These emission rates provide a comparison for the evaluation of control effectiveness and feasibility. The maximum degree of control,which results in the lowest NOR emission rate,is a combination of dry low-NOR combustors(DLN) for the turbines and low-NOR burners (LNB) for the duct burners in conjunction with either selective catalytic reduction (SCR)or SCONOx. The formation of NO,from the combustion of fossil fuels can be attributed to two basic mechanisms—fuel NOR and thermal NO,. Fuel NOR results from the oxidation of organically bound nitrogen in the fuel during the combustion process, and generally increases with increasing nitrogen content of the fuel. Because natural gas contains only small amounts of nitrogen,little fuel NO,is formed during combustion. The vast majority of the NO,produced during the combustion of natural gas is from thermal NOR,which results from a high-temperature reaction between nitrogen and oxygen in the combustion air. The generation of thermal NOR is a function of combustion chamber design and the turbine operating parameters, including flame temperature, residence time (i.e., the amount of time the hot gas mixture is exposed to a given flame temperature),combustion pressure,and fuel/air ratios at the primary combustion zone. The rate of thermal NO, formation is an exponential function of the flame temperature. The reduction of NO, emissions can be achieved by combustion controls and post-combustion flue gas treatment. Combustion modifications for turbines include both wet and dry combustion controls. Wet and dry combustion controls act to reduce the formation of NO, during the combustion process, while post- 22 combustion controls remove NON from the exhaust stream after it is generated. Thus,potential NON control technologies for the combustion turbine and duct burner include the following: Wet combustion controls • Water injection • Steam injection Dry combustion controls • Dry low-NON combustor design (with low-NON burners for the duct burner) • Other combustion modifications • Catalytic combustors (e.g., XONON) Post-combustion controls • Selective catalytic reduction (SCR) • Selective non-catalytic reduction (SNCR) • Non-selective catalytic reduction (NSCR) • SCONOx 2. Evaluate Control Technologies for Technical Feasibility The performance and technical feasibility of each "category" of NON controls listed above are discussed separately. Wet and dry combustion modifications as they are applicable to combustion turbines are discussed first(duct burner controls are achieved with the use of low-NON burners). A detailed discussion of post-combustion controls, which can control emissions from both the combustion turbines and duct burners, follows. Wet Combustion Controls—Water and Steam Injection Injecting water or steam directly into the turbine combustor are common NON control techniques for combustion turbines. The principle behind wet injection techniques is to lower the flame temperature in the combustor,which reduces the formation of thermal NON. Specifically,water or steam is injected into the primary combustion chamber to provide a heat sink that lowers the peak flame temperature of combustion. Because water acts as a better heat sink than steam (due to temperature and latent heat of vaporization), more steam is required to achieve an equivalent level of NON reduction. The injected water or steam exits the turbine as part of the exhaust. The performance of wet controls is primarily dependent on the water- or steam-to-fuel ratio, with NON emissions decreasing as the water-or steam-to-fuel ratio increases. Additional factors affecting the level of control are the combustor geometry and the design and location of the injection nozzle(s). In order to maximize NON reductions, there must be a homogeneous mixture of water droplets and fuel in the combustor.This homogeneous mixture is only achieved through the proper atomization and injection of the water within the turbine combustor region. Typically, for gas-fired turbines, steam injection can reduce NON emissions to levels of 15 to 25 ppmv @ 15% O2. Emission rates for water injection are higher due to the inability to achieve a homogeneous mix of water and fuel in the combustor and are usually around 25 to 45 ppmv @ 15% O2. Although the quenching effect of the water or steam lowers the peak flame temperature and thus reduces 23 NOx emissions, it can also increase CO and hydrocarbon emissions, decrease combustion efficiency, and increase maintenance requirements. Due to incomplete combustion, CO and hydrocarbon emissions can increase as the water- or steam-to-fuel ratio increases. The reduction in efficiency also can increase with increasing water- or steam-to-fuel ratios and is typically greater for water injection (due to the heat of vaporization). For some turbines,due to the injection of water or steam into the combustor,increased wear and erosion in the hot section of the turbine can result in increased maintenance and downtime. Water and steam injection have been used on gas-fired turbines in all size ranges for many years. Where both systems are available,steam availability at the site and other economic factors usually determine which system is used. These NOx control technologies are widely available and are technologically feasible. Dry Combustion Controls Dry combustion controls reduce NOx emissions without wet injection systems. Combustion modifications to reduce NOx formation include lean combustion, reduced combustor residence time, lean premixed combustion,and two-stage rich/lean combustion. Lean combustion uses additional excess air(greater than stoichiometric air-to-fuel ratio) to cool the flame and thus reduce thermal NOx formation. Reduced combustor residence times are achieved by introducing dilution air between the combustor and the turbine hot section. The rate of thermal NOx formation is reduced because the combustion gases are at higher temperatures for a shorter time. The idea behind lean premixed combustion is to premix the fuel and air prior to combustion in order to provide a homogeneous air/fuel mixture, which acts to reduce the combustion temperatures, and thus thermal NON. Rich/lean combustion uses a fuel-rich primary stage, quenching, and then a fuel-lean secondary stage to reduce NOx formation,however,this type of control is currently not very common. Currently,the most widely used combustion controls are dry low-NO„(DLN)combustors,which use lean premixed combustion to reduce the formation of thermal NON. Prior to the development of premix based dry-low NOx combustors,fuel and air were injected separately into the turbine's combustor section where oxygen in the combustion air needed to support the combustion process diffused to the flame front located at the combustor's fuel burner. Simply put,the combustion occurred in a diffusion flame similar to that of a Bunsen burner. The result of this approach was a range of fuel-to-air ratios over which combustion occurred and a corresponding range of flame temperatures. The dry-low NOx combustion process works to reduce the amount of thermal NOx that is formed by lowering the overall flame temperature within the turbine combustor by premixing the fuel and air at controlled stoichiometric ratios prior to combustion. DLN combustion is effective in achieving NO.emission levels comparable to the levels achieved using wet injection without the need for large volumes of purified water or steam. An increase in CO emissions can result from lower NOx emission rates(in the range of 9 ppmv). However,negligible increases in CO are associated with controlled NO. emission rates around 25 ppmv (the level for the proposed turbines before subsequent control). Thus,the increases in CO and VOC emissions that result from wet injection are not a factor with such DLN systems. Several turbine vendors have developed DLN systems for their turbines, therefore this technology is considered technically feasible. Catalytic combustors use a catalytic reactor bed mounted within the combustor to bum a very lean fuel-air mixture. This technology has been commercially demonstrated under the trade name XONON in a 1.5 MW natural gas-fired turbine in Santa Clara, California. Commercial availability of the technology for a 200 24 MW GE Frame 7 natural gas-fired turbine was recently announced. The technology has also been announced as commercially available for some models of small turbines (around 10 MW or lower). The combustor used in the Santa Clara demonstration engine is generally comparable in size to that used in GE Frame 7F engines. The technology has not been announced commercially for the engines proposed for this project, thus a commercial quotation for the use of XONON is not commercially available from the supplier, Catalytica Corporation. No turbine vendor, other than General Electric, has indicated the commercial availability of catalytic combustion systems at the present time. Consequently, catalytic combustion controls are not considered commercially available for this project and are not discussed further. Post-Combustion Controls • Selective Catalytic Reduction (SCR) The SCR process is a post-combustion control technology in which injected ammonia reacts with NOx in the presence of a catalyst to form water and nitrogen. The catalyst's active surface is usually a noble metal, base metal (titanium or vanadium) oxide, or a zeolite-based material. The geometric configuration of the catalyst body is designed for maximum surface area and minimum back-pressure on the turbine. An ammonia injection grid is located upstream of the catalyst body and is designed to disperse ammonia uniformly throughout the exhaust flow before it enters the catalyst unit. The desired level of NOx emission reduction is a function of the catalyst volume and ammonia-to-NOx(NH3/NOx)ratio. For a given catalyst volume, higher NH3/NOx ratios can be used to achieve higher NOx emission reductions,but can result in undesired increased levels of unreacted NH3 (called ammonia slip). The SCR catalyst is subject to deactivation by a number of mechanisms. Loss of catalyst activity can occur from thermal degradation if the catalyst is exposed to excessive temperatures over a prolonged period of time. Catalyst deactivation can also occur due to chemical poisoning. Principal poisons include compounds of arsenic,sulfur,potassium,sodium,and calcium. In applications where natural gas is fired, a catalyst life of 5 to 6 years has been demonstrated. SCR has been demonstrated effective at numerous installations throughout the United States. Typically, SCR is used in conjunction with other wet or dry NO.combustion controls(e.g.,DLN). Because SCR is a post-combustion control, emissions from both turbines and duct burners can be controlled. SCR requires the consumption of a reagent (ammonia or urea) and requires periodic catalyst replacement. Estimated levels of NO. control are in excess of 90%. • Selective Non-catalytic Reduction (SNCR) SNCR is another post-combustion technology where NOx is reduced by injecting ammonia or urea into a high-temperature region, without the influence of a catalyst. The SNCR technology requires gas temperatures in the range of 1200° to 2000°F.The exhaust temperature for the proposed turbines ranges from 1033°to 1135°F,which is below the minimum SNCR operating temperature. Thus,some method of exhaust gas reheat,such as additional fuel combustion,would be required to achieve exhaust temperatures compatible with SNCR operations. SNCR is most commonly used with boilers,and there are no entries in the RBLC indicating the use of SNCR for turbines. SNCR is considered technologically infeasible for this project due to the temperature considerations. However, even if SNCR were technically feasible,it would not be able to achieve NOx reductions comparable to SCR. 25 • Nonselective Catalytic Reduction (NSCR) NSCR uses a catalyst without injected reagents to reduce NOx emissions in an exhaust gas stream. Typically, NSCR is used in automobile exhaust and rich-burn stationary IC engines, and employs a platinum/rhodium catalyst. NSCR is effective only in a stoichiometric or fuel-rich environment where the combustion gas is nearly depleted of oxygen,and this condition does not occur in turbine exhaust where the oxygen concentrations are typically between 14 and 16%. Consequently, NSCR is not technologically feasible for this project. • SCONOx The SCONOx system uses a proprietary potassium carbonate coated oxidation catalyst to remove both NOx and CO. SCONOx is a relatively new system produced by Goal Line Environmental Technologies that began commercial operation in California at the Federal Plant owned by the Sunlaw Cogeneration Partners in December 1996. According to a press release from December 1999, for gas turbine installations larger than 100 MW, ABB Alstom Power is Goal Line's exclusive licensee for SCONOx. The combustion turbine at the Federal facility is a GE LM-2500 that is approximately 23 MW in size, roughly one-eighth the size of the combustion turbine proposed for this project. The application of the SCONOx system at the Federal Plant is the second-generation of the technology. The first generation was a pilot unit application that operated for ten months at another nearly identical GE LM-2500 based facility,the Growers facility, also owned by Sunlaw Cogeneration Partners. The SCONOx catalyst used at the pilot facility was transported to the Federal facility when the pilot unit was taken out of service. Two power plant projects in California proposed by PG&E Generating Company have recently proposed the use of SCONOx for NOx control, although both projects included switching to SCR as a contingency in their permit applications. The La Paloma Generating Project is a merchant plant that originally proposed using SCONOx on one out of its four turbines,although recently the decision was made to apply SCR to all four turbines. In addition,the technology's co-developer, Sunlaw, has proposed to use the technology in conjunction with ABB gas turbines at the Nueva Azalea site in Southern California. The SCONOx system does not use a reagent such as ammonia but instead utilizes natural gas as the basis for a proprietary catalyst regeneration process. The NO present in the flue gas is reduced in a two-step process. First, NO is oxidized to NO2 and adsorbed onto the catalyst. For the second step, a regenerative gas is passed across the catalyst periodically. This gas desorbs the NO2 from the catalyst in a reducing atmosphere of hydrogen(H2)which results in the formation of N2 and water(H2O)as the desorption products. For the regeneration/desorption step to occur there must be no oxygen(O2)present during this step. The CO present in the flue gas is oxidized to CO2 as part of the SCONOx process. In order for the SCONOx technology to work properly, inlet/outlet dampers must continuously isolate one quarter of the catalyst blocks for regeneration. The SCONOx potassium carbonate layer has a limited adsorption capability and requires regeneration about once every 15 minutes in normal service. Each regeneration cycle requires approximately 3 to 5 minutes. The regenerative gas is passed through the isolated portion of the catalyst while the remaining catalyst is left open to the flue gas flow. After the isolated portion is regenerated,the next set of dampers must close and isolate the next section of catalyst for regeneration. This cycle is continuously repeated. Assuming a four(4) section catalyst, and regeneration times of 15 minutes per section,results in approximately 35,000 regeneration cycles per year. At the Federal Plant the regenerative gas is produced from natural gas by processing it through a separate 26 skid mounted processing unit. The resulting regenerative gas is approximately 3 percent nitrogen, 1.5 percent CO2, and 4 percent H2, with steam making up the balance. Steam is used to: (1) dilute the regenerative gas hydrogen concentration below the lower explosive level; (2) act as a carrier gas; (3) promote the purging of the catalyst bed of the oxygen containing flue gas;and(4)promote even distribution of the regeneration gas throughout the catalyst bed. Goal Line has tested several methods for producing regeneration gas, including a one step method where steam,natural gas,and air are reacted at 900°F using an autothermal process. This process failed to produce consistent results and was abandoned. Goal Line has stated that in future applications,the regeneration gas will be generated in the HRSG at a temperature of approximately 600°F. This modified system to produce regeneration gas has not, to our knowledge, tested on any commercial applications, and as such, is most likely not demonstrated in practice. Because the active regenerant gas is hydrogen,the regeneration process must be performed in an atmosphere of low oxygen to prevent dilution of the hydrogen. In practice, the oxygen present in the exhaust gas of combustion turbines is excluded from the catalyst bed by dividing the catalyst bed into a number of individual cells or compartments that are equipped with front and rear dampers that are closed at the beginning of each regeneration cycle. Obtaining a good seal with the dampers is key to: (1) preventing oxygen in the flue gas from disrupting the regeneration process,and(2)evenly distributing the regeneration gases across the catalyst. Complete regeneration of the SCONOx catalyst system is dependent upon the proper functioning and sealing of these sets of dampers approximately four times each hour. Incomplete regeneration of the catalyst results in decreased system performance which in-turn results in increased NOx emissions. Based on an article by Goal Line (Campbell et al, February 1997), probably the most important cause of reduced performance in the pilot unit was poor distribution of regeneration gas over the catalyst. As a result,several design changes were incorporated into the system located at the Federal Plant. The SCONOx catalyst is very susceptible to fouling by very small amounts of sulfur in the flue gas. Sulfur causes the catalyst to loose activity. The impact of sulfur is minimized by a sulfur absorption catalyst,called SCOSOx, located upstream of the SCONOx catalyst. First, the SO2 is oxidized and absorbed on to the catalyst. The SO3 is then desorbed from the catalyst as part of the SCONOx regeneration process. The resulting byproduct of the regeneration is either H2S (for systems located in the HRSG where the flue gas temperature is below 450 °F at the catalyst) or SO2 (for systems located in the HRSG where the flue gas temperature is above 450 °F). In the case where H2S is formed,it is converted back to SO2 using an additional subsystem and directed into the exhaust downstream of the catalyst. In the case where SO2 is the byproduct,it is directed into the turbine exhaust downstream of the catalyst. For a new construction project, the system would be placed in the HRSG at a point where SO2 would be the primary product of the SCOSOx system. According to Goal Line/ABB, the catalyst requires periodic washing at least annually. The "washing" consists of removing the catalyst modules from the unit and submerging each module in a vessel containing potassium carbonate. Thus,the adsorbent portion of the SCONOx process must be revitalized or replaced at least annually. For units the size of the proposed turbine,total required"wash"time could be on the order of seven (7) days per turbine per wash cycle(including the time to allow safe entry to the HRSG). There are three options available for carrying out this washing: 27 • To shut down the unit for approximately one week to clean the catalyst. Shut down includes a two day cooling period prior to personnel entering the HRSG. Unbuttoning and entry into the HRSG. Dismantling of the catalyst support structure to allow the catalyst to be removed. Removal and dipping of the catalyst and then placement back into the HRSG. The actual logistics and design requirements of accomplishing this task on a unit the sizes of the proposed units are not yet known. In addition,this approach has the disadvantage of eliminating the ability to produce power during the outage. • Removal of the unit while on-line and replacement with clean catalyst while the other catalyst is washed. This approach is impractical in light of the need to assure that all damper seals maintain 100% integrity during the removal. The logistics associated with performing this operation on an application with units the size of the proposed unit is also several fold more complicated because of the need to maintain tight damper seals where one side is at operating temperature and the other is at ambient in order to allow worker access. Several safety issues would also have to be overcome. This approach also requires that a spare catalyst set be purchased and stored. Thus, additional storage facilities would also be required. • Bring the catalyst off-line only long enough to permit removal of the used catalyst and replacement with a spare catalyst set. The removed catalyst is then washed and prepared for placement back in service at the next wash outage. Any of the above operations will require several days to shutdown and cool the HRSG and SCOSOx/SCONOx sections to the point that the catalyst can be handled safely. Then each catalyst section will have to be removed,washed,dried,and put back in the HRSG before the units can startup again. Commercially quoted NO„emission rates for the SCONOx system range from 2.0 ppm on a 3-hour average basis, representing a 78% reduction, to 1.0 ppm with no averaging period specified (96% reduction). Because it has only been applied to a relatively small number of combustion turbine facilities, there are several long-term operational concerns that exist with the SCONOx system. Although technical concerns exist, the SCONOx system will be considered technologically feasible for the purposes of this analysis. Thus,based on the information in this section,the following NO„control technologies are technologically feasible for the proposed project: • Water injection • Steam injection • Dry low-NO,, combustors (low-NO,,burners for the duct burners) • Selective Catalytic Reduction (SCR) • SCONOx 3. Rank Technically Feasible Control Technologies by Control Effectiveness The technically feasible control technologies listed above are ranked by NO„ control effectiveness in the traditional "top-down" format in Table 5-1. 28 I'`y Table 5-1 NO„ Control Technologies Ranked by Effectiveness NO„ NO, Control Technically Emissions Environmental Energy Alternative Available? Feasible? (@ 15% 02) Impact Impacts Selective >90% Catalytic Yes Yes reduction Ammonia slip Decreased Reduction' 1 —3.0 ppm Efficiency >90% Reduced CO; SCONOx Yes Yes` reduction potential Decreased 1 —3.0 ppm reduction in Efficiency VOC Dry Low Reduced Increased NO, Yes Yes 9-25 ppm CO/VOC Efficiency Combustors Steam Increased Increased Injection Yes Yes 15—25 ppm CO/VOC Efficiency Water Yes Yes 25-42 ppm Increased Decreased Injection CO/VOC Efficiency a Typically used in conjunction with wet or dry combustion controls. b The availability of commercial guarantees for utility-scale projects is not clear. This technology has been used on a small number of gas turbines;to our knowledge it has not been demonstrated on utility-scale gas turbines. 4. Evaluate Most Effective Controls for BACT For large gas turbines such as the unit proposed,water and steam injection have been largely superseded by dry low-NO„combustors,due to the superior emission control performance and increased efficiency. The proposed project plans to use dry low-NO, combustors for the combustion turbine, thus no further discussion of water injection, steam injection, or dry low-NO„combustors is necessary. The duct burner will be equipped with low-NO„burners,which also represents a high level of emission control performance. The level of NQ control for SCR and SCONOx is essentially equivalent. However, the SCONOx process is much more complex both chemically as well as mechanically than the SCR technology. The principal differences between the two technologies are associated with whether the low emission levels proposed have been achieved in practice,the cost-effectiveness in achieving these levels,and secondary environmental impacts. Table 5-2 compares the two processes. The SCR catalyst needs to be located in the appropriate section of the HRSG and maintained at the proper temperature. An SCR system also requires ammonia to be injected upstream of the catalyst with good mixing and even distribution. By comparison,the SCONOx process is much more complex in that the catalyst requires continuous regeneration,not just the presence 29 of a reducing agent in the flue gas. Unlike SCR, the regeneration process for SCONOx requires a separate process to generate the regeneration gas and the catalyst must be separated from the flow of hot flue gas for the regeneration process to occur. Thus,the need for the isolation louvers and the ability to frequently remove the SCONOx catalyst for washing. Each SCONOx catalyst block also has inlet and outlet piping for the regeneration gas. In order to control flow of the regeneration gases, each inlet and outlet pipe has a set of electronically actuated valves. As such, each catalyst section has several actuators and valves that need to properly function and be maintained. In contrast, the SCR ammonia distribution system requires one automatic ammonia flow control valve and a set of manually adjusted valves used as part of the initial tuning of the ammonia injection grid. As a result, relative to the well-demonstrated application of SCR to natural gas-fired sources, the SCONOx processes will have a lower availability and higher operating and maintenance costs for the following reasons: • The mechanically complex nature of the isolation louvers; • The mechanically complex regeneration gas valving system; and, • The added catalyst regeneration/replacement step (potassium carbonate solution washing). Table 5-2 Comparison of SCR and SCONOx Removal Technologies SCR SCOSOx/SCONOx NOx SO2 NOx NOx Process Parameters Reduction Removal Oxidation Reduction Catalyst Yes Yes Yes Yes Reducing agent& Yes Yes No Yes equipment Mechanical seals No Yes Yes Yes Catalyst regeneration/ At least 5 years 5 years 5 years replacement annually By products/wastes Potassium NH3 slip 1125 or SO2 None solution 5.1.2 Evaluation of Achieved in Practice Guidance from the APCD is not available to determine if a control has been achieved in practice (AIP). However, the South Coast Air Quality Management District (SCAQMD) has established criteria for determining when control technologies should be considered AIP for the purposes of BACT evaluations. SCAQMD's BACT Scientific Review Committee has recently reviewed a proposed clarification of those criteria, which include the following elements: Commercial Availability: At least one vendor must offer this equipment for regular or full-scale operation in the United States. A performance warranty or guaranty must be available with the purchase of the control technology, as well as parts and service. Reliability: All control technologies must have been installed and operated reliably for at least six months. If the operator did not require the basic equipment to operate daily,then the equipment must 30 have at least 183 cumulative days of operation. During this period, the basic equipment must have operated(1)at a minimum of 50%design capacity;or(2)in a manner that is typical of the equipment in order to provide an expectation of continued reliability of the control technology. Effectiveness: The control technology must be verified to perform effectively over the range of operation expected for that type of equipment. If the control technology will be allowed to operate at lesser effectiveness during certain modes of operation,then those modes of operation must be identified. The verification shall be based on a performance test or tests,when possible,or other performance data. Technology Transfer: BACT is based on what is MP for a category or class of source. However, USEPA guidelines require that technology that is determined to be AIP for one category of source be considered for transfer to other source categories. There are two types of potentially transferable control technologies: (1)exhaust(backend)controls,and(2)process controls and modifications. For the first type, technology transfer must be considered between source categories that produce similar exhaust streams. For the second type,technology transfer must be considered between source categories with similar processes. 5.1.2.1 Achieved in Practice Criteria Evaluation for SCR SCR has been achieved in practice at a multitude of gas turbine installations throughout the world. This technology has also been demonstrated on large gas turbines through stack testing and continuous emissions monitoring systems(CEMS)at numerous facilities. SCR technology has been making continued advances over the past few years, although there are not that many facilities in operation designed to meet low NON permit limits of 3.0 ppm or less (most are in the permitting or construction phase). There are numerous facilities operating at higher NON concentrations, and experience from these facilities has allowed manufacturers to gain a better understanding of operations to optimize NO,reduction, sizing of catalyst systems,reagent distribution, and process and control systems. Some SCR system operational data is available on EPA's Acid Rain web site for sources required to submit emissions information. One such source is the Sacramento Power Authority-Campbell Soup cogeneration plant in Sacramento,California. CEMS data for this source indicate NO,emissions that are in compliance with its 3.0 ppm limit on a continuous basis,in fact,the actual NO,levels from the 120 MW Siemens V84.2 turbine are approximately 2.5-3.0 ppm(3-hour average). This facility has experienced a few excursions due to the gas turbine switching from pre-mix,or low-NON mode, into diffusion mode,which have resulted in emissions above 3 ppm. As a result,the permit has been modified to accommodate up to ten hours per year of excursions above the 3 ppm permit limit under certain.conditions. This site is an example of the knowledge gained from existing comparable sources operating with SCR (something that is not truly available with SCONOx). The experience at the SPA-Campbell Soup site demonstrates that lower emission levels are achievable on a continuous basis. However, it also indicates that the ability of the SCR system to track NON emissions changes upstream of the catalyst is further challenged at progressively lower concentrations. Another factor that is important to mention is the ability of measurement systems to accurately measure very low NON levels. SCAQMD for instance has indicated that current NO,measurement methods for stationary sources are accurate to ±1 ppm (Protocol for Rule 2012). This presents problems at permit levels of 5 ppm and lower for NON,although this challenge will be a factor for either SCR or SCONOx. The following is an evaluation of the proposed AIP criteria as applied to the achievement of extremely low 31 NOx levels using SCR technology to control both turbine and duct burner emissions. Commercial Availability: There are numerous manufacturers of SCR catalyst systems and standard commercial guarantees are available. Guaranteed NOx levels in the range of 2-5 ppm for turbines are commonly available. Reliability: There are numerous similar installations operating with SCR control systems throughout the United States. This technology has been available for years and has demonstrated the ability to meet low NOx emission rates. The SPA-Campbell Soup facility provides an example of a source achieving NOx levels complying with a 3 ppm permit limit during routine operations over time. There has not been evidence of adverse effects on overall plant operations and reliability from SCR system operating at these levels. Effectiveness: SCR technology has been demonstrated to achieve NOx levels below 3 ppm. CEMS data for a number of installations and sites is available for several years and demonstrates compliance with a NOx permit level of 3 ppm. Due to system design(SCR inlet NOx levels in excess of those for which the SCR system was designed that caused tripping from pre-mix to diffusion mode),short-term excursions have resulted in NOx concentrations above 3 ppm. However,these excursions have not been associated with diminished effectiveness of the SCR system. Consequently, as with most control systems designed to reduce emissions to very low levels, the application of SCR should reflect the potential for infrequent NOx excursions under specified conditions. Technology Transfer: SCR has been demonstrated on numerous similar installations,and is therefore not a situation of technology transfer. From the above discussion, SCR technology is considered to be achieved in practice. The technology is capable of achieving NOx levels of 3 ppm and below. The current BACT guidelines used by EPA Region IX indicate that NOx levels of<3.0 ppm on a 3-hour average basis are considered BACT for utility-scale gas turbines(without supplemental firing). The achievement of NOx concentrations below these levels,on either a short term or long term basis, has not been demonstrated in practice. Thus, the proposed NOx emission rate for the combustion turbines and duct burners of 3.0 ppm on a 3-hour average basis with the application of SCR meets BACT. 5.1.2.2 Achieved in Practice Criteria Evaluation for SCONOx The SCONOx system has only been applied to a relatively small group of combustion turbine facilities. As a result, there are several long-term operational concerns that exist with the SCONOx system. The SCONOx isolation louvers are moving parts in the flue gas stream that will require more frequent maintenance than any SCR components. In fact, no other combustion turbine systems or boilers have damper systems that require frequent operation from a fully open to a fully closed position. Louver and damper systems are subject to mechanical and thermal stresses and strains that result from changes in temperatures associated with startup and shutdown as well as normal fluctuations in operating temperatures during load changes or changes in steam demand. These thermal/mechanical stresses result in operating and maintenance problems that are magnified with increases in scale. It should be noted that the change in placement/position of the SCONOx from the Federal facility location where the operating temperature is 320 °F to the Goal Line stated preferred, undemonstrated, location where the operating temperature will be 550 to 650°F will increase the challenges associated with maintaining good seals during 32 regeneration. Another issue of concern is long-term catalyst availability and pricing. The SCONOx catalyst is a proprietary catalyst produced and available through only Goal Line/ABB, unlike SCR catalysts that are available through multiple suppliers that guarantee competitive pricing and availability. While Goal Line/ABB guarantees a catalyst life of three years, this catalyst life has not yet been commercially demonstrated over multiple applications, since only a small number of units has been operated over that length of time. It is important to note that although SCR catalyst is now well demonstrated,during the first three years of operation on the initial five(5)combustion turbine applications in the U.S. there were over five(5) catalyst change outs. Also, vendor guarantees are only good for replacement of the catalyst. The guarantee does not: • Pay for lost revenues associated with downtime; • Pay for the cost of any penalties resulting from any exceedence of a permit limit; • Pay for the cost of removing SCOSOx/SCONOx and replacing it with an SCR system;and, • Ensure that the catalyst will be replaced until the system works. Subsequent catalyst replacements are at the vendor's discretion and it is left to the vendor discretion to abandon a particular application at any time. All of these risks and their associated costs would be borne by the proposed project. In a recent application submitted for another Calpine facility,which is also in EPA Region IX,an analysis of available CEMS data for the SCONOx system at the Federal facility was conducted @lease refer to the supplemental BACT analysis for Metcalf Energy Center). For the period covering July through December 1997,review of the available SCONOx data indicated that up to 12 exceedences per year could be expected for a 3.0 ppm, 3-hour average limit, even when exceedences related to startups and shutdowns were excluded. According to the analysis, for a combined cycle gas turbine with a limit of 2.0 ppm on a 3-hour average basis(the BACT/LAER levels recommended by several agencies),the 1997 SCONOx data from the Federal site indicate that this limit would be exceeded 44 times per year(excluding exceedences associated with startups and shutdowns). Data was also obtained for the Federal facility from the period of April 1 through December 31, 1999. The more recent data are also consistent with the earlier data. According to the analysis, there were approximately 2,500 valid 1-hour average periods in the data set,excluding startups,shutdowns,and CEMS maintenance. For a 3.0 ppm limit based on a 3-hour averaging period,there were 20 exceedences(for the period April -December). The analyses conducted show that the SCONOx system at the Federal facility is not capable of maintaining low NO. levels of 3.0 ppm or less on a continuous basis. Moreover,the more recent data do not indicate improved performance over time. In addition to performance-related concerns about the SCONOx system,there are several specific concerns regarding applying the SCONOx system to this project. Applying the system on a unit that is six times larger than its previous first time fill-scale application would require a major redesign of the dampers. The dampers at the Federal Plant are 10 feet wide. The HRSG for this project would be approximately 32 feet wide. 33 A width that is 3.5 times greater than that previously demonstrated results in concerns about designing dampers that provide an adequate seal when fully opened and closed during the numerous regeneration cycles required(i.e., as many as 35,000 times per year). This concern is heightened for an application at temperatures greater than those at the Federal Plant (i.e., 650 °F versus 320 °F). In addition, potential interferences between damper actuators and the regeneration gas injection system would need to be resolved,as well as issues on attaining and maintaining cross flow distribution of regeneration gas across a 35 foot catalyst section. In an independent evaluation of SCONOx conducted by Stone&Webster,Independent Technical Review— SCONOx Technology and Design Review,from February 2000,it is reported that the initial operation of the SCONOx system at another installation—the Genetics Institute facility in Massachusetts-resulted in a rapid loss of performance due to poor operation of the regeneration system. The problem was traced to mechanical deficiencies,such as seal and gasket leakage,and numerous corrective actions were necessary. Further changes to the overall system included adding an external reformer and adding a sulfur filter to remove sulfur from the gas that feeds the external reformer. Moreover, Stone & Webster reports that a number of damper/seal design changes have been proposed by ABB based on results from testing of the system. The following is an evaluation of the proposed AIP criteria as applied to the achievement of extremely low NO„ levels using SCONOx technology. Commercial availability: SCONOx is available through only one vendor and has been applied to a very limited number of projects. In a press release, Goal Line/ABB indicate that commercial performance guarantees will be provided for SCONOx upon request. Although,due to the lack of information in the public domain,there are still questions regarding whether SCONOx technology is presently available with standard commercial guarantees for NO„levels as low as 2.0 ppm. Another concern is whether the guarantee will be passed on by the HRSG vendors. Also, will the system be able to achieve 3 ppm controlling both the turbine and duct burner emissions, especially on a system with a large number of duct burners Thus, numerous questions exist regarding the availability of a commercial guarantee for SCONOx. There are also numerous questions regarding scale-up of a SCONOx system to units of the size proposed for this project,consequently,problems associated with installation and operation have to be anticipated. As previously mentioned,even if a commercial guarantee is available, it does not cover the loss of revenue associated with downtime and the potential need to replace the SCONOx system with an SCR system if the required emission level cannot be achieved. Reliability: Due to the fact that the SCONOx system has not been installed and operated for an extended period of time on a utility-scale turbine,serious questions exist regarding the reliability of the system on such an installation. As the CEMS data from the Federal facility indicate,there has not been a demonstration of the SCONOx system's ability to meet NO„ levels of 3 ppm or lower over an extended period of time without numerous exceedences. There have also been numerous design changes since the original SCONOx installation at the Federal plant. As witnessed in the Stone & Webster report, there have been problems at the Genetics Institute facility that have also required redesign. Consequently,the system that would be applied to a utility-scale application would also likely require design changes,thus, the reliability of the SCONOx system is substantially unknown. 34 Effectiveness: The analysis contained in the Calpine Metcalf Energy Center application demonstrates that the effectiveness of the SCONOx system to meet a 3 ppm limit on a consistent basis without exceedences is in question. Also, there have been numerous design changes associated with the SCONOx system and as such it is uncertain as to whether the actual system that would be installed on a larger, utility-scale turbine has been subjected to performance testing. From the available data, if SCONOx technology were to be used to achieve extremely low NO. levels, it would be necessary to include permit conditions that would allow for the potentially frequent NQ excursions under certain conditions. Technology Transfer: SCONOx technology has been found to be capable of achieving extremely low NO„ levels by SCAQMD and EPA (although the data from the Federal facility does not support this conclusion for an extended period of time,at least not without numerous exceedences). The SCONOx system, based upon our knowledge, has not been installed on a utility-scale turbine for an extended period of time,and serious technical concerns have been enumerated in this application regarding such a scale-up of the technology. While it is not fair to regard this as technology transfer, it is fair to say that SCR has been installed on many more similar installations and is a more demonstrated technology. In summary, the evaluation concludes that the SCONOx process is not commercially demonstrated on larger, utility-scale turbines and the economic risks to the project versus SCR are considerable. This is because the moderate temperature SCONOx process (post-HRSG location)has not been commercially demonstrated, over the long term, on units the size of the proposed project, and the high temperature SCONOx process (mid-HRSG location) proposed by the developers for large turbines has not been commercially demonstrated on any size unit. The significant technical/economic risks are a result of the following: • No commercial demonstration of the SCONOx catalyst operation/regeneration at the mid- HRSG location proposed by the developers for large combustion turbine units like the proposed units; • No commercial demonstration of the regeneration gas system proposed by the developers for large combustion turbine units like the proposed units; • No commercial demonstration of a much larger more complex damper system needed to apply the SCONOx technology to very large CT/HRSG systems(concerns here are related to size, complexity,and placement of a damper system into a higher temperature position of the HRSG (i.e., 650 °F versus 350 °F)); and, • The additional complexity of the SCONOx technology when compared to SCR. This additional complexity will result in lower project availability and could impact revenue generation. 5. Select BACT Based on the analysis presented,either SCR or SCONOx is generally considered capable of achieving NO„ levels of 3.0 ppm for combustion turbines. Technical concerns are associated with the use of SCONOx however. BACT for NO„ is considered to be the use of either SCR or SCONOx systems in conjunction with dry low-NO,; combustors to achieve NO. levels for the combustion turbines of 3.0 ppm on a 3-hour average basis. The proposed project will have duct burners in the HRSG(low-NO„design),consequently, the proposed BACT rate needs to be higher to take this supplemental firing into account. Consequently, a NO,;level of 3.0 ppm on a 3-hour average basis is proposed,which is consistent with the lowest emission 35 rates contained in recent BACT decisions for similar sized units. Due to the technical concerns related to the use of SCONOx and the increased cost, the project proposes the use of SCR technology to meet this emission rate. Thus, the proposal is consistent with the BACT requirements for NOR. 5.1.3 Evaluation of Ammonia Emissions Although secondary emissions associated with the operation of an air pollution control device are typically excluded from BACT requirements, ammonia slip is often discussed in association with SCR. The following section discusses ammonia emissions as a result of the choice of control system and is presented in an analogous format to that for NOx. An economic analysis is also provided to show that the benefit of no ammonia emissions associated with SCONOx does not outweigh the cost of using this technology. 1. Identify Potential Control Technologies Ammonia emissions result from the use of ammonia-based NO„ control technologies (e.g., SCR). As presented previously,the reduction of NO„emissions can be achieved by wet and dry combustion controls and post-combustion flue gas treatment. Combustion controls act to reduce the formation of NO„during the combustion process, while post-combustion controls remove NO„ from the exhaust stream after it is generated. Potential NQ control technologies as identified for the combustion turbine and duct burner include the following: Wet combustion controls • Water injection • Steam injection Dry combustion controls • Dry low-NQ combustor design(with low-NOx burners for the duct burners) • Other combustion modifications • Catalytic combustors (e.g., XONON) Post-combustion controls • Selective catalytic reduction (SCR) • Selective non-catalytic reduction (SNCR) • Non-selective catalytic reduction (NSCR) • SCONOx Two of these NO„ control technologies result in ammonia emissions, SCR and SNCR. 2. Evaluate Control Technologies for Technically Feasibility Based on the previous discussion, the following NO„ control technologies are considered technologically feasible for the proposed project: • Water injection • Steam injection • Dry Low-NOx Combustors • Selective Catalytic Reduction 36 • SCONOx Of these technically feasible control alternatives, only SCR results in ammonia emissions. 3. Rank Technically Feasible Control Technologies by Control Effectiveness Table 5-3 presents the technically feasible control technologies ranked by potential ammonia emissions. Table 5-3 NOx Control Technologies Ranked by Ammonia Emissions Ammonia NOx Control Technically Emissions Alternative Available? Feasible? (@ 15% O2) Selective Catalytic Reductiona Yes Yes 5-10 ppm SCONOx Yesb Yes` 0 ppm Dry Low-NOx Combustors Yes Yes 0 ppm Steam Injection Yes Yes 0 ppm Water Injection Yes Yes 0 ppm a Typically used in conjunction with wet or dry combustion controls. The availability of commercial guarantees for utility-scale projects is not clear. This technology has been used on a small number of gas turbines;it has not been demonstrated on utility-scale gas turbines. 4. Evaluate Most Effective Controls for BACT The proposed turbines will be equipped with dry low-NOx combustors,which have largely superceded water and steam injection due to improved performance. Thus,water injection,steam injection,and dry low-NOx combustors are not discussed further. SCR and SCONOx are assumed to be able to achieve equivalent NOx reductions. SCONOx does not result in ammonia emissions,while SCR results in ammonia"slip" in the range of 5-10 ppm. Ammonia slip generally results from a gradual decline in catalyst activity over time. This requires increasing the amount of ammonia injected in order to maintain NOx concentrations at or below the design rate. Ammonia slip levels are usually specified for an associated NOx concentration and represent the maximum amount of ammonia emissions expected. At the initial catalyst installation ammonia slip is typically quite low, such as 1-2 ppm, and as the catalyst performance declines over time it begins to approach the guarantee level. Ammonia is not included on the Federal list of hazardous air pollutants. Although with the recent increase in power plant projects, especially those using combustion turbines and SCR controls, ammonia slip requirements are usually included as a permit term. For instance,the Northeast States for Coordinated Air Use Management (NESCAUM) has recommended an ammonia emissions limit of 10 ppmv, unless this 37 limit is shown to be inappropriate. Recent ammonia limits imposed by the California Energy Commission on new combined cycle and simple cycle turbine based power plants were set at levels of 10 ppm. In order to determine what ammonia slip levels have been included in recent permitting a query of the RBLC database for ammonia was conducted. The RBLC was searched for natural gas internal combustion (process type code 15.004)and also for the keyword turbine. Twenty-four entries were found with ammonia limits since January 1990. Some entries only had limits in terms of lb/hr or lb/MMBtu. In addition, ammonia skip levels proposed by other permitting agencies (not contained in the RBLC) were also reviewed. In order to have a normalized frame of reference only those entries with ppm limits were considered. The range of permitted ammonia limits is 5 to 30 ppm. The applicant is aware of some projects that have been permitted with lower ammonia slip rates(on the order of 5 ppm),however,these were either associated with slightly higher NO„levels.Ammonia slip limits on the order of 5 ppm were seen more often on aero-derivative turbines, with higher limits frequently seen on industrial and large frame turbines. In addition, these lower values have been seen to reduce operational flexibility. 5. Select BACT The project has proposed an ammonia slip rate of 10 ppm, which is consistent with information from the RBLC as well as information form other agency BACT evaluations. As mentioned previously,this is the maximum level of ammonia emissions that is expected to occur only at the end of the catalyst life. Lower ammonia slip rates have been permitted,however, the applicant is not aware of any sources in operation with extremely low NO„levels(on the order of less than or equal to 2.5 ppm)and lower ammonia slip rates. As discussed previously,SCR is proposed as the control technology to meet the NO„limit of 3.0 ppm(on a 3-hour average basis) for the turbines and duct burners, due to technical concerns and costs associated SCONOx. However,the SCONOx technology does not have associated ammonia emissions. Therefore,a further evaluation of the cost-effectiveness of this technology was performed with regards to the incremental cost assigned to the benefit of eliminating ammonia slip. The use of SCONOx is assumed to eliminate all ammonia emissions,which would be a reduction of approximately124.8 tons per year for the new turbine. Tables 5-4A through 5-4C present the cost-effectiveness analysis. As shown in Table 5-4A, the total annualized costs for SCR for the new turbine/HRSG are $2.38 million. Table 5-4B presents the total annualized costs for SCONOx,which are$5.68 million.Table 5-4C presents the annual incremental cost. Thus,the annual incremental cost of SCONOx is$3.30 million per year for the new turbine. Consequently, SCONOx is not cost-effective when compared to SCR. The applicant proposes to use SCR technology to meet a NOx level of 3.0 ppm on a 3-hour average basis for the combustion turbines and duct burners with an ammonia slip level of 10 ppm. This proposal is consistent with BACT requirements and with emission rates found in databases and literature sources reviewed. Table 5-4C SCONOx Incremental Cost(per gas turbine/HRSG) SCONOx Annualized Costs $5,683,843 SCR Annualized Costs $2,379,740 Incremental Annualized Costs $3,304,103 38 TABLE 5-4A Calpine Corp. -Rocky Mtn. Energy Center Hudson, CO. NOx SCR Control Costs CAPITAL COST SUMMARY DIRECT CAPITAL COSTS(2003$) Explanation of Cost Estimates per Turhine/HRSG 1. Purchased Equipment: Base Cost A) Pollution Control Equipment $1,450,000 SCR System,tanks,piping,containment.etc. B) Instrumentation &Controls(No CEMS) $101,500 OAQPS 7%of Base Cost C) Freight&Taxes $201,695 OAQPS 8%Taxes;5%Freight;on 1A&1B Total Purchased Equip. Costs(TEC): $1,753,195 Sum 1A,18,1C 2. Installation Costs: A) Foundation&Supports $140,300 USDOE 8%of TEC B) Erection and Handling $245,400 USDOE 14%of TEC C) Electrical $70,100 USDOE 4%of TEC D) Piping $35,100 USDOE 2%ofTEC E) Insulation $17,500 1%ofTEC F) Painting $17,500 USDOE 1%of TEC G)Site Preparation $0 0%of TEC Total Installation Costs(TINC): $525,900 Sum 2A,2B,2C,2O,2E,2F,2G Total Direct Capital Costs(TDCC): $2,279,095 Sum TEC,TINC INDIRECT CAPITAL COSTS 1. Engineering &Supervision $175,300 USDOE 10%ofTEC 2. Construction and Field Exp. $87,700 OAOPS 5%of TEC 3. Contractor Fees $175,300 OAQPS 10%of TEC 4. Start-up $35,100 OAQPS2%ofTEC 5. Performance Testing $17,500 OAQPS 1%ofTEC Total Indirect Capital Costs(TICC): $490,900 Sum 1,2,3,4,5,6 Total Direct& Indirect Capital Costs(TDICC): $2,769,995 SumTDCC,TICC Contingency(@ 5%): $138,500 5%TIICC TOTAL CAPITAL COSTS(TCC): $2,908,500 Sum TDICC,Contingency TABLE 5-4A Calpine Corp. -Rocky Mtn. Energy Center Hudson,CO. NOx SCR Control Costs • ANNUAL OPERATING COST SUMMARY DIRECT OPERATING COSTS (2003 $) Explanation of Cost Estimates per Turbine/HRSG 1. Operating Labor $45,443 GTACT©1hr/shlft,$41.50 hr,1095 hrs ,r 2. Supervisory Labor $6,800 OAQPS 15%Operating Labor 3. Maintenance Labor&Materials $45,443 .5 hr/shift,3 shifIsIday,$41.50/hr,+100%materials 4. Electricity Expense($0.0527/kWh) $8,812 220 volt/60 hz,@20 Kw/hr,Aigas XP120AA unit 5. Catalyst Cost(replace/disposal) 3 yrs $4,058,700 30 cuft/MW,$400/cult,$15/cult disposal. 6. Ammonia Costs $86,954 -80 lb/hr NH3,$260/ton NH3 7. Fuel Penalty $176,417 .15%fuel Increase/inch we(assumed 1.5'bp) 8. Annualized Catalyst Cost $1,546,771 CRF,7%,3 yrs Total Direct Operating Costs(TDOC): $1,916,640 Sum 1 through 8 INDIRECT OPERATING COSTS 1. Overhead $27,300 OAQPS 60%Total Labor Total Indirect Operating Costs(TIOC): $27,300 Sum 1 CAPITAL CHARGES COSTS 1. Property Tax $29,100 OAQPS 1%TCC 2. Insurance $29,100 OAQPS 1%TCC 3. General Administrative $58,200 OAQPS 2%TCC 4. Capital Recovery Cost(7%, 15 years) $319,400 10.98%%.Tcc Total Capital Charges Costs(TCCC): $435,800 Sum 1,2,3,4 TOTAL ANNUALIZED OPERATING COSTS: $2,379,740 sum TOoc,Tioc,Tccc TABLE 5-4A Calpine Corp.-Rocky Mtn. Energy Center Hudson, CO. NOx SCR Control Costs NOx Emission Summary Uncontrolled Case Emissions(60 F Peak Case) per Turbine/HRSG Base Concentration-Uncontrolled 15.0 ppm (DLN only) Annual Emission Rate 460.1 tpy(startup emissions not included) Controlled Emissions Case NOx Concentration 3.0 ppm Annual Emission Rate: 92.0 tpy(startup emissions not included) NOx Reduction from Uncontrolled Case: 368.1 tpy Control Cost Effectiveness: $6,500 per ton NOx References: OAQPS-OAQPS Cost Control Manual, 5th ED., February 1996. USDOE- Cost Analysis of NOX Control Alternatives for Stationary Gas Turbines, 1999. GTACT-EPA,Alternative Control Technologies Document-NOx Emissions for Stationary Gas Turbines, 1993. 40 CFR 60, Subpart KKKK TABLE 5-4B Calpine Corp.- Rocky Mtn. Energy Center Hudson, CO. NOx SCONOx Control Costs CAPITAL COST SUMMARY DIRECT CAPITAL COSTS (2003 $) Explanation of Cost Estimates per Turbine/HRSG 1. Purchased Equipment: Base Cost A) Pollution Control Equipment $5,000,000 SCONOx System B) Instrumentation & Controls(No CEMS) $350,000 OAQPS 7%of Base Cost C) Freight&Taxes $695,500 OAQPS 8%Taxes;5%Freight;on IA&1B Total Purchased Equip. Costs(TEC): $6,045,500 Sum 1A,18,1C (comparable to GE and NE quotes,see references 2. Installation Costs: A) Foundation &Supports $483,640 USDOE 8%of TEC B) Erection and Handling $846,370 USDOE 14%of TEC C) Electrical $241,820 USDOE 4%ofTEC D) Piping $120,910 USDOE 2%ofTEC E) Insulation $60,455 OAOPS 1%of TEC F) Painting $60,455 USDOE 1%ofTEC G) Site Preparation $0 OAQPS 0%of TEC Total Installation Costs (TING): $1,813,650 Sum 2A-2G Total Direct Capital Costs(TDCC): $7,859,150 Sum TEC,TINC INDIRECT CAPITAL COSTS 1. Engineering & Supervision $604,600 USDOE 10%of TEC 2. Construction and Field Exp. $302,300 OAQPS 5%of TEC 3. Contractor Fees $604,600 OAQPS 10%of TEC 4. Start-up $120,900 OAQPS2%ofTEC 5. Performance Testing $60,500 OAQPS 1%ofTEC Total Indirect Capital Costs(TICC): $1,692,900 Sum 1,2,3,4,5,6 Total Direct& Indirect Capital Costs (TDICC): $9,552,050 SumTDCC,TICC Contingency(@ 5%): $477,603 5%of TDICC TOTAL CAPITAL COSTS (TCC): $10,029,700 Sum TDICC,Contingency TABLE 5-4B Calpine Corp:Rocky Mtn. Energy Center Hudson, CO. NOx SCONOx Control Costs ANNUAL OPERATING COST SUMMARY DIRECT OPERATING COSTS(2003$) Explanation of Cost Estimates per Turbine/HRSG 1. Operating Labor $45,443 1 hr/shift,3 shift/day,365 days,$41.50 hr 2. Supervisory Labor $6,800 OAOPS 15%Operating Labor 3. Maintenance Labor&Materials $45,443 .5hr/shift,$41.50.hr,+100%for Materials Washing 1st layer&SCOSOx $400,000 per Alstom turbine Information,each year Washing 2nd and 3rd layers $200,000 per Alstom turbine information,every 3 years $152,440 CRF,7%,3 yrs 4. Electricity Expense-H2 Skid ($0.0527/kWh) $86,186 USDOE.6kW/MW 5. Catalyst Cost (replace/wash/disposal) $3,000,000 30 cuft/MW,$400/cuft,3 years,7% 6. Ammonia Costs $0 7. Fuel Penalty($0.0041/sdf nat gas) $587,945 .15%fuel increasennch backpressure,assumed 5"bp Reforming Nat Gas Costs($0.0041/scf $156,454 USDOE 14cf-gas/MW H2 Carrier Steam Costs($6/1000 lb steam) $1,520,932 USDOE 93 lb steam/MW 8. Annual Catalyst Cost $1,143,300 CRF,7%,3yrs Total Direct Operating Costs(TDOC): $4,144,943 Sum 1 through 6 INDIRECT OPERATING COSTS 1. Overhead $36,400 OAQPS 60%Total Labor Total Indirect Operating Costs(TIOC): $36,400 sum 1 CAPITAL CHARGES COSTS 1. Property Tax $100,300 OAQPS I%TCC 2. Insurance $100,300 OAOPSI%TCC 3. General Administrative $200,600 OAQPS 2%TCC 4. Capital Recovery Cost(7%, 15 years) $1,101,300 10.98%,TCC Total Capital Charges Costs(TCCC): $1,502,500 Sum 1,2,3,4 TOTAL ANNUALIZED OPERATING COSTS: $5,683,843 Sum TDOC,TIOC,TCCC TABLE 5-4B Calpine Corp.-Rocky Mtn. Energy Center Hudson, CO. NOx SCONOx Control Costs NOx Emission Summary Uncontrolled Case Emissions per TurbineIHRSG Base Concentration-Uncontrolled 15.0 ppm (DLN only) Annual Emission Rate 460.1 tpy(startup emissions not included) Controlled Emissions Case NOx Concentration 3.0 ppm Annual Emission Rate: 92.0 tpy(startup emissions not included) NOx Reduction from Uncontrolled Case: 368.1 tpy Control Cost Effectiveness: $15,400 per ton NOx References: OAQPS- OAQPS Cost Control Manual, 5th ED., February 1996. USDOE-Cost Analysis of NOX Control Alternatives for Stationary Gas Turbines, 1999. NE- Nooter Erickson, Westinghouse F turbine quote at$6.02 million(w/freight and taxes) GE-GE Frame 7 turbine quote at$6.5 million (w/freight and taxes) 40 CFR 60, Subpart KKKK TABLE 5-4C Calpine Corp. -Rocky Mtn. Energy Center Hudson, CO. NOx SCR Control Costs CAPITAL COST SUMMARY Incremental Cost to Add Catalyst for 2.5 ppm NOx DIRECT CAPITAL COSTS (2003$) Explanation of Cost Estimates per Turbine/HRSG 1. Purchased Equipment: Base Cost A)Pollution Control Equipment $325,000 SCR System,tanks,piping,containment,etc. B) Instrumentation&Controls(No CEMS) $22,750 OAQPS 7%of Base Cost C) Freight&Taxes $45,208 OAQPS 8%Taxes;5%Freight;on1A&1B Total Purchased Equip. Costs(TEC): $392,958 Sum IA.18,1C 2. Installation Costs: A) Foundation&Supports $31,400 USDOE 8%of TEC B) Erection and Handling $55,000 USDOE 14%of TEC C) Electrical $15,700 USDOE 4%of TEC D) Piping $7,900 USDOE 2%of TEC E) Insulation $3,900 1%of TEC F) Painting $3,900 USDOE I%of TEC G)Site Preparation $0 0%of TEC Total Installation Costs (TING): $117,800 Sum 2A,2B,2C,2D,2E,2F,2G Total Direct Capital Costs(TDCC): $510,758 Sum TEC,TINC INDIRECT CAPITAL COSTS 1. Engineering&Supervision $39,300 USDOE 10%of TEC 2. Construction and Field Exp. $19,600 OAQPS 5%of TEC 3. Contractor Fees $39,300 OAQPS 10%of TEC 4. Start-up $7,900 OAQPS 2%of TEC 5. Performance Testing $3,900 OAQPS 1%of TEC Total Indirect Capital Costs(TICC): $110,000 Sum 1,2,3,4,5,6 Total Direct& Indirect Capital Costs(TDICC): $620,758 sumTDCC,TICC Contingency(@ 5%): $31,000 5%TDICC TOTAL CAPITAL COSTS (TCC): $651,800 Sum TDICC.Contingency TABLE 5-4C Calpine Corp. -Rocky Mtn. Energy Center Hudson, CO. NOx SCR Control Costs ANNUAL OPERATING COST SUMMARY Incremental Cost to Add Catalyst for 2.5 ppm NOx DIRECT OPERATING COSTS (2003 $) Explanation of Cost Estimates per Turbine/HRSG 1. Operating Labor $45,443 GTACT @ 1 hr/shift,$41.50 hr, 1095 hrs/yr 2. Supervisory Labor $6,800 OAOPS 15%Operating Labor 3. Maintenance Labor&Materials $45,443 .5 hr/shift,3 shifts/day,$41.50/hr,+100%materials 4. Electricity Expense($0.0527/kWh) $8,812 220 volU60 hz,@20 Kw/hr,Algas XP120AA unit 5. Catalyst Cost(replace/disposal)3 yrs $4,058,700 30 cuft/MW,$400/cult,$15/cuft disposal. 6. Ammonia Costs $86,954 -601b/hr NH3,$260/ion NH3 7. Fuel Penalty $176,417 .15%fuel increase/Inch we(assumed 1.5"bp) 8. Annualized Catalyst Cost $1,546,771 CRF,7%,3 yrs Total Direct Operating Costs(TDOC): $1,916,640 Sum 1 through 8 INDIRECT OPERATING COSTS 1. Overhead $27,300 OAQPS 60%Total Labor Total Indirect Operating Costs (7 $27,300 sum 1 CAPITAL CHARGES COSTS 1. Property Tax $6,500 OAQPS 1%TCC 2. Insurance $6,500 OAQPS 1%TCC 3. General Administrative $13,000 QAQP52%TCC 4. Capital Recovery Cost(7%, 15 years) $71,600 10.98%,TCC Total Capital Charges Costs (TCCC): $97,600 Sum 1,2,3,4 TOTAL ANNUALIZED OPERATING COSTS: $2,041,540 sum TOOC,TIOC,TCCC TABLE 5-4C Calpine Corp. - Rocky Mtn. Energy Center Hudson, CO. NOx SCR Control Costs NOx Emission Summary Incremental Cost to Add Catalyst for 2.5 ppm NOx Uncontrolled Case Emissions(60 F Peak Case) per Turbine/HRSG Base Concentration-Controlled 3.0 ppm (DLN only) Annual Emission Rate 92.0 tpy(startup emissions not included) Additional Controlled Emissions Case NOx Concentration 2.5 ppm Annual Emission Rate: 76.7 tpy(startup emissions not included) NOx Reduction from Controlled Case: 15.3 tpy Control Cost Effectiveness: $133,400 per ton NOx References: OAQPS-OAQPS Cost Control Manual, 5th ED., February 1996. USDOE-Cost Analysis of NOX Control Alternatives for Stationary Gas Turbines, 1999. GTACT- EPA, Alternative Control Technologies Document-NOx Emissions for Stationary Gas Turbines, 1993. 40 CFR 60, Subpart KKKK 5.1.4 Analysis of Control Requirements for Carbon Monoxide 1. Identify Potential Control Technologies Carbon monoxide (CO) is a product of incomplete combustion. CO formation is limited by ensuring complete and efficient combustion of the fuel in the combustion turbine. High combustion temperatures, adequate excess air,and good air/fuel mixing during combustion minimize CO emissions. Measures taken to minimize the formation of NOx during combustion may inhibit complete combustion, which could increase CO emissions. Lowering combustion temperatures through premixed fuel combustion can be counterproductive with regard to CO emissions. However, improved air/fuel mixing inherent in newer combustor designs and control systems limits the impact of fuel staging on CO emissions. The applicable NSPS does not contain requirements for CO,thus,there is no real baseline emission rate. Based on a review of the information provided in the RBLC database and knowledge related to the control of CO emissions from combustion sources,the following CO control approaches were identified: • CO oxidation catalyst • SCONOx • Good combustion control 2. Evaluate Control Technologies for Technical Feasibility Oxidation catalysts have previously been applied to natural gas-fired combustion turbines located in CO nonattainment areas,and there are numerous suppliers of oxidation catalyst systems. The catalyst lowers the activation energy for the oxidation of CO to CO2 so that CO in the exhaust gas is converted to CO2. For units that include duct firing, the placement of the catalyst is defined by the need to protect it from temperatures in excess of 1100 degrees F. Because the removal efficiency of CO is fairly constant above approximately 550 degrees F,there is only minimal impact to the catalyst's performance associated with placing it further back in the HRSG. This technology has been applied to natural gas-fired combustion turbines of all sizes, and as such, is considered a demonstrated technology. CO removal efficiencies of up to 90 percent are typical. The oxidation catalyst is typically a precious metal catalyst. As the basis of control used to evaluate BACT for this application, 90 percent removal is used. The SCONOx process previously discussed as part of the NOx BACT analysis is used to control both NOx and CO. The SCONOx system provides for control of CO emissions to levels comparable to that of a conventional oxidizing catalyst. As part of the NO. BACT discussion, it was noted that SCONOx is currently being applied to a 25 MW sized combustion turbine operating at the Federal Plant. Based on available literature describing the Federal Plant's operation, a 90 percent removal efficiency is evaluated. Technical concerns were identified in association with application of the technology on a larger combustion turbine, however, this technology will be considered technically feasible for this analysis. Good combustion control, as the name infers, is based upon maintaining good mixing, a proper fuel/air ratio, and adequate time at the required combustion temperature. This technology is technically feasible and is the most commonly used technology to control CO emissions. Good combustion control is considered the baseline control technology for CO emissions. Thus,an evaluation is provided for the two 39 most stringent technically feasible control technologies,an oxidation catalyst and SCONOx,for energy, environmental, and economic impacts. 3. Rank Technically Feasible Control Technologies by Control Effectiveness Both an oxidation catalyst and SCONOx are considered in this analysis. Control efficiencies for both controls are 90 percent. Consequently, the following analysis compares these two controls as being equally effective for CO control. 4. Evaluate Most Effective Controls for BACT The addition of a CO oxidation catalyst to reduce outlet emissions to 9 ppmv (including duct burner firing)was evaluated. This assumes a control efficiency of 90 percent which is achievable in practice and can be guaranteed. For SCONOx, a 90 percent removal was also evaluated as potential BACT. The BACT evaluation that follows considered the energy, environmental, and economic impacts of the potential BACT levels evaluated. Energy Impacts: There is a pressure drop associated with each of the add-on controls that were evaluated. This pressure drop results in a backpressure on the combustion turbine, which in turn increases the heat rate(i.e.,decreases the turbine's efficiency). The end result is an energy impact in the form of additional fuel to make the same amount of electricty. Based on vendor information the increased backpressure on the turbine associated with oxidation catalyst systems is 1.5 inch w.c. Although, the backpressure for a SCONOx system is likely greater, a similar backpressure of 1.5 inch w.c. is used for this analysis. Each inch w.c. of backpressure on the turbine results in a 0.15%increase in the heat rate(i.e.,Btu/kwh). As a result,there is an increased fuel requirement to generate the same amount of power output. This penalty is included as an annual cost. It should also be noted that the additional fuel firing also results in additional emissions of all pollutants. Environmental Impacts: The spent oxidation catalyst is comprised of precious metals that are not considered toxic. This allows the catalyst to be handled and disposed of following normal waste procedures. Because of its precious metal content, the catalyst is often recycled by the manufacturer to recover the metals. The SCONOx system providers also take back the catalyst for reconditioning. The effective power reduction due to the pressure drop across the two add-on control technologies increases the emission rate of other criteria pollutants, such as NOx, on a per unit of power output. The use of natural gas in the catalyst regeneration process for SCONOx will result in release of some natural gas (methane) to the atmosphere due to leakage and venting. As noted above,the SCONOx catalyst also must be regenerated using a 4-step potassium carbonate bath and water rinses. Each module will generate approximately 1,500 gallons of wastewater per step. A SCONOx installation for the Project is expected to require the use of 40-60 modules. Even assuming the low end of only 40 modules,there would be approximately 240,000 gallons of wastewater produced each year for the new turbine (i.e., 4 x 1,500 x 40 x 1). Production of the regeneration gas requires additional water to generate the steam needed for the process. Such a significant increase in water consumption and waste discharge associated with SCONOx is a considerable concern for the project. Another concem associated with SCONOx, as discussed in further detail in the NO,, BACT section, is that an installation of the system in the hot section of the HRSG has not been demonstrated to the 40 satisfaction of the HRSG suppliers. HRSG suppliers are not yet willing to offer performance guarantees for their equipment if the SCONOX system is installed in the hot section of the HRSG. Economic Impacts: A summary of the capital and annual costs associated with the installation of an oxidation catalyst and SCONOx are presented in Table 5-5. The detailed cost analysis for the oxidation catalyst is shown in Table 5-6. Please refer to Table 5-4B for the SCONOx cost analysis. The cost of the oxidation catalyst system includes the catalyst, catalyst housing, HRSG modifications, and balance of plant equipment. Capital costs are based on scaled estimates from previous budgetary quotations from equipment manufacturers and other engineering estimates. It should be noted that the previous estimates were for systems of nearly the same size. As shown,the per turbine/HRSG total installed capital cost for the oxidation catalyst system is $2,062,100. The total installed capital cost for the SCONOx system is $10,029,700. The annual operating costs associated with the two alternative approaches are also presented in Table 5-5. The annual operating costs include catalyst replacement, energy impacts due to increased fuel usage, operating personnel, and maintenance. Throughout the life of the facility, the catalyst will require periodic replacement. Catalyst manufacturers are currently willing to guarantee a three-year catalyst life. Maintenance consists of the routine catalyst replacement costs. Labor for the operation and maintenance of the combustion control system is considered a part of the facilities normal operating expenses. The estimated annual operating cost associated with the oxidation catalyst and SCONOx systems are $570,055 and $5,683,843, respectively. Table 5-5 Summary of CO BACT Evaluation Results* Control Technology Capital Cost Annual Cost Annualized Cost Oxidation Catalyst $2,062,100 $343,655 $570,055 SCONOx $10,029,700 $4,582,543 $4,602,405 * All costs are presented on a per gas turbine/HRSG basis 5. Select BACT Based on the above discussion, both control technologies evaluated for CO control, an oxidation catalyst and SCONOx, are considered technically feasible and provide comparable reduction efficiencies. Even though the proposed project is located in an attainment area,and controls beyond combustion controls have not typically been required in attainment areas, the project is proposing the use of an oxidation catalyst to meet a voluntary BACT requirement of 9 ppm. The use of an oxidation catalyst versus SCONOx is supported by the technical questions associated with SCONOx and the large difference in cost. 5.1.5 Analysis of Control Requirements for PMio PM to is a Clean Air Act regulated pollutant defined as particulate matter equal to or less than a nominal aerodynamic particle diameter of 10 microns. Particulate matter is typically described as filterable and condensable PM. The following discussion explains the formation of both for combustion sources. 41 TABLE 5-6 Calpine Corp:Rocky Mtn. Energy Center Hudson, CO. CO Catalyst Control Costs CAPITAL COST SUMMARY DIRECT CAPITAL COSTS (2003 $) Explanation of Cost Estimates per Turbine/HRSG 1. Purchased Equipment: Base Cost A) Pollution Control Equipment $1,000,000 CO Catalyst System B) Instrumentation & Controls(No CEMS) $100,000 EPA1998 10%of Base Cost C) Freight&Taxes $143,000 8%Taxes;5%Freight;on 1A&1B Total Purchased Equip. Costs(TEC): $1,243,000 Sum 1A,1B,1C 2. Installation Costs: A) Foundation&Supports $99,400 EPA1998 8%of TEC B) Erection and Handling $174,000 EPA1998 14%of TEC C) Electrical $49,700 EPA19984%ofTEC D) Piping $24,900 EPA1998 2%of TEC E) Insulation $12,400 1%ofTEC F)Painting $12,400 EPA1998 1%of TEC G) Site Preparation $0 0%of TEC Total Installation Costs (TINC): $372,800 Sum 2A,28,2C,20,2E,2F,2G Total Direct Capital Costs(TDCC): $1,615,800 Sum TEC,TINC INDIRECT CAPITAL COSTS 1. Engineering&Supervision $124,300 EPA1998 10%of TEC 2. Construction and Field Exp. $62,200 OAQPS 5%of TEC 3. Contractor Fees $124,300 OAQPS 10%of TEC 4. Start-up $24,900 OAQPS2%ofTEC 5. Performance Testing $12,400 OAQPS 1%of TEC Total Indirect Capital Costs (TICC): $348,100 Sum 1,2.3.4.5,8 Total Direct& Indirect Capital Costs(TDICC): $1,963,900 Sum TDCC,TICC Contingency(@ 5%): $98,200 5%TDICC TOTAL CAPITAL COSTS (TCC): $2,062,100 Sum TDICC,Contingency TABLE 5-6 Calpine Corp:Rocky Mtn. Energy Center Hudson, CO. CO Catalyst Control Costs ANNUAL OPERATING COST SUMMARY DIRECT OPERATING COSTS (2003 $) Explanation of Cost Estimates per Turbine/HRSG 1. Operating Labor $30,295 EPA1998 2hr/day,@41.50 hr 2. Supervisory Labor $4,500 OAOPS 15%OperaOng Labor 3. Maintenance Labor& Materials $30,300 1 hr/day,$41.50/hr,+100%materials 4. Electricity Expense($0.0527/kWh) $0 5. Catalyst Cost(replace) $158,500 Scaled from Calpine IEEC AFC 6. Fuel Penalty($0.0041/scf gas) $117,556 .15%fuel Increse/inch wc,assumed 1^bp 7. Annual Catalyst Cost $60,404 CRF,7%,3 yrs Total Direct Operating Costs(TDOC): $243,055 Sum 1 through 7 INDIRECT OPERATING COSTS 1. Overhead $18,200 OAOPS 60%Total Labor Total Indirect Operating Costs(TIOC): $18,200 sum 1 CAPITAL CHARGES COSTS 1. Property Tax $20,600 OAOPS 1%TCC 2. Insurance $20,600 OAQPS 1%TCC 3. General Administrative $41,200 OAOPS 2%TCC 4. Capital Recovery Cost(7%, 15 years) $226,400 10.98%,TCC Total Capital Charges Costs(TCCC): $308,800 Sum 1,2,3,4 TOTAL ANNUALIZED OPERATING COSTS: $570,055 Sum TDOC,T!OC,TCCC TABLE 5.6 Calpine Corp.- Rocky Mtn. Energy Center Hudson, CO. CO Catalyst Control Costs Uncontrolled Case Emissions per Turbine/HRSG Base Concentration-Uncontrolled 90 ppm Annual Emission Rate 1640.0 tpy(startup emissions not included) Controlled Emissions Case CO Concentration 9.0 ppm Annual Emission Rate: 164 tpy CO Reduction from Uncontrolled Case: 1476.0 tpy Control Cost Effectiveness: $400 per ton CO References: OAQPS - OAQPS Cost Control Manual, 5th ED., February 1996. EPA1998- Cost Effectiveness fo Oxidation Catalyst Control of HAP Emissions from Stationary Combustion Turbines, EPA, 1998. For combustion sources, there are three potential sources of filterable PKo emissions: mineral matter found in the fuel, solids or dust in the ambient air used for combustion, and unburned carbon or soot formed by imcomplete combustion of the fuel. There is no source of mineral matter for natural gas-fired combustion sources, such as the proposed turbines and duct burners. In addition, as a precautionary measure to protect the high speed rotating equipment with a combustion turbine,the inlet combustion air is filtered prior to compression and use as combustion air. Also, the potential for soot formation in natural gas-fired turbines and duct burners is very low because of the excess air combustion conditions under which the fuel is burned. As a result, there is no real source of filterable PMio originating from either the turbine or duct burners. There are two sources of condensable PKo for combustion sources: condensable organics that are the result of incomplete combustion and sulfuric acid mist that is found as sulfuric acid dihydrate (H2SO4.2H2O). For natural gas-fired sources,there should be no condensable organics originating from the source because the main components of natural gas(i.e.,methane and ethane)are not condensable at the temperatures found in a Method 202 ice bath(the EPA reference method for measuring condensable PM). Thus, any condensed organics are from the ambient air. The most likely source of condensable PKo from natural gas-fired combustion sources is sulfuric acid dihydrate, which results when sulfur in the fuel and in the ambient air is combusted and then cools. Appendix M of 40 CFR Part 51 recommends that EPA Reference Methods 201or 201A be used to measure in-stack emissions of PKG. As part of Appendix M, EPA also recognizes that condensible emissions not collected by an in-stack method are also PM 10 and that these emissions contribute to ambient PMio levels. As a result,to establish source specific contributions of PKo, EPA suggests that PM10 measurements include both condensable particulate matter emissions and emissions measured by the in-stack methods. The use of EPA Reference Method 202 is recommended for determining the portion of condensable PM emissions that are PMio from stationary sources. The Method 201/201A and Method 202 portions of the sample are referred to as the filterable and condensable portions, because the PKo emissions form a source represent the sum of these two measurements. Only the most recent NSR permits issued for turbines require the measurement of both the filterable and condensable portions. Most combustion turbine permits only require measurement of the filterable PM10. Thus,comparison of the proposed PMio emission rate to emission rates in the RBLC can be tricky,because the lower rates may represent only the filterable PM10 portion, and not be directly comparable. Based upon the above discussion,the amount of both filterable and condensable PMio emissions from the natural gas-fired combustion turbines and duct burners should be very small relative to the total exhaust flow. However, the vendor guaranteed base load PKo emission rates are 11 lb/hr (0.0062 lb PM10/MMBtu) for the turbines and 0.010 lb PMio/MMBtu (6.6 lb/hr)for the duct burners. Vendor data on expected PMio emission rates are designed to allow for the high level of test error inherent in sampling for an extremely small quantity of PKo in a very large exhaust flow. In order to reduce the amount of variability/error,longer sampling times than are normally used by stack testers during compliance testing are required. Permit data from EPA's RBLC database beginning with January 2000 were searched for PM and PMio BACT decisions and corresponding limits. In particular, data listed for similarly sized natural gas-fired 42 installations were reviewed in detail. Based on a review of the information provided in the RBLC database,a knowledge of combustion source PM and PM10 controls,and taking into account technology transfer from other combustion sources, the following PM10 control approaches were identified: • Add-on control technologies including: electrostatic precipitators, baghouses or fabric collectors, and venturi or packed bed scrubbers; • Combustion turbine lubrication oil exhaust vent coalescers; • Combustion turbine inlet air evaporative coolers; • Use of clean (i.e., low ash) and low sulfur fuels such as distillate oil or natural gas; and • Combustion controls and practices designed to minimize the production of soot. Add-on controls are used to control particulate emissions from solid fuel (i.e., coal, coke, or waste) and residual oil-fired boilers because of the relatively high level of mineral matter(i.e., ash) in these fuels. There are no known applications of add-on controls for the purpose of controlling PM from distillate oil or natural gas-fired units, because these fuels have little if no ash that would contribute to the formation of PM or PM10. In addition, PM emissions from add-on control devices are typically higher than from uncontrolled natural gas-fired combustion units. Therefore,add-on PKo controls do not make practical sense and are not considered feasible for natural gas-fired turbines and duct burners. Two CT sites located in California were identified as having LAER-based permit PMK° limits and controls that included natural gas-firing, an air inlet filter cooler, and lube oil vent controls. The permit for one of the sites required the lube oil vent to be routed to the exhaust stream of the turbine, and the other site's permit required installation of an oil mist coalescer on the vent. Contact with a permit engineer at San Joaquin Valley Unified Air Pollution Control District indicated that the district requires the installation of oil mist coalescers designed to achieve a 95% removal efficiency of the oil mist. Inclusion of oil mist coalescers are usually standard practice on large frame turbines, such as the ones proposed. Vendor information indicates that venting the controlled stream to the turbine's exhaust would not be a form of control, but of dilution. For these reasons, the practice of routing the coalescer treated lube oil mist vent to the turbine exhaust is not considered further in this analysis. The proposed combustion turbines will include inlet air filters,which are required as part of the design to protect the rotating equipment. Inlet air coolers are included on units located in arid regions where high ambient tmeperatures combined with low relative humidity can sometimes preclude the ability to fire the turbine at full load. To overcome this, an inlet air cooler is placed downstream of the inlet air filters and upstream of the compressor air intake. Combustion air is drawn across a wetted surface (similar to a home humidifier screen)or fogging nozzles spray moisure directly into the inlet air. As a result of these processes,the inlet air is cooled and picks up moisture. These devices clean the ambient air upstream of the source,rather than controlling the emissions generated by the source. Therefore,these devices are not considered further in this analysis. The proposed combustion turbines and duct burners are natural gas-fired. They are also equipped with state-of-the-art combustion controls to ensure maximum fuel efficiency. As a result, the conversion of fuel carbon to CO2 will be maximized and the production of carbonaceous particulates minimized. In conclusion,because the combustion turbines and duct burners will fire clean burning natural gas, and their combustion controls will be state-of-the-art,add-on controls are not considered feasible. Particulate emissions from the proposed combined cycle units will be controlled via proper combustor design, 43 operation, and maintenance. With respect to combustion controls, there are no significant economic, energy,or environmental impacts. Review of the various databases indicates PM/PMto limits in the range of 0.0023-0.06 lb/MMBtu. The PM 10 emission rate for the proposed combined cycle units is toward the lower end of the range, approximately 0.01 lb/MMBtu. As noted before, it is difficult to make a direct comparison to the results in the RBLC because it is unclear as to whether the emission rate contained in the database includes both condensable and filterable PM. 5.1.6 Analysis of Control Requirements for VOC This section presents the BACT analysis for the proposed units having a potential to emit VOC (i.e., the combustion turbine and duct burner. The proposed combustion turbine and duct burner are natural gas-fired combustion units. The VOC emissions from natural gas-fired combustion sources are the result of two possible formation pathways: incomplete combustion, and recombination of the products of incomplete combustion. Complete combustion is a function of three key variables: time,temperature,and turbulence. Once the combustion process begins, there must be enough time at the required combustion temperature to complete the process, and during combustion there must also be enough turbulence or mixing to ensure that the fuel gets enough oxygen from the combustion air. Combustion systems with poor control of the fuel to air ratio, poor mixing, and/or insufficient time at combustion temperatures have higher VOC emissions than those with good controls. The proposed turbine and duct burner incorporate state-of-the-art combustion technology, and both are designed to achieve high combustion efficiencies. As a result, the proposed combustion equipment has very low expected VOC emission rates. The two most prevalent components of natural gas, methane(-92%by vol.) and ethane (-5%by vol.), are not defined as VOCs. The remaining portions of natural gas are propane and trace quantities of higher molecular weight hydrocarbons, all of which are nearly 100% combusted. The high energy efficiency of turbines and duct burners and low fraction of VOCs in natural gas result in a very low VOC emissions rate for the proposed new units. Additionally, the recombination of products of incomplete combustion is unlikely in well controlled turbine/duct burner systems because the conditions required for recombination are not present. Based on a review of the information provided in the various databases and knowledge related to the control of VOC emissions from combustion sources, and taking into account technology transfer from other combustion sources, the following VOC control approaches were identified: • Thermal oxidation, • Catalytic oxidation, and • Good combustion design and operation. Thermal oxidizers are used for combustion systems where VOC rates are high,such as waste incinerators. The thermal oxidizers for these types of sources are in the form of secondary combustion chambers and afterburners and are inherent to the combustion system's design. The VOC emissions from these types of sources are much higher because they combust fuels that are heterogeneous in nature and as a result it is difficult, if not impossible, to maintain the uniform time, temperature, and turbulence needed to ensure 44 complete combustion. Thermal oxidation systems work by raising the VOC containing stream to the combustion temperature to allow the combustion process sufficient time to reach completion. The controlled VOC rates from these systems are still higher than those being proposed for this project without VOC control. Also, because thermal oxidizers combust fuel, a significant amount of NO. emission can be generated. As such, thermal oxidizers are not considered further in this anlaysis. Oxidation catalysts have traditionally been applied to the control of CO emissions from clean fuel fired combustion sources located in CO nonattainment areas. As discussed previously, this technology uses precious metal based catalysts to promote the oxidation of CO and unburned hydocarbon (of which a portion is VOC) to CO2. The amount of VOC conversion is compound specific and a function of the available oxygen and operating temperature. Good combustion design and operation is the primary approach used to control VOC emissions from combustion sources. The VOC controls,inherent in the design and operation of a unit,include the use of clean fuels such as natural gas, and advanced process controls to ensure complete combustion and the best fuel efficiency. The proposed turbines and duct burners will be 100%natural gas-fired and each unit is designed with state-of-the-art combustion controls to maximize conversion of the natural gas to CO2, and minimize the production of VOC and CO. An oxidation catalyst is being proposed to control CO emissions, and such systems also achieve VOC reduction. Thus,the highest ranking,technically feasible control technology is being proposed for VOC control. The proposed VOC emission rate is 2.0 ppmv,which is consistent with values from the RBLC, and other recent BACT decisions, represents BACT for VOC. 5.1.7 Analysis of Control Requirements for SO2 The new combustion turbine and duct burner will be designed and operated to minimize emissions and will be fired solely with natural gas, which is inherently low in sulfur. Sulfur dioxide is formed during combustion due to the oxidation of the sulfur in the fuel. Add-on control devices (e.g., scrubbers) are typically used to control emissions from combustion sources firing higher sulfur fuels, such as coal. Flue gas desulfurization is not appropriate for use with low sulfur fuel, and is not considered for this project, because the realizable emission reduction is far too small for this option to be cost-effective. The use of natural gas is proposed as BACT for SO2. As discussed under the NSPS section,SO2 emissions will be below the regulatory limits required by Subpart KKKK. Also,from the various databases searched, there is no precedent for use of post-combustion control of SO2 on combined cycle units. 45 6.0 EVALUATED OPERATIONAL SCENARIOS Because of the variability in ambient temperature and the need for power augmentation,the emissions and associated stack parameters will vary. Seven different operating scenarios were identified as described below. These scenarios match those originally used for the existing facility combined cycle units. 1. base load during cold ambient temperatures (3 °F) 2. 70 percent load during average ambient temperatures (50 °F) 3. 70 percent load during hot ambient temperatures(90 °F) 4. maximum firing with power augmentation during high ambient temperatures (90 °F) 5. maximum firing without power augmentation during high ambient temperatures (90 °F) 6. maximum firing without power augmentation during high ambient temperature (102 °F) 7. maximum firing without power augmentation during average ambient temperature(50 °F) Nominal load refers to a nominal system output of 300 MW with inlet fogging and duct firing for the new turbine/HRSG. Additional steam is created through the use of a 658 MMBtu/hr(HHV basis)duct burner. The turbine stack parameters that produced the maximum impacts in the screening analysis were used in the full impact analysis to calculate the impacts for each pollutant and each avenging period. In addition, impacts from turbine startup were also modeled. Section 8 discusses the results of this load screening assessment. As part of this PSD permit application, a full impact analysis was conducted for those pollutants that are above the significant impact level(s). The impact analysis includes a demonstration that the proposed project will not cause or contribute to an exceedance of the NAAQS and PSD increments for the subject pollutant. All increment consuming sources within the largest significant impact area,plus 50 kilometers (screening area) were included in the analysis for comparison with the increment. For the NAAQS analysis, all sources within 50 kilometers of the largest SIL were included in the modeling assessment in addition to adding in background monitored concentration data, collected in the project area. For the NAAQS, this will produce extremely conservative results. 46 7.0 AIR QUALITY MODELING ANALYSIS 7.1 Overview of the Modeling Process The air quality modeling included with the PSD application has followed the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD) requirements as outlined in the"Compilation of Air Quality Modeling Guidance for Permits". As such,a modeling protocol has been submitted to and approved by the APCD. The protocol responses are included with this application (see Appendix D). The protocol followed modeling guidance provided by the U.S. Environmental Protection Agency(USEPA)in their "Guideline on Air Quality Models" (including supplements), the National Park Service's "Permit Application Guidance for New Air Pollution Sources" (Bunyak, 1993), the Federal Land Managers'"Air Quality Related Values Workgroup(FLAG)Phase I Report"(December 2000), and the "Interagency Workgroup on Air Quality Modeling (IWAQM) Phase 2 Recommendations"(1998)as well as the APCD modeling guidance found in the"Compilation of Air Quality Modeling Guidance for Permits",dated December 31, 1998,with recent updates, and APCD guidance on Long-Range Transport Model Selection and Application (May 21, 1999). 7.2 Goals of the Air Quality Modeling Analysis The objective of the modeling was to assess the potential air quality impacts from the RMEC proposed modification over a geographic area of interest where potentially significant impacts may occur. Modeling of ozone(O3)was not performed,as no suitable atmospheric dispersion model exists for this pollutant. Impacts from operation of the facility were compared to the following: Table 7-1 Modeling Criteria Summary Air Quality Criteria NO2 PM1p CO PSD Modeling Significant Impact Analysis ✓ ✓ ✓ PSD Monitoring Significant Concentration Analysis ✓ ✓ ✓ PSD Increment Analysis (Class I and Class II) ✓ ✓ Ambient Air Quality Standards (NAAQS and CAAQS) ✓ ✓ ✓ Class I and Class II Visibility/Regional Haze Analysis ✓ ✓ Analysis of Impacts to Soils, Vegetation, and Water ✓ Class I Area Acid Deposition Analysis ✓ The facility is subject to air quality PSD requirements for NOx, CO, and PM10, as potential facility emissions exceed the significant emission rates for those pollutants.For each pollutant subject to PSD review,the air quality analysis must consider the amount of PSD increment that is available to the new or modified source,as well as the potential amount of increment that the modified source is expected to consume. Since there are no PSD increments for CO or O3,only �.h 47 NO2 and PM 10 were considered in the increment analysis.The PSD increments in Class I and Class II areas are 2.5 and 25 micrograms per cubic meter (ug/m3) for annual NO2 concentrations; 8 and 30 ug/m3 for 24-hour PKo concentrations; and, 4 and 17 ug/m3 for annual PM10 concentrations, respectively. The project site is not designated as nonattainment for any pollutant. However, the Denver PMio nonattainment area is within 50 kilometers of the project site. Therefore, dispersion modeling was performed to determine if the RMEC modification would impact this nonattainment area. The significance ambient concentrations for Class I areas and the significance levels for Class II areas are listed in the following table. The Class I significance levels are not used to assess impacts to Class I areas. Rather,they are used to assess if an increment analysis in warranted for each Class I area. Table 7-2 Significance Values for Class 1/11 Areas Proposed Significant Ambient Concentrations for Class I Areas Annual 24-Hour 3-Hour NO2 0.1 ug/m3 PM10 0.2 ug/m3 0.3 ug/m3 SO2 0.1 ug/m3 0.2 ug/m3 1.0 ug/m3 Significance Levels for PSD for Class H Areas Annual 24-Hour 3-Hour NO2 1 ug/m3 PM10 1 ug/m3 5 ug/m3 SO2 1 ug/m3 5 ug/m3 25 ug/m3 7.3 Existing Meteorological and Air Quality Data Pre-application assessment modeling conducted with the Calpuff model utilized the five (5) years of existing meteorological data derived from Stapleton Airport(Denver)for 1986 through 1990.The data was obtained from the APCD staff and was already in extended CD 144 format. The PCRAMMET meteorological preprocessor, as recommended by the IWAQM Phase 2 Report, was used to process the surface, precipitation, and upper air data. PCRAMMET requires complete data sets of the following variables:wind speed,wind direction,temperature, ceiling height,opaque cloud cover or total cloud cover,surface pressure,relative humidity,and precipitation type. The five years of upper air data includes twice-daily mixing heights. Missing surface and upper air data were screened to identify missing or spurious values, and then edited to eliminate gaps or erroneous values. Surface data such as wind speed, wind direction,and temperature data periods of five hours or less were supplemented by interpolation between the last good hour and the next valid hour of data.Missing data periods of six hours or more were replaced with data from the previous hour(s)from the previous day(s),as discussed with John Vimont of the National Park Service. Missing mixing height data for three days or less was replaced by an interpolated value using data from previous day and next valid mixing 48 height. Missing mixing height data for periods greater than three days was replaced with seasonal moming/aftemoon mixing heights, calculated from the valid data for that year and season. PCRAMMET was run with wet deposition options as required in the Phase 2 Report.As such, the following domain averaged variables are required and were based on values expected in the modeling region: • Precipitation data • Minimum Obukhov length=2 meters • Anemometer height= 6.1 meters • Roughness length= 0.5 meters • Noon time albedo=6 • Bowen ratio=0.0 • Fraction of net radiation absorbed by ground= 0.150 Five years of data were preprocessed with PCRAMMET, which was then used as input into CALPUFF. Air quality data for the project region were derived from the APCD published annual reports and/or the AIRS database for the Northern Front Range AQCR. Data for the most recent available 3 years were used. The APCD was consulted on the appropriate values for background for any pollutants for which data is not available or current, i.e.,NO2 and SO2. 7.4 Site Representation USEPA defines the term "on-site meteorological data" to mean data that would be representative of atmospheric dispersion conditions at the source and at locations where the source may have a significant impact on air quality. Specifically, the meteorological data requirement originates in the Clean Air Act at Section 165(e)(1). Section 165(e)(I)defines on- site meteorology as the collection "of the ambient air quality at the proposed site and in areas which may be affected by emissions from such facility for each pollutant subject to regulation under [the Act] which will be emitted from such facility." This definition and USEPA's guidance on the use of on-site monitoring data,is also outlined in the"On-Site Meteorological Program Guidance for Regulatory Modeling Applications"(1987). The representativeness of the data is dependent upon (a) the proximity of the meteorological monitoring site to the area under consideration, (b) the complexity of the topography of the area,(c)the exposure of the meteorological sensors,and(d)the period of time during which the data are collected.As discussed below,the Stapleton Airport data satisfies the definition of on- site data. The terrain surrounding the proposed facility is illustrated in Figure 7-1.The facility is located within the South Platte River drainage in Weld County. Weld County is predominantly grassland and irrigated farmlands. Elevations in the project region vary due to the low rolling prairie type terrain. The elevation of the project site is approximately 5000 feet amsl. The 49 IC/ r -31s--b—S-1-.� 'Nis i ( , ) .-- x �_ Q„ '- r e fix ` 31 . c , f. l �f Site Location %,,{ kes Na k ¢' 1 6 '‘,s......../ 75 72 • T ,M __ i , C‘s.....,\ � •. ' trek�at � f , c Web Res it 4 IP iv N Rocky Mountain Energy Center Modification Application Figure 7-1 Surrounding Terrain terrain rises gradually to the south, as illustrated by the elevation contour lines and the north- south orientation of the small streams,which originate to the south of the facility. The attached windrose (Figure 7-2) of Stapleton Airport data from the APCD indicate a consistent wind pattern with a predominant wind direction from the south. This flow is indicative of the influence of the South Platte River drainage. The same orientation of wind flows is also expected at the proposed project area.Additionally,the meteorological boundary layer characteristics of surface roughness length, albedo, and Bowen ratio are expected to be similar between the two sites.Elevations between the two sites are within a few hundred feet of each other, so ambient temperatures are also expected to be similar. Representativeness has also been defined in the "Workshop on the Representativeness of Meteorological Observations" (Nappo et al., 1982) as "the extent to which a set of measurements taken in a space-time domain reflects the actual conditions in the same or different space-time domain taken on a scale appropriate for a specific application."Judgments of representativeness should be made only when sites are climatologically similar,as the project site and Stapleton Airport station clearly are. Representativeness has also been defined in the PSD Monitoring Guideline as data that characterizes the air quality for the general area in which the proposed project would construct and operate. The same large-scale topographic features that influence the Stapleton Airport station also influence the proposed project site in the same manner.As stated earlier,the met data set was obtained from and approved for use by the APCD,and has been used in other modeling studies in the regional areas east of the Rocky Mountains within Colorado. Representativeness of the met data is based upon the APCD analysis of the following parameters: • Aspect ratio of terrain, • Slope of terrain, • Ratio of terrain height to stack/plume height, and • Correlation of terrain features to prevailing meteorological conditions. 7.5 Background Concentration Background air quality values are delineated in Table 4-1. For pollutants with maximum modeled ground-level impacts greater than USEPA-defined significance levels(see Table 7-2), modeled concentrations will be added to these representative background concentrations to determine compliance with the AAQS. 7.6 Auer Land Use Analysis The areas surrounding the project site can be characterized as predominantly rural. Areas within a three km radius of the project,are predominately undeveloped prairie or farmland with small areas of residential development,mostly in the immediate vicinity of the small town of Hudson, Colorado. In accordance with the Auer land use classification methodology(USEPA "Guideline on Air Quality Models"), land use within the area circumscribed by a three km radius around the modified facility is greater than 50 percent rural.Therefore,in the modeling analyses supporting the permitting of the facility, rural coefficients were assigned. This is consistent with the determination made for the existing facility PSD permitting and modeling. 50 NM Nair RR Noreen,1id2-YWTlh1.YI&I1tUGPI IN It atm.CC • __r___- • • • _ _,_ MO ` Mn • I en • J • I • 1 Ts I • I I I I I I I iaWTT-'-"-- r F MIT I I I I • 1. II 11 • •' r I. • et Midlow Emil `II NOM MT Ca4CMa IT,l1 Yl ne WIIIIe Nncla u.nw Inhen.*cnl.l hyper! 'W!-'LW I-II. no.WIa ORN LaMNMM at,is T.Y ancbl e.Wti ": RInT/Td NOIY(YO6IRTK umeaen 'We -I 1 tin fRTcnu 2W'-We]' I2anINII!-"IT." WNW Mr Mons r.a ,ab�...n.rree mm.me Rocky Mountain Energy Center Modification Application Figure 7-2 Wind Rose—Modeling Summary 7.7 Air Quality Dispersion Models Several USEPA dispersion models are proposed for use to quantify pollutant impacts on the surrounding environment based on the emission sources' operating parameters and their locations. The models used for the air quality analysis included the Building Profile Input Program(BPIP,current version 95086),the Industrial Source Complex-Short Term Version 3 (ISCST3, current version 02035)), CTSCREEN (current version 94111), the long-range CALPUFF model (run in screening mode), and the VISCREEN visibility model (current version 88341). These models, along with options for their use and how they are used, are discussed below. These models were used for: • Comparison of Impacts to PSD Significant Ambient Impact Levels • Comparison of Impacts to Monitoring Significance Thresholds • PSD Class I and Class II Increment Consumption • Compliance with NAAQS and CAAQS • The impacts to Air Quality Related Values in Class I and Class II Areas Simple, Complex, and Intermediate Terrain Impacts For modeling the project in simple,complex,and intermediate terrain,the ISCST3 model was used with the hourly meteorological data from Stapleton Airport for 1986 through 1990. The ISCST3 model is a steady-state,multiple-source,Gaussian dispersion model designed for use with stack emission sources situated in terrain where ground-level elevations can exceed the stack heights of the emission sources.The ISCST3 model requires hourly meteorological data consisting of wind vector, wind speed, temperature, stability class, and mixing height. The model assumes that there is no variability in meteorological parameters over a 1-hour time period, hence the term steady-state. The ISCST3 model allows input of multiple sources and source groupings eliminating the need for multiple model runs. Complex phenomena such as building-induced plume downwash are treated in the ISCST3 model. The ISCST3 model was selected due in part to the lack of varying terrain surrounding the project site and is one of several models that are recommended by the USEPA for such evaluations. The ISCST3 model is capable of calculating pollutant concentrations in intermediate terrain.Intermediate terrain is defined as terrain between stack top and final plume height.In calculating pollutant concentrations in intermediate terrain,the model will select the higher of the simple and complex terrain calculations on an hour-by-hour,source-by-source and receptor-by-receptor basis. In addition, the ISCST3 model is preferred for this application because it incorporates algorithms for the simulation of aerodynamic downwash induced by buildings.These effects are of importance because many of the emission points may be below Good Engineering Practice(GEP) stack height. Technical options selected for the ISCST3 model are listed below.Use of these options follow the USEPA's (1986, 1987, 1990, and 1994) modeling guidance, APCD modeling guidance, and/or sound scientific practice. An explanation of these options and the rationale for their selection is provided below: 51 • Default option (includes final plume rise except for building wake downwash, stack-tip downwash except for Schulman-Scire[SS]downwash,buoyancy-induced dispersion except for SS downwash, default wind profile exponents, default temperature gradients, and calm processing via EPA policy); • Anemometer height= 10 m; • Rural dispersion parameters; and • Elevated receptor terrain heights option. The ISCST3 default options will be used as recommended by the Colorado guidance.The final plume rise option does not consider the possible effects of gradual plume rise on ambient concentrations during the rising phase of the plume downwind transport.Gradual plume rise is recommended by USEPA (1986, 1987, 1990, 1994)when there is significant terrain close to the stacks. The only significant terrain feature noted would be the Rocky Mountain foothills region, which lies due west of the site approximately 30-34 miles. Buoyancy-induced dispersion, which accounts for the buoyant growth of a plume caused by entrainment of ambient air,will be included in the modeling per USEPA/APCD guidance and because of the relatively warm exit temperature and subsequent buoyant nature of the exhaust plumes. Stack- tip downwash, which adjusts the effective stack height downward following the methods of Briggs (1972) for cases where the stack exit velocity is less than 1.5 times the wind speed at stack top,was selected as per USEPA/APCD guidance. As previously mentioned,based on the land use classification procedure of Auer(1978),land use within the area circumscribed by a three km radius around the proposed facility is greater than 50 percent rural. Therefore, in the modeling analyses supporting the permitting of the facility, rural coefficients were assigned. The calm processing option allows the user to direct the program to exclude hours with persistent calm winds in the calculation of concentrations for each averaging period. This option is generally recommended by the USEPA (1986, 1987, 1990, 1994) for regulatory applications.The ISCST3 model recognizes a calm wind condition as a wind speed less than or equal to 1 meter per second and a wind direction equal to that of the previous hour(a wind speed of 0 m/sec is used in the ASCII meteorological data file).The calm processing option in the ISCST3 model will then exclude these hours from the calculation of concentrations. Ambient Ratio Method NOx to NO2 chemical transformations evaluations, such as the ARM procedure will not be used,except as follows.No chemical transformations were used when comparing NOx impacts to the NO2 modeling significance levels.Chemical transformations may be used if the proposed source has a significant impact and a cumulative impact analysis is required to show compliance with the NO2 PSD increments or AAQS. For receptors less than 50 km from the proposed source the ARM default value of 0.75 will be used to convert NOx to NO2. For receptors greater than 50 km from the source,we understand that the APCD will still allow use of the ARM default value provided that the NOx impact values were derived from ISC3 in flat terrain mode. As an alternative, modeling staff supplemented the ISC3 analysis with 52 evaluations derived from Calpuff Screen per IWAQM Phase 2 Report. Good Engineering Practice Stack Height and Downwash ISCST3 can account for building downwash effects. Stack locations and heights,and building locations and dimensions will be input to BPIP.The first part of BPIP determines and reports on whether or not a stack follows GEP guidance or is being subjected to wake effects from a structure or structures. The second part calculates direction-dependent "equivalent building dimensions" if a stack is being influenced by structure wake effects. The BPIF output is formatted for use in ISCST3 input files. In accordance with APCD modeling guidance,the final modeling analyses will also include the following materials: • Plot plan showing emission points,nearby buildings(including dimensions),directions of cross-sections,property lines,fencelines,roads,and Universal Transverse Mercator(UTM) coordinates; • BPIP input and output files on diskette; • Table showing the buildings identifiers in the BPIP run(s)and plot plan;and US Geological Survey (USGS) 7%-minute (1:24,000) map(s) showing the facility and all maximum impact locations. Building downwash effects will not be simulated in assessing impacts beyond 50 km,as in the Class I and sensitive Class II impact analysis. Building downwash is believed to be insignificant at such distances, and as such will not be used in the Calpuff modeling runs. Good Engineering Practice Stack Height Evaluation Buildings or structures located close to emission sources may cause downwash of the exhaust plumes resulting in very high pollutant concentrations close to the emission source. The potential for downwash effects was evaluated to assess if close-in ambient air impacts have the potential to exceed'applicable ambient air quality standards. Evaluation of building downwash on adjacent stacks was performed to ensure that stack source heights were not at or below Good Engineering Practice(GEP)heights. The formula for GEP height estimation is the following: Hs=Hb+ 1.50Lb where, Hs- GEP stack height, Hb-Building height, Lb-The lesser building dimension of the height, length, or width. Based on an evaluation of the HRSG stacks and the corresponding facility structures, it was determined that GEP stack height calculations were necessary. To determine whether or not a structure potentially affects pollutant dispersion from a nearby emission source, EPA provides specific guidance. The guidance states that, if a structure is located within a certain distance from the emission source (stack), downwash effects on the 53 dispersion of stack emissions must be considered. The distance criteria are the following: - The emission source is within five times the lesser of the structure height or width when the source is downwind of the structure. - The emission source is within two times the lesser of the structure height or width when the source is upwind of the structure. - The emission source is within one and one-half the lesser of the structure height or width when the emission source is adjacent to a structure,regardless of the wind flow trajectory. Based on an examination of the facility plot plan and proposed stack heights,it was determined that the stacks would not be GEP heights design. Thus, an assessment of potential impacts from downwash was made. Figure 7-3 illustrates the location of the emission stacks and the structures used in the downwash analysis. The coordinates of these structures were identified from the computerized facility plot plan. The building dimensions used in the modeling analysis are listed in Table 7-3. Table 7-3 Building Dimensions for RMEC Air Quality Modeling Building Name Building Ht(m) Building Width(m) Building Length(m) Cooling Tower 10.67 14.6 219 Administration Bldg 12.19 27.4 46 CT Chem Bldg 3.66 6 9.4 HRSG(1-2) 28.04 12.2 32 New HRSG 28.04 12.2 32 Air Intakes(1-2) 24.38 13 13 New Air Intake 24.38 13 13 Combustion Turbine(1-2) 8.23 11 11 New Combustion Turbine 8.23 11 11 Water Tanks(1-2) 10.36 10 10 Demin Tank(1) 12.19 8 8 SteamTurbine(1) 14.33 8 11 The stack locations,stack heights,and building locations and dimensions were input to EPA's Building Profile Input Program (BP1P). BPIP is divided into two parts. The first part is designed to determine and report on whether or not a stack follows GEP guidance and is being subjected to wake effects from a structure or structures. The second part performs the "equivalent building dimension" calculations only if a stack is being influenced by structure wake effects. The program's output was input directly into the ISCST3 model input runstream. Receptor Selection Receptor and source base elevations were determined from USGS Digital Elevation Model (DEM)data using the 7'h-minute format(i.e.,30 meter spacing between grid nodes).The DEM data files were obtained from either the USGS.The receptor files are included on compact disk (CD). One 10-meter spacing DEM file was also identified and used in the analysis. As stated later, no maximum impacts occurred on this DEM data set, so the 10-meter resolution DEM 54 I • New Location of Aux Boiler 4437750 m . - • J O o . 4437700 - • n n n • I4437650 - New Turbine/HRSG 8 • • 4437600 • - • 4437550- • - I I 534500 534550 534600 534650 534700 Rocky Mountain Energy Center Modification Application Figure 7-3 Building Configuration-Modeling Analysis data set was not used. Cartesian coordinate receptor grids will be used to provide adequate spatial coverage surrounding the project area for assessing ground-level pollution concentrations,to identify the extent of significant impacts, and to identify maximum impact locations. Grid spacing will conform to the APCD guidance (Section 7.3 Receptor Networks). A three-dimensional receptor grid extending 15 km from the emission sources was used to identify pollutant concentrations. The grid was defined as follows: • Coarse grid spacing at 450 meters • Refined grid spacing at 30 meters • Fenceline grid spacing at 30 meters • Downwash grid spacing at 30 meters Elevations were determined from 7.5 minute USGS Digital Elevation Model (DEM) data which has 30 meter spaced grid points. Figure 7-4 illustrates the coarse grid receptor spacing. Figure 7-5 depicts the fenceline and downwash grids used,while figure 7-6 shows the refined grid spacing about the maximum impact location(s). 7.8 Analysis Scenarios Load Screening Pollutant emissions to the atmosphere from the proposed facility will occur from combustion of natural gas in the combustion turbine. In addition, the HRSG has the capacity to duct fire natural gas. Emission rates were provided by RMEC and are based on vendor data and additional conservative assumptions of turbine and HRSG performance. Turbine/HRSG emissions and stack parameters,such as flow rate and exit temperature,exhibit some variation with ambient temperature and operating load. In order to calculate the worst-case air quality impacts, a screening analysis (i.e., load screening)was performed to evaluate each operating scenario(based on operating load with and without HRSG firing and atmospheric conditions) to predict the worst-case facility configuration on a pollutant-specific basis. In the modeling analysis, maximum impacts will be predicted for maximum (100%) and reduced load conditions.In addition,different ambient temperatures will be evaluated for each load condition. Each of these conditions has unique performance characteristics that affect plume dispersion and thus predicted impacts. This analysis is most relevant to analyses for short term impacts.Annual impacts will be evaluated based on expected turbine performance at an ambient temperature representative of the project site.The temperatures and humidity levels selected for the short-term screening analyses will closely reflect the range of possible sites. The results of this screening analysis were used to select the worst-case operational scenarios for the modeling analyses in order to provide maximum operating flexibility.Refined modeling for the permit application was based on these worst-case scenarios. The screening modeling used to determine the worst-case operating condition (i.e., 55 Coarse Grid (450-meter spaced) Receptors 44540 + +)+ + + k+ + t' _ Q �y + ++ + + ��+' \ y d 4 + + + + �„'t`7^�-�{ + } �M ,i 445200r + r+ �+ , « +S N, + 3� 1►,, + ws _ ` , -4- 4450001 @ + . �. y.�• , -" b # c + ,'t+++ �+ ++ i + + J t } + + #- +I. t+ +f+�..'+ + ++ + +i + + + + ++ !++ . - 444800 r + I+ +Ha +++ ++` + 4 i - ++1 + + + 4 li li+c.kd u+ ++ +. d,+ `++ ¶;J1+!Ig1 44480or 12 J \—444400 .� .� it • ! -- Cl) EE +)+ + +}++ + + + + 4 + + +� + ++�+ R� +fit+k., � +� � + r.( +, ; a CS) 444201. 0 4440001 . � �t� .r 36 ..- + A. th 443800r � + ,MI � i 443600 —.} 9 4434000 „ + *J w iii + + + + so 443200 r++IF� +rY°p+ ►� +y�1 �. + i ii7fi F�j t1 'I+S:rf'' !Y"� � J �` >v :1 1 4430000 1+ 4- + ' ' '+ r+'ll ,.,H+ + p�,,,l f'4 - 1,4 r 4428000 �, +C ly-A+z+`5 \i++ _°`kt )-cif ` t• ._ 525000 530000 535000 540000 UTM Easting (meters) A^ Sources: ' v Base Map: Greeley 1:100,000 Metric Map �00 8000 DEM Data: Hudson, Keensburg, Klug Ranch, and Milton Reservoir 1:24,000 DEM Files(30-meter) Scale: 1"=4000 meters Rocky Mountain Energy Center Modification Application Figure 7-4 Coarse Receptor Grid Downwash/Fenceline (30-meter spaced) Receptors-r 4438800 + ++++ f` / !r!+++++++++++++++ + ++++`r' i f+++++++++++++++++++++- + - +++ i' �'r�. ,i:3. +++++++++ +++ +++ ++ ++ ++++++++++- ' + + +• • '+� '+� i +++++++++ +++++++++++++++ ++++ *++++++++++ +++- ++ +� +++++ � ` ++ +++++++++++++++++++++++++++ - - ++++++++++++- �+++ 44386'' ;�''� '+++++++ +++ +++'++++'++++++++++++++'+++ ++ + +++++ +++ -++ '++ +�++++++++++ + ++++++++++++++++++++++++++++++++++++• + ++ 4438400 ++++' ++T , ++++++ +++++++++++`+++4+ ++++++++++`++' ++ _ ++++ +++++++++ ! ++ ++4.4 +++`++++++. +++++-++++++ 4-++ #+4+ +++++++++ I +++ ++ +++++' +++++++++++ + ++4+ +++# +++'+++ + ++++++4- ++++++++ + �, +4+♦ 4++ +4 + ! +++ ++ . + ++++++++++++ -4+#+++' + co 4438200- ++++ +++ ++ + ' ++ + ++++++++++++ . ++++a• + - 1_. +++++ +++ + + , ++ +li +++'++++++++++++++++++ ..++ W +++++ +++++++' + +++++++ + 4.4 a) ++++++ +++++' + r +++++++ +++++ + ++++++++++ . +++ ++ ++++++ ++++ +++++++++++- +- ++ EE 4438000- +++++++ ++++ +++++ . ++ - +++++++++++ ( - - ' ��:+++++ ++++ + +++++++++++++\ . +++++++++++++ \ "'+ 4 ++++ ++ ++ t� ++++++++++++++'� ++++'+f' +++++ ++ ++ ++ ++++++++++++++ C 4437800 +++++++++++++++ i �!. �. . +++++_ ++++++k+$ ' + +++++++. +++ -% - - 2 -. '++++ 4 +++++++++-? + L ++++ +• ' ' ,` +++ +++ +++++.' O '++ +++++++++++ '' +1 ' ' ■ • :+4+ +4+ ++ }+++.' ++ Z 4437600- ++++++++++++++ i + '++++ ++++ ++++++++ ++ ++++++++++++++ � C ++++++++++++++ +++ +++ +++++++- ++ C +#++++++++++++ i +++ +++ ++++++•, ++ ++++++++++++++ + +++ ++ ++4.44 ++++ +++++,++++++- ++ i+++++++++++++ ' + ++ . + ++++ +++ ++++++• ++ D 4437400- +++}{++}++}+++++}+++++++++'₹++ :,•' , �` -yam+�+++++ ++'++++ +++ ++++++++++++,+++++:- Y�• +}`}}}IIII + +++++ +++++ +++ ++++++++ + +++++++++++++ + + �, �iii++++++ ++++ ++' +++++ +++++• ++ ++++++++++++++ + ++ h 1�6++++++ +++++ +++ ++++ +++++++-, ++ +4+4+44+++++ -' -;n ++++++ ++++ . ++ .+++ +++++++ 4437200 + 1, l +++++ +++++ +++ +++ +++++. "++ _ +++++++++++ ++++ ++++ +++ +++ ++++ + �.++ #i++++++##+ ++++ +++++ ++++ ++ +# ++.+++ ' ++++}b#4 ++++ +++++ ++++ ++++ +++ +� +w,. + + +++ +++ +++++ ++++ +++ ++ ++ +- + ++++++ -,_ V +++ +++++ .++++ ++++ ++ " + 4437000 ++ +++++ �' � -'/' ++++ ++++++ ++++ ++++ ++ V+++++ ++4 ++++ .+++ ++++ ++ ,.++ �- ++++ ++++++ +++' +++ + .. + ++++++++++ / ++++ ++++++- +++ - +++ +• + ++++++++++/ + ++++ ++++++`. +++' ++ +, +++++++++ :- + + +++ +++++++ ++++ ++ + 4436800 ++++++++ + +4+ ++++. +++++++++ +++++++++ +++++ +++++t 1 - ++++ 533600 534000 534400 534800 535200 535600 UTM Easting (meters) TN Sources: Base Map: Keensburg 1:24,000 Topo Map MIIIII0 600 DEM Data: Keensburg 1:24,000 DEM File(30-meter) Scale: 1"=400 meters Rocky Mountain Energy Center Modification Application Figure 7-5 Downwash/Fenceline Receptor Grid Fine Grid (90-meter spaced) Receptors +++++ +++++++++Rkwar 4441011 ++ +++++S++++++++++ + vT ++ ++++fr++++++++++ + ++++++ ++++++++++ +++ ++++ +++++++++ A • { { +++h+++++.++++ r��,, +++ ++++++++++++++:+ +++N+y) . f -ff+++++. ++++++ h', +++ +t+2+}t.,₹..₹i,++,+ ++++++[f . AL- _ 4440500 +++ ++++++++++++ +++++ + '++ +++++ + +++++ ++++++++++ ++++ +++ .\ +++ ++++-+++++++ +++++ + ++++++ ++++++ +++++++++ ++++ ++++ +++ ++++}+++++++ + +++ ++ ++++++ ++++++ +': +++++++++ +++ +++++++ - ++++++ ++++}++++++ +++ + ++++++ - ++++ + .\ + +++++++++ + ++++++++ +++ ++ F++++++ .a ++ + ++++++++ .+++ .++� ++ . ++++++. ++++++++ 4440000 +++ + �.' +++++.. 4-_, +, + .++ , ++++++++ ++ +++1 ++-++ ++++++ +++++++ ++ f.� y. + -Y ai iiy;i +++ ++++Ff + +++ ',.' f+ +++ . ++++ ++++++++4�+ ++++♦ '-> 4 +++ ++++ +++++ +++ + +++ ++++++++++ +++ --r- -.0g sx ++++++++"< ++ ++++ ++ + +++++++++ � +++ talitaL- ++++++ ++++++++-}++ ++++ +++ + ++++++++ " ' ! + ++ +++ ,, i. + +++1.7 +++++++-+ ++1++++ ++++ ++ - ++ !~1+++++ ++ ++++ I.. 443950 . +++rail ++++++++++ +++++ +4 �' ++++++ +++ +4+ +4 + ++++ ++++++++++ +yA - ++++ ++++ +++++ ++++ ' ++++++ +++++++ +++++++++ ++++ .++++ +++++++++++ ' ++++++++ 443900i t +++++ ++++++++ ++ .++++ +++++ ++++++ W+++++++ _ iA +.+ _3.3.}..₹.₹ +.++.++ �'l Cl) - + +++ +++ +++ / !,'�-' + +++++++++ ++ L ++++++++ +++4 4 ++++ / +++ -0 ++++++++ ++++ + +++++ ,, 1/ ++++ CD 443850. ++++++++ ++++ ++++++ ,f +++++ ++++++++ ++++ + +++++ E +4+4+4+4 ++++++ + ++++++ + `i +++++ +4+4+4+4 - +++++++ 4 +++ +++++++ +++++++ ++++ ++ ++++++ ,:! 4f Ilk. "' +++++++ C 443800e +++++ ++ ++++ �7 + ; ++++++ ++++++++ ++++ Z443750f ++++�J +++++++++ le '� +++ ' ++++++++++}+ ++++++ H 4437000 ,r + ++++++++++ + i R etrq0 +++ +++ f ++++++++++++++ ++ ++ ++++++++++++++ +++++�y + ++ms�µy++++ ++ + + 4436500 ' + +++ ++++++++ ++++++ • ++ +e+ ++ ri + ++ ++ ++4 ++++++++++++++++ ++ +++ +++++ 07 '+ + + +++ ++ ++++++++++++++++ ,+ + ++++ ++++++ + +++++++ +++++++++++++++ + ++ . ++++++ + 4436000 +52 ++++++ +++++++++++++ ++ +++ ++++++ +;+ :�+`4+++♦ ++++++++++�1 or- + +-`i+++++ ++ + - . ++++++++ � 4435500 '+++ ++++++++++++ ++ ++ + ++++ ++++, + +++++++++ + 1 / :, +++ +++++++++++++++++ ++ + +++ ++++ + ++++++++4 " N MN, ++++++ +++++++++++++++++ ++ +++ +++++ pY; +++++++++++ ♦♦♦ ++++++ +++++++++++++++++ ++ 0 ++++'++++++ * +++++++++++ ++++++ +++++++++++++++++ ++ , + ++1+ + +++++++++++ ++ +++++++++++++++++ +++�+++}++ ++ t+ +++++++++++ • 4++ ' 4435001 ++++++ ++++++++++4 +},+++ +++ ++. ir f ++ �yr ++++++ ++ +++++ +++++ ++++++++0,- j +++ ++++ ++ Al +++++ ++++++++++ +++ +++++ +.! +-j ++++++ ++++++ 531500 532000 532500 533000 533500 534000 534500 535000 535500 536000 536500 537000 537500 UTM Easting (meters) TN Sources: Base Map: Greeley 1:100,000 Metric Map �00 2000 DEM Data: Keensburg 1:24,000 DEM File(30-meter) Scale: 1"= 1000 meters Rocky Mountain Energy Center_ . Modification Application Figure 7-6 Fine Receptor Grid configuration which produces maximum facility impacts) will use five years of NWS meteorological data and a nested receptor grid as described above to determine the worst-case source configuration. This worst-case operating condition was then carried forward in the remaining air quality analyses. No further modeling was performed for those operating conditions that did not result in worst-case impacts. Significant Impact Analysis The NSR Workshop Manual contains an extensive listing of significant impact levels (SILs) that must be evaluated as part of the air quality modeling effort. It should be clearly noted that Class I SILs do not necessarily refer to or apply to ambient air quality impacts. In many instances, these SILs merely establish action thresholds within the permitting process. i.e., a source may have impacts less than the significant impact levels and still be considered significant for a Class I area. For example, the 1 ug/m3 (24-hour average) SIL applied to sources located within 100 km of a Class I area is not used to establish the significance of the sources' impacts, but rather to determine if the proposed sources' emissions would be considered"major"for purposes of PSD review and thus,require an increment analysis. An analysis of impacts to Class I AQRVs is automatically made, regardless of the significance levels. Such distinctions are clearly noted in the impact section. Initially,only the proposed project sources were modeled to determine maximum ground-level concentrations of criteria pollutants. Impacts were determined for I-hour and 8-hour CO averaging periods, 24-hour and annual avenging times for PM1o, and annual average concentrations for NO2.The results of these modeling runs were used to identify the extent of significance areas for NO2, PM10, and CO. The radius of impact was determined from the receptor furthest from the facility which was above significance. This maximum distance was then used for all subsequent analysis. PSD Increment Consumption Analysis Increment consumption of PM10 and NO2 were evaluated if impacts from the modification are above PSD modeling significance levels.As discussed in Section 8,all modeled impacts were less than significance levels. Thus, no increment modeling was performed. If modeled impacts triggered an increment analysis,the resulting concentrations would then be compared to the appropriate PSD increments to assess compliance. Additionally, the impact from the proposed new source alone will be compared with 75%of the PSD increment to demonstrate compliance with the State standard of 75%increment consumption restriction for major sources (Regulation No. 3, Part B §VII.A.5.a). Comparison of Impacts to NAAQS and CAAQS To assess compliance with the AAQS,the impacts resulting from the proposed project will be added to background levels of pollutants described earlier if the modeled impacts from RMEC are above significance levels. The applicant will also rely upon guidance provided in the APCD's Technical Guidance Series:Air Quality Modeling—Emission Inventories for Nearby and Other Background Sources (September 30, 1997). Where the background data does not contain specific,recently permitted sources,these sources will be modeled and included in the cumulative analysis..Appropriate background sources to be modeled will be determined in 56 consultation with the APCD.For example,background sources with significant concentration gradients should be included in the analysis. The total pollutant concentrations (modeled project and background source plus background)will then be compared to the AAQS to assess compliance. Pre- and Post-Construction Air Quality Monitoring Requirements The model-predicted maximum impact for each pollutant emitted in significant amounts(i.e., that exceed the PSD significant emission rate)from the proposed modification were compared with the PSD pre-construction monitoring significance levels (i.e., NO2, PM10, and CO). If these values are exceeded, then the applicant will discuss with APCD the need for pre- construction monitoring data. Currently, there is a lack of recent monitoring data from the immediate project area exists,but regional data is available that would be suitable for meeting any PSD pre-construction monitoring requirements as may be triggered. The applicant understands that the decision to require post-construction monitoring is not discretionary as suggested by federal regulations. Further, the applicant understands that the APCD can only exempt a source from post-construction monitoring if the source's impact or the existing background concentration is below the applicable monitoring de minus level. Additional Impacts Analysis The additional impacts analysis is an assessment of the impacts of air, ground, and water pollution on soils, vegetation, and visibility caused by any increase in emissions of any regulated pollutant from the modification under review,and from associated growth.There are four parts of the additional impacts analysis: 1)growth,2)ambient air quality impact analysis, 3)soils,water,and vegetation analysis,and 4)visibility impairment. This analysis will follow EPA's guidance provided in the New Source Review Workshop Manual(October 1990 draft), with the addition of Colorado-specific issues. The growth analysis will quantify the number of new employees,the availability of housing in the area, and associated commercial and industrial growth, and construction related activities and mobile sources. Because the number of new employees,as a result of the modification,is not envisioned to be large enough to result in a quantifiable increase in emissions from residential, commercial, or industrial growth(e.g., less than 5 new employees),the applicant expects only to have to prepare an emission inventory of fugitive dust generated from the construction activities. An inventory of soils, vegetation, and water in the significant impact area was performed. Impacts outside this area were assumed to be insignificant.The analysis of water is a Colorado- specific requirement. All vegetation with any commercial or recreational value within the significant impact area was identified. Similarly,water resources in the significant impact area were identified. Nitrogen loading on these water resources was quantified and compared with available reference levels. A visibility impairment analysis was conducted for scenic and/or important views as identified by the APCD. Only Pawnee Buttes was identified for this analysis. Pawnee Buttes is approximately 103 km north-northeast of the project site. A light extinction analysis was 57 performed for this location using the same methods as in the Class I visibility analysis (i.e., CALPUFF in a screening mode).No background or reference concentration was provided for this view. Therefore, the percent change in light extinction was not quantified. Only the light extinction attributed to the facility under worst-case conditions was quantified. 7.9 Class I and Sensitive Class II Area Impacts Calpine's Rocky Mountain Energy Center is located approximately 82 km east-southeast of Rocky Mountain National Park,and 120 km southeast of the Rawah Wilderness,both which are Federal Class I areas.Rocky Mountain National Park is administered by the National Park Service (NPS), and the Rawah Wilderness Area is administered by the US Forest Service (USFS).A complete Class I Area analysis consistent with the PSD program was conducted for these areas. The nearest Class II area with Class I area PSD SO2 protection is the Florissant Fossil Beds, which lies 142 km south-southwest of the project site. Since the facility will not emit SO2 at levels above the PSD significant emission rate,modeling for SO2 impacts within the Florissant Fossil Beds NM were not performed. An analysis of regional haze and acid deposition was conducted for several sensitive Class II areas. The modeling was conducted consistent with the modeling protocol submitted on May 27, 2005, with additional comments provided CDPHE-APCD on June 23, 2005 and July 7, 2005. CALPUFF Dispersion Model CALPUFF was run in a screening mode to assess the impacts to visibility and acid deposition on nearby wilderness areas. The screening mode of CALPUFF uses a 3-dimensional homogeneous meteorological field for simulating transport and dispersion of pollutants each hour. Worst-case time-averaged ambient impacts are assesses anywhere along a polar ring with a distance and elevation equivalent to the nearby Class I area or sensitive Class II area, as applicable. Five years of hourly surface and upper air data from a single monitoring station are required to required to identify the worst-case impacts when applying CALPUFF in a screening model. This is the same meteorological data set that was used in the February 2002 permit application document and analysis for the Rocky Mountain Energy Center,which was previously approved by CDPHE-APCD. Observations from Denver's Stapleton Airport for 1986-1990 were used in the analysis. The PCRAMMET meteorological preprocessor was used to process the data. Five years of SCRAM surface data was supplemented with precipitation,surface pressure,relative humidity, and precipitation type data from the NCDC SAMSON/HUSWO CD-ROMs data sets. 58 CALPUFF was run with the recommended defaults specified in the IWAQM Phase II summary report. User defined options were specified as follows: • Number of X grid cells=2 • Number of Y grid cells=2 • Grid spacing=200 km • Number of vertical layers=2 • Cell face heights=0, 5000 The land use parameters of surface roughness length(Zo) and leaf index were calculated following guidance provided by Ms. Doris Jung of CDPHE APCD. Using a topographic map which also shows various land use types(e.g.,forest,urban,etc.)the fractional amount of each land use type was determined along the direct path from the project to the subject Class I or Class II area. The weighted-mean value surface roughness length and leaf index was then calculated for each area and assigned in the CALPUFF input file, as shown in Table 7-4. TABLE 7-4. Land Use Parameters Class I or II Area Land Fraction Zo (m) Leaf Index Use Rocky Mountain Forest 0.34 1 7 National Park. Ag. Ir. 0.57 0.25 3 Urban 0.09 1 0.2 Weighted Average 0.57 4.11 Rawah Wilderness, Forest 0.5 1 7 Island Lake and Ag Ir. 0.5 0.25 3 Rawah#4 Lakes Weighted Average 0.63 5.0 Blue Lake, Crater Forest 0.36 1 7 Lake & Ag. Ir. 0.42 0.25 3 No Name Lake Urban 0.22 1 0.2 (Indian Peaks Weighted Average 0.69 3.82 Wilderness) Upper Bear Tracks Forest 0.34 1 7 Lake(Mt. Evans Ag. Ir. 0.52 0.25 3 Wilderness) Urban 0.14 1 0.2 Weighted Average 0.61 3.97 Pawnee Buttes Ag Ir. 0.5 0.25 3 Range 0.5 0.05 0.5 Weighted Average 0.15 1.75 59 Dry and wet deposition for individual chemical species as follows: Chemical Species Dry Deposited Wet Deposited SO2 gas phase 4 SO4 particle phase 4 NOx gas phase HNO3 gas phase 4 NO3 particle phase 4 PM to particle phase 4 CALPUFF also requires domain averaged background O3 and ammonia(NH3)concentrations for the Mesopuff II chemistry algorithm. For O3,the background concentration of 60 ppb was used. For NH3,a domain average value of 44 ppb was selected based on APCD Guidance on Long-Range Transport Model Selection and Application(May 21, 1999) and approved in the modeling protocol. Figure 7-7 illustrates the location of the nearby Class I areas,sensitive lakes,and scenic views. For each Class I area,receptors were placed in three polar receptor rings at distances equal to the nearest, middle, and farthest extent of the park or wilderness boundary, as shown. Receptors were spaced at one-degree intervals along each ring. A single elevation value is assigned to all receptors on a given ring. The selected elevation value is based on the average elevation of the arcs that extended through the Class I area being modeled. A single receptor ring with a radius equal to the nearest distance to an identified lake within each wilderness was created for the sensitive lakes in each wilderness area(not shown in Figure 7-7) for the determination of change in acid neutralization capacity(ANC). Two of the lakes are located in the Rawah Wilderness: Island Lake and Rawah#4. Three lakes are located in the Indian Peak Wilderness— Class II area,just south of Rocky Mountain National Park: Blue, Crater, and No Name. Two lakes are located in the Mt. Evans Wilderness Area— a Class II area:Upper Middle Bear Tracks and South Lake. Booth Lake and Upper Willow Lake are both located in the more distant Eagles Nest Wilderness, a Class I wilderness area. A single receptor ring was also created for calculating regional haze impacts at Pawnee Buttes(receptor ring not shown in the Figure). The Rocky Mountain Energy Center is located in the center of the map.Table 7-5 presents the distance and elevation of each receptor ring from the proposed combustion turbine. Since all high elevation lakes were run with a single CALPUF model run, the corresponding receptor ring number for each lake is also shown in the Table. Results identified in the Calpost output file can be identified with each sensitive lake through the use of the corresponding ring number. Following the IWAQM screening method, the maximum concentration, deposition rate or change in light extinction for each pollutant, for each distance averaging time modeled is selected for comparison with the appropriate AQRV. 60 FIGURE 7-7. Calpuff Class I Area Receptor Locations • 4550 .,•., Rawah • Wildernessr''• ...,....._..,,...,,.. .. ,,,.__W-•W_._W.........,Pawnea Btitte� - 1 x • .'..w..•.�• Rocky Mtn �, 4450 u'�-».�� Nat'l Park r W C c` I • o rm®mej Rocky Mtn • - Energy Center 4400 n apper nnx . ` eUpperA &sear Track3. d 4350 _.._..._.a...... 4300 ... . 400 450 500 550 600 650 UTM Easting(km) 61 Table 7-5. Distances and Elevations of Receptor Rings Area Receptor Ring Distance (km) Elevation No. Rocky Mountain Energy Center n/a 0 1514 m (4967 ft) Rocky Mountain National Park na 82 2560 m(8399 ft) 100 2865 m (9400 ft) 118 3612 m (11,850 ft) Rawah Wilderness n/a 121 3254 m(10,676 ft) 137 2683 m(8802 ft) 152 3087 m(10,218 ft) Pawnee Butte n/a 89 1492 m(4895 ft) Island Lake 1 129 3392 m (11128 ft) Rawah#4 Lake 2 133 3497 m(11474 ft) Blue Lake 3 87 3447 m(11310 ft) Crater Lake 4 91 3438 m(11280 ft) No Name Lake 5 94 3608 m(11836 ft) Upper Middle Bear Track Lake 6 104 3536 m(11600 ft) South Lake 7 108 3728 m(12230 ft) Booth Lake 8 153 3499 m(11480 ft) Upper Willow Lake 9 144 3475 m(11400 ft) POSTUTIL Post-processing Options: The POSTUTIL postprocessor was run to calculate the total nitrogen and total sulfur deposition from individual nitrogen or sulfur containing species. It was only used for the deposition and ANC analysis,as it's not necessary for the regional haze analysis.Nitrogen mass is contributed by SO4 (Calpuff tracks ammonium sulfate as SO4),NOx (as NO2), HNO3, and NO3 (Calpuff tracks ammonium nitrate as NO3). Only SO2 and SO4 contribute sulfur mass. Table 7-6 presents the ratio of molecular weights of sulfur to each sulfur-containing species and the ratio of nitrogen to each nitrogen-containing species TABLE 7-6. Ratio of Molecular Weights Sulfur Containing Species Ratio of Molecular Weights SO2 0.500000 SO4 0.333333 Nitrogen Containing Species SO4 0.291667 NOx 0.304348 HNO3 0.22222 NO3 0.452623 62 POSTUTIL also sums wet and dry deposition values to calculate total deposition. CALPOST Post-processing Options: Calpost was used to compute light extinction, and calculate time-averaged deposition rates. The following options were selected for use in the post processing control file. ✓ Method 6: Compute Extinction from speciated PM measurements and user specified RH factors. ✓ Monthly RH factors based upon seasonal values reported in FLAG Phase I guidance document ✓ Modeled species for visibility: sulfate, sulfuric acid nitrate, and fine particulate(PA/110. Following the FLAG guidance for Natural-Gas Fired Combustion Turbines, (http://www2.nature.nps.gov/air/Pemiits/emissions controltech.cfm), the following assumptions were incorporated into the modeling: • 25%of PM emissions are filterable and 75% of PM emissions are condensable. • All filterable PM will be considered elemental carbon (EC). • Condensable PM will be considered either organic carbon (OC) or sulfate. • Sulfate emissions are provided by the applicant. Sulfate(SO4)is emitted at a rate of 1.0 lb/hr. • OC emissions are computed as the difference between the condensable PM and the computed sulfate emissions. PM10 is emitted at a maximum short-term rate of 18.6 lbs/hr. EC was calculated as 25% of PM1o, due to the filterable fraction: EC=0.25 * 18.6 lbs/hr=4.65 lbs/hr The remaining 75%ofPM10 is considered condensable. Condensable PM10= 0.75 * 18.6 lbs/hr = 13.95 lbs/hr Of this, 1.O lbs/hr are SO4; the remaining portion is considered OC. 13.95 lbs/hr— 1.O lbs/hr= 12.95 lbs/hr= OC • -- The modeled amount of PM10 modeled with Calpuff consists of the sum of EC and OC: PM10(modeled)=4.65 lbs/hr+ 12.95 lbs/hr= 17.6 lbs/hr A weighted light extinction efficiency was then applied to the model-predicted PMl0 concentration as applied in Calpost. The weighted extinction efficiency was based upon the following values EC= 10,OC=4,and Soil= 1 (PM:0 is counted as soil). Hence,the weighted extinction efficiency was modeled as: 63 [(4.65 lbs/hr * 10)+(12.95 lbs/hr* 4)]/ 17.6 lbs/hr=5.59 Nitrogen and Sulfur Deposition on Soils Model-predicted deposition of nitrogen and sulfur from the proposed combustion turbine are compared with "deposition analysis thresholds" (DATs) as a method of determining if the impact from the proposed turbine will have an adverse effect upon resources located in nearby Class I areas that may be adversely affect by a change in air quality(i.e., air quality related values). The FLM's have established DATs, which are the additional amount of nitrogen (N) or sulfur (S) within a Class I area, below which estimated impacts from a proposed new or modified source are considered insignificant. DATs are based upon natural background deposition, a variability factor, and a cumulative factor. Background values for both the Eastern and Western United States were determined from the range of deposition values that are both scientifically valid,as well as conservative.A background value of 0.25 kg/ha/yr was established for both N and S in the Western United states. This value represents the low end of the regional range of values that are presented in estimates of regional natural background deposition. Historic natural background values (i.e., before the influence of anthropogenic sources) are difficult to obtain. Hence, models are often used to estimate natural background values. The range of modeled historic deposition values often range+50%or more between various studies for any given area. Hence,a 50%variability factor has been assigned to the natural background deposition values. In developing the 1996 proposal for New Source Review Reform, the U.S. Environmental Protection Agency(EPA)determined that,as long as no individual source contribution exceeds 4%of a Class I increment, it is unlikely that the accumulation of source over time will exceed that increment. The FLMs have applied the 4%value used in the Class I increment significant impact levels to these new DATs. Hence,the DATs for both nitrogen and sulfur(individually)in the Western United States are calculated as: DAT=0.25 kg/ha-yr*(0.5) * (0.04) = 0.005 kg/ha-yr The DAT is deposition threshold,not necessarily an adverse impact threshold. The DATA is the additional amount of deposition that triggers a management concern, not necessarily the amount that constitutes an adverse impact to the environment. 64 Nitrogen and Sulfur Deposition on Sensitive Lakes Lakes and streams differ in their sensitivity to atmospheric deposition of acidifying compounds. Several factors affect lake sensitivity including bedrock geology, soil and vegetation type, hydrologic characteristics, lake chemistry and biology,and precipitation volume. Areas with sensitive lakes and streams are commonly located using maps of bedrock geology. Seepage lakes,lakes that have no visible outlet,are likely to be affected by precipitation,while drainage lakes are likely to be influenced by watershed base cation supply. Seepage lakes are more sensitive to acidification with all other things being equal. The lake water combines many watershed factors that may be difficult to estimate or measure in the field and thus provides a convenient measure of sensitivity. One of many water chemistry parameters maybe used to assess sensitivity. In pristine areas receiving little or no acid deposition, acid neutralizing capacity (ANC) provides a good measure of sensitivity to acidic deposition (U.S. Forest Service, 1989). Acid neutralizing capacity is a measure of the ability of water to neutralize acid inputs. Lakes with a high ANC(≥25 ueq/l)can maintain a neutral pH even with some acidification whereas lakes with a low ANC (<25 ueq/1)will not maintain a neutral pH with acidic deposition. At the request of the Colorado APDC and the U.S.Forest Service,a screening level analysis for deposition induced changes in lake alkalinity was conducted to determine the effects of the proposed combustion turbine on several sensitive lakes in the nearby Wilderness areas. Table 7-7 presents a list of high elevation sensitive lakes selected for the screening analysis. The United States Forest Service,in consultation with the United States Geological Survey,has recommended that the change in ANC be assessed using the ten percent most sensitive ANC measurement(10%ANC). The ANC and watershed acres was obtained from the USFS. The annual average precipitation(meters of equivalent water)was based upon 1961-1990 NOAA cooperative stations and USGS-NRCS Snotel data, as shown in Figure 7-8. 65 TABLE 7-7. Class I and Class II Sensitive Bodies of Water 10% Watershed Annual Wilderness Distance Sensitive ANC Area Precip Area Class (km) Lake (ueq/I) (hectares) (m) Rawah I 129 Island 64.6 125 1.27 133 Rawah#4 41.2 175 Indian Peaks II 87 Blue 21.9 657 0.76 91 Crater 47.4 676 94 No Name 24.5 694 Mt. Evans II 104 Upper Middle 52.1 265 0.76 BearTrack 108 South 65.9 137 Eagles Nest I 153 Booth 84.1 138 0.76 144 Upper Willow 114.1 307 66 O 41/2Ellipprir ca a sr Ulill 4. 1, es.visr0 0 oi-kfrt o a w '' I r- 111," 0 tii r ..-*c., �e D df BDic 0 V i._ t d > Pit ^ ill m ir. Ii n A or x- a NN� g V G 10=0pq—O RC°41: gyl G N coVl in `,g b b u m " S¢ E�^e5 Y3 2 2 2 p D o aUO a e ^*�wu 0 ®®■�■ b & _ oa �� d k l0.QEno t c Le, N N m m c. Ell e4Y^�. yq� vv ® a c O p 00 k o C �2,y>d en ee 1p e, 10:422 °- �®❑®®IE &51 'a9e�$ c°°5 om aig Piz=3 i�. �.min08mCia The screening level analysis used to assess the pH and alkalinity change followed a technique presented by the USFS(January 2000). This technique,recommended by the Forest Service,quantitatively estimates the change in pH on a sensitive water body(i.e.,mountain lake)by incorporating predicted ambient deposition of total nitrogen. Total equivalents of acid deposition over a year that either fall directly into the lake,or are deposited in the catchment flows into the lake are calculated following the screening method. The screening model assumes that all the equivalents of acidity eventually reach the lake,where they titrate the alkalinity. The calculations associated with the screening method are shown below. ANC(o) = baseline ANC for entire lake catchment in eq = W*P*(1-Et)*A*(10,000m2/ha) (eq/106 ueq)*(103) liters/m3) A=baseline lake sample alkalinity in ueq/1 Hdep = acid deposition in eq—[H(s) +H(n)]*W*10,000m2/ha 10,000m2/ha Hs =sulfur deposition in eq/m2/yr=Ds (kg/ha/yr)*(ha/10,000m2)*(I000g/kg)*(eq/16g S) Hn=nitrogen deposition in eq/m2/yr=Dn(kg/ha/yr)*(ha/10,000m2)*(1000g/kg)*(eq/16g N) W=watershed area in ha P=average annual precipitation in meters Et=fraction of the annual precipitation lost to evaporation and transpiration(assume Et=0.33 unless better information is available) Ds= sulfur deposition in kg/ha/yr from all sulfur species (calculated with Calpuff) Dn=nitrogen deposition in kg/ha/yr from all nitrogen species An annual nitrogen and sulfur deposition flux was calculated by CALPUFF as described above. To conservatively calculate change in ANC at each lake,the maximum nitrogen and sulfur deposition rate at the receptor ring with a distance and elevation equal to or near that of each lake was calculated. These values were used in conjunction with the lake-specific values shown in Table 7-4 to calculate the percent change in ANC at each lake. According to the July 7,2005 comments on the modeling protocol received from the CDPHE-APDC,the USFS has established the following thresholds for ANC change in high altitude lakes: • For lakes with ANC 25 and above, a 10% change in ANC • For lakes with an ANC below 25, a 1 ueq/1 change • Lakes with a zero or negative ANC are evaluated against a threshold of"no change". These change in ANC calculated for each lake is compared with these thresholds. Visibility Analysis Visibility impacts,through the calculation of light extinction,are assessed using CALPUFF.CALPUFF is the IWAQM and FLAG recommended model for long-range transport. Since all Class I areas are greater than 50 km from the project site, a coherent plume analysis using VISCREEN was not performed for the Class I areas. 68 The methodology used to calculate the change in light extinction due to the proposed project followed the FLAG Phase I guidance (December 2000). Briefly, this method involves: calculating the reference level (also referred to as the natural background level),then calculating the single-source contribution(i.e.,the contribution due to the proposed facility), and calculating the change in extinction.Reference levels were calculated by quantifying the hygroscopic component,non-hygroscopic component,and Rayleigh Scattering component. The hygroscopic component refers to the component of light extinction caused by sulfate and nitrates as a function of relative humidity.The non-hygroscopic component refers to those pollutants whose light extinction properties do not change as a function of relative humidity(e.g.,organic carbon,soil,coarse particulate,and elemental carbon). Site-specific reference levels and f(RH)values used were obtained from the FLAG Phase I guidance. CALPUFF calculates the natural background level;that value was used in the comparative analysis. The contribution to light extinction from the facility itself was then quantified and compared with the 5%de minimis level. If the contribution from the proposed project does not exceed 5% light extinction,then no further visibility analysis is necessary. Increment Consumption and Cumulative Impacts Increment consumption and cumulative impacts of NO2 and PM lo are quantified for the applicable Class I areas. Concentrations of NO2 and PMi0 were also quantified using CALPUFF. Maximum short-term pollutant emission rates were used for both short-term and annual increments. A cumulative impacts analysis was not performed as impacts were less than screening thresholds (i.e., 4% of the Class I PSD increment). 69 8.0 MR QUALITY IMPACT ANALYSES 8.1 Impacts Analysis This section describes the impacts as calculated from the air quality dispersion modeling described in Section 7.0. All other input and output files are contained on the enclosed CD-ROM disk. All modeling analyses were performed using the techniques and methods as outlined in the modeling protocol submitted and approved by APCD. All new sources, i.e., turbine and HRSG,were modeled in the analysis for comparisons with significance levels,increments and NAAQS. Turbine startup emissions were also used in the analysis for 1-hour,3-hour, 8-hour,24-hour,and annual averaging periods. Only one turbine is expected to be in startup during a 1-hour time period. Load Screening Analyses Modeling was performed with 7 distinct load conditions(as described previously)in order to determine the operating condition that will result in the highest modeled concentrations.The results of the load screening analysis are listed below in Table 8-1. ISCST3 with five years of hourly meteorology was used in the load screening assessment. The maximum modeled concentrations are listed in bold in Table 8-1. Therefore,all additional modeling analyses were performed using the various cases that produced the maximum impact for each pollutant for each averaging period. The emissions used in the modeling assessment also included startup conditions for comparison to both short-term and annual averaging periods. Table 8-1 Load Screening Results for RMEC Case -,D :;E. :N. ;.'GP ,.F: `:B. J- Ambient Dry Bulb Temperature deg F 90 102 90 50 50 3 90 100% 100% 100% 100% 70%no 100%no 70°/0 no Conditions w/DB and w/DB and w/DB and w/DB and PA and no DB and no PA and no PA no PA no PA no PA DB PA DB Unitized Modeling Results for g/s/turb ;D -:E N- GP F B -:J Stack Height meters 53.340 53.340 53.340 53.340 53.340 53.340 53.340 Stack Diameter meters 5.639 5.639 5.639 5.639 5.639 5.639 5.639 Stack Temperature Kelvins 343.0 344.7 343.0 341.3 346.9 349.7 346.9 Stack Velocity m/s 20.422 18.898 19.202 19.812 16.459 21.641 16.459 1-hour ug/m3 4.07419 4.49355 4.44551 4.30505 5.29248 3.57046 3-hour ug/m3 1.81559 1.97701 1.96190 1.91057 2.28074 1.60265 Same as 8-hour ug/rn3 0.91361 1.03334 0.97998 0.95602 1.21311 0.72056 Case F 24-hour ug/m3 0.33450 0.40685 0.40334 0.39198 0.55693 0.27665 Annual ug/m3 0.01043 0.01097 0.01107 0.01103 0.01390 0.00912 Pollutant Modeling Results D E N' GP F B J _ NO2,as NO2.Maximum g/s/curb 3.150 2.898 3.024 3.024 1.638 2.394 1.512 SO2,Annual Average g/s/turb 0.176 0.164 0.164 0.176 0.088 0.139 0.088 CO g/s/turb 5.796 5.292 5.418 5.544 3.024 4.410 2.898 PM,°(excludes H2SO4 mist) g/s/turb 2.218 2.155 2.167 2.155 1.386 1.386 1.386 NO,,as NO2.Annual ug/m3 0.0329 0.0318 0.0335 0.0334 0.0228 0.0218 0.0210 SO2,3-hour Average ug/m3 0.3203 0.3238 0.3214 0.3370 0.2012 0.2221 0.2012 SO2,24-hour Average ug/m3 0.0590 0.0666 0.0661 0.0691 0.0491 0.0383 0.0491 SO2,Annual Average ug/m3 0.0018 0.0018 0.0018 0.0019 0.0012 0.0013 0.0012 CO, 1-hour Average ug/m3 23.614 23.780 24.086 23.867 16.004 15.746 15.338 CO,8-hour Average ug/m3 5.2953 5.4684 5.3095 5.3002 3.6684 3.1777 3.5156 PM".24-hour Average ug/m3 0.7419 0.8766 0.8741 0.8446 0.7719 0.3834 0.7719 PM,, Annual Average ug/m3 0.0231 0.0236 0.0240 0.0238 0.0193 0.0126 0.0193 70 Refined Air Quality Impact Analysis The emission rates used to model RMEC are summarized in Table 8-2. As discussed above, the turbine stack parameters for the cases that produced the maximum impacts were used in modeling the impacts for each pollutant and avenging period. For the annual NO„ and PMio modeling, Case N produced the maximum impacts and will be used in the refined modeling analysis. For S02 for all averages,it was case GP. Case N will be used for 1-hour CO modeling with Case E representing 8-hour CO and 24-hour PMto. The complete modeling input for each pollutant and averaging period is shown in Appendix B. The model receptor grids were derived from three-second DEM data. Initially,a 450-meter coarse grid was extended to ten (10) kilometers from RMEC in all directions. A 30 meter resolution downwash receptor grid was used within approximately 0.5 km of the site. Thirty-meter refined receptor grids were used in areas where the coarse grid analyses indicated modeled maxima for each site plan would be located. Receptors for the refined modeling analysis were from USGS DEM data for four 7.5-minute quadrangles. The nested receptor grids contained a total of approximately 11692 receptors. Table 8-2 ISCST3 model in ut data: source emissions for refined modeling (emissions in g/s). New Unit NO,; SO2 CO PMto One-Hour Average: Turbine/Duct Burner N/A N/A 113.65 N/A Three-Hour Average: Turbine/Duct Burner N/A 0.176 N/A N/A Eight-Hour Average: Turbine/Duct Burner N/A N/A 46.24 N/A 24-Hour Average: Turbine/Duct Burner 4.05 0.176 N/A 2.34 Annual Average: Turbine/Duct Burner 3.25 1.64 N/A 2.036 Note: I.CO 1-hour emission rate assumes turbine is in startup/shutdown.24-hour NO,used in Class I modeling. Turbine Startup Facility impacts were also modeled during the startup of one turbine to evaluate short-term impacts(1 hour and 8-hour CO) under startup conditions. Emission rates used for this scenario were based on an engineering analysis of available data,which included source test data from startups of the gas turbine at a similar Calpine facility. A summary of the data evaluated in developing these emission rates was shown in Appendix B. Turbine exhaust parameters for the minimum operating load point(70 percent)were used to characterize turbine exhaust during startup. Startup impacts were evaluated for both the one- and 8-hour averaging periods using ISCST3. Emission rates and stack parameters used in the startup modeling analysis are shown in Table 8-3. 71 Table 8-3 Emission rates and stack parameters used in modeling analysis for startup emissions impacts. Parameter Value Turbine stack 347.0 deg. K temperature Turbine exhaust velocity 16.46 m/s One-hour average impacts NO. emission rate N/A SO2 emission rate N/A CO emission rate 113.65 g/s PMio emission rate N/A Eight-hour average impacts* NO. emission rate N/A SO2 emission rate N/A CO emission rate 46.24 g/s PMio emission rate N/A *Eight-hour impacts use stack parameters from turbine screening results Case E. Preconstruction Monitoring To ensure that the impacts from the RMEC modification will not cause or contribute to a violation of an ambient air quality standard or an exceedance of a PSD increment, an analysis of the existing air quality in the area of RMEC is necessary. Colorado APCD rules require preconstruction ambient air quality monitoring data for the purposes of establishing background pollutant concentrations in the impact area. However,a facility may be exempted from this requirement if the predicted air quality impacts of the facility do not exceed the de minimis levels listed in Table 8-4. Table 8-4 APCD PSD preconstruction monitoring exemption levels . Pollutant Averaging Period De minimis Level CO 8-hr average 575 µg/m3 PMio 24-hr average 10 µg/m3 NO2 Annual average 14 µg/m3 SO2 24-hr average 13 µg/m3 A facility may,with the APCD approval,rely on air quality monitoring data collected at existing monitoring stations to satisfy the requirement for preconstruction monitoring. In such a case, in accordance with the USEPA PSD guideline, the last three years of ambient monitoring data may be used if they are representative of the area's air quality where the maximum impacts occur due to the proposed source. Results of the Ambient Air Quality Modeling Analyses The maximum facility impacts calculated from each of the modeling analyses described above are summarized in Table 8-5 below. 72 Table 8-5 Modeled maximum project impacts. Turbine Total Turbine Averaging Pollutant Time Only Impact a Startup (µg/m3) (µg/m3) (µg/m ) NO2 Annual 0.1218 0.1218 N/A SO2 3-hour Max 0.95697 0.95697 N/A 24-hour Max 0.1777 0.1777 N/A Annual 0.0027 0.0027 N/A CO 1-hour Max 592.6075 592.6075 1790.2 8-hour Max 53.3475 53.3475 N/A PMioa 24-hour 1.498 1.498 N/A Annual 0.0704 0.0704 N/A a Background not included since modeled impacts are less than significance. PSD Increment Consumption The Prevention of Significant Deterioration (PSD) program was established to allow emission increases (increments of consumption) that do not result in significant deterioration of ambient air quality in areas where criteria pollutants have not exceeded the National Ambient Air Quality Standards(NAAQS). For the purposes of determining applicability of the PSD program requirements,the following regulatory procedure is used. RMEC modification emissions are evaluated to determine whether the potential increase in emissions will be significant. Because this facility is an existing major facility,the level of emissions that requires an analysis of ambient impacts is determined on a pollutant-specific basis. The emissions increases are those that will result from the proposed new equipment. In this specific case, RMEC is currently considered a new major source. Potential emissions increases are compared with the levels considered significant for new sources in Table 8-6. i' 73 Table 8-6 Comparison of emissions increase with PSD significance emissions levels. Pollutant Modification PTE Significant Emission Levels Significant? (tons per year) (tons per year) NO. 113.0 40 yes SO2 5.7 40 no VOC 25.7 40 no CO 378.8 100 yes PMtp 70.8 15 yes If an ambient impact analysis is required, the analysis is first used to determine if the impact levels are significant. The determination of significance is based on whether the impacts exceed established significance levels,shown in Table 8-7. If the significance levels are not exceeded,no further analysis is required. Table 8-7 APCD PSD levels of si ificance. Significant Impact Maximum Allowable Pollutant Averaging Time Levels Increments NO2 Annual 1 µg/m3 25 µg/m3 SO2 3-hour 25 µg/m3 512 µg/m3 µS/24-Hour 5 µg/m3 91 m3 Annual 1 µg/m3 20 µg/m3 CO 1-Hour 2000 µg/m3 N/A 8-Hour 500 µg/m3 N/A PKo 24-Hour 5 µg/m3 30 µg/m3 Annual 1 µg/m3 17 µg/m 3 If the significance levels are exceeded, an analysis is required to demonstrate that the allowable increments will not be exceeded, on a pollutant-specific basis. Increments are the maximum increases in concentration that are allowed to occur above the baseline concentration. These PSD increments are also shown in Table 8-8. Table 8-6 shows that the RMEC modification will be significant for NOR,CO,and PM10. Emissions of SO2 and VOC are less than the major source significance emissions thresholds. The maximum modeled impacts from the RMEC modification were compared with the significance levels in Table 8-8 below. These comparisons show that RMEC does not exceed the significance levels for any pollutant for any averaging time. Thus, no multi-source modeling analyses were performed. 74 Table 8-8 Comparison of maximum modeled impacts and PSD significance thresholds. Maximum Significance Pollutant Averaging Time Modeled Threshold Significant? Impacts (µg/m3) (µg/m3) NO2 Annual 0.1217 1 no SO2 3-Hour 0.9569 25 no 24-Hour 0.1777 5 no Annual 0.0027 1 no CO 1-Hour 592.607 2000 no 8-Hour 53.347 500 no pM1oa 24-Hour 1.4979 5 no Annual 0.0704 1 no Preconstruction monitoring is not required because the maximum impacts did not exceed de minimis levels, as shown in Table 8-9. Table 8-9 Evaluation of preconstruction monitoring requirements. Maximum Exemption Con- Modeled Monitoring Pollutant Averaging centration Time Concentration Required? (µg/n►3) (µg/m3) NOx Annual 14 0.1218 no SO2 24-hr 13 0.1777 no CO 8-hr 575 53.348 no PMio 24-hr 10 1.498 no 8.2 Impacts on Class I Areas Increment consumption of NO2 and PM10 due to the proposed new combustion turbine was assessed in all Class I areas within 125 km. Table 8-10 presents a summary of the results of the increment consumption analysis. The maximum annual NO2 and PMio impacts occurred along the nearest receptor ring for each Class I area. The highest-second high 24-hour PM10 impacts occurred using the meteorology ofJanuary 21, 1987 for Rocky Mountain National Park and December 5, 1988 for the Rawah Wilderness area. 75 The model-predicted impacts are compared with the PSD Class I area increments and Class I area modeling significance thresholds. The maximum impacts in Rocky Mountain National Park and the Rawah Wilderness Area are less than 1%of the PSD Class I area increments. These values are less than the 4% PSD increment significance threshold for single source contribution; hence, a cumulative PSD increment analysis is not warranted. Since PSD increment consumption was not significant for these Class I areas using the screening approach,its reasonable to conclude that impacts would be even lower at more distant Class I areas on the other side of the Continental Divide(e.g.,Mt Zirkel Wilderness at 184 km away, and Eagles Nest Wilderness). Therefore, an explicit modeling analysis for these areas was not conducted. Table 8-10 Summary of PSD Class I Area Impacts CLASS I Pollutant Averaging Modeled PSD Class I Percent of AREA Period Concentration Increment PSD (ug/m3) (ug/m3) Increment Rocky NO2 Annual 0.012 2.5 0.5 Mountain PM10 24-hour 0.070 8 0.9 National Park Annual 0.011 4 0.3 Rawah NO2 Annual 0.005 2.5 0.2 Wilderness PMio 24-hour 0.046 8 0.6 Annual 0.006 4 0.2 Regional Haze Analysis Table 8-11 presents the results of the visibility analysis for the nearby Class I areas and for the integral view of Pawnee Buttes. For each Class I area, the background reference level, the total change, and the contribution from each light attenuating species is shown. However, since background measurements of light extinction are not monitored at Pawnee Buttes, only the model-predicted change in light extinction from each contributing species in shown. At Rocky Mountain National Park,the maximum change in light extinction is 4.5%,which was predicted to occur using the meteorology of December 27, 1990 (i.e., winter time conditions). The maximum light extinction occurred along the first receptor ring (82 km)at a direction of 2 degrees. The contribution from particulates (0.373 Mm-1) was slightly higher than from ammonium nitrate (0.306 Mm-1), while the contribution from ammonium sulfate was an order of magnitude less (0.043 Mm-1). At the Rawah Wilderness, the maximum predicted change in light extinction was 3.4%, which was predicted to occur along the nearest receptor at 121 km at 332 degrees from the facility. Ammonium nitrate and PM () were the primary responsible species, with ammonium sulfate causing less of an impact. This impact was predicted to occur during winter conditions using the meteorology of January 5, 1988. At the Pawnee Buttes,the maximum predicted light extinction was 16.483 Mm-1,which was predicted to occur at 168 degrees from the facility at the equivalent distance of Pawnee Buttes. Ammonium nitrate and PMio were the primary responsible species,with ammonium sulfate causing less of an impact.This impact was also predicted to occur during winter conditions using the meteorology of January 7, 1988. 76 In both Class I areas,the maximum model-predicted change in light extinction was below the FLM level of concern of 5%change for a single contributing source. Table 8-11 Summary of Visibility Impacts Class I area Back- Bext Bext Bext Bext Light Change in ground SO4 NO3 PM Total 10 g Bext (Mm") (Mm') (Mm') (Mm') Extinction(MnfRocky Mountain 16.0 1) 0.043 0.306 0.373 16.722 4.5 % National Park Rawah Wilderness 16.0 0.031 0.260 0.257 16.548 3.4 % Pawnee Buttes n/a 0.027 0.226 0.229 16.483 n/a Impacts on Soils and Vegetation The maximum model-predicted deposition rates for nitrogen and sulfur for nearby Class I areas are shown in Table 8-12. The maximum annual nitrogen and sulfur deposition rate for Rocky Mountain National Park were predicted to occur at the nearest receptor ring(81 km)along an eight-degree line of direction from the facility for both nitrogen and sulfur.The maximum annual nitrogen and sulfur deposition rate for the Rawah Wilderness were predicted to occur at the nearest receptor ring(117 km) along a seven(nitrogen)to eight (sulfur)degree line of direction from the facility. The FLM's have established DATs,which are the additional amount of nitrogen(N)or sulfur(S)within a Class I area, below which estimated impacts from a proposed new or modified source are considered insignificant.The model-predicted deposition rates are presented in Table 8-12 for the applicable Class I and sensitive Class II areas. The results for all areas are less than the DAT of 0.005 kg/ha-yr, which applies individually for nitrogen and sulfur, for the Western United States. For all Class I areas, the maximum model-predicted impacts are less than half of the DAT. As expected, impacts at the more distant Rawah Wilderness are less than that at Rocky Mountain National Park. 77 Table 8-12. Summary of Deposition Analysis Area Class Sensitive High Nitrogen Sulfur Elevation Lakes Deposition Deposition (kg/ha-yr) (kg/ha-yr) Rocky Mountain I n/a 2.45 E-3 3.30 E-4 National Park Rawah I 1.28 E-3 1.96 E-4 Wilderness Island Lake 9.93 E-4 1.55 E-4 Rawah#4 9.93 E-4 1.48 E-4 Pawnee Buttes II n/a 1.35 E-3 1.73 E-4 Indian Peaks II Blue Lake 2.18 E-3 2.99 E-4 Wilderness Crater Lake 2.00 E-3 2.79 E-4 No Name Lake 1.89 E-3 2.65 E-4 Mt. Evans II Upper Middle Bear Wilderness Track Lake 1.56 E-3 2.25 E-4 South Lake 1.44 E-3 2.11 E-4 Eagles Nest I Booth Lake 6.62 E-4 1.14 E-4 Wilderness Upper Willow Lake 7.73 E-4 1.29 E-4 Impacts on High Elevation Sensitive Lakes Table 8-13 presents the results of the ANC screening calculations. For each lake, the input data, intermediate values, and percent change in ANC are shown. The nitrogen (N) and sulfur (S) deposition values are the maximum values calculated using CALPUFF. The nitrogen deposition rates are an order of magnitude greater than the sulfur deposition rates, as expected for a natural gas-fired combustion turbine. The greatest impacts to sensitive high elevation lakes occurs in the Indian Peaks Wilderness,at Blue Lake and No Name Lake. The high impacts appear to occur where relatively higher deposition (due to the relatively close location) occurs over areas with low baseline ANC. Although Crater Lake is also in the Indian Peaks Wilderness, its higher baseline ANC allows the lake to buffer the acid containing species better,hence it has a smaller predicted change in ANC. Its also interesting to note that while the lakes in the Rawah Wilderness Area receive more precipitation, their more distant location results in lower deposition values. When combined with high baseline ANC,the predicted change in ANC is very small (0.02%). In all cases the predicted change in ANC is less than 1%,even for lakes with low ANC(less than 25 ueq/1). The USFS service has established that a change of less than 1%in low ANC lakes and 10%in high ANC lakes would be below a level of concern, as the case here. The results of this analysis are considered conservative for several reasons. First, the deposition rates calculated by CALPUFF in a screening mode were not specific to wind direction,the maximum predicted value within the receptor ring was used. Second,the generation of ANC is in the watershed catchment is assumed constant over time. Third, all atmospheric deposition of sulfates and nitrates into the catchment is assumed to enter the lake and neutralize an equivalent amount of ANC. Fourth,the monitored baseline 78 acid neutralizing capacity of the lake represents baseline acid neutralization capacity of the water in the catchment area. These assumptions are intended to be conservative, as they do not incorporate aquatic ecosystem biogeochemistry. 79 En '+ e 7 V O N M en r- 1/40 e� N . O O N M 10 M en O O V o 3 [.t ti _. o Nc$ w b 0 tn 1/40 0. It N en O ^ ... Pt W In NEt Da 0, '• V d- b O N M e N O CO Ol co O in b M 7 0 0 V 0 >. S 000 W W h o v W W o 01 C 01 e N O N N N 1/40 0.0 01 W T 0 M v O N M vl b 0 V M in 0 0 vl M 1/40 M 0 0 0 vl 0 LC s `o W w o o m ti o • o ri. c .13 Et •--• V' M r 0 N en 1/40 vl N 7 1n ri 0 0 0 M b en lD O O T 0 • ;d ;E4 in Lu b O O co tl W 6 L N lei ,r -. w 13 1. N cn 01 a . n 7 M ON 0 N M Cr in _ U d O O V M 'O M N_ 0 0 - .-. ay h p d N W W O O b W mr •' 6 on ✓ J N • • C dz O " 7 7 M 7 O N en N `D In CA 0 O O r en 1/40 M 0 0 0 7 0 co C W N 0 p • t,N1 O '� d U 'J N N ^ 0 ni :, 00 O r T V' M GO O N M .n b -n � U ti ,_ O 0 b M lO M 1/40 0 0 7 R! 'el d aJ N W W N N •co T W W • O (_) ti ,V C o co 0 N a\ b U NJ N ri N ? 't o r` en --• 1- b 'n N y ^ O O 1` vt N M ON O 0 M 0 eli y C yy}. 7 W W O 7 w W o --II i C V OMi. N 1✓? O r oo as - 04 3 0 0 vl u1 N M 01 kr. M O O O Ca j` d b W [T. ^' p 000 r W 6 F 3 ,tl C vii, a en N a r ti 4 y — T eC N C t'a a _ crf = at., `-'0 s O 4l .2 Di C E . 7 U;., o , ....i ea u z O ° a c^p I > u Ld U b N .. .� .5 b = N^N u ++ C )., bq w cy N ° ¢ OO a. D. w S �dxxx pt 8.3 Impacts on Class II Areas The proposed source impact area lies within the confines of the Weld County,which is a Class II area,and is currently attainment for all pollutants. Since lead is not emitted from the combustion of natural gas fuels no further discussion on this pollutant is necessary. The modeled source impacts as delineated above were less than the SILs for all pollutants for all averaging periods. As secondary air quality standards are designed to protect agricultural interest,the impacts to soils and vegetation would be insignificant as the impacts are less than the air quality standards. Potential Stack Emission Effects on Soil and Vegetation Emissions from the new turbine/HRSG stack will not significantly affect vegetation and soils surrounding the RMEC project area. The following discussion presents the results of an analysis of the turbine/HRSG stack emissions for the RMEC modification project. The purpose of this analysis is to evaluate the potential detrimental effects that the projected turbine/HRSG stack emissions from the RMEC plant site will have on surrounding vegetation. Potential pollutant stack emissions included in this analysis include carbon monoxide(CO),inhalable particulates(Pt),and oxides of nitrogen and sulfur (NOx and SO2). No pollutant emissions are predicted to result in concentrations exceeding the U.S. Environmental Protection Agency (USEPA) prevention of significant deterioration (PSD)significant impact levels,for either short-term or annual averaging periods for CO,PM10,,NOx,and 5O2. Carbon Monoxide Plants metabolize and produce carbon monoxide(CO). Few studies on thresholds for detrimental effects on vegetation have been conducted. Most available studies use very high CO concentrations(above 100 ppm). Soil microorganisms probably acts as a buffering system and sink for CO. There are no known detrimental effects on plants due to CO concentrations of 10,000 to 230,000 µg/m3 (USEPA 1979). Zimmerman et al. (1989) exposed a variety of plant species to CO at concentrations of 115,000 µg/m3 to 11,500,000 µg/m3 from 4 to 23 days. While practically no growth retardation was noted in plants exposed at the lower level,retarded stem elongation and leaf deformation were observed at the higher concentrations. Pea and bean seedlings also exhibited abnormal leaf formation after exposure to CO at 27,000 µg/m3 for several days (USEPA 1979). Comparatively low levels of CO in the soil have been shown to inhibit nitrogen fixation. Concentrations of 113,000 µg/m3 have been shown to reduce nitrogen fixation,while 572,000 to 1,142,000 µg/m3 result in nearly complete inhibition(USEPA 1979). Maximum predicted 1-hour and 8-hour CO emissions have been calculated from RMEC. All impacts from CO are well below 113,000 ug/m3,even when including a background concentration. Therefore,predicted CO emission levels from the RMEC are not expected to result in adverse effects on vegetation. Sulfur Dioxide and Nitrogen Oxides 5O2 and NOx are airborne pollutants of concern for the RMEC modification project. The extent of their effect on soils and vegetation would be directly related to a variety of factors, including wind speed, direction and frequency, air temperature,humidity,the geomorphology of the area,and the location of the proposed project in relation to sensitive plant communities in the zone of impact. 81 Sulfur dioxide tends to convert to sulfite and sulfate during chemical transformation in soils. Interpretation of the results of investigations published to date has engendered considerable controversy due to the complexity of terrestrial ecosystems. However,the effects of acidified precipitation containing sulfate(SO4) on terrestrial ecosystems have been investigated with respect to alteration of soil chemistry as it relates to vegetation health. High levels of SO4 may reduce soil pH, thereby decreasing the availability of certain essential nutrients and increasing the concentrations of soluble aluminum,which reduces plant growth. In soils where nitrate-nitrogen is not limiting plant growth, excess nitrate may percolate through the soil column, carrying base cations and exerting an acidifying effect. Increased atmospheric contributions of nitrate may influence vegetation in a species-specific way, with some species taking advantage of its fertilizing characteristics while others (such as those occurring in nitrogen-limited soils) are adversely affected. Sulfur is a significant plant nutrient and can be directly absorbed into the soil. Therefore,an increase in SO2 in the soil (particularly at levels below threshold limits)would not have an adverse effect on vegetation. SO2 can affect vegetation directly(as a gas) or indirectly by means of its principal reaction product, SO4 (e.g.,acidification of soils). In addition, a third mechanism of impact is the formation of acid mist. Direct effects of injury can be manifested as foliar necrosis,decreased rates of growth or yield,predisposition to disease, and reduced reproductive capacity. Environmental factors, such as temperature,light,humidity, and wind speed,influence both the rate of gas absorption and the plant physiological response to absorbed quantities. The higher the humidity,the higher the absorption of gases. Exposure duration and frequency are also important factors that determine the extent of injuries. Guidelines for air emission impact assessment provided in the technical literature are diverse and threshold dosages required to cause injury are extremely variable. This is due to the variety of factors affecting plant responses to phytotoxic gases. Consequently, in cases where emissions are below lower threshold limits, decreased yields can result in the absence of visible injury (Sprugel et al. 1980) and long-term impacts should be addressed. Among the different published attempts to define SO2 thresholds for vegetation effects,two represent worst- case situations. Loucks et al.(1980)presented threshold ranges between 131 µg/m3 and 262 µg/m3 SO2,and McLaughlin(1981) suggested values of 1310 µg/m3 SO2 for the 1-hour average and 786 µg/m3 for the 3- hour average. According to the dose-injury curve for SO2-sensitive plant species provided by the USFWS (1978), the lowest 3-hour concentration expected to cause injury to plants is approximately 390 µg/m3, which is significantly lower than the projected concentrations from RMEC. However, these predicted values are applicable only when plants are growing under the most sensitive environmental conditions and stage of maturity. Thresholds for chronic plant injury by SO2 have been estimated at about 130 µg/m3 on an annual average (USFWS 1978). The maximum annual average concentration modeled for this project 0.0039 µg/m3)is far below the USFWS threshold for chronic exposure,and the worst-case projected 3-hour maximum of about 0.629 µg/m3 is substantially below the McLaughlin protection level of 786 µg/m3. Consequently,the projected concentration of SO2 is not expected to cause visible foliar injury or significant adverse chronic effects. 82 Nitrogen dioxide is potentially phytotoxic, but generally at exposures considerably higher than those resulting from most industrial emissions. Exposures for several weeks at concentrations of 280 to 490 µg/m3 can cause decreases in dry weight and leaf area, but 1-hour exposures of at least 18,000 µg/m3 are required to cause leaf damage. The modeled maximum RMEC emissions of NO2 impacts of 0.1218 µg/m3 are far below these threshold limits(219.0 µg/m3 or 0.1169 ppm). This indicates that NOx emissions from the RMEC,when considered in the absence of other air pollutants,would not adversely affect vegetation. Airborne Particulates Particulate emissions will be controlled by inlet air filtration and use of natural gas. The deposition of airborne particulates(PMio)can affect vegetation through either physical or chemical mechanisms. Physical mechanisms include the blocking of stomata so that normal gas exchange is impaired, as well as potential effects on leaf adsorption and reflectance of solar radiation. Information on physical effects is scarce, presumably in part because such effects are slight or not obvious except under extreme situations(Lodge et al. 1981). Studies performed by Lerman and Darley(1975) found that particulate deposition rates of 365 g/m2/year caused damage to fir trees, but rates of 274 g/m2/year and 400-600 g/m2/year did not damage vegetation at other sites. The maximum annual predicted concentration for PKo from the RMEC modification is 0.0704 µg/m3. Assuming a deposition velocity of 2 cm/sec (worst-case deposition velocity, as recommended by the California Air Resources Board[CARB]),this concentration converts to an annual deposition rate of 0.0442 g/m2/year,which is several orders of magnitude below that which is expected to result in injury to vegetation (i.e., 365 g/m2/year). The primary chemical mechanism for airborne particulates to cause injury to vegetation is by trace element toxicity. Many factors may influence the effects of trace elements on vegetation, including temperature, precipitation, soil type,and plant species(USFWS 1978). Trace elements adsorbed to particulates emitted from power plant emissions reach the soil through direct deposition, the washing of plant surfaces by rainfall, and the decomposition of leaf litter. Ultimately,the potential toxicity of trace elements that reach the root zone through leaching will be dependent on whether the element is in a form readily available to plants. This availability is controlled in part by the soil cation exchange capacity, which is determined by soil texture, organic matter content, and kind of clay present. Soil pH is also an important influence on cation exchange capacity; in acidic soils, the more mobile, lower valence forms of trace metals usually predominate over less mobile,higher valence forms. The soils located in the RMEC project area will have a lower potential for trace element toxicity due to the comparatively high soil pH commonly found in these soils. Perhaps the most important consideration in determining toxicity of trace elements to plants relates to existing concentrations in the soil. Several studies have been conducted relating endogenous trace element concentrations to the effects on biota of emissions from model power plants (Dvorak et al. 1977, Dvorak and Pentecost et al. 1977, Vaughan et al. 1975). These studies revealed that the predicted levels of particulate deposition for the area surrounding the model plant resulted in additions of trace elements to the soil over the operating life of the plant,which were, in most cases, less than 10 percent of the total existing levels. Therefore,uptake by vegetation could not increase dramatically unless the forms of deposited trace elements were considerably more available than normal elements present in the soil. 83 9.0 SOCIOECONOMIC AND GROWTH IMPACTS One of the required public services is the need for a reliable electricity supply. The proposed project modification is just one part of a complex mix of electrical generation sources that will provide electrical power to the region in both the short and long term. 9.1 Socioeconomic Impacts Presently, the facility does foresee the need to hire additional operations personnel. As a result, the modification project, once completed, will not cause any new impacts as a result of hiring or relocating personnel.Construction contractors and workers will likely be obtained from the surrounding regional area. All of the construction specialties required by the proposed modification project are readily available in the greater Denver Metropolitan area. As the project is built, there will be from time to time,a small influx of engineering and technical staff to oversee certain aspects of equipment placement and testing.These individuals will not require permanent housing and will instead make use of the numerous hotel and motel facilities in the project area.As a result, the socioeconomic impacts of the project will be insignificant when compared to the other aspects of economic growth in and around the area. The project will increase the payroll value for the construction categories,but should have an insignificant affect on all other economic categories. 9.2 Growth Inducing Impacts The proposed project,which will result in an additional 300 MW of electrical power on the power grid,is in and of itself not a growth inducing impact.As stated above,the increases in population growth,and demand for services,both public and private,in the Denver and central Colorado areas is occurring at a phenomenal rate. The power plant,as proposed,is not the cause of the growth,but rather is a response to the growth and need for electrical power in the area. Independently owned and operated power plants such as RMEC have an excellent track record of reliability and stability. These types of plants, which use clean fuels, such as natural gas,state of the art combustion technologies, such as gas turbines, and environmental control systems to minimize emissions to the air, water,and land surface,will continue to provide the public with reasonably priced electricity for many years into the future. r 84 10.0 SUMMARY AND CONCLUSIONS The data and supporting analyses provided in this document demonstrate the following: • All applicable requirements of the Colorado APCD and EPA are satisfied. • Emissions from the proposed modification will not cause or contribute to an exceedance of any state or federal AAQS or PSD increment. • Emissions will be controlled using Best Available Control Technology(BACT). • Emissions will not cause detrimental effects to vegetation or soils. • Air Quality Related Values, including visibility, will be protected at all Class I areas and sensitive Class I areas. • The modification project will not cause significant population growth in the area. The air quality analyses set forth in this document were conducted in accordance with EPA guidelines and included all of the Colorado APCD requirements. Based on the results of these analyses,it is concluded that the Rocky Mountain Energy Center modification project will not pose an adverse threat to the maintenance of the local or regional AAQS, or to the health and welfare of the general public. 85 REFERENCES Colorado APCD Regulations. Air Monitoring Network NAMS/SLAMS Review Reports for 1996, 1997, 1998, Colorado APCD,July 1997, July 1998, July 1999. Weather America-Detailed Climatological Data,TV Publications Inc., 1996. Weather of U.S. Cities,R.A. Wood, 5th Ed., Gale Research, ITP Information Group. Climates of the United States, Volume II.-Western States,NOAA,U.S. Dept. of Commerce. Comparative Climatic Data for the United States,NOAA,U.S. Dept. of Commerce, April 1985. U.S.Bureau of the Census,Population Division,Statistical Information Section,Population Estimates Program, 7-1-98. U.S. Fish and Wildlife Service,Division of Endangered Species,Listed Species Under FWS Jurisdiction as of 12-31-97 by State and Territory. Soils and Men, U.S. Dept of Agriculture,Yearbook 1938. Western Economic Research, Census Tract Map Service, Colorado Census Tract Map, Map#C23, 1994. New Source Review Workshop Manual, USEPA, OAQPS, October 1990. Permit Application Guidance for New Air Pollution Sources,John Bunyak,National Park Service,Air Quality Div.,NRR-NPS/NRAQD/NRR-93/09, March 1993. IWAQM-Phase I Report: Interim Recommendation for Modeling Long Range Transport and Impacts on Regional Visibility, USEPA-OAQPS, EPA 454/R-93-015, 4/93. Clean Air Status and Trends Network(Castnet) at http://www.epa.gov/ardpublc/acidrain/castnet IWAQM-Phase II Report: Summary Report and Recommendations for Modeling Long Range Transport Impacts, USEPA-OAQPS, EPA 454/R-98-019, 12/98. Draft Guideline on Air Dispersion Modeling, APCD, Revised, January 1998. OAQPS Cost Control Manual, 4th Ed., USEPA-OAQPS,EPA 450/3-90-006, January 1990. Alternative Control Techniques Document-NO„ Emissions from Stationary Gas Turbines, USEPA-OAQPS, EPA 453/R-93-007, January 1993. Guidance for Power Plant Siting and BACT, CARB-CEC, Stationary Source Div., June 1999. Stationary Combustion Turbine Database,Alpha-Gamma Technologies Inc.,Database Report and Summary to EPA/OAQPS-ESD Combustion Group,February 1999. Cooling Tower Drift: Its Measurement, Control,and Environmental Effects, G.K.Wistrom,et al.,CTI Annual Meeting,January 1973. Appendix A APEN Forms dlrojewo00\anua paeH 04 eseeIa1:M05E l lueosy\:a -- - -- —r- rt Ap oy;, LK> 8Q 5G° ' `3 is m mph 0_g � €_ =Q3 < g g' vi 1 Ov ). s au'° — F az $o \ n zg e n u F g�g atilt� rn V `o D E v E ffixn 6 3y5or. $> ≥ g W _ E C /.. S fig a IS N p ��C or. c•� a x �j`o tu Uq� y _ 3 s ,,., a.u- q _ 3 pp AN g yy 5Z .c� pK 0$¢$$0 99fis E p C u_.E4 Q 4 a > ll CO ..1 R X S 4 5 XXXC ❑❑O. O❑ ik E Z V p o 0 ZO in to Z 0 � 1p°0 I:. C 3 Lr EF-12.4 C .c E 2 9993 SS •iFz. fN ora g e a. r p a c`i•. 8 8 5 E E = 10 -AT o c_ z o x&'m w a !Z' > > > > > > a D 0 0 -0X« I w�, 2 o a SO: v i in riii e- P-^Nn. puK .Z at Q Vl P U G sz is x € y -Yp 55_ �/E d .y0 z a5 E p9 p afry "a 2 a9 T 5 rn 0.. o Ei rO_ ^W ;II c 8 , �$ c ' z z0� Z F1 —,4 c 8o n �'e < v m s E20 O a x <(i iA WALL > c g � V � � U 6s�Uy 1 a tr KEr pF0 � hm . Ii �Em E < Pt X vi tis e. m 'F r0". a 514 EL ZV hR<o 3 < to 2 0 � a lam+ C p b _ ❑ 0 O y 3 u r g 3 { w W ' -❑ ::'• I ran, T/4 U srtQ0m L9 a p ge= -- .1S.a S s V) 2 '8.0IgtuWO1 E5' tilt.VD d Isw6 `06&•' V �W \ pew ,--, VNgcOFz S ❑^ ' 3g .. . , 03800 (+\ .au b° �xgE .9 .v ae a <"< mU 8S Ww og EEe €- 9 zz Z o° `e �y 8 E y Y p �e �Z 'y z Z ZN t a. Q O igs t5L5 tjL !0E 'S C G' KO 0c IIa i'S aF'Ze fir o f it 4i m F- ❑ p.J a 0 0 0 kt a E �' F-+ �oo°�`o F ° �� z W, o V. Zo <' 6 a:9u � eOQ� C F sF o kLo C3 . Cyj qGa •� • E >t e< O W hl C U Z V c .V% 8 0 `o s 0 co' 0 g F. 2 .°W.R e g �c W d O C K O O c F 3 h `c •u O Z Z Z Z V W p m tills,.we0. z ❑z`z;z< yzt Q u s $ Z 8 . z 3 a Ws e z c zz1x (-op, y .5 aq :a z l Y a o 5 •$$ <ad § m g < ,2ay`,'D' a' gm 0.-- u 0 U E cg G z z ti 0.J _S 1000 0400 � 5C k p C dirDde 00001anpo pJeH IN eseaIadisa6eWI ;ua3sy\:O s 0� a ¢ a ¢ < < a ¢ a ¢ ¢ Q ¢ (.- . . zzzzzzzzzzzzz - [v o 2 z r: • N Z "' U W "' O cc rri 9 o a el '8 gaa Q V 'E l 0O N v N O 0000 C 00 -- N N v s (s.. V N rt R N A N N UJ et. To C.,) NEr u u 0 yM VU rrU U vU vU 4vJ� A2 v2 2 U Z .D P .0 .0 .0 .0 .0 A .0 .0 .0 .O En rn,.� 4;"' W 1--- S' R 'is' lO c0 t7 tO n! Q eC edEN Ets ❑ V H Z w (..-1 -- € A A A A A A A A A A A A I- N Q 3 N v�n w w w cT. I... w w w w w 7. w c° e. Cn a` c ¢ Q Q Q Q Q ¢ Q Q E Q a�i C7 p U U U U U U U U U U o r U U ° U 2 " z W :i N On a N C N -- r, N N N .U O O . O C, 0 0 O O 6 O O O I—i o'i w W E w w w 4 W cif W W W 0 on 0 ..0 N o, cc 0 '0 00 _o Za �� oo v, d m ry n = <I b b O -: —; Nsi' V N N 7. I . J o J Ece c. n OS 5 a y. z L. Le o'gs Z .. W - .v U - Q G .A _6C _ G u '-@ i. 0r. 0 c J .0 id g r aa>i a. 0 >, _3 of re E G N U ¢ "`c as C. p co W O a U 0o U G W L z A. p 67, 0. N .. c is O •v N �. /1 Et d UN C. Z i cc4 o w y "" O N _ N a r0, m m o, omo co w w a U G D W .E€ O v VON oO Op O N , 0000 NO 1= N 'n `" vi 1D O ., m o L p 6-. Q z t c, n O O h ^, a O ^ G p `"\ I' ' ° E G m U 03 r; z dLL'3d9L0000\GAPQ pie-of asealaa\se5eWI 3uaasW3 g 2 -8 € t 8 g z 8 8 E0 * 9 a V C t w g s g 6 E S $ • e .1 I 8 42 8 i € 1 n 3 g $ 8 O. c I I 0 W r s ? i- $ qA 8 E a _ E 1 w W ; = y 8 E g ww F - I bE $ e Cg L d C• q• 4$ 11 G( Jill a 3` ' 5. § 2 ili . E E s Y We W a a O _ m _ 5 �O t g E OE a t m €7 I V, Y Lo a. _- 6 1 9 a a w _ a i 1 a o 5 W 2 E t ' 8 a€ mw a 's g �� x - Wei E v g a d 3 Z a u E $ P _ R g - C y E 8 U € C 4i 6 y ,c s V% a F. I Im € ' 9 = ww .,z o 3 E 8 a .. o � '1 v � h 8 E € v 3 Z W �:S ill i• _ m o° ` El3 x n a' g P a _ 2 12 E O a w E €s Sa 8 5aQ O. M B a c 2.E .5 E 1 �Z z Z .ri 8 I El a Z 9 9 z° =s 13 E hl 8 I = s U 9 S $ t a 9 ty p Ed it; 6 $ 6 .n is 1 V1 ^, ua^ ti- - m -C3 u m E 'L :-I L` Y'2 C E a. ca e 's ' 1 ht E I Y 2 a `tL ca y `=i El E v y 'e c t '�' Yi =L9 Oeel L•' C =p C G C G T W z a 8= L . I 8 L-'a 'Ss. :1E: i € e = m E w 0 1 • E e, d ViZ m S 4. it T t Lg.ti .3� S t8 e4 47 g 050 w o e hl w `u < ; I 1 to- i 8� F. a e 2 _ U$ at. U Fri OC fr 4 w Appendix B Emissions Calculations and Data Sheets h 0 0 N C r O O r W O COO W W O O CO r l- W CO W W W V V V < r O a N M N N O N t0 6 6 6 r N m m co m O .- r r r N co co a to .4 O O CO ^ t` 01 W CO CO A IO f 147,5 [° 3 S s k a" t,P';if 't tt c�+ls'_ 4R SYut "` ,,,sik t „,* ° '14)4.14.0.")<P400;` 'P 0r))0.,. nk` ogle ' e�" • } i ;;;; ,,,, ,4t1 t ,,s�gr. a• . ; y ^- to Ay co co co UJ H k.,ag[W K _ �' .nI 2 O m # ° e. . ;00t..0 .B #� to '°% ' "O.-4. • ID y 3':. i S S ? "' § S h. by to %'.1 X L°v 001)504.1 Y `o TO7. y spa Y g- d la 'y " �M g(- �vT #�tf L�Yuti,-,t:,-.a.4.4:442'.41 ".t, 7,t{ 1� nly�u',��x C p�'4 MS N ti3 Ol L , It t k iiii. VV: Viiifkiii c6 F6 . iiii7lii `'� x e'€P s ,00 eykC° Vie '# a wy .g.415.0.s ie7.tr'#aM' s ki ' m m 'f-�( P �'2"{�h. d �3 "2'3'4S- W - ,-;•;_.j T,"` g ike T a o!`16,114:(4-140: 0 t O 6 `4T„t7 ``�t�Lt : LIFi PaLl Sy t en ;to„ , 110 fv.i ''- Y o t If CD al C • �'S ` '& Pr�`02-P `S '77.1 a ni i, W .. ,. -. t S '`"�, Si m k_-' "'rI H.&`.. .,.. . M 1 .„ 's': .. -...r c `o c D O O O n 0 o O O CD CO CO o O W r r �• (0 CD O CO CO 0 0 V V N-t7 N O 6 t0 ,_ m e+ G G h th lV N t0 N co t0 Oi r 6t0 r r .- .- Lei d a E d y co W a co ,-r OI a Cr) 00N r r 0 c J 0 IX O a T coU.Sr c ^� � � En E c D w 6- E EoCr c7 YOD � W N N N N "' N N N '" N N N "' N N N N N N N `" c m o E W C C EEE co E E E o EEE N E E E w E C E y y a " E Q N CO CO D N co N D CO N Co D CO CO N D CO CO in D y O c ' .p D D _ S D D D S D 1) T D D D \ D D D _ T o a X Po C E C J J J 0 c J J J O E J J J O E J J J O C• J = J o c w p E 3 .A. coon- 0 0 0 = 0 0 0 0 2 $ o o o 2 Q 0 0 0 2 2 o c c Y E 2 2 2 2 2 2 = 2 2 . 2 2 2 - 2 2 2 U O w G r to' W N oo r a7 co' N A r P5 co' B r th W N • r t7 tO N 9 n J 2) OY M a a o 0 O 0 0 o d 5 y E E E E i-. E E E E E E E E r E E E E F E E E E F �' E _m J J J J _ J J J J _ J J J J _ J J J J _ J J J J _ N x %i E E E E o E E E E E E E E '^ E E E E ro E E E E - 5 m J CO Ilk CD .X .X .X .X J .X .X .X .X J J J c % N U CO 1J U c c R R K x X x x R c R A R R c N L (0 E d co m m c m m m m c a m co co co d' W Z U > a W Z .- N w �� CALPINE _ • I Rocky Mountain Energy Center Expansion Expected Emissions Summary HRSG lbs/hr tons/yr Emissions(each unit) Peak Cold Max. Peak Base Total NOR, as NO2 25 19 25 64 31 95 CO 46 35 46 117 56 173 VOC, as CH4 5.8 4.5 5.8 15 7 22 PM10 18.6 12.0 18.6 47 19 67 SO2 1.4 1.1 1.4 3.6 1.7 5.3 CTG Start Hot Cold Total 'r Emissions(each unit) lbs/start lbs/start tons/yr NON, as NO2 80 240 18 CO 902 2,706 206 VOC, as CH4 16 48 4 PM10 19 56 4 SO2 1.4 4.2 0.3 Auxiliary Boiler Emissions lbs/hr tons/yr NO,, as NO2 0.49 0.00 CO 0.50 0.00 VOC, as CH4 0.06 0.00 PM10 0.24 0.00 SO2 0.01 0.00 Emergency Generator Emissions lbs/hr tons/yr NOR, as NO2 31.70 0.00 CO 39.05 0.00 VOC, as CH4 4.59 0.00 PM10 1.84 0.00 SO2 0.65 0.00 Fire Pump Emissions lbs/hr tons/yr NOR, as NO2 1.85 0.00 CO 0.13 0.00 VOC, as CH4 0.10 0.00 PKo 0.03 0.00 SO2 0.06 0.00 Cooling Tower Emissions lbs/hr tons/yr PM10 0.00 0.0 Summary(2) 1 of 1 7/9/2005 N-W0-O LL rOOW NO In0OW CI)CID N 0ocN0 0 -6, 0,6 w LL 0 0 0 Q P 0 N N ' N r r N N 0 10 In CO N Q I--•e- P 00at NF CO 000 .r- T• OOf NT- O o 0 N 1 N Z r f W 1�O e O a mr0 W rO II N 0 0 0 Or O 10 IC 0 N LL IO W W .?„9.4.7-a ._ NIn rm rry ! 0A01. 0 V 0 N 0 N P Qf P C O Q0r 17r O-o- N 0 IS N N Z r ea r o e o r O O 0 0 W N 0 a N N N 0 an N I.-an m .-C mj W 0 0 a to00QQNQ0 O N CON W r N CO O N I-- 0 O Q (90) N000Nr Q O O 0 0 r C] r p r O O r m N rC N W zN Co a mW mpe m Z rci 2218`°``''' 0n00 ,. N Q m°W mQ o <6 mN W In CO NO(7oNm mirror Na�N pmNri ai m 0r •o ' n N Z m m OQm r 000 CO ON 0 to r-In CO Nm CO PI oQ O m J N m N W O (c 0 N N O ry n.- N N WIN OI r N d 0 N Q N CO N <0 N O O P mr W ` O�m' nry r f CO N ' ^ 0 n r N Z a NANO e O LL r001noON an N O In m m m O Cr N N N N m 0 H Cr. a CO 0 CO m •Q ' N O N N m 0 Q O I�N P N. o N O O ry N O 0 N O O 0 m m 1C a fC N 0 N Z O WPOpO LL rOOONQW N Om NN P 00PN0 m 0 0 100 0 ON N m m N CO CO 0 0 V U mQ p �CI]cn 04 O ON f0NN�_ rN N ONo N a R N r N Z r r 0 N z al.-OOO00N N ON NQ N O 0Wo- o N0 0 h 0 m N O(J 0 N 0 0 m 0 N Po—m r N 0 O 0 N 0 N m cc 0 I0 -O O O m N' .N- a N m O 0 Ip N N N Q r n r N IS Z o a d N N....?.0 o-0 o m N 0 CO 0 IO N N N a 0 0 Cr N O 0 co 0 0'0 c ^ OU' ONN—�0 N to Nan N0 rN n QCI r I-, 0 0 E < !0 'O In 0 P m r Q [00 r m m 3 K N Ti N � r 0 N O Z s a _ co e N N-2...N LL r O O in CO 0 m to r o r m co P O N 0 Q N 2 O O O00 m ' N00r N 0rm0 m c'O•- r LL (0 0 N t m N 0 ,- r m 0 0a m m a 0 - 0 0 Z O .O In r co N r n r N c d N N I`r • O Y N e Q N e N LL r O O O fp N Q a O O P m N N 01 N 0 0 0 m a O01 .-Ng- O O 10 0 0 0In N W ' N 0 N a 3 0 r O('J 0 N N 0 M m O N m O 0 Q a m a 0 O 'N O O 0 N` N'- N u' N O n u z to o o o m r LCN�N LL '000QN' NN CO 00000 0 U n V 0 O p N O LL A 0 0 0 0 a co in n` N In m r N A N 0 N N 0 0 d 0• r o r O •O N 0 0 N N r N p I--r m 0 a N E Or _d a (p N N r 8 c S Z O N 0 Z N r q Oo N 1IOl P 0 c ? E . 0 to o 1 N c n E a o to " a X 3 rr (Jd a A w r o € a a y LL LL d u. s N LL r≤ • > S S 5 O'- m 00 in i0 To c vCl' E m E. a w ^ aai fl) 013 d 3 a Ea w a r EEa Ea r Ea r E r EE c EE t r r E m o m o o m `o 8 " m Na SOe Oe mOmm Eaoma as an an a as aada.o > 6N o m a o.&" .G S m a U -J Tia m u" m - a 7+ 0 o- _ G1 W O C > 3 0 m 5, 5 u c Z D a m °c S 0 y m 0 5 g o 0 ___ CO t a d c n d w cc g E E v m x h o m v 5 E 3 m €, LL J ZF ≥ m W i m) E m - tm $ Em' E ra a c N CO E >Z x .j S c < y 3 0 212 u E v . g 3 z a � dE! a ' m 0 �`. E'm w N nz. 4 0 _ F m m w c " gU UG ca ,Ew c= alE of LL Fm-I9 Z LT O Z wa' o y 2 Z y ntea _ € =° " � - ° " -t 2 Ua a v aay-JI"5a- > O > E w < J vq. c o m o - to E E EO a Fmn 10 EEa—a+ ma`n m `actm h UUUUNN . t0 2 oCQ�.Q `m m LU 'TvaJ a a< (' w ¢ w m m o' E E o o > > > a w m x O O O O x m O O O O o 0 o m x Er fi m .^ 032 x a o ' ft WUJW«UULLLLLLLLOSSWWWW w ZZOO > > wwv0wmaa Co <ZOUZi W W W0Ew<U CCALPINE -ea Rocky Mountain Energy Center Expansion Expected HRSG Stack Emissions Assumptions Plant Design Parameter's Number of Combustion Turbines 1 Combustion Turbine Manufacturer Siemens Westinghouse Combustion Turbine Model 501 FD Ambient Pressure, psia 12.23 HRSG Stack Diameter,ft 18.5 HRSG Stack Height,ft 175 Duct Burner Emissions Without PAG With PAG NOx, Ib/MMBtu as NO2(HHV) 0.080 0.080 CO, Ib/MMBtu (HHV) 0.100 0.250 VOC, lb/MMBtu as CH4(HHV) 0.020 0.050 PM10, Ib/MMBtu (HHV) 0.015 0.015 NGx Catalyst Design Parameters NOx Catalyst Required? (Yes/No) Yes Design Outlet NON, ppmvd @ 15% O2, Annual Average 3.0 Design Outlet NOx, ppmvd @ 15% O2, Maximum 3.0 Ammonia Slip, ppmvd @ 15% O2 10 SO2 to SO3 Conversion 10% SO3 to H2SO4 Conversion 100% Added PM10, lb/hr 1.0 CO Catalyst Design Parameters CO Catalyst Required?(Yes/No) Yes Design Outlet CO, ppmvd @ 15% O2 9.0 Design Outlet VOC, ppmvd as CH4 @ 15% O2 2.0 Added PM10, lb/hr 1.0 Operating Profile(each CTG) Annual Operating Profile Peak Base Off Days/week 6 calc'd 1 Hours/day 16 calc'd 0 Months/yr 12 calc'd 0 Hours/yr 5,100 3,204 0 Combustion Turbine Starts Cold Hot Number of Starts 52 300 Hours/start 3 1 Basis for Maximum 1-Hour Emissions CTG's Undergoing Cold Start 1 CTG's Undergoing Hot Start 0 Basis for Maximum 3-Flour Emissions CTG's Undergoing Cold Start 1 CTG's Undergoing Hot Start 0 Basis for Maximum 8-Hour Emissions CTG's Undergoing Cold Start 1 CTG's Undergoing Hot Start 0 Basis for Maximum 24-Hour Emissions CTG's Undergoing Cold Start 1 CTG's Undergoing Hot Start 0 HRSG Assumptions 1 of 1 7/9/2005 CAL•d• • CPINE _I Rocky Mountain Energy Center Expansion Expected HRSG Stack Emissions Operating Conditions Case D E N GP F B. .1 Ambient Dry Bulb Temperature°F 90 102 90 50 50 3 90 Ambient Wet Bulb Temperature°F 63 73 63 41 41 2 63 Combustion Turbines Operating 1 1 1 1 1 1 1 Combustion Turbine Load 100% 100% 100% 100% 70% 100% 70% Inlet Fogging?(Yes/No) Yes Yes Yes No No No Yes Duct Firing?(Yes/No) Yes Yes Yes Yes No No No Power Augmentation?(Yes/No) Yes No No No No No No Fuellnput'total) GT Fuel(LHV) MMBtu/hr 1,493 1$60: 1,401 1,464 1;090 1,613 1,049 HRSG Fuel(LHV) MMBtu/hr 595 549 561 553 0 0 0 Total Fuel(LHV) MMBtu/hr 2,088 1,909 1,962 2,017 1,090 1,613 1,049 HHV/LHV= 1.1068 GT Fuel(HHV) MMBtu/hr 1,653 1,505 1,551 1,620 1,206 1,785 1,161 HRSG Fuel(HHV) MMBtu/hr 658 607 621 612 0 0 0 Total Fuel(HHV) MMBtu/hr 2,311 2,112 2,172 2,233 1,206 1,785 1,161 GT Fuel lb/hr 74,620 67,953 70,029 73,150 54,470 80,591 52,398 HRSG Fuel lb/hr 29,725 27,423 28,029 27,651 0 0 0 Total Fuel lb/hr 104,345 95,376 98,058 100,801 54,470 80,591 52,398 Combustion Turbine Exhaust(total) Margined Exhaust Flow lb/hr 3,244,591 3051,443. 3,141,173 3,272,250 2,728,880 .. 3,527,693 2,694163 Exhaust Flow Margin 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% N2 mole% 70.53% 73.78% 74.40% 75.50% 75.79% 75:83% 74.75% 02 mole% 11.43% 12.42% 12.56% 12.79% 13165% 1270% 13:57% CO2 mole% 3.85% - 3.79% 3.81% 3.84% 3.43%.. 3.92% 3.32% N20 mole% 14.18% 10.01%. 9.24% 7.88% 7.13% 7.55% 8.36% Ar mole% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% N2 mass% 71.42% 73.52% 73.91% 74.60% 74.78% 74.81% 74.12% 02 mass% 13.23% 14.14% 14.25% 14.44% 15.38% 14.32% 15.37% CO2 mass% 6.12% 5.93% 5.94% 5.96% 5.31% 6.08% 5.18% H2O mass% 9.24% 6.42% 5.90% 5.01% 4.52% 4.79% 5.33% Ar mass% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% Total 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% Molecular Weight 27.67 28.11 28.20 28.35 28.39 28.39 28.25 HRSG 1 of 4 7/9/2005 operating Conditions- Case; ,i r1) I *E. ( . 'Il'i' ,f= "GP °I =F I II I y tombustlonTurbine.ExhaustkAnal)isis(each'turbine) N2 lb/hr 2,317,189 2,243,352 2,321,583 2,441,137 2,040,704 2,639,175 1,997,093 O2 lb/hr 429,104 431,382 447,539 472,356 419,695 505,017 414,138 CO2 lb/hr 198,639 180,928 186,598 194,910 145,020 214,551 139,507 H2O lb/hr 299,659 195,781 185,453 163,847 123,461 168,949 143,626 Ar lb/hr 0 0 0 0 0 0 0 Total lb/hr 3,244,591 3,051,443 3,141,173 3,272,250 2,728,880 3,527,693 2,694,363 Maximum Exhaust Flow lb/hr 3,244,591 3,051,443 3,141,173 3,272,250 2,728,880 3,527,693 2,694,363 Margined Exhaust Flow Ib/hr 3,244,591 3,051,443 3,141,173 3,272,250 2,728,880 3,527,693 2,694,363 Combustion TurbinesEmissions(each lturbine) NO„@ 15%O2 ppmvd 25 25 25 25 25 25 25 CO ppmvd 25 10 10 10 10 10 10 VOC ppmvw 1.2 1.2 1.2 1.2 2.3 1.2 2.3 NO„as NO2 Ib/hr 149 135 139 145 108 160 104 CO lb/hr 70 27 28 30 25 32 24 VOC,as CH4 lb/hr 2.3 2.1 2.1 2.2 3.5 2.4 3.5 PM,0 lb/hr 13.4 13.4 12.7 14.0 11.7 15.6 10.9 SO2,Annual Average lb/hr 1.1 1.0 1.0 1.1 0.8 1.2 0.8 SO2.Maximum lb/hr 1.1 1.0 1.0 1.1 0.8 1.2 0.8 Duct Burner Emissions(each HRSG). NO„as NO2 Ib/hr 53 49 50 49 0 0 0 CO Ib/hr 165 61 62 61 0 0 0 VOC,as CH, lb/hr 32.9 12.1 12.4 12.2 0.0 0.0 0.0 PMra lb/hr 9.9 9.1 9.3 9.2 0.0 0.0 0.0 SO2,Annual Average lb/hr 0.4 0.4 0.4 0.4 0.0 0.0 0.0 5O2,Maximum lb/hr 0.4 0.4 0.4 0.4 0.0 0.0 0.0 Total:Emissions:Upstream:of Catalyst(each FIRED) NQ,as NO2 lb/hr 201 184 189 194 108 160 104 CO lb/hr 235 88 90 91 25 32 24 VOC,as CH4 lb/hr 35.2 14.2 14.6 14.5 3.5 2.4 3.5 PMro lb/hr 23.3 22.6 22.1 23.2 11.7 15.6 10.9 SO2,Annual Average lb/hr 1.6 1.4 1.5 1.5 0.8 1.2 0.8 SO2, Maximum lb/hr 1.6 1.4 1.5 1.5 0.8 1.2 0.8 HRSG 2 of 4 7/9/2005 =Operating.Conditions. Case 1 3 it,- ,.,t ,N I `GP I F I B I NO 'CatalystTerformance`:(each HRSG,.AnnualAverage) NO,Reduction,as NO2 lb/hr 176 161 165 170 95 141 91 NO,Reduction(mass basis) % 88% 88% 88% 88% 88% 88% 88% PM10 Increase lb/hr 1.0 1.0 1.0 1.0 1.0 1.0 1.0 PM10 Increase(mass basis) % 4% 4% 5% 4% 9% 6% 9% NH3 Slip lb/hr 31 28 29 30 16 24 15 NH3 Reacted Ib/hr 68 63 64 66 37 55 36 Total NH3Added lb/hr 99 91 93 96 53 79 51 -CO Catalyst Performance(each HRSG) CO Reduction Ib/hr 189 46 47 47 1 -3 2 CO Reduction(mass basis) % 81% 53% 52% 51% 5% -9% 7% VOC Reduction lb/hr 29.3 8.9 9.1 8.8 0.5 0.0 0.6 VOC Reduction(mass basis) % 83% 63% 62% 61% 15% 0% 18% PM10 Increase lb/hr 1.0 1.0 1.0 1.0 1.0 1.0 1.0 PM10 Increase(mass basis) % 4% 4% 4% 4% 8% 6% 8% HRSG Stack Exhaust Analysis(each HRSG) N2 lb/hr 2,317,584 2,243,716 2,321,955 2,441,504 2,040,704 2,639,175 1,997,093 O2 lb/hr 319,109 329,905 343,819 370,036 419,695 505,017 414,138 CO2 lb/hr 277,492 253,675 260,953 268,262 145,020 214,551 139,507 H2O lb/hr 360,130 251,568 242,473 220,098 123,461 168,949 143,626 Ar lb/hr 0 0 0 0 0 0 0 Total lb/hr 3,274,315 3,078,865 3,169,201 3,299,900 2,728,880 3,527,693 2,694,363 N2 mass% 70.8% 72.9% 73.3% 74.0% 74.8% 74.8% 74.1% O2 mass% 9.7% 10.7% 10.8% 11.2% 15.4% 14.3% 15.4% CO2 mass% 8.5% 8.2% 8.2% 8.1% 5.3% 6.1% 5.2% H2O mass% 11.0% 8.2% 7.7% 6.7% 4.5% 4.8% 5.3% Ar mass% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Total mass% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% N2 moles/hr 82,731 80,094 82,887 87,155 72,847 94,211 71,291 O2 moles/hr 9,973 10,310 10,745 11,564 13,116 15,782 12,942 CO2 moles/hr 6,305 5,764 5,929 6,095 3,295 4,875 3,170 H2O moles/hr 19,990 13,964 13,459 12,217 6,853 9,378 7,972 Ar moles/hr 0 0 0 0 0 0 0 Total moles/hr 118,999 110,132 113,021 117,032 96,112 124,247 95,375 N2 mole% 69.5% 72.7% 73.3% 74.5% 75.8% 75.8% 74.7% O2 mole% 8.4% 9.4% 9.5% 9.9% 13.6% 12.7% 13.6% CO2 mole% 5.3% 5.2% 5.2% 5.2% 3.4"/ 3.9% 3.3% H2O mole% 16.8% 12.7% 11.9% 10.4% 7.1% 7.5% 8.4% Ar mole% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% Total mole% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% Molecular Weight 27.52 27.96 28.04 28.20 28.39 28.39 28.25 Stack Temperature deg F 158 161 158 155 165 170 165 Stack Velocity ft/sec 67 62 63 65 54 71 54 HRSG 3 of 4 7/9/2005 ,Operating Conditions Case -I a .,D .) ;; ;E ('. rN rGP )' 1E •) ..gB -( .J Calculated-HRSG Stack`Emissions(each`HRSG); NO„,@ 15%02,Annual Average ppmvd 3.0 3.0 3.0 3.0 3.0 3.0 3.0 NO„,@ 15%02,Maximum ppmvd 3.0 3.0 3.0 3.0 3.0 3.0 3.0 CO,@ 15%02 ppmvd 9.0 9.0 9.0 9.0 9.0 9.0 9.0 VOC,as CH4 @ 15"/02 ppmvd 2.0 2.0 2.0 2.0 2.0 1.1 2.0 NH3slip,@ 15%02 ppmvd 10.0 10.0 10.0 10.0 10.0 10.0 10.0 NOx,as NO2,Annual Average lb/hr 25 23 24 24 13 19 12 NOx,as NO2,Maximum lb/hr 25 23 24 24 13 19 12 CO lb/hr 46 42 43 44 24 35 23 VOC,as CH4 lb/hr 5.8 5.3 5.5 5.6 3.0 2.4 2.9 PM40(excludes H25O4 mist) lb/hr 25.3 24.6 24.1 25.2 13.7 17.6 12.9 NH3 lb/hr 30.9 28.3 29.0 29.9 16.0 23.7 15.4 502,Annual Average lb/hr 1.4 1.3 1.3 1.4 0.7 1.1 0.7 SO3.Annual Average lb/hr 0.0 0.0 0.0 0.0 0.0 0.0 0.0 H2SO4 Mist,Annual Average Ib/hr 0.2 0.2 0.2 0.2 0.1 0.2 0.1 502,Maximum lb/hr 1.4 1.3 1.3 1.4 0.7 1.1 0.7 SO3,Maximum lb/hr 0.0 0.0 0.0 0.0 0.0 0.0 0.0 H2SO4 Mist,Maximum lb/hr 0.2 0.2 0.2 0.2 0.1 0.2 0.1 Permitted HRSG Stack Emissions(each HRSG) NO„,@ 15%02 Annual Average ppmvd 3.0 3.0 3.0 3.0 3.0 3.0 3.0 NO„,@ 15%O2 Maximum ppmvd 3.0 3.0 3.0 3.0 3.0 3.0 3.0 CO,@ 15%02 ppmvd 9.0 9.0 9.0 9.0 9.0 9.0 9.0 VOC,as CH4 @ 15%02 ppmvd 2.0 2.0 2.0 2.0 2.0 2.0 2.0 NH3 Slip,@ 15%02 ppmvd 10.0 10.0 10.0 10.0 10.0 10.0 10.0 NO„,as NO2 Annual Average lb/hr 25 23 24 24 13 19 12 NO„,as NO2 Maximum lb/hr 25 23 24 24 13 19 12 CO lb/hr 46 42 43 44 24 35 23 VOC,as CH4 lb/hr 5.8 5.3 5.5 5.6 3.0 4.5 2.9 PM10(excludes H25O4 mist) lb/hr 17.6 17.1 17.2 17.1 11.0 11.0 11.0 NH3 lb/hr 30.9 28.3 29.0 29.9 16.0 23.7 15.4 SO2,Annual Average lb/hr 1.4 1.3 1.3 1.4 0.7 1.1 0.7 SO3,Annual Average lb/hr 0.0 0.0 0.0 0.0 0.0 0.0 0.0 H25O4 Mist,Annual Average lb/hr 1.0 1.0 1.0 1.0 1.0 1.0 1.0 SO2,Maximum lb/hr 1.4 1.3 1.3 1.4 0.7 - 1.1 0.7 803,Maximum lb/hr 0.0 0.0 0.0 0.0 0.0 0.0 0.0 H2SO4 Mist,Maximum lb/hr 1.0 1.0 1.0 1.0 1.0 1.0 1.0 HRSG 4 of 4 7/9/2005 AL C: CPINE I Rocky Mountain Energy Center Expansion Expected Combustion Turbine Start Emissions Hot Start Emissions NO„, as NO2 lb/hr 80 CO lb/hr 902 VOC, as CH4 lb/hr 16 PM10 Note 1 lb/hr 19 SO2 Note 1 lb/hr 1.4 Cold Start Emissions NO, as NO2 lb/hr 80 CO lb/hr 902 VOC, as CH4 lb/hr 16 PM10 Note 1 lb/hr 19 SO2 Note 1 lb/hr 1.4 Notes: 1. SO2 and PM10 values are the calculated worst-case full load emission rates. CTG Start 1 of 1 7/9/2005 p p p p p p p p p p p �1�l ' 628626282 $ 8888888 $ 8888 $ 86:888888 N m O O O o 0 00 $ $ O $ $ 0 O O $ O O 0 $ $ O N ^.'O 8 Y 4 $ O 0 0 ^ 0 0 OO O O O O OO O OO O OO OO O C OO O O O O OO H 2.N WON 2.w WON N p p p QQ OO pp pp N o Np N6" pp p p N8 j2� O C O O OO $ OO 0 0 0 0 0 0 0• 8 0 0 0 0 0 0 O 8 •0 N'0 W W W W W W O =000=000 O666oO 0 00 m n O o 0 0 0 8 0 0 8 8 8 8 8 8 8 8 8 8 8 8 $ $, a . o 0 118 q 8 8 3 ,V fV O O O O O O O O O O D O O G O O 0 0 0 0 0 0 0 N N N WO N N N O N LL 0 0 ^ of C 4 T 288888 $ 88888 $ 888 $ 888.„'-90, 9-„,08 N m JL aim - 000 mo 000000 , 00 , 00 . oN p Q ' O O O o G G 0 0 0 0 0 O 0 0 0 0 0 o O G 0 O O m 3:cWi O oWi, n O N J:. 1+1 O' N 0 111 . 0 0 r1"° 0 0 0 888888880° 80° 8880° 8888, LC) 4 O$ e g o o d c d o c d 0 o 0 d d O 0 d 0 c 0 c 0 0 d c N Z N N N Z 1Wp o N 9.:. p p p :N p O 1 Np Nm o N$ 0 1m.) O^ 0 0 'O 0 0 0 888888888888888 $ 2 „88, 8 , 888 0 0 00 $ 0 $ 0 0 0 00 O 0 000 0 00 $ 0r 8 Oy O o o Y g 6 0 0 0 o O 0 O O O O O o O O O O O O O O o 1•1Q N WO N 0 0 N _y$ son ron N N N N 8 N, N N (mV N N O I� ' %i 2 O r N Y ip CI 2 0 0 m 2 r N _2 n n m N pN 8 m N 00 NN N pN N lep•1 1N'I np 0 pN 1p1 17 Op O 166 Z.1'p1 160 9 0 88888888 $ 88 $ 8 $ 88888 $ 288 $ 8 8 8 8 8 8 8 $ 8 8 408 8 $ 8 88 8 8 8 $ 2 8 8 0 88 8 8 8 y E Q N 1.1 e N N N N m N N N 1.1 a 4 O =o =O ns 2 3 $ 8 LL 88882888888888888818888888, r N 0 0 $ o O 0 ^ N < 1q 19 OI 4 IG m N O G O 0 ' 0 f p L , 0 O m m N CO N O m 40 r N 0 0 00 N N c m 0 0 Co N 00 8 `0 m mr m m i-.a 0 w N t7 m 2 m 0 Y N N N fl•1 m 0 0 m N r 0 m O O R4 h a4 1� E a m 0 p 0 N 0 $ $ N N N 0 0 0 0 0 Cml 0 T O n N V 0 m m m $ 0 m 0 r 0 o V:20mNNm10•110'12 ^ NNNN10m ' 4N ^ 1.1Oo I6 211/1 8 ONI, $ N 8 0 8 $ 0 0 N $ $ N 8 $ N N $ N $ r $ O $ 0 m O^, gOn 10 000m 4 01. ro+ OMN 1110 - 00 p^ p ONer y p 1p .2C N V m 0 0 N 0 1m•1 0 N 0 . 0 0 $ N N m O m N $ 0 0 0 0 0,1 O N t7 4 m N 0 O m m 0- 1 L N N m m rn m m m m N m ... ... o: 1,- ,... R ,0 m m .4 m 1^n 2 o n u ,;m., m 04 0 0 N 0 N O O O m N O 8 0 0 m N 0 0 $ 0 0 8 0 $ 0 0 b > p i0 N 0 001 0 _ t a1 N N ^ l0V N o m 0 N N 0 0 0 Ip N 1'1 r N r-: 1 N N N N N N N N ( N 1- N m m m 0 '- O o - $ O N 0 N vi a Cl) m m ea' rn m N a m °le O n o 4 ' n Imp 80' n o < 0 < 7 i,E 0 `o _ 04 0 a 0 _ a, 01 0 0 e , ' o O o . z ^ Z ^ : c 000000 ^ ^ � m a a p 4 N O N 4 m � m 0 b 0 m '•.0 8 O 68 ; 22 § 88822262222422282 0 0_ . 2 01 N n m_ P 4_ m 0 l4V N O 0 0 ^ 8y N o ^ 0 m m C _ _ _ N 6 0 0 < 2 < O m 66666666666666666666666666 OOOOOOOOOOOOOOOOOOOO OOOO Z O 2 O 0= t7 O N 4 4 ^ m ^ m N N 0 f O 0 0 m O 0 0 0 0 0 0 a m a p o 0 0 0 'o $ 8 , g n 40, o f2 " " a `Si n c94 -' n •n n 1'• �,; m m e m m N m m = m m m N N N C ON . e4e Doe oe $ " a^ o0000 $ 0 � e1OO en en . 800 8 �8 11IIr� p N N m O O O, O 0 O >.X"S pi O N O O O O O o O O O o O O O O O O O O O ^ 4 $ 666 666 a$.p LL 0 E C o 0 •a o o y aq < o oq p 0 0 p o o $ 0 ^ p C w A r N F O 0 + O, 0 + 0 0 0 0 0 `! 0 8 $ ry ` a5 a p. ^.d. _ OOOOOOOOOOOOOOOOOOOO6OO66OO6 6O6O6O6 O O 8 8 Ea Ea « R . m 0 0a0 - ° assy � ;F ;ea � aF � aaFe aE ae c0 v p $ " 9 & a a o o $ § § 0 8 8 8 8 § § § § § g S m 1 0 a>oo `° m ^ o) _ciao E 86666666666666666666666 ° `a o' C 2 W W e e .. .. x p C _ _ _ _ _ _ _ ___ o N N n 2 ° 2 x O a j1 U U U U U O O O U U U U U U U U U U U U 0 2 Z 0 N 2 w 2 U O c c t L pZ T; > N w > $- m > m m e c a > d y s 3 > 0 < y mg T 0 c m m > > c t L7 �„� y : > 2 > L h > 5'> > d m m n 5 m E ? ? s -] -x.2 3 Ku Zwam & c n c wh m � xaz> f w < 2 'zur<awxh.2Est= 'i Appendix C Modeling Input/Output Files on CD Modeling file CD included in the original signed copy only. Appendix D Miscellaneous Support Data APPLICABLE REQUIREMENTS AND FORM 2000-604 Operating Permit An of Rev 06-95 Colorado Department of Public Health and Environment STATUS OF EMISSION UNIT Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: New Unit 4. Unit identification code: New Unit 8. Limitation 9. Compliance 5. Pollutant 6. Colorado Air Quality 7. Status Regulations State or Only IN OUT Construction Permit Number Reg. 1.III.A.1.c (Section ✓ PE =0.5(FI)-o.zs ✓ PM II.C) <20% Opacity v'Smoke and Opacity Reg. 1.II.A.1(Section II.C) ✓ EPA Method 9 NO„ 40 CFR60 Subpart Da PM <0.03 Ib/MMBtu ✓ <20°/0 Opacity except 1 —6 vg Smoke and Opacity 40 CFR60 Subpart Da min <27% per hour NOx 40 CFR60 Subpart Da NO„<0.2 lb/MMBtu ✓ SO2 40 CFR60 Subpart Da SO2 < 0.2 Ib/MMBtu V NO,<<0.01394 Ib/MMBtu Turbine NO„CO, VOC and CO < 0.04537 Ib/MMBtu fry PM Control Equipment BACT pt l <0.00735 1b/MMBtu Limits VOC < 0.04537 Ib/MMBtu Hourly NO,@15°/n Oz ivNO, Reg. 6, Part A, Subpart GG <102ppmvd burning NG, Hourly SO2 @15% O2 Reg. 6, Part A, Subpart GG <150ppmvd or sulfur content, ✓ SO2 in fuel <0.8%,., Reg. 6, Part B,II,D,3,b ✓ Hourly SOz<0.35 lb/MMBtu ✓ SO2 (Section II.D) NO,&CO Permit 02WE0228 Mod 1 ✓ GEMS with QA/QC Plan ✓ Odor Reg 2.A.2 V Detection after 15x dilution ✓ i 10. Other requirements (e.g., malfunction reporting, special operating conditions from an State Only Compliance ce existing permit such as material usage, hours of operation, etc.) IN OUT General Provisions (40 CFR 60 Part A), Subpart Misc. Startup, shutdown excess ✓ emission reporting ✓ Permit 02WE0228 Condition 10 Fuel Usage Limit ✓ Permit 02WE0228 Condition 13 Initial Performance Stack Tests APEN Reg.3 Annual Reporting if changed we iv **** USE FORM 2000-700 TO EXPLAIN HOW COMPLIANCE WAS DETERMINED FOR EACH APPLICABLE REQUIREMENT**** a Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division E INSTRUCTIONS ON REVERSE SIDE Facility name: Rocky Mountain Energy Center 2.Facility identification code:CO 12 3 13 4 2 3. This form supplements Form for Emission Units New Unit Additional Information, Diagrams Item Number Pollutant Colorado Air Quality Regulations Criteria and non-criteria pollutants Reg No. 1 (5 CCR 1001-3) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 3, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-5) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 4, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-6) Criteria and non-criteria pollutants Reg No. 5 (5 CCR 1001-7) Criteria and non-criteria pollutants Reg No. 6 (5 CCR 1001-8) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 7 (5 CCR 1001-9) Criteria and non-criteria pollutants Reg No. 8 (5 CCR 1001-10) criteria and non-criteria pollutants Reg No. 9 (5 CCR 1001-11) Criteria and non-criteria pollutants Reg No. 10 (5 CCR 1001-12) Criteria and non-criteria pollutants Reg No. 11 (5 CCR 1001-13) Criteria and non-criteria pollutants Ambient Air Quality Standards (5 CCR 1001-14) Criteria and non-criteria pollutants Reg No. 12 (5 CCR 1001-15) Criteria and non-criteria pollutants Reg No. 13 (5 CCR 1001-16) Criteria and non-criteria pollutants Reg No. 14 (5 CCR 1001-17) Criteria and non-criteria pollutants Reg No. 15 (5 CCR 1001-18) Criteria and non-criteria pollutants Reg No. 16 (5 CCR 1001-19) Criteria and non-criteria pollutants SIP and Listed Nonattainment Areas (5 CCR 1001-20) Criteria and non-criteria pollutants Reg No. 18 (5 CCR 1001-22) Criteria and non-criteria pollutants Reg No. 19 (5 CCR 1001-23) AQRV & Visibility Analyses Colorado Air Pollution Control Division February 17, 2005 Northern Front Range: Visibility: Evaluate potential visibility impacts for receptors less than 50 km from the proposed source with the VISCREEN model. For receptors greater than 50 km from the proposed source include in the regional haze evaluation. Class I areas to be included in the evaluation: Rocky Mountain National Park Rawah Wilderness Area Mt. Zirkel Wilderness Area Eagles Nest Wilderness Area Files with the recommended receptor grid for all Federal Class I areas can be downloaded from: http://www2.nature.nps.gov/air/mans/Receptors/index.htm Apply the analysis techniques presented in the Federal Land Managers' Air Quality Related Values Workgroup (FLAG), Phase I Report,December 2000. The FLAG document provide seasonal background values for each of the Class I areas. Class II areas to be included in the evaluation: Name of Area Lake or Feature Background Receptor ece E ptor LValues UTM ocation N Zone 13 Zone 13 Pawnee National Pawnee Buttes FLAG- Rocky 586,514 4,519,602 Grasslands Mountain NP Mount Evans WA Upper Middle Bear Tracks FLAG-Rocky 447,883 4,380,132 South Mountain NP 442,329 4,382,311 Indian Peaks WA Blue FLAG- Rocky 447,223 4,437,569 Crater Mountain NP 443,463 4,436,236 No Name 441,388 4,427,859 Total Deposition: Evaluate potential atmospheric deposition impacts by estimating the total deposition of sulfur and nitrogen compounds. Use the same receptor grid use for the visibility analysis. See the FLAG document for more guidance. Class I Areas to be evaluated: Rocky Mountain National Park Rawah Wilderness Area Mt. Zirkel Wilderness Area Eagles Nest Wilderness Area Flat Tops Wilderness Area For the purposes of this analysis, since the Rocky Mountain National Park is the closest Federal Class I area to be evaluated, impacts can be evaluated using Guidance on Nitrogen and Sulfur Deposition Analysis Thresholds. See the FLAG website to download the guidance: http://www2.nature.nps.gov/airipermits/flag/flaeinfo/ Class II areas to be included in the evaluation: Name of Area Lake or Feature Receptor Location UTM E UTM N Zone 13 Zone 13 Pawnee National Pawnee Buttes 586,514 4,519,602 Grasslands Mount Evans WA Upper Middle Bear Tracks 447,883 4,380,132 South 442,329 4,382,311 Indian Peaks WA Blue 447,223 4,437,569 Crater 443,463 4,436,236 No Name 441,388 4,427,859 Lake Chemistry Evaluation: Evaluate the potential impacts of the proposed source to the chemistry of sensitive lakes. A user's guide has been prepared by the US Forest Service, "Screening Methodology for Calculating ANC Change to High Elevation Lakes", January 2000. Lakes to be included in the evaluation: Rawah WA Island Rawah Lake#4 Indian Peaks WA Blue Crater No Name Mount Evans WA Upper Middle Bear Tracks South Eagles Nest WA Booth Upper Willow • For lakes in the Class I areas, site-specific receptors can be included for the lakes or the same grid used for the visibility analysis can be used. When using the visibility receptor grid, if a receptor does not fall at the same site as the lake, use an average of the receptors surrounding the lake to determine the annual deposition. See attached Excel spreadsheet file (USFS Sensitive Lakes Feb 04.xls) for the location and background values for each of the lakes. CO C 0) r n N CD 7 N CD CO `N n co-N N `0 =W N `tD `N CO CO OD CO CO OD CO CO 0 CO CU ` OD CO Q Q cc cc Q Q L r C .C L C L 3 3 3 3 3 3 1n LO n CO 0) CO n Oo n co 0) Nt rr C00 (nD N OD N M N e to CO c 0 O L .C t -C -C N m h O 0 0 v 3 3 Co 3 3 3 O coal OM MM 0 O N 0 W n 0 (0 00) 0) N N '- N N CO 6 h h co 0, O 0 0 0 0 0 E E E E E E n co E ti co co co CD 0) V u) rO _ Cl @ r r) OP C�O Tm R �N V N CtTNO tT(O � q, Lai O Oin CD 0 0 Q Q Q Q Q Q i e0 e 0" O 0 O 0 O 0 r • 0 0 0-) M co M 0) 0 0 0 0 0 W 00 WNCDN W cc) ca W ' O W u) W! No V O N O CO. W M O T Z of F M M n O W n M't I- 7 � vv evv v v J co co v co) M N O COO Cam') N CON CI N O N O In Zroin Z 1n CV CO Z 7- CI0 (N Zrnrn Zw 200 rno gro co of gram grnm g ' goo '- < N � 't C V F MC) F- MM l-- N. NN • v a a V a J v Ni J v a v I- v a co N O• ar' N r- CO N n O ---OD N 0 Co OWN O Ma -Occorr O °' r ON OOD N N � N N N `0 N N "O'0 O O `_" O N 0 O)DD O)DDD 0)DD O)DD 0)D 70). -o C N N C )O N N C LO )0 C CD CD C O O co O o 0 0 0 0 0 J 0 0 0 0 J 7- J M • M O CD N N fra'Y I) co N O M CN ED 0 tn.) a 0 0 0 0 0 M coam 0 7 co O N 0 O , N N 0 0 0 0 _ co co O 0 N N 0 D D ' D D D D D O D D O D O D D 1600 00000 CO CO CD m 0O) J 0 co M 1--- ....i K K J V a a J CO CO J CO CO N T.'" C,O O f0+) JC O CO') .O 0 .c...co ��...N O O 7- 7- C CO N CO C CO 01 C V ' C 7- Z N N O O .�- O .- O r r _ 0 m N 03 76 70 C CD 0 N 0 0 W W W W W W 0 Y CO -J D 0 a CO Y CO r O ` C < Co O C H o 3 0 ca 0 4 a m R cli > $ m J SaS .00 Y Q 0 Y Cit, 0 D 0 12 o 0 O O 0 0 J 0 a J O C E J a W 0 W N Z 0 3 E CO (n ..0_. 03 3 0 N t E Z a z m Z A z _ m ZD m c2 m ys ^) m d iS m0 d t7 0 76 J: cn z m e m m 0 z o d O. rns o a D C s a s rn � 0 m m m v , D `e o o O a o m m o a o co m a m m E 7 Z J y � S _J C) Z 2JDN L11 -.) C07 Cl) N J 7 J a V) 7 COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT AIR POLLUTION CONTROL DIVISION TECHNICAL SERVICES PROGRAM TO: Greg Darvin FROM: Nancy Chick SUBJECT: Background Concentrations DATE: May 16, 2005 The following background concentrations are recommended for your modeling project. Blue Spruce Energy Center Near Watkins, CO Basis for Estimate PM10 Annual Arithmetic Mean 22 ug/m3 Rocky Mountain Arsenal PM10 24 Hour 2nd Max 66 ug/m3 1994 - 96 CO 1 Hour 2nd Max 5 ppm Welby, 78th & Steele CO 8 Hour 2nd Max 3 ppm 2001 - 2003 NO2 Annual Mean .010 ppm Denver Airport 1995 — 1996 SO2 Annual Mean .002 ppm Rocky Mountain Arsenal SO2 3 Hour 2nd Max .036 ppm 1992 - 1996 SO2 24 Hour 2nd Max .011 ppm Ozone 1 Hour 2nd Max .098 ppm Rocky Mtn Arsenal 1992-96 Ozone 8 Hour 2nd Max .069 ppm Lead 1 Month Average 0.03 ug/m3 Highest 2003 quarter at 215t and Broadway, Denver Rocky Mountain Energy Center Near Fort Lupton, CO Basis for Estimate PM10 Annual Arithmetic Mean 33 ug/m3 Fort Lupton Cogen PM10 24 Hour 2nd Max 83 ug/m3 1991 - 92 CO 1 Hour 2nd Max 5 ppm Welby, 78th & Steele CO 8 Hour 2nd Max 3 ppm 2001 - 2003 NO2 Annual Mean .012 ppm Kodak Windsor 1992 — 1994 SO2 Annual Mean .002 ppm Rocky Mountain Arsenal SO2 3 Hour 2nd Max .036 ppm 1992 - 1996 SO2 24 Hour 2nd Max .011 ppm Ozone 1 Hour 2nd Max .095 ppm Kodak Windsor 1992-94 Ozone 8 Hour 2nd Max .069 ppm Rocky Mtn Arsenal 1992-96 Lead 1 Month Average 0.03 ug/m3 Highest 2003 quarter at 215` and Broadway, File wp 4.3.5 STATE OF COLORADO Bill Owens,Governor Douglas H.Benevento,Executive Director ov cow Dedicated to protecting and improving the health and environment of the people of Colorado 4300 Cherry Creek Dr.S. Laboratory Services Division * Rte. Denver,Colorado 80246-1530 8100 Lowry Blvd. \F1876 Phone(303)692-2000 Denver,Colorado 80230-6928 'reps TDD Line(303)691-7700 (303)692-3090 Colorado Department Located in Glendale,Colorado of Public Health http://www.cdphe.state.co.us and Environment June 23, 2005 Gregory S. Darvin Atmospheric Dynamics, Inc. 2925 Puesta Del Sol Road Santa Barbara, CA 93105 Re: Modeling Protocol for the Calpine Rocky Mountain Energy Center Turbine/HRSG Modification Project Dear Mr. Darwin, The Air Pollution Control Division (Division)has reviewed the May 27, 2005 Modeling Protocol for the Calpine Rocky Mountain Energy Center Turbine/HRSG Modification Project (Protocol). The following comments are based on the expectation, as stated in the Protocol with no emissions estimates provided, of the project to be minor for sulfur dioxide (SO2)and volatile organic compounds (VOC)and major for nitrogen oxides (NON), carbon monoxide (CO), and particulate matter less than 10 microns (PMto)with respect to Prevention of Significant Deterioration(PSD). Changes to the status of the project may alter the scope of the modeling analysis. The protocol is approved provided that the comments are addressed in the modeling submittal. Comments: Goals of the Air Quality Modeling Analysis An ambient air quality analysis is necessary for a pollutant if impacts from the emissions increase exceed the modeling significance levels. If requested by the Division or the Federal Land Managers (FLMs), the Additional Impact Analysis (Regulation No. 3, Revision 4/22/04, Part D, Section VI.A.6) submitted for this project need to be included a Class II Area Acid Deposition Analysis. Applicability to USEPA Regulations Per Regulation No. 3, Revision 4/22/04, Part A, Section I.B.16, only volatile organic compounds (VOC) is a precursor to ozone. In addition to those listed in the Protocol for NON, VOC, SO2, CO, and PM1o, significant (PSD)emission rates also exist for lead, fluorides, sulfuric acid mist, hydrogen sulfide,total reduced sulfur and reduced sulfur compounds (Regulation No. 3, Revision 4/22/04, Part D, Section II.A.44.a). Provide emission rates for all of the pollutants above in the application/modeling submittal. Proposed Emission Sources The PMio emission rates in the application/modeling submittal should include both filterable and condensable PKo emissions. If a modeling significance level is exceeded for a pollutant subject to PSD review, a CAAQS/NAAQS analysis and a PSD increment analysis are triggered for that pollutant, averaging period, and area classification. If a modeling significant level is exceeded for a pollutant not subject to PSD review,a CAAQS/NAAQS analysis is triggered for that pollutant and averaging period. These analyses include new(including those with a complete application but not yet permitted) and existing nearby sources, within 5 km(minor modification) or 50 km(PSD modification) of the significant impact area of the project. Nearby sources outside this radius expected to increase impacts to approach or exceed standards should also be included in the analysis. Contact the Division for inventories of recently permitted sources, sources with a complete application but not yet permitted and existing nearby sources. The "Proposed Significant Ambient Concentrations for Class I Areas"and"Significance Levels for PSD for Class II Areas" on page 4 of the Protocol are modeling significance levels for Class I PSD increments and modeling significance levels for CAAQS,NAAQS, and Class II PSD increments, respectively. Existing Meteorological and Air Quality Data The Protocol proposes to use five (5) years(1986-1990) of meteorological data collected at Denver Stapleton Airport that was approved for the permit issued in 2002 for both ISCST3 and CALPUFF Screen modeling. If meteorological data collection is required with pre-construction monitoring (to be determined using results of the significant impact analysis),this data will be used in the ISCST3 modeling. Background Concentration The Protocol lists the background concentrations provided by the Division for the current project and for the 2002 application. For the record, the background concentrations listed in the 2002 application are 0.098 ppm for 1-hr O3, 5 ppm for 8-hr CO, 10 ppm for 1-hr CO, 33 µg/m3 for annual PM10, 101 µg/m3 for 24-hr PMio. If a CAAQS/NAAQS analysis is necessary, background concentrations are added to impacts from the project and nearby sources and then compared to standards. Air Quality Dispersion Models ISCST3 is appropriate for transport distances less than 50 km. This range is sufficient for near-field impact analyses such as CAAQS/NAAQS and Class II PSD increment analyses. CALPUFF Screen is used to determine impacts greater than 50 km from the project. Good Engineering Practice Stack Height and Downwash Provide the datum of the Universal Transverse Mercator(UTM) coordinates for emission points, buildings, and fencelines. Receptor Selection Provide the datum of the UTM coordinates for the receptors. The receptor grid should be large enough to capture the entire significant impact area. Fine receptor grid spacing (100 meters or less) should cover areas of elevated concentrations, including areas of violations, to determine the magnitude and location of the maximum concentration. 2 Load Screening The Protocol discusses the determination of the worst-case operating scenario with a screening analysis and using only the worst-case operating scenario in the ambient air impact analyses. For near-field impact analyses, follow EPA's Guideline on Air Quality Models, "A range of operating conditions should be considered in screening analyses; the load causing the highest concentration, in addition to the design load, should be included in refined modeling." PSD Increment Consumption Analysis Compliance with Colorado's 75%increment consumption restriction is demonstrated if the maximum impact from the increment-consuming emissions of all emission units, existing and new, at the major stationary source (the facility or facilities that are considered a"single" source) is less than 75%of the applicable increment. Comparison of Impacts to NAAOS and CAAOS The CAAQS/NAAQS analysis includes nearby sources, new (including those with a complete application but not yet permitted) and existing. Pre- and Post-Construction Air quality Monitoring Requirements Per Regulation No. 3, Revision 4/22/04, Part D, Section VI.A.3 through VI.B.3, the Division may exempt pre- or post-construction monitoring if impacts from the project are less than the monitoring de minimis levels. Refer to the Division's October 29,2004 letter(attached)regarding pre-construction monitoring determination. Additional Impact Analysis The Division expects the applicant to prepare an inventory of nearby soil and vegetation types in the area AND review literature or work with specialists to determine if any of the inventoried soils or vegetation of recreational or economic value (e.g., crops) would be adversely affected by impacts from the proposed facility/modifications. Sources of information for inventory development are, but not limited to, CSU cooperative extension, local Chamber of Commerce, Department of Agriculture, and Department of Natural Resources. Good references for a literature review are studies and reports published by,but not limited to, the above references and EPA, USDA Forest Service,National Park Service (NPS), and universities. From the New Source Review Workshop Manual (page C.31), "... if no significant ambient impacts are predicted for a particular pollutant, the applicant must still consider any additional impacts which the proposed source may have concerning impairment on visibility, soils and vegetation, as well as any adverse impacts on air quality related values in Class I areas." Coleen Campbell or the FLMs may provide additional comments. Class I and Sensitive Class II Area Impacts CALPUFF Screen is used to determine the project's impact on visibility, acid deposition, and Class I PSD increment. CALPUFF Screen is not suitable for modeling multiple facilities in a regional haze analysis. To determine the full impact from the modification, the Division requests that all emissions (NOx, SO2, and PMio, H2SO4) increases be included in the visibility analysis. Coleen Campbell or the FLMs may provide additional comments. CALPUFF Dispersion Model— Screening Mode A minimum of one receptor ring is used to determine acid deposition impacts at sensitive lakes. Land use, leaf area index, and roughness length should be based on a domain-average (path from the facility 3 to the area of interest). PMK()dry and wet deposition is not selected. Deposition of PMio is acceptable. In the absence of specific data, speciation of condensable PM10 into organic carbon and sulfates should follow National Park Service's recommendation (http://www2.nature.nps.gov/air/Permits/emissions ControlTech.cfm#particle) for use in CALPUFF Screen. Coleen Campbell or the FLMs may provide additional comments. CALPOST Model Options Species used in the visibility analysis should follow National Park Service's recommendation above. Coleen Campbell or the FLMs may provide additional comments. Nitrogen Deposition on Sensitive Lakes Coleen Campbell or the FLMs may provide comments. Increment Consumption and Cumulative Impacts The Protocol states"the same emission inventory used to assess increment consumption from cumulative impacts in Class II areas will be used in the Class I analysis." If a cumulative Class I increment analysis is necessary,contact the Division. The cumulative Class I and II inventories will not be the same due to the additional emissions units that are outside the transport range of ISCST3 (up to 50 km) and within the larger transport range (several hundred kilometers) of CALPUFF. Best Available Control Technology The permit engineer will review the BACT analysis and provide comments during the permitting process. If you have any questions,please contact me at 303-692-3192 or by e-mail at doris.iung(a,state.co.us. Sincerely, Doris Jung Technical Services Program Air Pollution Control Division Cc: Coleen Campbell,Division/Technical Services Program Chip Hancock, Division/Stationary Sources Program Jeff Sorkin, USDA Forest Service Bud Rolofson,USDA Forest Service Liana Reilly,National Park Service John Notar,National Park Service 4 STATE OF COLORADO Bill Owens,Governor Douglas H.Benevento,Executive Director .p4•cozo Dedicated to protecting and improving the health and environment of the people of Colorado o 4300 Cherry Creek Dr.S. Laboratory Services Division * * Denver,Colorado 80246-1530 8100 Lowly Blvd. « ' * Phone(303)692-2000 Denver,Colorado 80230-6928 reps TDD Line(303)691-7700 (303)692-3090 Colorado Department Located in Glendale,Colorado P of Public Health http://www.cdphe.state.co.us and Environment July 7, 2005 Gregory S. Darvin Atmospheric Dynamics, Inc. 2925 Puesta Del Sol Road Santa Barbara, CA 93105 Re: Modeling Protocol for the Calpine Rocky Mountain Energy Center Turbine/HRSG Modification Project Dear Mr. Darwin, The Air Pollution Control Division (Division) has reviewed the May 27, 2005 Modeling Protocol for the Calpine Rocky Mountain Energy Center Turbine/HRSG Modification Project (Protocol). The following comments are based on the expectation, as stated in the Protocol with no emissions estimates provided, of the project to be minor for sulfur dioxide (SO2) and volatile organic compounds (VOC) and major for nitrogen oxides (NOx), carbon monoxide (CO), and particulate matter less than 10 microns (PMIo) with respect to Prevention of Significant Deterioration (PSD). Changes to the status of the project may alter the scope of the modeling analysis. Doris Jung, Division, provided comments regarding the modeling on June 23, 2005. The protocol is approved provided that the comments provided by Doris Jung on June 23, 2005 and the comments provided below are addressed in the modeling submittal. Comments: Class I and Sensitive Class H Area Impacts As included in Doris Jung's June 23, 2004 memo, to determine the full impact from the modification, the Division requests that all emissions (NOx, SO2, and PMIo, H2SO4) increases be included in the visibility analysis. CALPUFF Dispersion Model— Screening Mode A minimum of one receptor ring is used to determine acid deposition impacts at each of the sensitive lakes to be evaluated. Evaluate the lakes listed on page 22 of the protocol. Total Deposition The significance level for deposition in the western United States is 0.0005 kg/ha-yr at Class I areas. A significance level has not been established for the Class II areas, but disclosure of the potential impacts is provided for interested public. All of the Class II areas listed on page 20 of the modeling protocol are to be included. Sensitive Lakes Nitrogen and sulfur deposition is to be estimated and the change in acid neutralization capacity(ANC) is to be calculated for the bodies of water indicated on page 22. The USFS has established the following thresholds for ANC change in high altitude lakes: For lakes with ANC 25 and above, a 10% change in ANC. For lakes below 25 ANC, a 1 ueq/l change. (note: different units) Lakes with zero or negative ANC are evaluated against a threshold of"no change. If you have any questions, please contact me at 303-692-3224 or by e-mail at coleen.campbell@state.co.us. Sincerely, Coleen Campbell Technical Services Program Air Pollution Control Division Cc: Dan Ely, Division/Technical Services Program --* WP File 4.2.2.8 Doris Jung, Division/Technical Services Program Chip Hancock, Division/Stationary Sources Program Jeff Sorkin, USDA Forest Service Bud Rolofson, USDA Forest Service Liana Reilly, National Park Service John Notar, National Park Service 2 Jim Hines From: Jim Hines Sent: Tuesday, June 28, 2005 1:11 PM To: Kent Morton Cc: Jim Gooding; Jim Hines Subject: American Farm Land Trust CE Kent, FYI- After repeated calls and two letters, American Farmland Trust called. They stated they are not pursuing any land trusts or conservation easements in Colorado. They did offer some other groups to contact, which I will do. They include the Colorado Cattleman Association Agricultural Land Trust, and the Colorado Coalition of Land Trusts. Jim Hines, CCIM Director, Land Department Western Regional Office 925-479-6664 925-577-7503 cell Jim Hines.vcf 1 Anacapa Land Company, LLC P.O. Box 11749 Pleasanton, CA 94588-1749 Phone: 925-479-6664 Tall Free: 877-446-4466 Fax: 925-479-7309 Junel, 2005 American Farmland Trust 1200 18th Street, N.W. Washington, D.C. 20036 Re: Donation of+/- 600 Acres of Agricultural Land Weld County, Colorado Dear Sir or Madam; This is a follow-up of our April 5, 2005 letter (see copy attached) whereby Anacapa Land Company, LLC ("Anacapa") is interested in donating or placing into an agricultural trust approximately 600 acres of prime farmland located in Weld County, Colorado. Anacapa Land Company strongly desires that this parcel remain in productive agricultural use, and would be very interested in discussing the terms and conditions upon which the American Farmland Trust could take stewardship of this beautiful property. Please contact me at 925-479-6664 or my assistant Deanne Boreni at 925-479-6628 to discuss how this property may benefit the American Farmland Trust. Sincerely, mes A. Hines, CCIM irector , _ . ..., . . . Land Department r1\3.,, #' Anacapa Land Company, LLC P.O. Box 11749 Pleasanton, CA 94588-1749 Phone: 925-479-6664 Toll Free: 877-446-4466 Fax: 925-479-7309 April 5, 2005 American Farmland Trust 1200 18th Street, N.W. Washington, D.C. 20036 Re: Donation of+/-600 Acres of Agricultural Land Weld County, Colorado Dear Sir or Madam; Anacapa Land Company, LLC ("Anacapa") is interested in donating or placing into an agricultural trust approximately 600 acres of prime farmland located in Weld County, Colorado (see attached site map) that Anacapa currently owns. Anacapa desires that this parcel remain in productive agricultural use, and would be very interested in discussing the terms and conditions upon which the American Farmland Trust could take stewardship of this beautiful property. Should American Farmland Trust be interested in this property, copies of the Mineable Resource Investigation Report and the Mineral Remoteness Report for Conservation Easement can be made available for further review. I look forward to discussing how this property may benefit American Farmland Trust. Please call me at 925-479-6664 or my assistant Deanne Boreni at 925-479-6628. Sincerely, ames A. Hines, CCIM irector Land Department LC , cic_s,a11JeT (Lc STATE OF COLORADO Bill Owens,Governor Douglas H.Benevento,Executive Director 0v.cot Dedicated to protecting and improving the health and environment of the people of Colorado yei �o 4300 Cherry Creek Dr.S. Laboratory Services Division * boy* Denver,Colorado 80246-1530 8100 Lowry Blvd. (Ins' Phone(303)692-2000 Denver,Colorado 80230-6928 TDD Line(303)691-7700 (303)692-3090 Weld County Planning Department Colorado Department Located in Glendale,Colorado n7rgp F`/ 0'Flr`F of Public Health http://www.cdphe.state.co.us and Environment APR 0 i 2007 March 26, 2007 R,E C t G V E D Steve Moreno Weld County Clerk 1402 N. 17th Ave. Greeley, CO 80631 Dear Mr. Moreno: On April 4, 2007, the Air Pollution Control Division will publish a public notice for Rocky Mountain Energy Center in the Farmer and Miner, March 29, 2007 in the Windsor Beacon, and March 27th in the Ft. Morgan Times, A copy of this public notice and the public comment packet are enclosed. Thank you for assisting the Division by posting a copy of this public comment packet in your office. Public copies of these documents are required by Colorado Air Quality Control Commission regulations. The packet must be available for public inspection for a period of thirty(30) days from the date the public notice is published. Please send any comment regarding this public notice to the address below. Colorado Dept. of Public Health&Environment APCD-SS-B 1 4300 Cherry Creek Drive South Denver, Colorado 80246-1530 Attention: Jacquie N. Barela Regards,>2 C 6:71 Jo Matson for Jacqueline N. Barela Public Notice Coordinator Stationary Sources Program Air Pollution Control Division Enclosure 1 t_Let(C. r et11 CLCJ 1 ,,tr. _ ncr „n 0C '• 41— / �L TITLE V PERMIT APPLICATION ROCKY MOUNTAIN ENERGY CENTER WELD COUNTY COLORADO March 2005 Submitted on behalf of Rocky Mountain Energy Center, LLC CIO Calpine 6211 Weld County Road 51 Keenesburg, CO 80643 Prepared by Arc_Qais4 . ,ATMOSPHE' 3 AMICS METEOROLOGICAL AND AIR QUALITY MODELING Atmospheric Dynamics, Inc. 2925 Puesta del Sol Rd. Santa Barbara, CA 93105 NOTICE OF A PROPOSED TITLE V OPERATING PERMIT WARRANTING PUBLIC COMMENT NOTICE is hereby given that an Operating Permit application has been submitted to the Colorado Air Pollution Control Division, 4300 Cherry Creek Drive South, Denver, Colorado 80246-1530, for the following source of air pollution: Applicant: Rocky Mountain Energy Center, LLC. 717 Texas Avenue, Suite 1000. Houston, TX 77002 Facility: Rocky Mountain Energy Center 6211 Weld County Road 51 Keenesburg, CO 80643 Rocky Mountain Energy Center, LLC. has applied for an Operating Permit for their facility in Weld County, CO. This facility consists of two (2) combined cycle combustion turbines used to generate electricity. Each turbine is equipped with a heat recovery steam generator and natural gas fired duct burner. The only fuel used in these units is natural gas A Copy of the applications, including supplemental information, the Division analysis, and a draft of the Operating Permit 05OPWE279 has been filed with the Weld County Clerk's office. Based on the information submitted by the applicant, the Division has prepared the draft operating permit for approval. Any interested person may contact Jackie Joyce of the Division at 303-692-3267 to obtain additional information. Any interested person may submit written comments to the Division concerning 1) the sufficiency of the preliminary analysis, 2)whether the permit application should be approved or denied, 3) the ability of the proposed activity to comply with applicable requirements, 4) the an quality impacts of, alternatives to, and control technology required on the source or modification, and 5) any other appropriate air quality considerations. Any interested person may submit a written request to the Division for a public comment hearing before the Colorado Air Quality Control Commission (Commission). If requested, the hearing will be held before the Commission at their regularly scheduled meeting within 60 days of its receipt of the request for a hearing unless a longer time period is agreed upon by the Division and the applicant. The hearing request must: 1) identify the individual or group requesting the hearing, 2) state his or her address and phone number, and 3) state the reason(s) for the request, the manner in which the person is affected by the proceedings, and an explanation of why thf person's interests are not already adequately represented. The Division will receive and consider the written public comments and requests for any hearing for thirty calendar days after the date of this Notice. RELEASED TO: Farmer& Miner PUBLISHED: April 4, 2007 The Windsor Beacon Published: March 29, 2007 Ft. Morgan Times Published: March 27, 2007 on March 26, 2007 COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT AIR POLLUTION CONTROL DIVISION OPERATING PERMIT SUMMARY PERMIT NUMBER: 05OPWE279 AIRS ID#: 1231342 DATE: March 26, 2007 APPLICANT: Rocky Mountain Energy Center, LLC REVIEW ENGINEER: Jacqueline Joyce SOURCE DESCRIPTION Rocky Mountain Energy Center, LLC has applied for an Operating Permit for their facility located at 6211 Weld County Road 51 in Weld County. This facility consists of two combustion turbines, each equipped with a heat recovery steam generator(HRGS) and duct burner used to generate electricity and is classified under SIC 4911. Natural gas is the only fuel used in these turbines and duct burners. In addition to the turbines and duct burners, this facility consists of a diesel fuel-fired emergency generator, a natural gas-fired auxiliary boiler and a cooling water tower. This facility is located in an area designated as attainment or attainment/maintenance for all criteria pollutants and is located within the 8-hr ozone control area. Rocky Mountain National Park, a Federal Class I designated area is within 100 km of this facility. There are no affected states within 50 miles of this facility. This facility is a major stationary source for the purposes of Prevention of Significant Deterioration (PSD) requirements. This facility is subject to 112(r), the Accidental Release Requirements. Since potential controlled emissions from the turbines exceed the major source level (100 tons/yr), the compliance assurance monitoring (CAM) requirements apply to each turbine/HRSG/duct burner. FACILITY EMISSION SUMMARY Potential To Emit Emission Unit PM PKo SO2 NOx CO VOC HAPS' Turbines/HRSGs2 126.8 126.8 11.8 240.4 782.2 50.6 See Table • Aux. Boiler3 2.28 2.28 0.08 4.7 4.75 0.58 on Page Fire Water Pump4 0.43 0.43 0.03 1.02 0.61 0.13 32 Emergency Generators 0.20 0.20 0.04 3.44 4.24 0.05 Cooling Towel-6 19.3 19.3 0.89 "spa - .? , Total 149.01 149.01 11.95 249.56 791.80 52.70 13.01 HAP emissions are based on the Division's analysis. The total HAP limit is set at 13.10 tons/yr. 2Based on the permitted emissions indicated in Attachment A of the permit. 3PM, PKo and CO emissions based on requested emissions provided on the APEN submitted on March 21, 2007. SO2 and VOC based on the Division's analysis. NOx based on the permitted emissions indicated in Attachment A of the permit. °Based on the APEN de minimis of 850 hours/year of operation (per Reg 3, Part A, Section II.D.1.sss.(ii)), these are higher than requested and provided for in the construction permit. sBased on the permit de minimis of 250 hours/year of operation (per Reg 3, Part B, Section II.D.1.c.(ii)), these are higher than requested and provided for in the construction permit. sBased on requested PM and PM10 emissions on the APEN submitted on March 21, 2007. Note VOC emissions are chloroform emissions, which is also a HAP. Note that the source reports potential emissions in lieu of actual emissions; therefore, data on actual emissions is not available. EMISSION SOURCES Two (2)turbines/HRSGs/duct burners—There are two permitted turbines/HRSGs/duct burners at this facility. Each combustion turbine can generate approximately 152 MW, with an additional 326 MW from the steam turbine. The turbines are not equipped with a by-pass stack, therefore, the turbines only operate in combined cycle mode (e.g. turbine plus HRSG). Best available control technology(BACT) requirements applied to these units for PM, PM10, NOx, CO and VOC emissions. BACT for these turbines was determined as follows: NOx: dry low NOx combustion systems and selective catalytic reduction, CO: good combustion practices and an oxidation catalyst,VOC: use of pipeline quality natural gas as fuel, good combustion practices and an oxidation catalyst and PM/PM1o_ use of pipeline quality natural gas as fuel. The turbines have BACT (short-term) emission limits for NOx, CO, VOC, PM and PM10. Compliance with the NOx and CO BACT limits shall be monitored using the continuous emission monitoring systems, compliance with the PM/PM10 BACT limit was demonstrated in a performance test, with a subsequent test required within the last eighteen (18) months of the permit term and compliance with the VOC BACT limit was demonstrated in a performance test. Since the oxidation catalyst controls both CO and VOC emissions, demonstrated compliance with the CO BACT limit using the CEMS is considered surrogate monitoring for the VOC BACT limit. Both units are also subject to the Acid Rain requirements. The turbines are subject to NSPS GG (NOx and SO2 limits), as well as Reg 1 limits for opacity, PM and SO2 and Reg 6, Part B limits for opacity, PM and SO2. The duct burners are subject to NSPS Da (NOx, SO2, PM and opacity requirements), as well as Reg 1 and Reg 6, Part B limits for opacity and PM. Streamlining of less stringent requirements has been done as appropriate. These units are subject to annual fuel consumption limits and annual PM, PM10, SO2, NOx, VOC and CO emission limits. Compliance with the annual NOx and CO limits are monitored using the continuous emission monitoring systems. Annual SO2 emissions are monitored using the continuous monitoring system required by Acid Rain. Compliance with the annual fuel consumption and the PM, PM10 and VOC emission limitations is monitored by recording fuel use and calculating emissions monthly. Compliance with the Reg 1 and Reg 6, Part B PM, opacity and SO2 limitations shall be presumed, in the absence of credible evidence to the contrary, since pipeline quality natural gas is the only fuel permitted to be used in the turbines and duct burners. The source shall use the procedures in 40 CFR Part 75 Appendix D to demonstrate that pipeline quality natural gas is used as fuel. Auxiliary Boiler—The auxiliary boiler is subject to BACT for PM, PM10, NOx and VOC. BACT for the boiler was determined as follows: NOx-low NOx burners, CO—good combustion practices, PM/PM10— use of pipeline quality natural gas and VOC use of pipeline quality natural gas. Short term BACT limits are included for NOx and CO. Compliance with the NOx BACT limit shall be monitored using the GEMS. Compliance with the CO BACT limit was demonstrated with an initial compliance test, with a subsequent test required within the last eighteen (18) months of the permit term. The boiler is also subject to NSPS Db (NOx limit and NOx CEMS), as well as Reg1 and Reg 6, Part B PM and opacity requirements. Streamlining of less stringent requirements has been done as appropriate. This unit is also subject to an annual fuel consumption limits and annual PM, PM10, NOx and CO emission limitations. Compliance with the annual fuel consumption and PM, PM10 and CO emission limits shall be monitored by recording fuel use and calculating emissions monthly. Compliance with the annual NOx limits shall be monitored using the CEMS. Compliance with the Reg 1 and Reg 6, Part B PM and opacity limitations shall be presumed, in the absence of credible evidence to the contrary, since pipeline quality natural gas is the only fuel permitted to be used in the boiler. Emergency Generator—The emergency generator was included in the construction permit but is exempt from APEN reporting requirements if operated for no more than 100 hours per year. Under that scenario the emergency generator would be considered an insignificant activity and included in Appendix A of the permit. If operated for more than 100 hours per year but less than 250 hours per year the emergency generator is exempt from the construction permit requirements in Regulation No. 3, Part B. Since the emergency generator is expected to operate for more than 100 hours but less than 250 hours in 2007, the emergency generator is included in Section II of the permit, rather than in the insignificant activity list. The emergency generator is subject to a Reg 1 SO2 emission limit. The permittee shall be required to record hours of operation annually and calculate annual emissions, if annual hours of operation exceed 100. Compliance with the Reg 1 SO2 limit is based on annual sampling of the diesel fuel or retention of vendor receipts, indicating the fuel sulfur content does not exceed 0.5 percent by weight. Cooling Water Tower—The cooling water tower is subject to BACT for PM and PM10 emissions. BACT has been determined to be drift eliminators capable of achieving drift levels of 0.0005% or less. Annual PM and PM10 emission limits, as well as annual limitations on the quantity of water circulated also apply to the cooling water tower. In addition, the cooling tower is subject to the Reg 1 opacity standard. Compliance with the annual limits on emissions and the quantity of water circulated will be monitored by determining water circulated and calculating emissions monthly. The total solids concentration in the circulating water is necessary to calculate emissions, therefore the source will determined the total solids concentration quarterly. Compliance with the opacity requirement is presumed, in the absence of credible evidence to the contrary, provided the towers and drift eliminators are operated and maintained in accordance with good engineering practices. Facility wide HAP limit—There is a facility wide HAP limit for both total HAPs and formaldehyde. The permit requires that emissions from significant HAPS be calculated monthly and a rolling twelve month total be maintained to monitor compliance with the HAP limits. Note that only the turbines/HRSGs/duct burners and the cooling tower are significant sources of HAPS. INSIGNIFICANT ACTIVITIES A list of insignificant activities is included in the draft Operating Permit. ALTERNATIVE OPERATING SCENARIOS No alternative operating scenarios are included in the draft Operating Permit. TECHNICAL REVIEW DOCUMENT For OPERATING PERMIT 05OPWE279 to be issued to: Rocky Mountain Energy Center, LLC Weld County Source ID 1231342 Prepared by Jacqueline Joyce September 2006 Revised October 2006 and March 2007 I. Purpose: This document establishes the basis for decisions made regarding the Applicable Requirements, Emission Factors, Monitoring Plan and Compliance Status of Emission Units covered within the Operating Permit proposed for this site. It is designed for reference during review of the proposed permit by the EPA, the Public and other interested parties. Conclusions made in this report are based on information provided by the applicant in the Title V application submitted March 14, 2005, comments on the draft permit and technical review document submitted on November 17, 2006 and January 19, 2007, additional information submitted on March 21, 2007, various telephone conversations and e-mail correspondence with the source and review of Division files. This narrative is intended as an adjunct to the reviewer and has no legal standing. Any revisions made to the underlying construction permits associated with this facility made in conjunction with the processing of this operating permit application have been reviewed in accordance with the requirements of Regulation No. 3, Part B, Construction Permits, and have been found to meet all applicable substantive and procedural requirements. This operating permit incorporates and shall be considered to be a combined construction/operating permit for any such revision, and the permittee shall be allowed to operate under the revised conditions upon issuance of this operating permit without applying for a revision to this permit or for an additional or revised Construction Permit. II. Source Description The Rocky Mountain Energy Center (RMEC) consists of two combined cycle combustion turbines used to generate electric power under Standard Industrial Classification 4911. The facility consists of two natural gas fired combustion turbines, two heat recovery steam generators, each equipped with natural gas fired duct burners, a steam turbine, cooling tower and auxiliary boiler. There are two diesel fired engines, one driving an emergency generator and one driving a fire pump. The RMEC has the capacity to generate up to 630 MW of electricity. Each combustion turbine can Page 1 generate approximately 152 MW, with an additional 326 MW from the steam turbine. The turbines are not equipped with a by-pass stack, therefore, the turbines only operate in combined cycle mode (e.g. turbine plus HRSG). The facility is located at 6211 Weld County Road 51, just east of the town of Hudson, in Weld County Colorado (bounded by CR 49 to the west, CR 16 to the north and CR 51 to the east). The area in which the plant operates is designated as attainment for all criteria pollutants, but is located within the 8-hour Ozone Control Area as defined in Colorado Regulation No. 7, Section II.A.16. There are no affected states within 50 miles of the facility. Rocky Mountain National Park, a Federal Class I designated area, is within 100 km of the facility. The facility is considered to be a major stationary source (potential to emit > 100 tpy of any criteria pollutant). Facility wide emissions are as follows: Potential To Emit Emission Unit PM PM10 SO2 NOx CO VOC HAPS' Turbines/HRSGs2 126.8 126.8 11.8 240.4 782.2 50.6 See Table on Page 32 Aux. Boiler3 2.28 2.28 0.08 4.7 4.75 0.58 Fire Water Pump" 0.43 0.43 0.03 1.02 0.61 0.13 Emergency 0.20 0.20 0.04 3.44 4.24 0.05 Generator' Cooling Towers 19.3 19.3 0.89 I s t '.- .. sn 3, ° k hf�.Tn c• ,. .„..:�'..2�. J Total 149.01 149.01 11.95 249.56 791.80 52.70 13.01 'HAP emissions are based on the Division's analysis. The total HAP limit is set at 13.10 tons/yr. 2Based on the permitted emissions indicated in Attachment A of the permit. 3PM, PM10 and CO emissions based on requested emissions provided on the APEN submitted on March 21, 2007. SO2 and VOC based on the Division's analysis. NOx based on the permitted emissions indicated in Attachment A of the permit. °Based on the APEN de minimis of 850 hours/year of operation (per Reg 3, Part A, Section II.D.1.sss.(ii)), these are higher than requested and provided for in the construction permit. 5Based on the permit de minimis of 250 hours/year of operation (per Reg 3, Part B, Section II.D.1.c.(ii)), these are higher than requested and provided for in the construction permit. 6Based on requested PM and PM10 emissions on the APEN submitted on March 21, 2007]. Note VOC emissions are chloroform emissions, which is also a HAP. Except as indicated in the footnotes in the above table, potential to emit of criteria pollutants.is based on the permitted emission limits specified in Attachment A of the construction permit (02WE0228, initial approval, modification no. 1, issued June 23, 2004). Note that the potential to emit above does not reflect the permitted emissions for a proposed new turbine at this facility (Colorado Construction Permit 05WE0524, initial approval issued July 17, 2006). An application to modify the Title V permit to include that turbine is due twelve months after that turbine commences operation. However, HAP emissions from that turbine are limited to 5.4 tons/yr for all HAPS and 1 tons/yr for Page 2 formaldehyde. Therefore, the facility is still a minor source for HAPS (18.5 tons/yr total, formaldehyde 3.44 tons/yr). The breakdown of HAP emissions for each emission unit is provided for in the table on page 32 of this document. The method for estimating HAP emissions is indicated in the footnotes on this table. The source indicated that this facility is subject to the 112(r) Accidental Release Requirements. A risk management plan was submitted to EPA as required. Compliance Assurance Monitoring (CAM) Requirements CAM applies to any emission unit that is subject to an emission limitation, uses a control device to achieve compliance with that emission limitation and has potential pre-control emissions greater than major source levels. The turbines/HRSGS are equipped with dry low NOx (DLN) combustion systems and selective catalytic reduction (SCR) to reduce NOx emissions and an oxidation catalyst to reduce CO and VOC emissions. Although DLN combustion systems are not considered control devices as defined in 40 CFR Part 64 § 64.1, as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV, since they are considered inherent process equipment, the SCR and oxidation catalysts are considered control devices. The turbines/HRSGS are subject to a variety of short-term and annual NOx, CO and VOC emission limits. The Division considers that the control devices are necessary to meet the NOx, CO and VOC short- term BACT emission limits and the annual NOx, CO and VOC emission limits. The Division does not consider that the SCR is necessary to meet the NSPS GG or Db NOx limitations. Therefore, CAM does apply to the turbines/HRSGs at this facility. For large pollutant specific emission units (emissions above the major source level, when control device considered), the CAM plan shall be submitted as part of the Title V permit application, if the application is submitted after April 20, 1998 (40 CFR Part 64 § 64.5(a)(1)(i), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). Permitted emissions of NOx and CO exceed the major source level (100 tons/yr), therefore, CAM applies to the turbines/HRSG for NOx and CO upon initial issuance of the Title V permit. Permitted VOC emissions are below the major source level; therefore, CAM does not apply with respect to VOC emissions until renewal of the Title V permit (40 CFR Part 64 § 64.5(b), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV III. Emission Sources The following sources are specifically regulated under terms and conditions of the Operating Permit for this Site. Units S001 and S002: Two (2) Westinghouse, Model No. 501FD, Combustion Turbines rated at 1785 mmBtu/hr (HHV at ISO conditions), Serial Nos. 37A8191 and 37A8196 and Two (2) Heat Recovery Steam Generators (HRSG), each Page 3 equipped with a duct burner rated at 675 mmBtu/hr. The facility power generating capacity is 630 MW(at peak capacity) from both turbines and both HRSGS. Each turbine is capable of generating 152 MW of power. The HRSGs serve a steam turbine rated at 326 MW. The turbines only operate in combined cycle mode and emissions from the turbines/duct burners are controlled by selective catalytic reduction (NOx) and an oxidation catalyst (CO and VOC). 1. Applicable Requirements: The initial approval construction permit (02WE0228) for the facility was issued on July 15, 2002, with a modification issued on June 23, 2004. A request was submitted on March 22, 2007 to revise the construction permit; however, the revisions only affected the emergency generator. According to the Title V permit application, the turbines/HRSGs commenced operation in March 2004. It is not clear when the self-certification was submitted and no final approval permit has been issued. Under the provisions of Colorado Regulation No. 3, Part C, Section V.A.3, the Division will not issue a final approval construction permit and is allowing the initial approval construction permit to continue in full force and effect. The appropriate provisions of the initial approval construction permit have been directly incorporated into this Title V operating permit. The applicable requirements included in the construction permit for the turbines/HRSGs/duct burners are as follows: • Within 180 days after commencement of operation, compliance with the conditions contained in this permit shall be demonstrated to the Division (condition 2). According to the Division's August 28, 2006 inspection report, the self- certification was submitted on October 14, 2004. Therefore, this requirement will not be included in the permit. • Emissions of hazardous air pollutants shall not equal or exceed the thresholds for applicability of MACT standards, prior to reaching these thresholds, this permit shall be suitably modified and standards complied with (condition 4). It is not clear why this condition is included in the permit. If facility HAP emissions exceed the major source level, the appropriate MACT standards would apply. This permit contains limitations on formaldehyde and HAP emissions to keep emissions below the major source level. This condition will not be included in the permit. • Regulation No. 6, Part A, Subpart Da — Standards of Performance for Electrical Steam Generating Units, applies to the duct burners, as follows (condition 7): o Particulate matter emissions shall not exceed 0.03 lbs/mmBtu (§ 60.42a(a)(1)) o Opacity of emissions shall not exceed 20% opacity (6-minute averages), except for one six-minute period not to exceed 27% (§ 60.42a(b)) Page 4 o SO2 emissions shall not exceed 0.20 lbs/mmBtu, on a 30-day rolling average (§ 60.43a(b)(2)) Note that 40 CFR Part 60 Subpart Da § 60.43a(b)(2) specifically states that the SO2 limitation is "100 percent of the potential combustion concentration (zero percent reduction) when emissions are less than 0.2 lbs/mmBtu". Since these units burn natural gas, emissions will be below 0.2 lbs/mmBtu (40 CFR Part 75, Appendix D allows sources burning pipeline quality. natural gas to use a default emission factor of 0.0006 lbs/mmBtu). Because emissions are below 0.2 lbs/mmBtu the source may emit 100% of the potential combustion concentration, i.e. no limits. However, since this "no SO2 limits" only applies if emissions are below 0.2 lbs/mmBtu, the Division included the upper bound of 0.2 lbs/mmBtu as the emission limitation. o NOx emissions shall not exceed 0.2 lbs/mmBtu. The NOx limit included in the construction permit is not correct. NSPS Subpart Da was revised September 16, 1998 and established different NOx limitations for sources that commenced construction or modification after July 9, 1997. Since the duct burner/HRSG commenced construction after July 9, 1997 the new NOx standard of 1.6 lbs/MW-hr in 40 CFR Part 60 Subpart Da § 60.44a(d)(1) applies to each duct burner. Although not included in the construction permit, the following requirements from NSPS Da also apply: o Compliance with the NSPS requirements shall be monitored in accordance with the requirements in 60.48a and 60.49a, including but not limited to the following: • Demonstrate compliance with the NOx emissions in accordance with the requirements in § 60.48a(k). The NSPS allows the permittee to either conduct a performance test or use a NOx continuous emission monitoring system (GEMS) to demonstrate compliance with the NSPS NOx limit. The source conducted performance tests on May 8, 11, 12, 20 and September 16, 2004. Although the incorrect NSPS limit was in the construction permit, the results of the testing indicate compliance with the correct NSPS Da NOx limits. NSPS Da does not require a NOx GEMS for duct burners (§ 60.49a(o)) and requires no further NOx monitoring for duct burners beyond the initial test. o Performance tests shall be conducted in accordance with the requirements in § 60.50a(f). The source has already conducted performance tests in May and September 2004, which included testing for PM and NOx, as discussed above. A performance test for SO2 was not required because the units burn natural gas as fuel so a compliance test for SO2 is not necessary. Page 5 o Reporting requirements in § 60.51a The source has already submitted the performance test data from the initial performance test as required by 40 CFR Part 60 Subpart Da § 60.51 a(a) so this requirement shall not be included in the operating permit. In addition, as discussed previously, since the source elected to demonstrate compliance with the NSPS Da NOx limits with the one-time performance test, the NSPS Da NOx CEMS requirements do not apply and therefore, the remaining reporting requirements (all others that potentially apply to this unit are related to CEMS), also do not apply. • Regulation No. 6, Part A, Subpart GG—Standards of Performance for Stationary Gas Turbines, applies to the turbines, as follows (condition 7): o Concentration of NOx emissions shall not exceed 102 ppmvd at 15% O2 o Concentration of SO2 emissions shall not exceed 150 ppmvd at 15 % O2 or the fuel combusted shall not contain sulfur in excess of 0.8% by weight. Although not specifically identified in the construction permit, the source is subject to monitoring requirements on the nitrogen and sulfur content of the fuel. It is not clear whether the source submitted an alternative monitoring plan to EPA for approval. However, NSPS GG was revised on July 8, 2004 (Federal Register, Volume 69, No. 130) to provide additional monitoring options for NOx emissions and nitrogen and sulfur content monitoring that have previously been approved by EPA. The revisions specify that for sources that do not take credit for fuel-bound nitrogen in their NOx emission limitations that no fuel sampling for nitrogen is required. Finally, for sampling fuel for the sulfur content, the revisions specify that no fuel sampling is required for units burning natural gas. The Division will include the appropriate provisions from the revised NSPS GG in the permit or streamline as appropriate. • Regulation No. 6, Part A, Subpart A— NSPS General Provisions, applies to the turbines and duct burners (condition 7) o Good practices (§ 60.11(d)) o Circumvention (§ 60.12) Note that a more extensive list of requirements from 40 CFR Part 60 Subpart A was included in the construction permit. However, these requirements, if still applicable, will be included in the permit as periodic monitoring or under the continuous emission monitoring requirements and will not be specifically identified as requirements under the NSPS general provisions. • Regulation No. 6, Part B, Section II — Standards of Performance for New Fuel- Burning Equipment (condition 7). These are State-only requirements. o Particulate Matter Emissions shall not exceed PE = 0.5(FI)-o.26 (Section II.C.2) Page 6 Where: PE = Particulate emissions in lbs/mmBtu Fl = Fuel input in mmBtu/hr Although the construction permit included the particulate matter limit, the limit only applies to units with a design heat input less than 250 mmBtu/hr. The design heat input rate for each turbine and duct burner exceed 250 mmBtu/hr; therefore, the particulate matter requirements do not apply. o Opacity of emissions shall not exceed 20% (Reg 6, Part B, Section II.C.3) o SO2 emissions shall not exceed 0.35 lbs/mmBtu (Reg 6, Part B, Section II.D.3.b). This standard only applies to the turbines. Note that the NSPS general provisions (40 CFR Part 60 Subpart A) are adopted by reference into Reg 6, Part B, Section I. • Best available control technology (BACT) shall be applied for control of emissions for NOx, CO, PM, PM,() and VOC, BACT shall be as follows for the turbines and HRSGs (condition 8): NOx: BACT is defined as DLN combustion and SCR with NOx emissions limits as follows: o Except as provided for below, emissions not to exceed 3 ppmvd at 15% oxygen on a 1-hour average. o During startup and shutdown, NOx emissions shall not exceed 300 ppmvd at 15% oxygen on an hourly average. Mass emissions of NOx (lbs/hr) during periods of startup and shutdown shall be included in determining compliance with the annual limitations. o Startup is defined as four (4) hours for cold startup, and one (1) hour for hot startup. o Shutdown is defined as one (1) hour It has generally been the Division's policy to define startup and shutdowns in terms of reaching a given operating mode or parameter, rather than a time based definition. Therefore, the Division has revised these definitions to include revised startup and shutdown definitions. Startup shall be defined as 30 minutes after the turbine reaches Stage-C Operation and shutdown shall be defined as when the operator gives the signal to shutdown the unit, until fuel is no longer fired in the turbine. Note that these definitions are consistent with definitions for similar turbines. The Division will provide the source with a chance to comment on and revise those definitions during the pre-public comment review period. Note that the averaging time for the startup and shutdown has also been revised. The limit shall be averaged over the duration of the startup and shutdown period, rather than on a one-hour average. Page 7 o Monthly average emissions of NOx shall not exceed 0.01394 lbs/mmBtu heat input. The Division considers that since hourly NOx BACT limits (in ppm) are provided that a monthly NOx limit is not necessary. It appears that the lbs/mmBtu limit is based on the annual permitted NOx emissions divided by the annual permitted heat input (based on a Btu content of 1057 Btu/scf). Therefore, this limit will not be included in the permit. CO: BACT is defined as good combustion practices and an oxidation catalyst with CO emission limits as follows: o Except as provided for below, emissions not to exceed 9 ppmvd at 15% oxygen on a 1-hour average. o Except as provided below, during startup and shutdown, CO emissions shall not exceed 1,000 ppmvd at 15% oxygen on an hourly average. o During the first hour of a hot startup, CO emissions shall not exceed 2,000 ppmvd at 15% oxygen on an hourly average. o Startup and shutdown have the same definitions as provided for NOx. As discussed above under NOx, the Division will revised the startup and shutdown limits to be parameter or operating mode based rather than time and the limits will be averaged over the entire startup and/or shutdown period. Therefore, the Division considers that a separate CO limit during the first hour of a cold start is not necessary and the limit was not included in the permit. o Monthly average emissions of CO shall not exceed 0.04537 lbs/mmBtu heat input. The Division considers that since hourly CO BACT limits (in ppm) are provided that a monthly CO limit is not necessary. It appears that the lbs/mmBtu limit is based on the annual permitted CO emissions divided by the annual permitted heat input (based on a Btu content of 1057 Btu/scf). Therefore, this limit will not be included in the permit. PM/PM10 BACT is defined as use of pipeline quality natural gas and application of good combustion practices, with PM/PM10 emission limits as follows: o Emissions of particulate matter shall not exceed 0.00735 lb/mmBtu. No averaging time was provided, the Division assumes that the averaging time was intended to be the average of three (3) one-hour test runs. The permit will be revised to clarify that. VOC BACT is defined as use of pipeline quality natural gas, application of good combustion practices and the oxidation catalyst, with VOC emission limits as follows: Page 8 o Emissions of particulate matter shall not exceed 0.00293 lb/mmBtu. No averaging time was provided, the Division assumes that the averaging time was intended to be the average of three (3) one-hour test runs. • Prior to final approval being issued, the source shall submit an operating and maintenance plan for all control equipment (condition 9). According to the Division's August 28, 2006 inspection report, since the continuous emission monitoring systems and data acquisition and handling system monitor compliance with virtually all permit conditions no operating and maintenance plan is required. It should be noted that the operating permit includes appropriate periodic monitoring to insure compliance with the requirements in this permit. • The turbines/HRSGs are subject to the following processing limits (condition 10). o Consumption of natural gas shall not exceed 32,625 MMscf/yr. • Total facility emissions are subject to the following limitations (condition 11). Attachment A of the permit includes individual emission limits for the equipment at the facility. The Division does not consider that an overall facility limit is appropriate or necessary for this facility, therefore, the Division will only include emission limits in the permit for the various pieces of equipment. The permit included facility wide emission limits for formaldehyde and total of other HAPS. Based on the Division's analysis these HAP emission limits are not adequate. Based on the performance tests for formaldehyde, emissions are 2.44 tpy alone from the turbines/HRSGS, this is based on using the highest average test result (turbine 1, 0.00015 lb/mmBtu), multiplied by the design heat input rate (2,311 mmBtu/hr) at 8760 hrs/yr of operation and the lowest average test result (turbine 2, 0.00013 lb/mmBtu) multiplied by the design heat input rate and the remainder of the hours (hours of operation are based on the fuel consumption limit multiplied by 1057 Btu/scf and divided by the combined heat rate of the turbine/duct burner (2,311 mmBtu/hr)). Note that based on the highest average test result multiplied by allowable heat input (permitted fuel multiplied by 1057 Btu/scf), formaldehyde emissions are 2.59 tpy. In addition, there were other HAPS for which the Division could not confirm the source of the emission factor; therefore, we are requiring use of a different emission factor to set the permit limits. Therefore, the HAPS emission limits need to be revised the reflect formaldehyde emissions based on test results and the different emission factors for other HAPS. The emission limits that will be included in the permit for the facility are as follows: o PM (includes condensables) 126.8 tons/yr o PM10 (includes condensables) 126.8 tons/yr o SO2 11.8 tons/yr Page 9 o NOx 240.4 tons/yr o CO 782.2 tons/yr o VOC 50.6 tons/yr o Facility wide Formaldehyde 2.44 tons/yr o Facility wide total HAPS 13.1 tons/yr The source submitted revised APENs on March 21, 2007 to reflect the change in HAP emissions. • For the turbines/HRSG, GEMS shall be installed, calibrated, certified, maintained and operated to measure and record the following (condition 12): o Hourly concentration of NOx, ppmvd, corrected to 15% O2 o Hourly concentration of O2, in percent o Emissions of NOx, tons/month, and tons per rolling twelve month periods o Hourly concentration of CO, ppmvd, corrected to 15% O2 o Emissions of CO, tons/month, tons per rolling twelve month periods o Fuel flow rate, SCF per hour for natural gas o The CEMS shall meet the QA/QC requirements in 40 CFR Part 60 Appendix F and Subpart A, 40 CFR Part 75 and Division approved plan. Note that the Division will indicate in the Title V permit that the GEMS shall also record emissions of NOx and CO in lbs/hr, as well as tons/month. The Division presumes that the rolling twelve month totals are not recorded on the data acquisition and handling system (DAHS) for the CEMS. Therefore, the twelve month rolling totals will not be identified as values recorded on the GEMS. • Performance tests shall be conducted to demonstrate compliance with the emission limitations (condition 13). Performance tests were conducted on May 8, 11, 12, 20 and September 16, 2004 and the results of the test have been approved by the Division. Therefore, the performance test requirements will not be included in the permit. • APEN reporting requirements (condition 14). The APEN reporting requirements will not be identified in the permit as a specific condition but are included in Section V (General Conditions) of the permit, condition 22.e. Although not specifically identified in Colorado Construction Permit 02WE0228, the turbines are subject to the following applicable requirements: • Particulate matter emissions, from each turbine and duct burner, shall not exceed 0.1 lbs/mmBtu (Reg 1, Section III.A.1.c) Page 10 • Sulfur dioxide emissions, from each turbine and duct burner, shall not exceed 0.35 lbs/mmBtu, on a 3-hour rolling average (Reg 1, Section VI.B.4.c.(ii) and VI.B.2). • Compliance Assurance Monitoring Requirements in 40 CFR Part 64, as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV. Note that no CAM plan was submitted, the NOx and CO GEMS will be used to directly monitor compliance with the emission limitations. • Each turbine/HRSG is subject to the Acid Rain requirements as follows: o Allocated SO2 allowances are listed in 40 CFR Part 73.10(b), however, since these are new units, no allowances were allocated. SO2 allowances must be obtained per 40 CFR Part 73 to cover SO2 emissions for the particular calendar year. o There are no NOx emission limitations since these units are not coal-fired boilers. o Acid rain permitting requirements per 40 CFR Part 72. o Continuous emission monitoring requirements per 40 CFR Part 75. o This source is also subject to the sulfur dioxide allowance system (40 CFR Part 73) and excess emissions (40 CFR Part 77). Streamlining of Applicable Requirements Opacity The turbines and duct burners are subject to the Reg 1 20% opacity requirement and the Reg 1 30% opacity requirement for certain specific operational activities. The Reg 1 20% opacity requirement applies at all times, except for certain specific operating conditions under which the Reg 1 30% opacity requirement applies. The turbines and duct burners are also subject to the state-only Reg 6, Part B 20% opacity requirement. The duct burners are subject to the NSPS opacity requirements (20% I 27%). The NSPS opacity requirements are not applicable during periods of startup, shutdown and malfunction in accordance with the requirement in 40 CFR Part 60 Subpart A § 60.11(c). Reg 6, Part B, Section I.A, adopts, by reference, the 40 CFR Part 60 Subpart A general provisions. 40 CFR Part 60 Subpart A § 60.11(c) specifies that the opacity requirements are not applicable during periods of startup, shutdown and malfunction. The Reg 1 20% / 30% requirements are more stringent than the Reg 6 Part B opacity requirements during periods of startup, shutdown and malfunction. While the Reg 6, Part B 20% opacity requirement is more stringent during fire building, cleaning of fire boxes, soot blowing, process modifications and adjustment or occasional cleaning of control equipment. The NSPS opacity requirements are more stringent than the Reg 1 30% requirements under all the specific operating conditions except startup but are less stringent than the state-only Reg 6 requirements. The Reg 1 (20%/30%) opacity requirements are more stringent than the NSPS requirements during startup, shutdown and malfunction. Therefore, since no one opacity requirement is more stringent than Page 11 the other at all times, all four opacity requirements are included in the operating permit. See the attached grid for a clarified view on the opacity requirements and their relative stringency. It should be noted that since the turbines and duct burners use natural gas as fuel, the Division will presume, in the absence of credible evidence to the contrary, that these units are in compliance with all of the opacity requirements. SO, Only the Regulation No. 1, Regulation No. 6, Part B (which only applies to the turbine) and NSPS Subpart Da (which only applies to the duct burner) SO2 requirements are in the same units and can therefore be compared for the purposes of streamlining. The Regulation No. 1 and No. 6, Part B SO2 standards are the same, 0.35 lbs/mmBtu. The Regulation No. 6, Part B requirement is a state-only requirement. Reg 6, Part B, Section I.A, adopts, by reference, the 40 CFR Part 60 Subpart A general provisions. Although not specifically stated in the general provisions, the Division has concluded after reviewing EPA determinations that the NSPS standards are not applicable during startup, shutdown and malfunction, although any excess emissions during these periods must be reported in the excess emission reports. Specifically, EPA has indicated (4/18/75, determination control no. A007) that when 40 CFR Part 60 Subpart A § 60.11(d) was developed "...it was recognized that sources which ordinarily comply with the standards may during periods of startup, shutdown and malfunction unavoidably release pollutants in excess of the standards." In addition, EPA has also indicated (5/15/74, determination control number D034) that "[s]ection 60.11(a) makes it clear that the data obtained from these reports are not used in determining violations of the emission standards. Our purpose in requiring the submittal of excess emissions is to determine whether affected facilities are being operated and maintained 'in a manner consistent with good air pollution control practices for minimizing emissions' as required by 60.11(d)." Therefore, the Division considers that the Reg 6, Part B SO2 requirements do not apply during periods of startup, shutdown and malfunction. Therefore, the Regulation No. 1 SO2 requirement is more stringent than the Regulation No. 6, Part B requirement and the Regulation No. 6, Part B requirements will be streamlined out of the permit. The NSPS Subpart Da requirement of 0.2 lbs/mmBtu applies to the duct burner and the Reg 1 SO2 requirement applies to the turbine. Since the duct burner cannot be operated without the turbine and since the duct burner and turbine share a stack, for all practical purposes the turbine and duct burner combination together are subject to the Reg 1 and the NSPS Da SO2 requirements. Although the NSPS Da requirement of 0.2 lbs/mmBtu appears to be more stringent than the Regulation No. 1 requirement, the NSPS Da requirement is based on a 30-day rolling average and the Reg 1 requirement is on a 3-hour rolling average. It is likely that the Reg 1 limit could be violated without violating the NSPS Da requirement. Therefore, these requirements cannot be adequately compared for stringency so both requirements will be included in the operating permit. Page 12 These units (turbine/HRSG/duct burner) are also subject to the Acid Rain SO2 requirements. Sources subject to Acid Rain must hold adequate SO2 allowances to cover annual emissions of SO2 (1 allowance = 1 ton per year of SO2) for a given unit in a given year. The number of allowances can increase or decrease for a unit depending on allowance availability. Allowances are obtained through EPA, other units operated by the utility or the allowance trading market and compliance information is submitted (electronically) to EPA. Pursuant to Regulation No. 3, Part C, Section V.C.1.b, if a federal requirement is more stringent than an Acid Rain requirement, both the federal requirement and the Acid Rain requirement shall be incorporated into the permit and shall be federally enforceable. For these reasons, the Acid Rain SO2 requirements have not been streamlined out of the permit. The source will have to demonstrate compliance with the Acid Rain SO2 requirements and the Reg 1 and NSPS Da SO2 requirements. Note that the Acid Rain SO2 allowances appear only in Section III (Acid Rain Requirements) of the permit. NOx Since the NSPS Subpart GG and BACT concentration limits are in the same units, they can be compared for purposes of streamlining. The BACT concentration limits are applicable at all times. The Division considers that the NSPS Subpart GG requirements are not applicable during periods of startup, shutdown and malfunction (as discussed in the SO2 streamlining section above). The BACT NOx limits are much more stringent than the NSPS limits (3 ppmvd vs 102 ppmvd) and the averaging times for the BACT limit are more stringent are different (1-hr for BACT and 4-hr for NSPS). Therefore, since the NSPS Subpart GG limits are less stringent than the BACT concentration limits, the NSPS Subpart GG limits will be streamlined out of the operating permit. Note that streamlined conditions are subsumed within the requirements identified in Section II of the permit For purposes of compliance demonstration, compliance with the conditions in Section II of the permit also serve as compliance demonstration for the subsumed condition. Since the NSPS GG NOx limit has been streamlined out in favor of the BACT NOx limits, the source may wish to retain records of ambient temperature and humidity data which is used to convert NOx values to ISO standard day conditions, in the event that the NOx BACT limit is violated at such a level that compliance with the NSPS GG BACT limit is uncertain. The duct burner is subject to an NSPS Subpart Da NOx limit of 1.6 lbs/MW-hr gross energy output, on a 30-day rolling average. The source submitted information on January 19, 2007 demonstrating that the NSPS Da NOx limit is less stringent than the NOx BACT limit. The Division agrees and therefore, the NSPS Da NOx limit has been streamlined out of the permit in favor of the NOx BACT limit. PM The turbines and duct burners (alone and together) are subject to a Reg 1 particulate matter standard and the BACT limit and the duct burners are subject to the NSPS Da particulate matter standard. Since the duct burners would not be operated without the Page 13 turbines and since the duct burners and turbines share a stack, for all practical purposes the turbine/duct burner combinations together are subject to the NSPS Da particulate matter standard. The NSPS Da requirement does not apply during periods of startup, shutdown and malfunction, as specifically stated in § 60.48a(c). The Reg 1 and the BACT particulate matter standards apply at all times. The particulate matter BACT limit is more stringent than both the Reg 1 and NSPS Da limit at all times (see attached grid). In addition, the testing requirements for the PM BACT limit and the Reg 1 BACT limit are based on three (3) one-hour tests, while NSPS Da PM limit is based on the average of three (3) two-hour tests; consequently the averaging times for the Reg 1 and NSPS Da limit are as stringent or more stringent than the averaging time for the PM BACT limit. Therefore, the NSPS Da and the Reg 1 particulate matter limits will be streamlined in favor of the BACT limit. Monitoring These units (turbines/HRSGs) are subject to several types of monitoring requirements. The construction permit requires that the stacks be equipped with continuous emission monitoring systems (GEMS) to monitor and record NOx and CO emissions and the construction permit requires that these monitors be installed, maintained, calibrated and operated according to 40 CFR Part 60, Appendix F and Subpart A, 40 CFR Part 75 and a Division approved plan. These units are also subject to the Acid Rain requirements and as such are required to monitor emissions in accordance with the requirements in 40 CFR Part 75. The duct burner is subject to NSPS subpart Da. For combined cycle units (turbine plus duct burner) NSPS Da allows compliance with the NOx requirements to be demonstrated with either a one-time performance test or a CEMS. NSPS Da specifically states that combined cycle units are not required to have NOx GEMS (40 CFR Part 60 Subpart Da § 60.47a(o)). Since the source demonstrated compliance with the NSPS Da NOx limit with a one-time performance test, the NSPS Da NOx GEMS requirements do not apply to the duct burner and therefore need not be considered further for purposes of streamlining. Since the source has installed Part 75 NOx (and diluent) CEMS, the permit will specify that the NOx (and diluent) GEMS must meet the requirements in 40 CFR Part 75. This is consistent with the language in the construction permit, so no streamlining of requirements is necessary. It should also be noted that the 40 CFR Part 60 excess emission reporting requirements for NOx will remain in the permit as 40 CFR Part 75 does not contain any NOx excess emission reporting requirements. It should be noted that the NSPS GG revisions indicate that no nitrogen sampling is required if credit was not taken for fuel-bound nitrogen in setting the NOx emission limitations. This was the case for these units. Therefore, since sampling the fuel for the nitrogen content is not required, there are no requirements to streamline. Under the Acid Rain provisions, sources that demonstrate that the gas burned meets the definition of pipeline quality natural gas may use an emission factor to calculate Page 14 hourly SO2 emissions, as allowed by 40 CFR Part 75 Appendix D. The NSPS GG revisions specify that no fuel sampling is required if natural gas is used as fuel, since these turbines burn pipeline quality natural gas, which has a lower sulfur content then natural gas, the methods to demonstrate that natural gas is used as fuel will be streamlined in favor of the Part 75 pipeline quality natural gas requirement. Miscellaneous Since the turbines and duct burners are subject to federal NSPS requirements (Subparts Da and GG) and state-only NSPS requirements (Reg 6, Part B, Section II), they are subject to the general provisions on a federal and state-only basis. The state- only general provisions will be streamlined in favor to the federal general provisions. 2. Emission Factors: Emissions from these turbines are produced during the combustion process, and are dependent upon operating conditions and specific properties of the natural gas being burned. The pollutants of concern are Nitrogen Oxides (NOx), Carbon Monoxide (CO), Volatile Organic Compounds (VOC) and Particulate Matter (PM and PM1o). Small quantities of Hazardous Air Pollutants (HAPs) are also emitted dependent upon the makeup of the fuel and combustion efficiency. NOx and CO emissions shall be determined using the continuous emission monitoring system required by the construction permit. SO2 emissions shall be determined using monitoring methods required by 40 CFR Part 75, Appendix D. The source proposed to use the following emission factors to monitor compliance with the emission limits: Pollutant Emission Factor Source (lbs/mmBtu) PM 0.001 From performance tests conducted May 8, 11, 12, PM10 0.001 20 and September 16, 2004. VOC Unit 1 -7.3 x 10-0 Unit2- 1.5x104 _ The above emission factors are based on the test results (average of 3 tests) for each turbine/HRSG. The Division agrees that the emission factors are appropriate to use to monitor compliance with the annual PM, PMio and VOC annual limitations. The facility is also subject to HAP limits, which include a facility wide total HAP limit and a formaldehyde limit. Since there are significant HAPS from the turbines/duct burners, the source will be required to demonstrate compliance with the facility wide HAP limits. Since permitted HAP emissions are well below the major source level, the Division will only require that emissions from significant HAPS be calculated. The HAP emission factors to be used in these calculations are as follows: Page 15 Pollutant Emission Factor Source Formaldehyde S001 - 1.5 x 10' lb/mmBtu From performance tests conducted May 8, 11, 12, 20 S002- 1.3 x 104 lb/mmBtu and September 16, 2004. Acetaldehyde 1.37 x 10'' Ib/mmSCF From California Air Toxics Emission Factor (databases)for natural gas-fired turbines with COC and SCR. Acrolein 1.89 x 10-2 lb/mmSCF Benzene 1.33 x 10.2 lb/mmSCF Ethylbenzene 1.79 x 10.2 lb/mmSCF Hexane 2.59 x 10-' lb/mmSCF Propylene Oxide 4.78 x 10.2 Ib/mmSCF Toluene 7.10 x 10"2 lb/mmSCF Xylene 2.61 x 10-2 lb/mmSCF Note that the emission factors listed in bold are not the same as the emission factors used in the initial construction permit application because the Division could not confirm those emission factors. 3. Monitoring Plan: The source will be required to monitor compliance with the NOx and CO BACT and annual emission limitations using the CEMS. Compliance with the annual SO2 emission limits will be monitored using the continuous monitoring system required by 40 CFR Part 75 Appendix D. Compliance with the annual VOC, PM and PKo emission limitations shall be monitored using emission factors and the fuel consumption from the turbines and duct burners. Compliance with the various short term SO2 requirements and the opacity requirements shall be presumed, in the absence of credible evidence to the contrary, since only natural gas is permitted to be used as fuel in the turbines and duct burners. Performance tests were conducted to demonstrate compliance with the PM and VOC BACT emission limits and the results of the tests were much less than 50% of the standard (for PM, average test results 0.001 lb/mmBtu vs. 0.00735 lb/mmBtu BACT limit (14% of BACT limit) and for VOC, highest average test result 0.00073 lb/mmBtu vs. 0.00293 lb/mmBtu BACT limit (25% of BACT limit)). Compliance with the PM BACT limit shall be presumed, in the absence of credible evidence to the contrary, since • natural gas is the only fuel permitted for use in the turbines/duct burners. In addition, the Division will require that a performance test be conducted within the last 18 months of the permit term to verify compliance with the PM/PM10 BACT limit. Since VOC emissions are controlled by the oxidation catalyst, which also controls CO emissions and CO emissions are monitored with the CO CEMS, the Division considers that compliance with the VOC BACT limit is presumed, in the absence of credible evidence to the contrary, provided compliance with the CO BACT limit is demonstrated. Because compliance with the VOC BACT limit will be monitored continuously using compliance with the CO BACT limits as a surrogate and the fact that only pipeline quality natural Page 16 gas is permitted to be used as fuel, the Division considers that no further performance tests are required for the VOC BACT limit. 4. Compliance Status: In the Title V permit application, the source indicated that the turbines/HRSGS were in compliance with all applicable requirements. Upon issuance of the Title V permit to adjust the HAP emission limits, the Division agrees that the source will be in compliance with all applicable requirements. Unit 5003. John Deere, Model No. 6081AF001, Serial No. RG6081A159985, Internal Combustion Engine Driving an Emergency Fire Water Pump, Rated at 182 hp and 1.26 mmBtu/hr. Diesel Fuel Fired. Unit S005: Caterpillar, Model No. 3512B, Serial No. 1GZ01360, Internal Combustion Engine Driving an Emergency Generator, Rated at 1810 hp and 6.51 mmBtu/hr. Diesel Fuel Fired. 1. Applicable Requirements: The two diesel fuel-fired engines are included in Colorado Construction Permit 02WE0228 (initial approval, modification 1, issued June 23, 2004), the permit includes diesel fuel consumption limits for the two engines, operating limits of 200 hrs/yr for the fire pump and 100 hrs/yr for the emergency generator and presumably the emission limits are included in the facility wide limitations (individual emission limits are included in Attachment A of the permit). The fire pump is exempt from APEN reporting provided it is operated for less than 850 hrs/yr (Colorado Regulation No. 3, Part A, Section III.D.1.sss.(ii)). While it is necessary to consider emissions from APEN exempt equipment in determining whether a project is subject to PSD review (i.e. emissions above the major stationary source threshold and/or significance level), it is not necessary to conduct a BACT analysis on an emission unit that would not be required to have a permit, nor would it be necessary to require a permit for an emission unit that would otherwise be exempt from permitting because it is part of a project that has triggered PSD review. Therefore, the fire pump will be included in the Title V permit as an insignificant activity. As identified in the construction permit and in the Title V permit application, the emergency generator exceeds the size of APEN exempt emergency generators noted in Colorado Regulation No. 3, Part A, Section II.D.1.ttt; however, all emergency generators operated less than 250 hrs/yr are exempt from construction permit requirements according to Colorado Regulation No. 3, Part B, Section II.D.1.c.(ii). As discussed above for the fire pump, since a permit is not required for the emergency generator a BACT analysis was not conducted for the emergency generator. The Division does not feel that a BACT analysis would be necessary for such a unit and that such analysis would not result in any add-on controls on this unit. In their January 19, 2007 submittal, the source provided information indicating that the emergency generator was actually rated at 1810 hp, not the 2000 hp indicated in the construction permit and the Title V permit application. Emergency generators less than Page 17 1840 hp are exempt from the APEN reporting requirements if they are operated for less than 100 hrs per year and may be considered insignificant activities (Colorado Regulation No. 3, Part A, Section II.D.1.ttt.(iii) and Part C, Section II.E.3.nnn.(iii)). Based on that information, the Division could consider this engine an insignificant activity and include it in the list of insignificant activities in Appendix A of the permit. However, the source submitted an application to modify the construction permit on March 22, 2007 to increase the number of hours the emergency generator is permitted to run and to increase the quantity of permitted diesel fuel for both the fire-pump and the generator. Due to an outage in May of 2007, the diesel generator will need to run for more than 100 hours per year but less than 250 hours per year. At that level, the emergency generator would be subject to APEN reporting requirements but exempt from construction permit requirements. Therefore, the Division will include the emergency generator in the Section II of the Title V permit, rather than in the insignificant activity list. Note that since it is expected that in future years, the engine will be operated at less than 100 hours per year and would be exempt from APEN reporting requirements the Division will include provisions for lesser monitoring requirements for this unit if hours of operation in any year fall below 100 hours per year. In addition, to the APEN reporting requirements, the emergency generator is subject the following applicable requirements: • Visible emissions shall not exceed twenty percent (20 %) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30% opacity (condition 6). Note that Colorado Regulation No. 1 does not identify the 20% opacity requirement as a condition that only applies during normal operation and EPA has objected, in comments on another operating permit, to the term "normal operations" applied to the 20% opacity standard. The specific operational activities subject to the 30% opacity requirement are also conditions that can be considered "normal operation". In addition, there are additional specific operational conditions included under the 30% opacity limit. Based on engineering judgment the Division considers that building a new fire, cleaning of fire boxes and soot-blowing does not apply to the operation of this engine when burning No. 2 fuel oil. In addition, this engine does not have a control device, so adjustment or occasional cleaning of control devices do not apply to this unit. Process modifications may apply to engines, however, based on engineering judgment, the Division believes that such activities would be unlikely to occur for longer than six minutes. Startup is an activity that applies to this engine, however based on engineering judgment the Division believes that startup for this engine is quick and lasts less than twelve (12) minutes. Under the Reg 1 30% opacity standard, one 6 minute interval in each hour while one of the specific activities is occurring is not subject to an opacity limitation. For the remainder of the hour, the opacity emissions are limited to 30%, however, the 30% opacity standard is based on a six minute average. Therefore, for an Page 18 emission unit that takes less than twelve (12) minutes to start up, the 30% opacity standard is not applicable. Therefore, the 30% opacity requirement has not been included in the operating permit. • Sulfur dioxide emissions shall not exceed 0.8 lb/mmBtu (Colorado Regulation No. 1, Section B.4.b.(i)). Note that this requirement was not included in the construction permit Although the construction permit included fuel consumption and emission limits, as well as hours of operation for the emergency generator, since this unit is exempt from construction permit requirements, the Division is not including the fuel consumption and emission limits in the Title V permit. However, it should be noted that if hours of operation for this unit exceed 250 hrs/yr, then a construction permit would be required and emission and throughput limits would be required. The Division would reopen the permit for cause to include such requirements if the hours of operation exceeded the permit exempt level of 250 hrs/yr. 2. Emission Factors: Emissions from this engine is from the combustion of fuel oil. The pollutants of concern are Particulate Matter, (PM and PMio), Nitrogen Oxides (NOx), Sulfur Dioxide (SO2), Carbon Monoxide (CO), and Volatile Organic Compounds (VOC). Some hazardous air pollutants (HAPs) are generated through the combustion process, although emissions are minimal. Approval of emission factors for this unit is necessary to the extent that accurate actual emissions are required to verify the need to submit revised APENs to update the Division's Emission Inventory. In the Title V permit application the source indicated that they were basing emissions from the engine on emissions factors from the manufacturer, with SO2 emissions based on a fuel sulfur content of 0.05 % by weight (fuel oil density of 7.05 lb/gal). The emission factors to be included in the permit are as follows: Pollutant Emission Factor PM 0.4 g/hp-hr PM10 0.4 g/hp-hr SO2 5.14 x 10-2 Ib/mmBtu NOx 6.9 g/hp-hr CO 8.5 g/hp-hr VOC 1 g/hp-hr Note that at 250 hrs/yr of operation, PM, PM10, VOC and SO2 emissions are below the APEN de minimis level, so the source will not be required to calculate emissions of these pollutants from this unit; however, emissions from all criteria pollutants are to be included on any revised APENS. 3. Monitoring Plan: The source will be required to record hours of operation annually for purposes of calculating emissions to determine APEN reporting requirements. Page 19 Emissions shall be based on hours of operation and the maximum horsepower of the engine. 4. Compliance Status: In the Title V permit application, the source indicated that the engines were in compliance with all applicable requirements. Unit S004: Rentech, Natural Gas Fired Boiler, Rated at 129 mmBtu/hr, Serial No. 2002-49. Equipped with Low NOx Burners. 1. Applicable Requirements: The initial approval construction permit (02WE0228) for the facility was issued on July 15, 2002, with a modification issued on June 23, 2004. A request was submitted on March 22, 2007 to revise the construction permit; however, the revisions only affected the emergency generator. According to the Title V permit application, the boiler commenced operation in February 2004. It is not clear when the self-certification was submitted and no final approval permit has been issued. Under the provisions of Colorado Regulation No. 3, Part C, Section V.A.3, the Division will not issue a final approval construction permit and is allowing the initial approval construction permit to continue in full force and effect. The appropriate provisions of the initial approval construction permit have been directly incorporated into this Title V operating permit. The applicable requirements included in the construction permit for the boiler are as follows: • Conditions 2 (self-certification), 5 (emissions of hazardous air pollutants), 9 (submittal of operating and maintenance plan), 13 (performance test) and 14 (APENs) are addressed as discussed above under Units S001 and S002 (combustion turbines/HRSGs). • Visible emissions shall not exceed twenty percent (20 %) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30% opacity (condition 6). Note that Colorado Regulation No. 1 does not identify the 20% opacity requirement as a condition that only applies during normal operation and EPA has objected, in comments on another operating permit, to the term "normal operations" applied to the 20% opacity standard. The specific operational activities subject to the 30% opacity requirement are also conditions that can be considered "normal operation". Therefore, the language in the permit will not specify "normal operation". The 30% opacity requirement will be written to include all the specific operational activities identified in Reg 1. • Regulation No. 6, Part A, Subpart Db — Standards of Performance for Industrial- Commercial — Institutional Steam Generating Units, as follows (condition 7): o The boiler operates exclusively on natural gas, and the operation does not exceed 1,900 hrs/yr. Page 20 This condition is listed in the construction permit as a requirement under NSPS Subpart Db, however, NSPS Db does not require any limitations on hours of operation unless the source wishes to limit the capacity factor in order to have lesser monitoring requirements. The hours of operation limit is not sufficient to allow for the lesser monitoring and the fuel consumption limit provided later in the permit stipulates limited operation on only natural gas, therefore, this requirement will not be included in the permit. o Nitrogen oxide emissions shall not exceed 0.20 lb/mmBtu, the NOx emission limitation is on a 30-day rolling average and apply at all times including periods of startup, shutdown and malfunction (40 CFR Part 60 Subpart Db §§ 60.44b(l)(1), (h) and (i)). o Compliance with the NOx emission limits under § 60.44b shall be determined through performance testing under paragraph (e) and (f), or under paragraphs (g) and (h) of this section as applicable (40 CFR Part 60 Subpart Db § 60.46b(c)). Note that paragraph (f) applies to duct burners and paragraphs (g) and (h) apply to units that meet the requirements in 60.44b(j). The boiler does not meet the provisions of 60.44b(j). Since the boiler runs infrequently the Division allowed compliance with the NOx limit to be demonstrated with a performance test (three (3) one hour test runs). The performance test were conducted May 8, 11, 12, 20 and September 16, 2004 and demonstrated compliance with the NOx limits. o The owner or operator subject to the NOx limitation under 60.44b shall install, calibrate, maintain and operate a continuous monitoring system (40 CFR Part 60 Subpart Db § 60.48b(b)(1)). The NOx continuous monitoring system is subject to the requirements in 60.48b(c), (d), (e) and (f). o Reporting and recordkeeping requirements under § 60.49b(a) - startup notice, (b) — performance test data, (d) — daily fuel, capacity factor, (g) — recordkeeping, (h) — excess emission reports, (i) — NOx monitoring reports and (o) — recordkeeping duration. Note that, except for the hours of operation limit discussed above, the construction permit only included the NSPS Db NOx emission limits in the permit, the other monitoring requirements are specified in NSPS Subpart Db be were not included in the permit. • Regulation No. 6, Part A, Subpart A— NSPS General Provisions (condition 7) o Good practices (§ 60.11(d)) o Circumvention (§ 60.12) Note that a more extensive list of requirements from 40 CFR Part 60 Subpart A was included in the construction permit. However, these requirements, if still applicable, will be included in the permit as periodic monitoring or under the Page 21 continuous emission monitoring requirements and will not be specifically identified as requirements under the NSPS general provisions. • Regulation No. 6, Part B, Section II — Standards of Performance for New Fuel- Burning Equipment (condition 7). These are State-only requirements. o Particulate Matter Emissions shall not exceed PE = 0.5(FI)-°.26 (Section II.C.2) Where: PE = Particulate emissions in lbs/mmBtu Fl = Fuel input in mmBtu/hr o Opacity of emissions shall not exceed 20% (Reg 6, Part B, Section II.C.3) Note that the NSPS general provisions (40 CFR Part 60 Subpart A) are adopted by reference into Reg 6, Part B, Section I. • BACT shall be applied for control of emissions for NOx, CO, PM, PM10 and VOC, BACT shall be as follows for the auxiliary boiler (condition 8): o 1,900 hrs/yr of operation o NOx — dry low NOx combustion system, emissions shall not exceed 0.038 lb/mmBtu o CO — good combustion practices, emissions shall not exceed 0.039 lb/mmBtu It should be noted that the permit did not include a BACT analysis for VOC, PM or PM1° emissions. The Division considers that good combustion practices would be BACT for CO as well as VOC. In addition, the Division considers that use of pipeline quality natural gas as fuel would be BACT for the boiler. The Division has on occasion not set BACT emission limitations for PM, PM1° and VOC emissions for sources relying on good combustion practices and fuel restriction as the control technology. These BACT determinations will be included in the Title V permit; however, no emission limitations will be provided for PM, PM1° and VOC. In addition, the permit does not specify the averaging time for the BACT limits for NOx and CO. Since the construction permit did not require a continuous emission monitoring system for the boilers, it is presumed that compliance would be demonstrated based on the performance test (the average of three (3) one hour tests). The permit will be revised to specify that the averaging time for the CO BACT limit shall be the average of three (3) one hour tests and that the NOx BACT limit is based on a 3-hr rolling average, since the boiler is equipped with a NOx GEMS as required by NSPS Subpart Db. Finally, since the permit also includes a fuel consumption limit in the permit for the boiler, the Division does not believe that a limit on the hours of operation is also necessary. Therefore the Division will not include the hours of operation limit in the permit. • The boiler subject to the following processing limits (condition 10). Page 22 o Consumption of natural gas shall not exceed 231,882,687 scf/yr. It should be noted that Attachment A of the permit lists individual fuel consumption and emission limits for specific equipment. The fuel consumption limit provided in Attachment A is 259,070,700 scf/yr. The Division considers that most likely the fuel consumption limit provided in the main part of the permit is probably correct and has included that limitation in the Title V permit. In addition, the Division will round this limit to 231.9 mmSCF/yr in the permit to simplify the recordkeeping. • Total facility emissions are subject to the following limitations (condition 11). As discussed above, Attachment A includes individual emission limits for the equipment at the facility. The Division does not consider that an overall facility limit is appropriate or necessary for this facility; therefore, the Division will only include emission limits in the permit for the various pieces of equipment. The permit included facility wide emission limits for formaldehyde and total of other HAPS. Based on the fuel consumption limits and the emissions factors in the construction permit application, total HAP emissions from the boiler are 0.003 tpy (based on AP-42 emission factors, total HAPS are 0.22 tpy). Since the boiler is not equipped with a control device to reduce HAP emissions and based on the requested fuel consumption limit, HAP emissions from the boiler are so low, the Division does not consider that a HAP emission limit is necessary for the boiler. Therefore, no HAP limit has been included for the boiler. The emission limits that will be included in the permit for the boiler are as follows: o PM 2.28 tons/yr o PM10 2.28 tons/yr o NOx 4.7 tons/yr o CO 4.75 tons/yr 5O2 and VOC emissions are below the APEN de minimis level so emission limits for those pollutants have not been included in the permit; however, all criteria pollutants must be reported on APENS. In addition, Attachment A of the construction permit lists individual CO emissions at 2.8 tons/yr. Based on the emission factor in the permit application (same as the BACT limit), the CO emission limit would be exceeded at the permitted fuel consumption rate. Therefore, the Division has increased the CO emission limit in the Title V permit. In addition, Attachment A of the permit did not include PM and Milo emission limits. Based on the emission factors and permitted natural gas consumption rate, emissions of PM and PM10 are above the APEN de minimis level; therefore, limits on PM and PM10 emissions will be included in the permit. The source submitted a revised APEN on March 21, 2007, requesting CO, PM and PM10 emissions of 4.75, 2.28 and 2.28 tons/yr, respectively. Page 23 Although not specifically identified in Colorado Construction Permit 02WE0228, the boiler is subject to the following applicable requirements: • Particulate Matter Emissions shall not exceed PE = 0.5(FI)-°.26 (Reg 1, Section III.A.1.b) Where: PE = Particulate emissions in lbs/mmBtu Fl = Fuel input in mmBtu/hr Streamlining of Applicable Requirements Opacity The boiler is subject to the Reg 1 20% opacity requirement and the Reg 1 30% opacity requirement for certain specific operational activities. The Reg 1 20% opacity requirement applies at all times, except for certain specific operating conditions under which the Reg 1 30% opacity requirement applies. The boiler is also subject to the state-only Reg 6, Part B 20% opacity requirement. Reg 6, Part B, Section I.A, adopts, by reference, the 40 CFR Part 60 Subpart A general provisions. 40 CFR Part 60 Subpart A § 60.11(c) specifies that the opacity requirements are not applicable during periods of startup, shutdown and malfunction. The Reg 1 20%/30% requirements are more stringent than the Reg 6 Part B opacity requirements during periods of startup, shutdown and malfunction. While the Reg 6, Part B 20% opacity requirement is more stringent during fire building, cleaning of fire boxes, soot blowing, process modifications and adjustment or occasional cleaning of control equipment. Therefore, since no one opacity requirement is more stringent than the other at all times, all three opacity requirements are included in the operating permit. See the attached grid for a clarified view on the opacity requirements and their relative stringency. PM The boiler is subject to the Reg 1 particulate matter requirements and the state-only, Reg 6, Part B particulate matter requirements. The particulate matter requirements in both Reg 1 and Reg 6, Part B are the same standard. The Reg 1 particulate matter requirements apply at all times. For the same reasons as indicated under the SO2 streamlining section for the turbines/HRSGs the Reg 6, Part B particulate matter requirements are not applicable during startup, shutdown and malfunction. As a result, the Reg 6, Part B requirements have been streamlined out of the permit. NOx The NSPS Db and BACT limits are in the same units, therefore, they can be compared for purposes of streamlining. The NSPS Db NOx limits are applicable at all times, including periods of startup, shutdown and malfunction. The NOx BACT limits are also applicable at all times. The NOx BACT limits are much more stringent than the NSPS limit (0.038 lb/mmBtu vs 0.20 lb/mmBtu) and the averaging time for the NOx BACT limit is more stringent than the NSPS Db limits (3-hr rolling average for BACT, 30 day rolling Page 24 average for NSPS). Therefore, since the NSPS Db limit is less stringent than the BACT limit, the NSPS Db limit will be streamlined out of the operating permit. Monitoring The construction permit does not include any monitoring requirement for the auxiliary boiler, It is presumed that compliance with the NOx BACT limit would be demonstrated by a performance test. NSPS Db requires that the source be required to install and operate a NOx GEMS to demonstrate compliance with the NOx limit. Although the Division is streamlining out the NSPS Db NOx limit in favor of the NOx BACT limit, since the monitoring for the NSPS Db limit is more stringent, the source will be required to use the CEMS to demonstrate compliance with the NOx BACT limit. Note that the CEMS will be required to meet the same requirements in 40 CFR Part 60 Subparts A and Db, except for the data replacement requirements in 40 CFR Part 60 Subpart Db § 60.48b(f), since the minimum data requirements are based on the 30-day averaging period for the NSPS Db emission limit that is being streamlined from the permit. NSPS Db requires that the NOx GEMS shall have a span value of 500 ppm (40 CFR Part 60 Subpart Db § 60.48(e)(2)). However, since the BACT emission limit is lower than the NSPS Db limit; therefore, a narrower span value is more appropriate for a lower limitation. Since the Division has streamlined out the NSPS Db NOx limit, we are also streamlining the 500 ppm span value requirement for the NOx GEMS in favor of a more appropriate 100 ppm span value. NSPS Db also includes recordkeeping and reporting requirements, such as submitting startup notices and performance test results, GEMS recordkeeping and GEMS monitoring and excess emission reports. Since the unit has started up and conducted and submitted performance test results, the startup notification and submittal of performance test results have already been submitted and no longer apply. Since the GEMS recordkeeping and monitoring and excess emission reports all related to the 30- day limit that has been streamlined from the permit, the Division considers that these requirements are streamlined under the requirement to report under the excess emission reporting requirements for the NOx BACT limit. Under NSPS Db, the source is required to retain records for two years, while under Title V, records must be retained for five years. The Division will streamline the NSPS Db requirement for record retention in favor of the Title V recordkeeping requirement (Section V, Condition 22.b and c). Miscellaneous Since the boiler is subject to federal NSPS requirements (Subpart Db) and state-only NSPS requirements (Reg 6, Part B, Section II), they are subject to the general provisions on a federal and state-only basis. The state-only general provisions will be streamlined in favor to the federal general provisions. Page 25 2. Emission Factors: Emissions from this boiler are produced during the combustion process, and are dependent upon operating conditions and specific properties of the natural gas being burned. The pollutants of concern are Nitrogen Oxides (NOx), Carbon Monoxide (CO), Volatile Organic Compounds (VOC), and Particulate Matter (PM and PM1o). Small quantities of Hazardous Air Pollutants (HAPs) are also emitted dependent upon the makeup of the fuel and combustion efficiency. Compliance with the emission limits included in the permit shall be based on the following emission factors: Pollutant Emission Factor Source PM 0.0186 lb/mmBtu Manufacturer PM,a 0.0186 lb/mmBtu CO 0.039 lb/mmBtu The NOx continuous emission monitoring system shall be used to determine compliance with the NOx emission limitations. 3. Monitoring Plan: —The source will be required to record fuel consumption and calculate emissions monthly to monitor compliance with the annual fuel consumption and emission limitations. Monthly emissions and fuel consumption shall be used in twelve month rolling totals to monitor compliance with the annual limitations. For the annual NOx emission limitations (both short term and annual), compliance will be monitored using the NOx CEMS. Compliance with the PM, opacity and SO2 requirements are presumed, in the absence of credible evidence to the contrary whenever natural gas is used as fuel in the boiler. The results of the initial compliance test for the CO BACT limit were less than 50% of the standard (0.0164 lb/mmBtu), therefore, a performance test shall be required in the last 18 months of the permit term to verify compliance with the CO BACT limit. 4. Compliance Status: In the Title V permit application, the source indicated that the boiler was in compliance with all applicable requirements. Unit S006: Marley, Model No. F4910, 13 Cell Cooling Water Tower, Rated at 176,000 Gal/Min. 1. Applicable Requirements: The initial approval construction permit (02WE0228) for the facility was issued on July 15, 2002, with a modification issued on June 23, 2004. A request was submitted on March 22, 2007 to revise the construction permit; however, the revisions only affected the emergency generator. The Title V permit application did not indicate when the cooling water tower commenced operation; however, the Division presumes that operation commenced in March 2004 when the turbines/HRSGs commenced operation. It is not clear when the self-certification was submitted and no final approval permit has been issued. Under the provisions of Colorado Regulation No. 3, Part C, Section V.A.3, the Division will not issue a final approval construction permit and is allowing the initial approval construction permit to continue in full force and effect. The appropriate provisions of the initial approval construction permit have been directly Page 26 incorporated into this Title V operating permit. The applicable requirements included in the construction permit for the boiler are as follows: • Conditions 2 (self-certification), 5 (emissions of hazardous air pollutants), 9 (submittal of operating and maintenance plan) and 14 (APENs) are addressed as discussed above under Units S001 and S002 (combustion turbines/HRSGs). • Visible emissions shall not exceed twenty percent (20 %) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30% opacity (condition 6). Note that Colorado Regulation No. 1 does not identify the 20% opacity requirement as a condition that only applies during normal operation and EPA has objected, in comments on another operating permit, to the term "normal operations" applied to the 20% opacity standard. The specific operational activities subject to the 30% opacity requirement are also conditions that can be considered "normal operation". Based on engineering judgment, the Division believes that for purposes of opacity emissions none of the conditions under the 30% opacity requirement apply. Specifically activities such as fire building, cleaning of fire boxes and soot blowing are not germane to cooling towers. In addition, there is really no "startup" involved in operating a cooling tower. Finally, the Division does not believe that adjustment of the control device (drift eliminators) can be done while operating the tower and that process modifications would be limited. Therefore, the 30% opacity requirement will not be included in the operating permit as the specific operating activities under which it applies does not occur with this unit. • BACT shall be applied for control of PM and PM10 emissions, BACT shall be as follows for the cooling tower (condition 8): o High efficiency drift eliminators to limit the drift to 0.0005%. o Emissions of particulate matter shall not exceed 0.42 lbs per million gallons of water circulation. The 0.42 lbs/million gallons of water is based on total solids concentration used to estimate permitted emissions (10,000 ppmw) and the efficiency of the drift eliminators. The level of total solids concentration in the cooling tower is not really a result of the control technology but based more on the method of operation (i.e. number of cycles). Typically PSD permits for cooling towers usually only include as a BACT limitation specifying the efficiency of the drift eliminators, and not a limit based on the total solids concentration. Therefore, the Division will not include the 0.42 lbs/million gallons of water circulation limit in the permit. Note that the annual PM and PM10 emission limitations for the cooling tower are based on this hourly limitation multiplied by the annual water circulation rate. Page 27 • The cooling tower is subject to the following processing limits (condition 10). o Water circulated shall not exceed 91,595,260,800 gal/yr In their comments submitted on November 17, 2006, the source indicated that the cooling tower was actually i•ated at 176,000 gallons per minute; therefore, they submitted a revised APEN on January 19, 2007 to increase the annual limit on the quantity of water circulated to 92,505.6 mmgal/yr. • Total facility emissions are subject to the following limitations (condition 11). As discussed above under the Auxiliary Boiler, the Division does not consider that an overall facility limit is appropriate or necessary for this facility; therefore, the Division will only include emission limits in the permit for the various pieces of equipment. Based on a chloroform emission factor of 2.3 kg/109 liter and the requested water circulation limit, chloroform emissions exceed the APEN de minimis level for HAP reporting (emissions are 1775 Ibs/yr) but not for criteria pollutant reporting (chloroform is a VOC). Therefore, since chloroform emissions from the cooling tower are significant, they should be included in the total HAP limit for the facility. As discussed above under Units S001 and S002 (turbines/HRSGS), the facility total HAP limit is being revised in the Title V permit. The emission limits that will be included in the permit for the boiler are as follows: o PM 19.1 tons/yr o PM10 19.1 tons/yr o Facility wide total HAPS 13.1 tons/yr As discussed previously, the source has requested an increase in the limitation on the quantity of water circulated, which also results in an increase in PM and PM10 emissions. The source submitted a revised APEN on January 19, 2007 to increase the PM and PKo emission limits to 19.3 tons/yr. The source submitted a revised APEN on March 21, 2007 that included a HAP addendum to address chloroform emissions. 2. Emission Factors: Since cooling water towers provide direct contact between the cooling water and the air passing through the tower, some liquid can be entrained in the air stream and emitted as "drift" droplets. Particulate matter contained in the "drift" is considered an emission as well as any chloroform from water treatment chemicals used in the cooling water tower. Approval of emission factors for this unit is necessary to monitor compliance with the emission limits. The permit will require the source to calculate emissions from the cooling water towers in the following manner: PM = PKo=(water flow, gpm)x(water density, lbs/gal)x(% drift)x(total solids, ppm) Where: %drift= 0.0005% (BACT limit) Density of water= 8.34 lbs/gallon Total Solids= to be determined quarterly CHCI3= (water flow, gpm) x (3.785 I/gal)x(2.3 kg CHCI3/109 liter)x 2.205 lb/kg Page 28 Where: 2.3 kb/109 liter emission factor -from "Locating and Estimating Air Emissions from Sources of Chloroform", EPA-450/4-84-007c, March 1984, for recirculating units 3. Monitoring Plan: The source will be required to monitor and record the water circulation rate and calculate emissions monthly. In order to calculate emissions, the total solids content of the circulating water in the tower must be analyzed. The permit will require that the total solids content of the circulating water in each tower be analyzed quarterly. In the absence of credible evidence to the contrary, compliance with the opacity requirement will be presumed provided the cooling tower and associated drift eliminators are operated and maintained in accordance with the manufacturer's recommendations and good engineering practices. 4. Compliance Status: In the Title V permit application, the source indicated that the cooling tower was in compliance with all applicable requirements. IV. Insignificant Activities The source indicated that the following general categories of insignificant activities at this site include: landscaping and site housekeeping devices < 10 hp, tanks with annual throughput less than 400,000 gal per year (limited contents), and internal combustion engines (limited size and hours of operation). A specific list of insignificant activities was not included in the Title V permit application. However, based on the information in the Title V permit application, the construction permit and information provided by the source, the following insignificant activities are located at this facility: Units with emissions less than APEN de minims — non-criteria reportable pollutants (Req 3, Part C.II.E.3.b) Two (2) 12,000 gal anhydrous ammonia storage tanks Fuel (gaseous) burning equipment < 5 mmBtu/hr (Req 3, Part C.II.E.3.k) Water bath fuel heater Landscaping and site housekeeping devices < 10 hp (Req 3, Part C.II.E.3.bb) Garden tractor Stationary Internal Combustion Engines - limited size or hours (Req 3, Part C.II.E.3.xxx.(ii)) Diesel-fired emergency fire water pump (182 hp) V. Alternative Operating Scenarios Page 29 No alternative operating scenarios were requested for this facility. VI. Permit Shield Permit Shield for Non-Applicable Requirements The source indicated that they wanted the permit shield from all Colorado Air Quality Control regulations that were not identified as specifically applicable to the emissions units at their facility on Title V permit application forms 2000-604. No justification was provided for these regulations. The source has the right under Title V of the Clean Air Act Amendments (CAAA) to request the shield for regulations they determine are not applicable to specific equipment at a site in question. However, justification for each non-applicability determination is required. The Title V permit application did not provide a justification for non-applicability determinations, nor was the specific requirement clearly identified. For these reasons, the permit shield was not granted for any non-applicable requirements. Permit Shield for Streamlined Requirements These requirements are applicable to the emission units at the Rocky Mountain Energy Center. As discussed previously in this document, under streamlining of applicable requirements, the Division has included the above requirements, as appropriate in the permit shield for streamlined/subsumed conditions. The following applicable requirements were streamlined out of the permit for the turbines/HRSGs/duct burners and have been included in the permit shield. • 0.1 Ib/mmBtu PM requirement (Reg 1, Section III.A.1.c) streamlined out since the PM BACT limit is more stringent. • State-only— 0.35 lbs/mmBtu SO2 requirement (Reg 6, Part B, Section II.D.3.b), streamlined out since Reg 1 SO2 requirement is more stringent. • State-only— NSPS general provisions (Reg 6, Part B, Section I), streamlined out since units are subject to federal NSPS general provisions. • Monitor sulfur content of fuel (40 CFR Part 60 Subpart GG § 60.334(h)(3)), streamlined out in favor of the Acid Rain requirements in 40 CFR Part 75 Appendix D for gas-fired units (sulfur sampling). • 102 ppmvd NOx at 15% O2 and ISO conditions (40 CFR Part 60 Subpart GG § 60.332(b)) streamlined out since NOx BACT limit is more stringent. • 1.6 lb/MW-hr NOx, on a 30-day rolling average (40 CFR part 60 Subpart Da § 60.44a(d)(1)) streamlined out since NOx BACT limit is more stringent. Page 30 • 0.03 lb/mmBtu PM, the average of three (3) two hour tests (40 CFR part 60 Subpart Da § 60.42a(a)(1)) streamlined since the PM BACT limit is more stringent. The following applicable requirements were streamlined out of the permit for the auxiliary boiler and have been included in the permit shield. • State-only — PM emissions shall not exceed 0.5(Fl)°26 lb/mmBtu (Reg 6, Part B, Section II.C.2), streamlined out since Reg 1 PM requirement is more stringent. • State-only — NSPS general provisions (Reg 6, Part B, Section I), streamlined out since units are subject to federal NSPS general provisions. • 0.20 lb/mmBtu NOx, on a 30-day rolling average (40 CFR Part 60 Subpart Db § 60.44b(l)(1)) streamlined in favor of the NOx BACT limit. • NSPS Db requirement for NOx span value to be 500 ppm (40 CFR Part 60 Subpart Db § 60.48b(e)(2)), streamlined in favor of a 100 ppm, which is more appropriate for the lower BACT limit. • NSPS Db recordkeeping, monitoring and excess emission reports (40 CFR Part 60 Subpart Db §§ 60.49b(g), (h) and (i)) streamlined in favor of excess emission reporting for NOx BACT limit. • Retain records for two (2) years (40 CFR Part 60 Subpart Db § 60.49b(o)) streamlined in favor of Title V recordkeeping requirements. V. Acid Rain Requirements Both turbines are affected units under the Acid Rain Program which is governed by 40 CFR Parts 72, 73, 75, 76, 77 and 78 and as such the source is required to have provisions for the Acid Rain requirements in its Title V permit. Units subject to the Acid Rain requirements are required to hold adequate SO2 allowances and have NOx limitations. This facility is not listed under 40 CFR 73.10(b)(2) and therefore must obtain SO2 allowances as needed. Since these units are not coal-fired boilers, they do not have any NOx limitations under the Acid Rain Program. Typically, units subject to the Acid Rain requirements are required to continuously measure and record emissions of SO2, NOx (with diluent monitor either CO2 or O2) and CO2 as well as opacity and volumetric flow in accordance with the requirements in 40 CFR Part 75. Since these units meet the definition of gas-fired units in 40 CFR Part 72 §72.2, these units are not required to have a continuous opacity monitoring system and can use an alternate monitoring method (Appendix D), in lieu of installing and operating a continuous emission monitoring system for SO2. Page 31 co CO co N p! N f § ° ri L. S ; § 00 ) , Z 7 wz , co4 u § E E co ® cci . } \ \ # ; § 0 �n \ § `V. ) E 2 ) co 9= , a § I oeue ®~ tl)C 1515 azi co -4- 0 _Amo ° ° ( ( , f O ....,.-- ,-c co co 03 cu cc f Cl. qq , , —a. { \ > _ k �l�u m w 01 co ICI ) , ) = k 2 a N ( S $ Gj / ) o / _x -• , co , - 00 / /el 0. \ \ N ( ) « e § \ ee. 0 A ; , , N � ( \ § IL GfO m f c , ! ; ( oc / ) __+e ° m ° ) /} / k k in k _a � W % % § § / « _!9G , , 2 ) ( CO I N ; # e ( | } ) 2 ° � EE & _, ° , in w / °N \ { \ { ) E in CO § a co 0 ) ) me ° / _ co _ 0 k2 t 4 § co \ - E ) 4P�_ ~ , , N9 ~ } {22 ) 15 2 \ S FEE _ 0 § — — ) / r ) ti / i) / _ \ k \ \ (« wnm_w . _ ; fEPE 2 , ) { a $ k ) , ° a ❑ ❑ O N -,9 .LI w � si S,S R'' OO iJ '42. Y _ O N. p:�At y�'I• '� g o a '' `3 td - a 6 0 o �i n o "COW rl O ❑ C 4) M N `a a xa m;u 'O U 7 * O GV 1 O 7 O o V ...., C O X 2. v o -7 ti W id y p, 0. , w N O l0 N O �1 dl y O O ti O "d O © 4J U O O I el e 444 idr. 0 •O +O 0.1 O O " k O O (". ays { N 7 M O .� C) rl N n¢ s'{5A : :!OP..0.E.. 7 $ O 5 V aPPI a'�}� ^' y �' ^ 4) tE 7 ❑ 3 O M Vi •&p FJ+f +�yv#EPrt N 3 0 , N a F. S o+ a 4. $.a 0 ≥ y O O O O G GJ U O 7 O 0� C4 ypr 7 ro 2 O O ❑ 7 X 0 0 O Q i' i E1; O C ,� V] W M O G O m ,� N �i d . .�'F*I .�v, y y �* 4+ 1 s a 0 C CA X 'F ' O j`>f l ~Fl �`� as t 7 7 c G C d u p o et -'§' E ! ra 0 V ai 7 U W ri O .S U en N P2"V " v-' 4., #. " � a 7 L tA' ,2 Apr.,-,. `i3 0 td L i+ U .� O q e � ,Z yx� `O V a b to L a , rfi lr: ' y: U R c 3 `° � y0 e ir " Mom 3. .E il I 0:.2 M O . x rl N let t h ,0-W..E6 .t 5•2 V W t U C Virallartirititex:7 iiiii:i't Mr % a A oe �5� I { �'�' C C E o Li 1 �`'t e i F h''� N+oil O O tE y d = To ., I fi s `tlr O O ❑ E f.' z G 5 0 E z a E. U 7 0 O V CO .. : C .. 7 C �+ C .0 0.. w u to co y a O t G a O' I-. .O�' R PLi . Ek' i I i , ti "' m m O• O ❑ t'�k^CO x^ti:of { s E C o i' U :, xn, fi' 5 y 'O .1,' O ai "' ci .k, '; cl p w o e ea �o •o a x h , � v 7 ❑ O 2' ZC C ti o C .O w E E a.rtl C Fv ?^w e1 O gr O = C ae E 0 y 40.E y .S O ,hE `i N C. en z, q r x.. e k' "y1 N N O E N s' �` . ,= 'O T t b ❑ p , m t cO� - O.0 O .fl i 0 al al - U C 0.Phi .L 'OO 'C 1-I COFej o ° = O 7U � r ° '- eli4-',.... CL v) c A ❑ d c °° o b 5 O �O.0 k a VJ NN OO o 7 C 7 O Q ou d oq v « v1 7 t J a rL u v • a � Z la _d i ** ti x C a � \ ` } \ \ / ) . , \ | ) — / \ \ \ z \) a - , z \ 7 { / ) / f ) \ � § / j ' ( / / © ; ) ) ) _ / $ \ . j \ \ \ \ ± C ® - \ \ a I ]ifl / )L.4. \ 2 a { / \ 0 § 2 a «+ ) ( ® = n \ § \ / $ 0 a _ ] $ } $ I k � { \ / Z - \ } a » \ tRI_ ) In - / 0 z 0 \ 8 / \ ) ) . % e / / % § $ $ \ 2 . u 6 ) 2 \ Q._ § a 0.0 ( a $ $ e \ ) 2 2 2 k L , ( ) \ ? < \ / / N Oct0 O o vo a 7. y . o C0 'b•^W O^ p CU .5 ate+ `� \ O N d O W n O F •, V s N O v b V - X 1+ o'ro .G .5 W ,.4 o Q. y O y g '2 N N °,?,.. a.+ C� Oy., G C U o e o f o M O .- N cn N °� 0 o O O. t �' v y 0 et t c 3 ° ° E E o 1/40 ��±± o o i > O OO 0 O C 'a. +O V o :3 o O .y 2 V1 M O .� N Om '.r7 N a C in N j O .= 0 A cn C d CO id 4 • N U 0 3 e o a p N •" N N 'U o " o R C -' _ o O n o JD o:•� :.aim N �.2 E 'o tb O Y _ at to re LE =C C O6. yt d m 3 E ro y a U o to yRI 'O L O N d.. U O O R N V .S L k. M O .E. y 0 N 0L "Q G O q 4 A C G :D t4 CO J ti o et 3 "O gG c ro a O ct ea — co w O y lC• o y Z N z 3oo ell bw 0 • O tai T E y W U y 0saw R cr d 3 c a a W O y CI. 'b y V — 'ro ., CC0 `ri O 0 C o y C! 2 CL) 0 G v; • W JQynj G',. .�. a.d bA tO v . Y t N �d �' S •a h N 'ri Cl) M O . ;m cn• z ti m G •y y a `o b p O E € bN O O ems+ �y71. L to Z N ON W ctl -t) C O. et• y D C m tie, p 0 M cn a m O .n d u c] i, O •r tO t t o L.a) 0 V ,_, a c b V " U U O G a r .O `° .O R o u V 04 ti fl ,rzr ari ¢ dco ) (4 6s Vi > ;.0)4u O * * h cF Colo 57v _4d_ 4 o SINE Nu" 876 Colorado Department of Public Health and Environment OPERATING PERMIT Rocky Mountain Energy Center, LLC Issued: DRAFT AIR POLLUTION CONTROL DIVISION COLORADO OPERATING PERMIT FACILITY NAME: Rocky Mountain OPERATING PERMIT NUMBER Energy Center FACILITY ID: 1231342 05OPWE279 ISSUE DATE: EXPIRATION DATE: MODIFICATIONS: See Appendix F of Permit Issued in accordance with the provisions of Colorado Air Pollution Prevention and Control Act, 25-7-101 et sec. and applicable rules and regulations. ISSUED TO: PLANT SITE LOCATION: Rocky Mountain Energy Center, LLC Rocky Mountain Energy Center, LLC 717 Texas Avenue, Suite 1000 6211 Weld County Road 51 Houston, TX 77002 Keenesburg, CO 80643 Weld County INFORMATION RELIED UPON Operating Permit Application Received: March 14, 2005 And Additional Information Received: November 17, 2006, January 19, 2007 and March 21, 2007 Nature of Business: Electrical Power Generation Primary SIC: 4911 RESPONSIBLE OFFICIAL FACILITY CONTACT PERSON Name: Mr. Jason M. Goodwin, P. E. Name: Gary Aron Title: Director—EH & S Title: Operations Manager Phone: (713) 570-4795 Phone: (303) 536-2518 SUBMITTAL DEADLINES Semi-Annual Monitoring Period: EXAMPLE (January 1 —June 30, July 1 —December 31) Semi-Annual Monitoring Report: EXAMPLE (Due August 1, 2006 & February 1, 2007 & subsequent years) Annual Compliance Period: EXAMPLE (January 1 — December 31) Annual Compliance Certification: EXAMPLE (Due February 1, 2007 and subsequent years) Note that the Semi-Annual Monitoring Reports and Annual Compliance Certifications must be received at the Division office by 5:00 p.m. on the due date. Postmarked dates will not be accepted for the purposes of determining the timely receipt of those reports/certifications. FOR ACID RAIN SUBMITTAL DEADLINES SEE SECTION 11I.4 OF THIS PERMIT Table of Contents: SECTION I - General Activities and Summary 1 1. Permitted Activities 1 2. Alternative Operating Scenarios 2 3. Prevention Of Significant Deterioration (PSD) 2 4. Accidental Release Prevention Program (112(r)) 2 5. Compliance Assurance Monitoring (CAM) 2 6. Summary of Emission Units 3 SECTION II - Specific Permit Terms 4 1. Units S001 & S002—Two (2)Natural Gas Fired Combustion Turbines Each Equipped with a HRSG and Duct Burner 4 2. S005- Emergency Generator Rated at 1,810 hp 19 3. S004—Rentech Natural Gas Fired Boiler Rated at 129 mmBtu/hr 21 4. S006—Marley Cooling Water Tower 26 5. Facility Wide HAP Limits 28 6. Continuous Emission Monitoring Requirements 29 SECTION III - Acid Rain Requirements 34 1. Designated Representative and Alternate Designated Representative 34 2. Sulfur Dioxide Emission Allowances and Nitrogen Oxide Emission Limitations 34 3. Standard Requirements 34 4. Reporting Requirements 38 5. Comments, Notes and Justifications 38 SECTION IV - Permit Shield 39 1. Specific Non-Applicable Requirements 39 2. General Conditions 39 3. Streamlined Conditions 39 SECTION V - General Permit Conditions 41 I. Administrative Changes 41 2. Certification Requirements 41 3. Common Provisions 41 4. Compliance Requirements 45 5. Emergency Provisions 46 6. Emission Standards for Asbestos 46 7. Emissions Trading, Marketable Permits, Economic Incentives 46 8. Fee Payment 46 9. Fugitive Particulate Emissions 47 10. Inspection and Entry 47 11. Minor Permit Modifications 47 12. New Source Review 47 13. No Property Rights Conveyed 47 14. Odor 47 15. Off-Permit Changes to the Source 48 16. Opacity 48 17. Open Burning 48 18. Ozone Depleting Compounds 48 Table of Contents: 19. Permit Expiration and Renewal 48 20. Portable Sources 48 21. Prompt Deviation Reporting 49 22. Record Keeping and Reporting Requirements 49 23. Reopenings for Cause 50 24. Section 502(b)(10) Changes 51 25. Severability Clause 51 26. Significant Permit Modifications 51 27. Special Provisions Concerning the Acid Rain Program 51 28. Transfer or Assignment of Ownership 51 29. Volatile Organic Compounds 51 30. Wood Stoves and Wood burning Appliances 52 APPENDIX A-Inspection Information 1 Directions to Plant 1 Safety Equipment Required 1 Facility Plot Plan 1 List of Insignificant Activities 1 APPENDIX B i Reporting Requirements and Definitions 1 Monitoring and Permit Deviation Report-Part I 5 Monitoring and Permit Deviation Report- Part II 7 Monitoring and Permit Deviation Report -Part III 9 APPENDIX C 1 Required Format for Annual Compliance Certification Report 1 APPENDIX D 1 Notification Addresses 1 APPENDIX E 1 Permit Acronyms 1 APPENDIX F 1 Permit Modifications 1 Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page I SECTION I - General Activities and Summary 1. Permitted Activities 1.1 The Rocky Mountain Energy Center (RMEC) consists of two combined cycle combustion turbines used to generate electric power under Standard Industrial Classification 4911. The facility consists of two natural gas fired combustion turbines, two heat recovery steam generators (HRSG), each equipped with natural gas fired duct burners, a steam turbine, cooling tower and auxiliary boiler. There are two diesel fired engines, one driving an emergency generator and one driving a fire pump. The engine driving the fire-pump is considered an insignificant activity and included in the insignificant activity in Appendix A of the permit. The RMEC has the capacity to generate up to 630 MW of electricity. Each combustion turbine can generate approximately 152 MW, with an additional 326 MW (at peak capacity) from the steam turbine. The turbines are not equipped with a by-pass stack, therefore, the turbines only operate in combined cycle mode (e.g. turbine plus HRSG). The facility is located at 6211 Weld County Road 51,just east of the town of Hudson, in Weld County Colorado (bounded by CR 49 to the west, CR 16 to the north and CR 51 to the east). The area in which the plant operates is designated as attainment for all criteria pollutants, but is located within the 8-hour Ozone Control Area as defined in Colorado Regulation No. 7, Section II.A.16. There are no affected states within 50 miles of this facility. Rocky Mountain National Park, a federal class I designated area is within 100 km of this facility. 1.2 Until such time as this permit expires or is modified or revoked, the permittee is allowed to discharge air pollutants from this facility in accordance with the requirements, limitations, and conditions of this permit. 1.3 This Operating Permit incorporates the applicable requirements contained in the underlying construction permits, and does not affect those applicable requirements, except as modified during review of the application or as modified subsequent to permit issuance using the modification procedures found in Regulation No. 3, Part C. These Part C procedures meet all applicable substantive New Source Review Requirements of Part B. Any revisions made using the provisions of Regulation No. 3, Part C shall become new applicable requirements for purposes of this operating permit and shall survive reissuance. This permit incorporates the applicable requirements (except as noted in Section II) from the following construction permit: 02WE0228. 1.4 All conditions in this permit are enforceable by US Environmental Protection Agency, Colorado Air Pollution Control Division (hereinafter Division) and its agents, and citizens unless otherwise specified. State-only enforceable conditions are: Permit Condition Number(s): Section II, Conditions 1.12.1 and 3.11 (opacity) and Section V - Conditions 3.d, 3.g (last paragraph), 14 and 18 (as noted) Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 2 1.5 All information gathered pursuant to the requirements of this permit is subject to the Recordkeeping and Reporting requirements listed under Condition 22 of the General Conditions in Section V of this permit. 2. Alternative Operating Scenarios 2.1 The permittee shall be allowed to make the following changes to its method of operation without applying for a revision of this permit. 2.1.1 No separate operating scenarios have been specified. 3. Prevention Of Significant Deterioration (PSD) 3.1 This source is located in an area designated attainment or attainment/maintenance for all pollutants. This facility is categorized as a major stationary source (Potential to Emit > 100 Tons/Year) as of the issuance date of this permit. The Division issued a PSD permit for this facility on July 15, 2002. Future modifications at this facility resulting in a significant net emissions increase (see Reg 3, Part D, Sections II.A.26 and 42) for any pollutant as listed in Regulation No. 3, Part D, Section II.A.44 or a modification which is major by itself will result in the application of the PSD review requirements. 3.2 There are no other Operating Permits associated with this facility for purposes of determining applicability of Prevention of Significant Deterioration regulations. 4. Accidental Release Prevention Program (112(r)) 4.1 Based on the information provided by the applicant, this facility is subject to the provisions of the Accidental Release Prevention Program (section 112(r)) of the Federal Clean Air Act. 5. Compliance Assurance Monitoring(CAM) 5.1 The following emission points at this facility use a control device to achieve compliance with an emission limitation or standard to which they are subject and have pre-control emissions that exceed or are equivalent to the major source threshold. They are therefore subject to the provisions of the CAM program as set forth in 40 CFR Part 64, as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV: Units S001 and S002 —Combustion Turbines/HRSGs/Duct Burners See Section II, Condition 1.13 for compliance assurance monitoring requirements. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 3 6. Summary of Emission Units 6.1 The emissions units regulated by this permit are the following: Emission AIRS Facility Description Pollution Control Unit Stack Identifier Device Number Number S001 001 CT-01 One(1)Westinghouse,Model No. 501FD,Natural Gas-Fired Dry Low NOx Combustion Turbine, Serial No. 37A8191. The Turbine is Rated (DLN)Combustion at 1785 mmBtu/hr(HHV at ISO conditions). The turbine is Systems and operated in combined cycle mode only and the heat recovery Selective Catalytic steam generator(HRSG)is equipped with a duct burner rated at Reduction(SCR) 675 mmBtu/hr. The turbine drives a generator capable of for NOx and generating 152 MW of power and the HRSG drives a steam Oxidation Catalyst generator rated at 326 MW(at peak capacity). for CO and VOC. S002 002 CT-02 One(1)Westinghouse,Model No. 501FD,Natural Gas-Fired Dry Low NOx Combustion Turbine, Serial No. 37A8196. The Turbine is Rated (DLN)Combustion at 1785 mmBtu/hr(HHV at ISO conditions). The turbine is Systems and operated in combined cycle mode only and the heat recovery Selective Catalytic steam generator(HRSG)is equipped with a duct burner rated at Reduction(SCR) 675 mmBtu/hr. The turbine drives a generator capable of for NOx and generating 152 MW of power and the HRSG drives a steam Oxidation Catalyst generator rated at 326 MW(at peak capacity). for CO and VOC. S005 005 S005 Caterpillar,Model No. 3512B,Internal Combustion Engine Uncontrolled Driving an Emergency Generator, Serial No. 1GZ01360. The Engine is Diesel Fuel-Fired and rated at 1810 hp and 6.51 mmBtu/hr. 5004 004 S004 Rentech,Natural Gas Fired Boiler, Rated at 129 mmBtu/hr,Serial Low NOx Burners No.2002-49. S006 006 S006 Marley, Model No. F4910, 12 Cell Cooling Water Tower,Rated at Drift Eliminators 176,000 gal/min. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 4 SECTION II- Specific Permit Terms 1. Units S001 & S002—Two (2) Natural Gas Fired Combustion Turbines Each Equipped with a HRSG and Duct Burner Unless Otherwise Specified Limits are for Both Turbines/HRSGs/Duct Burners Parameter Permit Limitations Compliance Monitoring Condition Emission Number Short Term Long Term Factor Method Interval BACT 1.1 See Condition 1.1. N/A See Condition 1.1. Requirements PM/PM I0 1.2. N/A 126.8 tons/yr PM 0.001 Recordkeeping Monthly lb/mmBtu and Calculation PM10 0.001 lb/mmBtu For Each Turbine/13RSG/duct N/A See Condition 1.2. burner: 0.00735 lbs/mmBtu,the average of three(3)test runs VOC 1.3. N/A 50.6 tons/yr Unit 1 -7.3 x Recordkeeping Monthly 104 lb/mmBtu and Calculation Unit2-1.5x 10-0 lb/mmBtu For Each Turbine/HRSG/duct N/A See Condition 1.3. burner: 0.00293 lbs/mmBtu,the average of three(3), 1-hr tests SO2 1.4. N/A 11.8 tons/yr N/A 40 CFR Part 75, As specified in Appendix D 40 CFR Part 75,Appendix D For Each Turbine: N/A Fuel Restriction Only Pipeline 150 ppmvd @ 15%O2 OR Use of Quality Natural Fuel Which Contains Less than 0.8 Gas is Used as Weight%Sulfur Fuel For Each Turbine: 0.35 lbs/mmBtu,on a 3-hour rolling average For Each Duct Burner: 0.20 lbs/mmBtu, on a 30-Day Rolling Average Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 5 Parameter Permit Limitations Compliance Monitoring Condition Emission Number Short Term Long Term Factor Method Interval NOx 1.5. For Each Turbine/HRSG/Duct N/A Continuous Continuously Burner: Emission 3 ppmvd @ 15%O2 on a 1-hr Monitoring average,except as provided for System below During Startup and Shutdown: 300 ppmvd @ 15%O2 averaged over the startup and/or shutdown period N/A 240.4 tons/yr CO 1.6. For Each Turbine/HRSG/Duct N/A Continuous Continuously Burner: Emission 9 ppmvd @ 15%O2 on a 1-hr Monitoring average,except as provided for System below During Startup and Shutdown: 1,000 ppmvd @ 15%O2 averaged over the startup and/or shutdown period N/A 782.2 tons/yr Natural Gas 1.7. N/A 32,625 mmSCF/yr N/A Recordkeeping Monthly Consumption Continuous 1.8. N/A N/A N/A See Condition 1.8. Emission Monitoring System Requirements Fuel Flow Meter 1.9. N/A N/A N/A See Condition 1.9. i Sulfur Content of 1.10. Pipeline Quality Natural Gas(total N/A See Condition 1.10. Fuel sulfur content not to exceed 0.5 grains/100 SCF) NSPS General 1.11. N/A N/A N/A As Required by Subject to Provisions NSPS General NSPS General Provisions Provisions Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 6 Parameter Permit Limitations Compliance Monitoring Condition Emission Number Short Term Long Term Factor Method Interval Opacity 1.12. State Only Requirement: Not to N/A See Condition Exceed 20% 1.12. Not to Exceed 20%(6-minute average),Except for One Six Minute Average Not to Exceed 27%Per Hour Not to Exceed 20%Except as Provided for Below For Certain Operational Activities- Not to Exceed 30%,for a Period or Periods Aggregating More than Six (6)Minutes in any 60 Consecutive Minutes Compliance 1.13. N/A N/A N/A See Condition 1.13. Assurance Monitoring Requirements Acid Rain 1.14. See Section III of this Permit Certification Annually Requirements 1.1 The turbines/HRSGs/duct burners are subject to the requirements of the prevention of Significant Deterioration (PSD) Program. Best Available Control Technology (BACT) shall be applied for control of Nitrogen Oxides (NOx), Carbon Monoxide (CO), Particulate Matter (PM and PMto) and Volatile Organic Compounds. BACT has been determined as follows: 1.1.1 BACT for NOx has been determined to be dry low NOx (DLN) combustion system and selective catalytic reduction (SCF) with the emission limits identified in Condition 1.5.1 (Colorado Construction Permit 02WE0228). 1.1.2 BACT for CO has been determined to be good combustion practices and an oxidation catalyst with the emission limits identified in Condition 1.6.1 (Colorado Construction Permit 02WE0228). 1.1.3 BACT for PM and PMto has been determined to be use of pipeline quality natural gas as fuel, good combustion practices with the emission limitations identified in Condition 1.2.2 (Colorado Construction Permit 02WE0228). 1.1.4 BACT for VOC has been determined to be use of pipeline quality natural gas as fuel, good combustion practices and an oxidation catalyst with the emission limitations identified in Condition 1.3.2 (Colorado Construction Permit 02WE0228). Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 050PWE279 Page 7 1.2 PM and PKo emissions are subject to the following requirements: 1.2.1 Total Annual emissions of PM and PKo from both turbines/HRSGs/duct burners together shall not exceed the above limitations (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 3.1 to set emission units for individual equipment instead of a facility wide total). Monthly emissions from each turbine/HRSG/duct burner shall be calculated by the end of the subsequent month using the above emission factors (from performance tests conducted May and September 2004) and the heat input for the month as recorded on the data acquisition and handling system (DAHS) for the continuous emission monitoring system (required by Condition 1.8) in the following equation: tons/mo=(EF, Ibs/mmBtu)x heat input(mmBtu/mo) 2000 lbs/ton Monthly emissions from each turbine/HRSG/duct burner shall be summed together and used in a twelve month rolling total to monitor compliance with the annual limitations. Each month a new twelve month total shall be calculated using the previous twelve months data. 1.2.2 For purposes of BACT, Total (filterable plus condensable) Particulate Matter(PM) and Particulate Matter less than 10 microns (PM10) emissions from each turbine/HRSG/duct burner shall not exceed 0.00735 lbs/mmBtu, based on the average of three (3) one-hour test runs (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to specify the averaging time). Compliance with the PM and PM10 BACT limits shall be monitored as follows: 1.2.2.1 In the absence of credible evidence to the contrary, compliance with the particulate matter emission limits is presumed since only pipeline quality natural gas that meets the requirements in Condition 1.10 is permitted to be used as fuel in the turbines and duct burners. 1.2.2.2 A performance test shall be conducted within 18 months of expiration of this permit in accordance with the requirements of 40 CFR Part 60 Subpart A§ 60.8 using EPA Test Methods 5 and 202. A stack testing protocol shall be submitted for Division approval at least thirty (30) calendar days prior to performance of the test required under this condition. No stack test required herein shall be performed without prior written approval of the protocol by the Division. The Division reserves the right to witness the test. In order to facilitate the Division's ability to make plans to witness the test, notice of the date (s) for the stack test shall be submitted to the Division at least thirty (30) calendar days prior to the test. The Division may for good cause shown,waive this thirty (30) day notice requirement. In instances when a scheduling conflict is presented, the Division shall immediately contact the permittee Operating Permit Number: 050PWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 8 in order to explore the possibility of making modifications to the stack test schedule. The required number of copies of the compliance test results shall be submitted to the Division within forty-five (45) calendar days of the completion of the test unless a longer period is approved by the Division. 1.3 VOC emissions are subject to the following requirements: 1.3.1 Total Annual emissions of VOC from both turbines/HRSGS/duct burners together shall not exceed the above limitations (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to set emission units for individual equipment instead of a facility wide total). Monthly emissions from each turbine/HRSG/duct burner shall be calculated by the end of the subsequent month using the above emission factors (from performance tests conducted May and September 2004) and the heat input for the month as recorded on the data acquisition and handling system(DAHS) for the continuous emission monitoring system (required by Condition 1.8) in the following equation: tons/mo=(EP,lbs/mmBtu)x heat input(mmBtu/mo) 2000 lbs/ton Monthly emissions from each turbine/HRSG/duct burner shall be summed together and used in a twelve month rolling total to monitor compliance with the annual limitations. Each month a new twelve month total shall be calculated using the previous twelve months data. 1.3.2 For purposes of BACT, VOC emissions from each turbine/HRSG/duct burner shall not exceed 0.00293 lb/mmBtu, based on the average of three (3) one-hour test runs (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to specify the averaging time). In the absence of credible evidence to the contrary, compliance with the VOC BACT emission limit is presumed provided the requirements in Condition 1.6.1 (CO BACT limits) are met. 1.4 Sulfur Dioxide (SO2) emissions shall not exceed the following limitations: 1.4.1 Total Annual Sulfur Dioxide (SO2) emissions from both turbines/HRSGs/Duct Burner together shall not exceed the above limitations (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to set emission units for individual equipment instead of a facility wide total). Compliance with the annual SO2 emission limitations shall be monitored using the monitoring method specified in 40 CFR Part 75 Appendix D. Monthly emissions from each turbine/HRSG/duct burner shall be summed together and used in a twelve month rolling total to monitor compliance with the annual limitations. Each month a new twelve month total shall be calculated using the previous twelve months data. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit ti 05OPWE279 Page 9 1.4.2 Each turbine shall meet one of the following requirements: 1.4.2.1 Sulfur Dioxide (SO2) emissions from each turbine shall not exceed 150 ppmvd at 15% O2 OR 1.4.2.2 No fuel, which contains sulfur in excess of 0.8 percent by weight, shall be used in these combustion turbines (40 CFR Part 60 Subpart GG §§ 60.333(a) & (b), as adopted by reference in Colorado Regulation No. 6, Part A). Compliance with the above requirements is presumed, in the absence of evidence to the contrary, since only pipeline quality natural gas that meets the requirements in Condition 1.10 is permitted to be used as fuel in these turbines. 1.4.3 Sulfur Dioxide (SO2) emissions from each turbine shall not exceed 0.35 lbs/mmBtu, on a 3-hr rolling average (Colorado Regulation No. 1, Section VI.B.4.c.(ii) and VI.B.2). In the absence of credible evidence to the contrary, compliance with the SO2 limitations is presumed since only pipeline quality natural gas that meets the requirements in Condition 1.10 is permitted to be used as fuel in these turbines. 1.4.4 Sulfur Dioxide (SO2) emissions from each duct burner shall not exceed 0.20 lbs/mmBtu on a 30-day rolling average (40 CFR Part 60 Subpart Da§ 60.43a(b)(2), as adopted by reference in Colorado Regulation No. 6, Part A). In the absence of credible evidence to the contrary, compliance with the sulfur dioxide limitations is presumed, since only pipeline quality natural gas that meets the requirements in Condition 1.10 is permitted to be used as fuel in these duct burners. 1.5 Emissions of Nitrogen Oxides (NOx) shall not exceed the following limitations: 1.5.1 For purposes of BACT, Nitrogen Oxide (NOx) emissions from each turbine/HRSG/duct burner shall not exceed the following limitations (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to revise the definitions of startup and shutdown): 1.5.1.1 Except as provided for below, emissions of NOx shall not exceed 3 ppmvd at 15% O2, on a 1-hour average. 1.5.1.2 During periods of startup and shutdown, emissions of NOx shall not exceed 300 ppmvd at 15% O2, as averaged over the duration of the startup and/or shutdown period. 1.5.1.3 "Startup"means the setting in operation of any air pollution source for any purpose. Setting in operation for these turbines begins when flame is detected in the turbine. Setting in operation for these turbines ends 30 minutes after the turbine reaches Stage-C operation. 1.5.1.4 "Shutdown"means the cessation of operation of any air pollution source for any purpose. The cessation of operation for these turbines begins Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 10 when the command signal is initiated by the turbine operator to shutdown the unit and ends when fuel is no longer being fired in the turbine. Compliance with the NOx BACT emission limitations shall be monitored as follows: 1.5.1.5 Compliance with the NOx BACT limit in Condition 1.5.1.1 shall be monitored using the continuous emission monitoring systems (CEMS) required by Condition 1.8. Except as provided for in condition 1.5.1.6, all the CEMS concentration (ppm) data points, shall at the end of each clock hour, be summarized to generate the one-hour average NOx concentration. Each clock hour average NOx concentration shall be compared to the limitation in Condition 1.5.1.1. 1.5.1.6 Compliance with the NOx BACT limit in Condition 1.5.1.2 shall be monitored using the CEMS required by Condition 1.8. All concentration data points within the startup and/or shutdown period shall be averaged together to generate the average NOx concentration for a given startup and/or shutdown period. The average NOx concentration for each startup and shutdown period shall be compared to the limitation in Condition 1.5.1.2. In the event that the startup ends within a clock hour or the shutdown begins within a clock hour, all non-startup and/or non-shutdown concentration(ppm) data points within that clock hour shall be averaged together to generate the average NOx concentration and that average concentration shall be compared to the limitations in Condition 1.5.1.1. 1.5.2 Total Annual emissions of NOx from both turbines/HRSGs/duct burners together shall not exceed the above limitation(Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to set emission units for individual equipment instead of a facility wide total). Monthly emissions from each turbine/HRGS/duct burner shall be determined using the continuous emission monitoring system required by Condition 1.8. Monthly emissions from each turbine/HRSG/duct burner shall be summed together and used in a twelve month rolling total to monitor compliance with the annual emission limitation. Each month a new twelve month total shall be calculated using the previous twelve months total. 1.6 Emissions of Carbon Monoxide (CO) shall not exceed the following limitations: 1.6.1 For purposes of BACT, Carbon Monoxide (CO) emissions from each turbine/HRSG/duct burner shall not exceed the following limitations (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to revise the definition of startup and shutdown and to remove the limit for CO during the 1st hour of a cold startup): 1.6.1.1 Except as provided for below, emissions of CO shall not exceed 9 ppmvd at 15%O2, on a 1-hour average. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 11 1.6.1.2 During periods of startup and shutdown, emissions of CO shall not exceed 1,000 ppmvd at 15% O2, as averaged over the duration of the startup and/or shutdown period. 1.6.1.3 "Startup" shall have the same definition as in Condition 1.5.1.3. 1.6.1.4 "Shutdown" shall have the same definition as in Condition 1.5.1.4. Compliance with the CO BACT emission limitations shall be monitored as follows: 1.6.1.5 Compliance with the CO BACT emission limitation in Condition 1.6.1.1 shall be monitored using the CEMS required by Condition 1.8. Except as provided for in Condition 1.6.1.6, all the CEMS concentration (ppm) data points, shall at the end of each clock hour, be summarized to generate the one-hour average CO concentration. Each clock hour average CO concentration shall be compared to the limitation in Condition 1.6.1.1. 1.6.1.6 Compliance with the CO BACT emission limitation in Condition 1.6.1.2 shall be monitored using the CEMS required by Condition 1.8. All concentration(ppm) data points within the startup and/or shutdown period shall be averaged together to generate the average CO concentration for a given startup and/or shutdown period. The average CO concentration for each startup and shutdown period shall be compared to the limitation in Condition 1.6.1.2. In the event that the startup ends within a clock hour or the shutdown begins within a clock hour, all non-startup and/or non-shutdown concentration (ppm) data points within that clock hour shall be averaged together to generate the average CO concentration and that average concentration shall be compared to the limitation in Condition 1.6.1.1. 1.6.2 Total Annual emissions of CO from both turbines/HRSGs/duct burners together shall not exceed the above limitations (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3,to set emission units for individual equipment instead of a facility wide total). Monthly emissions from each turbine/HRGS/duct burner shall be determined using the continuous emission monitoring system required by Condition 1.8. Monthly emissions from each turbine/HRSG/duct burner shall be summed together and used in a twelve month rolling total of emissions to monitor compliance with the annual emission limitation. Each month a new twelve month total shall be calculated using the previous twelve months total. 1.7 Total natural gas consumption for both turbines/HRSGs/duct burners together shall not exceed the above limitations (Colorado Construction Permit 02WE0228). The natural gas consumption for each turbine/HRGS/duct burner shall be monitored and recorded monthly using the fuel flow meters required by Condition 1.9. Monthly natural gas fuel consumption for each turbine/HRSG/duct burner shall be summed together and used in a rolling twelve month total to monitor compliance with the annual limitation. Each month a new twelve month rolling total shall be calculated using the previous twelve months data. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 12 1.8 Each of the turbine/HRSG/duct burner exhaust stacks shall be equipped with a continuous emission monitoring system to measure and record the following: 1.8.1 Concentration of Oxides of Nitrogen; ppmvd corrected to 15 % O2, hourly average; 1.8.2 Emissions of Oxides of Nitrogen;pounds per hour, tons per month; 1.8.3 Concentration of Carbon Monoxide; ppmvd corrected to 15% O2, hourly average; 1.8.4 Emissions of Carbon Monoxide, pounds per hour, tons per month; 1.8.5 Concentration of Oxygen,percent hourly average; 1.8.6 Operating mode—startup, shutdown and/or standard operation; and The continuous emission monitoring systems shall meet the requirements in Condition 6 of this permit. Monthly emissions of NOx and CO from the continuous emission monitoring system shall be used as specified by Conditions 1.5.2 and 1.6.2 to monitor compliance with the annual NOx and CO emission limitations. 1.9 Each turbine/HRSG/duct burner shall be equipped with an in-line fuel flow meter that meets the requirements in 40 CFR Part 75 Appendix D to measure fuel combusted in each turbine. Fuel flow data shall be recorded on a data acquisition and handling system as specified in 40 CFR Part 75 Appendix D (Colorado Construction Permit 02WE0228). 1.10 The permittee shall maintain records demonstrating that the natural gas burned meets the definition of pipeline quality natural gas as defined in 40 CFR Part 72. Specifically, the permittee shall demonstrate that the natural gas burned has a total sulfur content less than 0.5 grains/100 SCF. The demonstration shall be made using any of the methods identified in 40 CFR Part 75 Appendix D, Section 2.3.1.4. These records shall be made available to the Division upon request. 1.11 Regulation No. 6, Part A, Subpart A, General Provisions apply as follows: 1.11.1 No article, machine, equipment or process shall be used to conceal an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to, the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gasses discharged to the atmosphere. (Colorado Construction Permit 01AD0575 and 40 CFR Part 60 Subpart A § 60.12, as adopted by reference in Colorado Regulation No. 6, Part A) 1.11.2 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall to the extent practicable, maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 13 acceptable operating and maintenance procedures are being used will be based on information available to the Division which may include, but is not limited to monitoring results, opacity observations,review of operating and maintenance procedures, and inspection of the source (Colorado Construction Permit 01AD0575 and 40 CFR Part 60 Subpart A § 60.11(d), as adopted by Regulation No. 6, Part A). 1.12 The turbines/HRSGs/duct burners are subject to the following opacity requirements: 1.12.1 State-Only Requirement: No owner or operator may discharge, or cause the discharge into the atmosphere of any particulate matter which is greater than 20% opacity (Colorado Regulation No. 6, Part B, Section II.C.3). This opacity standard applies to each turbine/HRGS/duct burner. This opacity standard applies at all times except during periods of startup, shutdown and malfunction (40 CFR Part 60 Subpart A § 60.11(c), as adopted by reference in Colorado Regulation No. 6, Part B, Section I.A). Note that this opacity requirement is more stringent than the opacity requirement in Conditions 1.12.2 and 1.12.4 during periods of building of a new fire, cleaning of fire boxes, soot blowing,process modifications and adjustment or occasional cleaning of control equipment. 1.12.2 No owner or operator of a source shall cause to be discharged into the atmosphere from any affected facility any gases which exhibit greater than 20 percent opacity (6- minute average), except for one 6-minute period per hour of not more than 27 percent opacity ((40 CFR Part 60 Subpart Da § 60.42a(b), as adopted by reference in Colorado Regulation No. 6, Part A and Colorado Construction Permit 99WE0762 PSD). This opacity standard applies to each duct burner. This opacity standard applies at all times except during periods of startup, shutdown and malfunction (40 CFR Part 60 Subpart A § 60.11(c), as adopted by reference in Colorado Regulation No. 6, Part A). Note that this opacity requirement is more stringent than the opacity requirement in Condition 1.12.4 during periods of building of a new fire, cleaning of fire boxes, soot blowing, process modifications and adjustment or occasional cleaning of control equipment. 1.12.3 Except as provided for in Condition 1.12.4 below, no owner or operator of a source shall allow or cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity (Colorado Construction Permit 02WE0228 and Colorado Regulation No. 1, Section II.A.1). This opacity standard applies to each turbine/HRGS/duct burner. 1.12.4 No owner or operator of a source shall allow or cause to be emitted into the atmosphere any air pollutant resulting from the building of a new fire, cleaning of fire Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 14 boxes, soot blowing, start-up, process modifications, or adjustment or occasional cleaning of control equipment which is in excess of 30%opacity for a period or periods aggregating more than six (6) minutes in any sixty (60) consecutive minutes (Colorado Construction Permit 02WE0228 and Colorado Regulation No. 1, Section II.A.4). This opacity standard applies to each turbine/HRGS/duct burner. In the absence of credible evidence to the contrary, each turbine shall be presumed to be in compliance with the above opacity requirements whenever natural gas is used as fuel. 1.13 The Compliance Assurance Monitoring (CAM) requirements in 40 CFR Part 64, as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV, apply with respect to the NOx and CO emission limitations identified in Conditions 1.5 and 1.6 as follows: 1.13.1 The permittee shall monitor the exhaust gas NOx and CO concentration(ppmvd at 15% O2) and mass (lbs/hr) emissions using the continuous emission monitoring system required by Condition 1.8. Exceedances, for purposes of CAM, shall be any 1-hr period that the NOx and/or CO concentration exceeds the limits identified in Condition 1.5.1.1 and 1.6.1.1, any NOx and/or CO concentration average over either a startup and/or shutdown period that exceeds the limits identified in Conditions 1.5.1.2 and 1.6.1.2 and any twelve month period that the NOx and/or CO emissions (tons/yr) exceeds the limits identified in Condition 1.5.2 and 1.6.2. Exceedances of these limitations shall be reported as required by Section II, Condition 6.5 and Section V, Conditions 21 and 22.d of this permit. 1.13.2 Operation of Approved Monitoring 1.13.2.1 At all times,the owner or operator shall maintain the monitoring, including but not limited to, maintaining necessary parts for routine repairs of the monitoring equipment(40 CFR Part 64 § 64.7(b), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.2.2 Except for, as applicable, monitoring malfunctions, associated repairs, and required quality assurance or control activities (including, as applicable, calibration checks and required zero and span adjustments), the owner or operator shall conduct all monitoring in continuous operation(or shall collect data at all required intervals) at all times that the pollutant-specific emissions unit is operating. Data recorded during monitoring malfunctions, associated repairs, and required quality assurance or control activities shall not be used for purposes of these CAM requirements, including data averages and calculations, or fulfilling a minimum data availability requirement, if applicable. The owner or operator shall use all the data collected during all other periods in assessing the operation of the control device and associated control system. A monitoring malfunction is any sudden, infrequent, not reasonably preventable failure of the monitoring to provide valid data. Monitoring failures that are caused in part by poor maintenance or careless operation are not malfunctions (40 Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 15 CFR Part 64 § 64.7(c), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.2.3 Response to excursions or exceedances a. Upon detecting an excursion or exceedance, the owner or operator shall restore operation of the pollutant-specific emissions unit (including the control device and associated capture system)to its normal or usual manner of operation as expeditiously as practicable in accordance with good air pollution control practices for minimizing emissions. The response shall include minimizing the period of any startup, shutdown or malfunction and taking any necessary corrective actions to restore normal operation and prevent the likely recurrence of the cause of an excursion or exceedance (other than those caused by excused startup or shutdown conditions). Such actions may include initial inspection and evaluation, recording that operations returned to normal without operator action (such as through response by a computerized distribution control system), or any necessary follow-up actions to return operation to within the indicator range, designated condition, or below the applicable emission limitation or standard, as applicable (40 CFR Part 64 § 64.7(d)(1), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). b. Determination of whether the owner of operator has used acceptable procedures in response to an excursion or exceedance will be based on information available, which may include but is not limited to, monitoring results, review of operation and maintenance procedures and records, and inspection of the control device, associated capture system, and the process (40 CFR Part 64 § 64.7(d)(2), as adopted by reference in Colorado Regulation No. 3,Part C, Section XIV). 1.13.2.4 After approval of the monitoring required under the CAM requirements, if the owner or operator identifies a failure to achieve compliance with an emission limitation or standard for which the approved monitoring did not provide an indication of an excursion or exceedance while providing valid data, or the results of compliance or performance testing document a need to modify the existing indicator ranges or designated conditions, the owner or operator shall promptly notify the Division and, if necessary submit a proposed modification for this permit to address the necessary monitoring changes. Such a modification may include, but is not limited to, reestablishing indicator ranges or designated conditions, modifying the frequency of conducting monitoring and collecting data, or the monitoring of additional parameters (40 CFR Part 64 § 64.7(e), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.3 Quality Improvement Plan(QIP) Requirements Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 16 1.13.3.1 Based on the results of a determination made under the provisions of Condition 1.13.2.3.b,the Division may require the owner or operator to develop and implement a QIP (40 CFR Part 64 § 64.8(a), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.3.2 The owner or operator shall maintain a written QIP, if required, and have it available for inspection(40 CFR Part 64 § 64.8(b)(1), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.3.3 The QIP initially shall include procedures for evaluating the control performance problems and, based on the results of the evaluation procedures, the owner or operator shall modify the plan to include procedures for conducting one or more of the following actions, as appropriate: a. Improved preventative maintenance practices (40 CFR Part 64 § 64.8(b)(2)(i), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). b. Process operation changes (40 CFR Part 64 § 64.8(b)(2)(ii), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). c. Appropriate improvements to control methods (40 CFR Part 64 § 64.8(b)(2)(iii), as adopted by reference in Colorado Regulation No. 3,Part C, Section XIV). d. Other steps appropriate to correct control performance (40 CFR Part 64 § 64.8(b)(2)(iv), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). e. More frequent or improved monitoring (only in conjunction with one or more steps under Conditions 2.9.3.3.a through d above) (40 CFR Part 64 § 64.8(b)(2)(v), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.3.4 If a QIP is required, the owner or operator shall develop and implement a QIP as expeditiously as practicable and shall notify the Division if the period for completing the improvements contained in the QIP exceeds 180 days from the date on which the need to implement the QIP was determined(40 CFR Part 64 § 64.8(c), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.3.5 Following implementation of a QIP, upon any subsequent determination pursuant to Condition 1.13.2.3.b, the Division or the U.S. EPA may require that an owner or operator make reasonable changes to the QIP if the QIP is found to have: a. Failed to address the cause of the control device performance problems (40 CFR Part 64 § 64.8(d)(1), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV); or Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 17 b. Failed to provide adequate procedures for correcting control device performance problems as expeditiously as practicable in accordance with good air pollution control practices for minimizing emissions (40 CFR Part 64 § 64.8(d)(2), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.3.6 Implementation of a QIP shall not excuse the owner or operator of a source from compliance with any existing emission limitation or standard, or any existing monitoring, testing,reporting or recordkeeping requirement that may apply under federal, state, or local law, or any other applicable requirements under the federal clean air act (40 CFR Part 64 § 64.8(e), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.4 Reporting and Recordkeeping Requirements 1.13.4.1 Reporting Requirements: The reports required by Section V, Condition 22.d, shall contain the information specified in Appendix B of the permit and the following information, as applicable: a. Summary information on the number, duration and cause (including unknown cause, if applicable), for monitor downtime incidents (other than downtime associated with zero and span or other daily calibration checks, if applicable) ((40 CFR Part 64 § 64.9(a)(2)(ii), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV); and b. The owner or operator shall submit, if necessary, a description of the actions taken to implement a QIP during the reporting period as specified in Condition 1.13.3 of this permit. Upon completion of a QIP,the owner or operator shall include in the next summary report documentation that the implementation of the plan has been completed and reduced the likelihood of similar levels of excursions or exceedances occurring (40 CFR Part 64 § 64.9(a)(2)(iii), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.4.2 General Recordkeeping Requirements: In addition to the recordkeeping requirements in Section V, Condition 22.a through c. a. The owner or operator shall maintain records of any written QIP required pursuant to Condition 1.13.3 and any activities undertaken to implement a QIP, and any supporting information required to be maintained under these CAM requirements (such as data used to document the adequacy of monitoring, or records of monitoring maintenance or corrective actions) (40 CFR Part 64 § 64.9(b)(I), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 18 b. Instead of paper records, the owner or operator may maintain records on alternative media, such as microfilm, computer files, magnetic tape disks, or microfiche,provided that the use of such alternative media allows for expeditious inspection and review, and does not conflict with other applicable recordkeeping requirements (40 CFR Part 64 § 64.9(b)(2), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.5 Savings Provisions 1.13.5.1 Nothing in these CAM requirements shall excuse the owner or operator of a source from compliance with any existing emission limitation or standard, or any existing monitoring, testing, reporting or recordkeeping requirement that may apply under federal, state, or local law, or any other applicable requirements under the federal clean air act. These CAM requirements shall not be used to justify the approval of monitoring less stringent than the monitoring which is required under separate legal authority and are not intended to establish minimum requirements for the purposes of determining the monitoring to be imposed under separate authority under the federal clean air act, including monitoring in permits issued pursuant to title I of the federal clean air act. The purpose of the CAM requirements is to require, as part of the issuance of this Title V operating permit, improved or new monitoring at those emissions units where monitoring requirements do not exist or are inadequate to meet the requirements of CAM(40 CFR Part 64 § 64.10(a)(1), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.5.2 Nothing in these CAM requirements shall restrict or abrogate the authority of the U.S. EPA or the Division to impose additional or more stringent monitoring, recordkeeping, testing or reporting requirements on any owner or operator of a source under any provision of the federal clean air act, including but not limited to sections 114(a)(1) and 504(b), or state law, as applicable (40 CFR Part 64 § 64.10(a)(2), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.13.5.3 Nothing in these CAM requirements shall restrict or abrogate the authority of the U.S. EPA or the Division to take any enforcement action under the federal clean air act for any violation of an applicable requirement or of any person to take action under section 304 of the federal clean air act (40 CFR Part 64 § 64.10(a)(2), as adopted by reference in Colorado Regulation No. 3, Part C, Section XIV). 1.14 These units are subject to the Title IV Acid Rain Requirements. As specified in 40 CFR Part 72.72(b)(1)(viii), the acid rain permit requirements shall be complete and segregable portion of the Operating Permit. As such the requirements are found in Section III of this permit. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit # 05OPWE279 Page 19 2. S005- Emergency Generator Rated at 1,810 hp Parameter Permit Limitations Compliance Monitoring Condition Emission Factor Number Short Term Long Term Method Interval NOx 2.1. N/A N/A 6.9 g/hp-hr Recordkeeping Annually, if and Calculation Hours of Operation CO N/A N/A 8.5 g/hp-hr Exceed 100 Hours of 2.2. N/A N/A N/A Recordkeeping Annually Operation SO2 2.3. 0.8 lbs/mmBtu 1.01S lb/mmBtu Fuel Restriction Only No.2 Diesel Fuel is Used as Fuel Fuel Sampling 2.4. N/A I N/A N/A ASTM Methods Annually Opacity 2.5. Not to Exceed 20% N/A EPA Method 9 Annually S=weight percent sulfur in fuel 2.1 The emission factors listed above have been approved by the Division and shall be used to calculate emissions from the emergency generator (from the manufacturer). If hours of operation for this engine exceed 100 hours in any calendar year, annual emissions of Nitrogen Oxide (NOx) and Carbon Monoxide (CO) emissions for purposes of APEN reporting and payment of annual fees shall be determined using the above emission factors, the maximum horsepower (1,810 hp) and the hours of operation (as required by Condition 2.2) the following equation: Tons/yr=f EF(s/hp-hr)x hour of operation (hrs/yr)x maximum hpl [(453.6 g/lb)x(2000 lbs/ton)] 2.2 Hours of operation shall be monitored annually and recorded in a log to be made available to the Division upon request. Recorded data shall be used to calculate emissions as required by Condition 2.1. Note that if annual hours of operation exceed 250 hours in any year, the engine is no longer exempt from the permitting requirements in Colorado Regulation No. 3, Part B and the permittee shall submit an application to revise this permit within 30 days in order to include the appropriate applicable requirements. 2.3 Sulfur Dioxide (SO2) emissions shall not exceed 0.8 lbs/mmBtu (Colorado Regulation No. 1, Section VI.B.4.b.(i)). In the absence of credible evidence to the contrary, compliance with the SO2 emission limitation shall be presumed since only No. 2 Diesel Fuel is permitted to be used as fuel in this engine. The permittee shall maintain records that verify that only No. 2 diesel fuel is used as fuel in these engines. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 20 This presumption is based on the sulfur content of the No. 2 diesel fuel not to exceed 0.5 percent by weight. 2.4 No. 2 diesel fuel shall be sampled and analyzed, annually, using ASTM methods, or equivalent as approved by the Division in advance, to determine the sulfur content of the fuel. In lieu of annual sampling, the sulfur content of the diesel fuel oil may be monitored by maintaining a file of readable copies of vendor invoices or certificates of quality reporting the sulfur content of the diesel fuel. The file information shall be made available to the Division for review upon request. 2.5 No owner or operator of a source shall allow or cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity (Colorado Regulation No. 1, Section II.A.1). Compliance with this limitation shall be monitored by conducting a visual emission observation annually, in accordance with the provisions in EPA Reference Method 9. All opacity observations shall be performed by an observer with current and valid Method 9 certification. Results of Method 9 readings and a copy of the certified Method 9 reader's certificate shall be kept on site and made available to the Division upon request. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 21 3. S004—Rentech Natural Gas Fired Boiler Rated at 129 mmBtu/hr Parameter Permit Limitations Compliance Monitoring Condition Short Term Long Term Emission Factor Method Interval Number BACT 3.1. See Condition 3.1 N/A See Condition 3.1 Requirements PM 3.2. 0.164 lbs/MMBtu N/A Fuel Restriction Only Natural Gas is Used as Fuel N/A 2.28 tons/yr 0.0186 lb/mmBtu Recordkeeping Monthly PM10 N/A 2.28 tons/yr 0.0186 lb/mmBtu and Calculation NOx 3.3. 0.038 lb/mmBtu,on a 3-hr rolling N/A Continuous Continuously average Emission N/A 4,7 tons/yr Monitoring System CO 3.4. 0.039 lb/mmBtu,based on the N/A See Condition 3.4. average of three(3)test runs N/A 4.75 tons/yr 0.039 lb/mmBtu Recordkeeping Monthly and Calculation Natural Gas 3.5 N/A 231.9 mmscf/yr Fuel Meter Recordkeeping Daily Consumption NSPS General 3.6 N/A N/A N/A As required in the NSPS General Provisions Provisions NSPS 3.7. Determination of Annual N/A Daily Recording 12-Month Recordkeeping Capacity Factor of Fuel Rolling Requirement Average Continuous 3.8 N/A N/A N/A See Condition 3.8 Emission Monitoring Requirements Opacity 3.9. Not to Exceed 20%,Except as N/A Fuel Restriction Only Natural Provided for in 3.10 Gas is Used Opacity 3.10. For Certain Operational N/A as Fuel Activities-Not to Exceed 30%, for a Period or Periods Aggregating More than Six(6) Minutes in any 60 Consecutive Minutes Opacity—State- 3.11. Not to Exceed 20% N/A Only 3.1 The auxiliary boiler is subject to the requirements of the prevention of Significant Deterioration (PSD) Program. Best Available Control Technology (BACT) shall be applied for control of Nitrogen Oxides (NOx), Carbon Monoxide (CO), Particulate Matter (PM and PM10) and Volatile Organic Compounds. BACT has been determined as follows: Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 22 3.1.1 BACT for NOx has been determined to be Low NOx burners with the emission limit identified in Condition 3.3.1 (Colorado Construction Permit 02WE0228). 3.1.2 BACT for CO has been determined to be good combustion practices with the emission limit identified in Condition 3.4.1 (Colorado Construction Permit 02WE0228). 3.1.3 BACT for PM and PMl°has been determined to be use of pipeline quality natural gas as fuel. 3.1.4 BACT for VOC has been determined to be use of pipeline quality natural gas as fuel and good combustion practices. 3.2 Particulate Matter (PM and PM10) emissions from the boiler are subject to the following requirements: 3.2.1 PM emissions shall not exceed 0.164 lb/mmBtu (Colorado Construction Permit 02WE0228 and Colorado Regulation No. 1, Section III.A.1.b). In the absence of credible evidence to the contrary, compliance with the particulate matter emission limits is presumed is natural gas is the only fuel permitted for use as fuel in the boiler. Note that the numeric PM standard was determined using the design heat input for the boiler(129 mmBtu/hr)in the following equation: PE= 0.5 x(FI)°26' where: PE =particulate standard in lbs/mmBtu FI=fuel input in mmBtu/hr 3.2.2 Emissions of PM and PMt° shall not exceed the annual limitations listed above (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to add the annual PM and PMT() emission limitations based on requested emissions on the APEN submitted March 21, 2007). Monthly emissions from the boiler shall be calculated by the end of the subsequent month using the above emission factors (from manufacturer), the monthly natural gas consumption and the heat content of the natural gas for the month as indicated in the DAHS in the following equation: Tons/mo=EF pb/mmBtu)x natural gas use(mmSCF/mo)x heat content of gas(mmBtu/mmSCF) 2000 lbs/ton Monthly emissions shall be used in a rolling twelve month total to monitor compliance with the annual limitations. Each month a new twelve month total shall calculated using the previous twelve months' data. 3.3 Nitrogen Oxide (NOx) emissions from the boiler are subject to the following requirements: 3.3.1 For purposes of BACT,NOx emissions from the boiler shall not exceed 0.038 lb/mmBtu, on a 3-hour rolling average (Colorado Construction Permit 02WE0228, as Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit/4 05OPWE279 Page 23 modified under the provisions of Section I, Condition 1.3 to specify the averaging time). Compliance with the BACT NOx limit shall be monitored using the NOx CEMS required by Condition 3.9. 3.3.2 Annual emissions of NOx from the boiler shall not exceed the above limitations (Colorado Construction Permit 02WE0228). Monthly emissions from the boiler shall be determined using the NOx CEMS required by Condition 3.9. Monthly emissions shall be used in a twelve month rolling total to monitor compliance with the annual limitations. Each month a new twelve month total shall be calculated using the previous twelve months' data. 3.4 Carbon Monoxide (CO)emissions from the boiler are subject to the following requirements: 3.4.1 For purposes of BACT, CO emissions from the boiler shall not exceed 0.039 lb/mmBtu, based on the average of three (3)test runs (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to specify the averaging time). Compliance with the CO BACT limit shall be monitored as follows: 3.4.1.1 Compliance with the CO BACT emission limitation shall be presumed, in the absence of credible evidence to the contrary, provided the boiler is operated in accordance with manufacturer's recommendations and good engineering practices. 3.4.1.2 A performance test shall be conducted within the 18 months of expiration of this permit using the appropriate EPA methods. A stack testing protocol shall be submitted for Division approval at least thirty (30) calendar days prior to performance of the test required under this condition. No stack test required herein shall be performed without prior written approval of the protocol by the Division. The Division reserves the right to witness the test. In order to facilitate the Division's ability to make plans to witness the test, notice of the date (s) for the stack test shall be submitted to the Division at least thirty (30) calendar days prior to the test. The Division may for good cause shown,waive this thirty (30) day notice requirement. In instances when a scheduling conflict is presented, the Division shall immediately contact the permittee in order to explore the possibility of making modifications to the stack test schedule. The required number of copies of the compliance test results shall be submitted to the Division within forty-five (45) calendar days of the completion of the test unless a longer period is approved by the Division. 3.4.2 Annual emissions CO from the boiler shall not exceed the limitation stated above (Colorado Construction Permit 02WE0228, as modified under the provision of Section I, Condition 1.3 to increase CO emissions to level requested on the APEN received March 21, 2007). Monthly emissions from the boiler shall be calculated by Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 24 the end of the subsequent month using the emission factor above (from the manufacturer), the monthly natural gas consumption and the heat content of the natural gas for the month as indicated in the DAHS in the following equation: Tons/mo=EF(lb/mmBtu)x natural gas use(mmSCF/mo)x heat content of Ras(mmBtu/mmSCF) 2000 lbs/ton Monthly emissions shall be used in a rolling twelve month total to monitor compliance with the annual limitations. Each month a new twelve month total shall be calculated using the previous twelve months' data. 3.5 Natural gas consumption from the boiler shall not exceed the limitation stated above (Construction Permit 02WE0228). Natural gas consumed in each boiler shall be recorded daily, as required by 40 CFR Part 60 Subpart Db § 60.49(d), as adopted by reference in Colorado Regulation No. 6, Part A. Daily quantities of natural gas consumed shall be summed to determine the monthly natural gas consumption. Monthly quantities of natural gas consumption for the boiler shall be used in a twelve month rolling total to monitor compliance with the annual limitation. Each month a new twelve month total shall be calculated using the previous twelve months data. 3.6 Regulation No. 6,Part A, Subpart A, General Provisions applies as follows: 3.6.1 No article, machine, equipment or process shall be used to conceal an emission which would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to,the use of gaseous diluents to achieve compliance with an opacity standard or with a standard which is based on the concentration of a pollutant in the gasses discharged to the atmosphere (§ 60.12) 3.6.2 At all times, including periods of startup, shutdown, and malfunction, owners and operators shall to the extent practicable, maintain and operate any affected facility including associated air pollution control equipment in a manner consistent with good air pollution control practice for minimizing emissions. Determination of whether acceptable operating and maintenance procedures are being used will be based on information available to the Division which may include, but is not limited to monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source (Colorado Construction Permit 91MR933, initial approval, modification 4, dated October 26, 1999 and 40 CFR Subpart A§ 60.11(d)). 3.7 The owner of operator of an affected facility shall record and maintain records of the amounts of each fuel combusted during each day and calculate the annual capacity factor individually for coal, distillate oil, residual, oil, natural gas, wood, and municipal-type solid waste for the reporting period. The annual capacity factor is determined on a 12-month rolling average basis with a new annual capacity factor calculated at the end of each calendar month (40 CFR Part 60 Subpart Db § 60.49b(d), as adopted by reference in Colorado Regulation No. 6, Part A). Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 25 3.8 The owner or operator of an affected facility subject to a NOx standard under 40 CFR Part 60 Subpart Db § 60.44b shall install, calibrate, maintain, and operate a continuous monitoring system, and record the output of the system for measuring nitrogen oxides emissions discharged to the atmosphere (40 CFR Part 60 Subpart Db § 60.48b(b)(1), as adopted by reference in Colorado Regulation No. 6, Part A). The NOx CEMS shall meet the requirements in Condition 6 of this permit. In addition, to recorded the NOx concentration (1b/mmBtu), as required by Condition 6.4.2, the CEMS shall also record the NOx mass emission rate in lbs/hr and tons/month. Monthly NOx emissions from the CEMS shall be used as specified by Condition 3.3.2 to monitor compliance with the annual NOx emission limitation. 3.9 Except as provided for in Condition 3.10 below, no owner or operator of a source shall allow or cause the emission into the atmosphere of any air pollutant which is in excess of 20% opacity (Colorado Construction Permit 02WE0228 and Colorado Regulation No.1, Section II.A.1). In the absence of credible evidence to the contrary, compliance with the opacity standard shall be presumed since only natural gas is permitted to be used as fuel for this boiler. 3.10 No owner or operator of a source shall allow or cause to be emitted into the atmosphere any air pollutant resulting from the building of a new fire, cleaning of fire boxes, soot blowing, start-up, process modifications, or adjustment or occasional cleaning of control equipment which is in excess of 30% opacity for a period or periods aggregating more than six (6) minutes in any sixty (60) consecutive minutes (Colorado Regulation No. 1, Section II.A.4). In the absence of credible evidence to the contrary, compliance with the opacity standard shall be presumed since only natural gas is permitted to be used as fuel for this boiler. 3.11 State-Only Requirement: No owner or operator may discharge, or cause the discharge into the atmosphere of any particulate matter which is greater than 20% opacity (Colorado Regulation No. 6, Part B, Section II.C.3). In the absence of credible evidence to the contrary, compliance with the opacity standard shall be presumed since only natural gas is permitted to be used as fuel for this boiler. Note that this opacity standard applies at all times except during periods of startup, shutdown and malfunction (40 CFR Part 60 Subpart A § 60.11(c), as adopted by reference in Colorado Regulation No. 6, Part B, Section I.A). Note that this opacity requirement is more stringent than the opacity requirement in Condition 3.10 during periods of building of a new fire, cleaning of fire boxes, soot blowing, process modifications and adjustment or occasional cleaning of control equipment. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 26 4. S006—Marley Cooling Water Tower Parameter Permit Limitations Compliance Monitoring Condition Short Term Long Term Emission Factor Method Interval Number BACT 4.1. N/A N/A N/A See Condition 4.1. Requirements PM 4.2. N/A 19.3 tons/yr See Condition 4.2 Recordkeeping Monthly and Calculation PMm N/A 19.3 tons/yr Water Circulated 4.2 N/A 92,505.6 N/A Recordkeeping Monthly mmgal/yr Total Solids 4.3 N/A N/A N/A Laboratory Quarterly Concentration Analysis Opacity 4.4 Not to Exceed 20% N/A See Condition 4.4. 4.1 The cooling water tower is subject to the requirements of the prevention of Significant Deterioration (PSD) Program. Best Available Control Technology (BACT) shall be applied for control of Particulate Matter (PM and PM10). BACT has been determined to be the use of drift eliminators to achieve drift levels of 0.0005% (Colorado Construction Permit 02WE0228). 4.2 Particulate Matter (PM and PM10) emissions shall not exceed the limitations above (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3, to include the requested PM and PM10 emissions indicated on the APEN submitted on March 21, 2007). Emissions shall be calculated monthly using the following equations: PM=PM10(tons/month)=Q x d x%drift x x total solids concentration 2000 lbs/ton Where: Q=water circulated,gal/month d=density of water, lbs/gal(from T5 application d=8.34 lbs/gal) %drift=0.0005%(BACT limitation) Total solids=in ppm(lbs solids/106 lbs water)-to be determined by Condition 4.3. The most recent analysis shall be used in the monthly calculation. Monthly emissions shall be used in a twelve month rolling total to monitor compliance with the annual limitation. Each month a new twelve month total shall be calculated using the previous twelve months data. 4.3 The Water Circulated through the cooling water tower shall not exceed the limitation above (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3, to include the requested water circulation limit indicated on the APEN submitted on March 21, 2007). The quantity of water circulated shall be determined each month by multiplying the hours of operation of each pump (two pumps, each pump 88,000 gal/min) by the design flow rate of each pump as follows: Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 27 Water Circulation Rate=hours of operation (hrs/mo) x Design Flow Rate (Gal/min) x 60 min/hr Monthly quantities of water shall be used in a twelve month rolling total to monitor compliance with the annual limitation. Each month a new twelve month total shall be calculated using the previous twelve months data. 4.4 Samples of water circulated through the tower shall be taken and analyzed quarterly. Calculations of monthly emissions shall be made using the total solids concentration determined from the most recent required analysis. A copy of the procedures used to obtain and to analyze samples shall be maintained and made available to the Division upon request. 4.5 Opacity of emissions from the cooling water tower shall not exceed 20% (Colorado Regulation No. 1, Section II.A.1). In the absence of credible evidence to the contrary, compliance with the opacity standard shall be presumed, provided the drift eliminators on the tower are operated and maintained in accordance with the manufacturers' recommendations and good engineering practices. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 28 5. Facility Wide HAP Limits Parameter Permit Limitations Compliance Monitoring Condition Short Term Long Term Emission Factor Method Interval Number Facility Wide 5.1 N/A 2.44 tons/yr See Condition 5.1 Recordkeeping and Monthly Formaldehyde Calculation Emissions Facility Wide N/A 13.1 tons/yr See Condition 5.1 Total HAPs 5.1 Emissions of HAPs shall not exceed the limitations stated above (Colorado Construction Permit 02WE0228, as modified under the provisions of Section I, Condition 1.3 to reflect requested emissions on the APENS submitted on March 21, 2007). Emissions shall be calculated by the end of the subsequent month using actual throughputs and the following compliance emission factors. Emission Unit I Pollutant I Emission Factor I Emission Factor Source Turbines/HRSG/Duct Formaldehyde Unit 1 — 1.5 x 10'Ib/mmBtu From performance tests Burners Unit 2— 1.3 x l0'°lb/mmBtu conducted May 8, 11, 12, 20 and September 16, 2004. Acetaldehyde 1.37 x 10-r lb/mmSCF From California Air Acrolein 1.89 x 10-2 lb/mmSCF Toxics Emission Factor Benzene 1.33 x 10-2 lb/mmSCF (databases)for natural Ethylbenzene 1.79 x 10-2 lb/mmSCF gas-fired turbines with COC and SCR. Hexane 2.59 x 10-1 lb/mmSCF Propylene Oxide 4.78 x 10.2 lb/mmSCF Toluene 7.10 x 10.2 lb/mmSCF Xylene 2.61 x 10-2 lb/mmSCF Cooling Water Tower Chloroform 2.3 kg/109liters from"Locating and Estimating Air Emissions from Sources of Chloroform",EPA-450/4- 84-007c,March 1984,for re-circulating units. A twelve-month rolling total shall be maintained for demonstration of compliance with annual limitations. Each month, a new twelve month total shall be calculated using the previous twelve months data. Records of calculations shall be maintained for Division inspection upon request. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 29 6. Continuous Emission Monitoring Requirements Note that the continuous emission monitoring requirements identified in this Condition for each turbine/HRSG/duct burner, are in addition to the continuous emission monitoring requirements required by the Acid Rain Program, which are identified in Section III of this permit. The permittee shall have 60 days following the issuance date [DATE] of this permit for software revisions and testing to meet the requirements specified in this section. 6.1 Equipment and QA/QC Requirements 6.1.1 The Continuous Emission Monitoring Systems (CEMS) are subject to the following requirements: 6.1.1.1 The NOx (and diluent) monitors for the auxiliary boiler is subject to the applicable requirements of 40 CFR Part 60. The monitoring systems shall meet the equipment, installation and performance specifications of 40 CFR Part 60 Appendix B, Performance Specifications 2 and 3. These CEMS are subject to the quality assurance/quality control requirements in 40 CFR Part 60 Appendix F and Subpart A § 60.13. 6.1.1.2 Except as provided for below, the CO monitors for the turbines/HRSGS/duct burners are subject to the applicable requirements of 40 CFR Part 60 (Colorado Construction Permit 02WE0228). The monitoring systems shall meet the equipment, installation and performance specifications of 40 CFR Part 60 Appendix B, Performance Specification 4/4A. These CEMS are subject to the quality assurance/quality control requirements in 40 CFR Part 60 Appendix F and Subpart A § 60.13. a. The CO CEMS data shall meet the applicable "primary equipment hourly operating requirements" for hourly average calculation methodology specified in 40 CFR Part 75 Subpart B § 75.10(d). b. Annual CO monitor relative accuracy (RA) testing will be performed in ppm @ 15 % O2 measurement units, and will be performed according to 40 CFR Part 60, Appendix B, Performance Specification 4A. c. Relative accuracy test audit(RATA) frequency will be determined according to 40 CFR Part 75 Appendix B. 6.1.1.3 The NOx (and diluent) monitors for the turbines/HRSGs/duct burners are subject to the applicable requirements of 40 CFR Part 75 (Colorado Construction Permit 02WE0228). The monitoring systems shall meet the equipment, installation and performance specification requirements in 40 CFR Part 75, Appendix A. These CEMS shall meet the quality Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 30 assurance/quality control requirements in 40 CFR Part 75, Appendix B, the conversion procedures of Appendix F and the traceability protocols of Appendix H. 6.1.2 Quality assurance/quality control plans shall be prepared for the continuous emission monitoring systems as follows: 6.1.2.1 The quality assurance/quality control plan for the NOx(and diluent) monitors for the auxiliary boiler shall be prepared in accordance with the applicable requirements in 40 CFR Part 60, Appendix F. 6.1.2.2 The quality assurance/quality control plan for the CO monitors for the turbines/HRSG/duct burners shall be prepared in accordance with the applicable requirements in 40 CFR Part 60, Appendix F, except that gas cylinder audit (GCA)testing is not required during quarters with less than 168 hours of operating time. 6.1.2.3 The quality assurance/quality control plan for the NOx (and diluent) monitors for the turbines/HRSG/duct burners shall be prepared in accordance with the applicable requirements in 40 CFR Part 75, Appendix B. The quality assurance/quality control plans shall be made available to the Division upon request. Revisions shall be made to the plans at the request of the Division. 6.2 General Provisions 6.2.1 CO monitors for turbines/HRSGs/duct burners and NOx (and diluent) monitors for auxiliary boiler: The permittee shall ensure that all continuous emission monitoring systems required are in operation and monitoring unit emissions at all times except for monitoring system breakdowns,repairs, calibration checks and zero and span adjustments required under 40 CFR Part 60 Subpart A § 60.13(d) (40 CFR Part 60 Subpart A § 60.13(e)). 6.2.2 NOx (and diluent) monitors for turbines/HRSGs/duct burners: The permittee shall ensure that all continuous emission monitoring systems required are in operation and monitoring unit emissions at all times that the affected unit combusts any fuel except as provided in 40 CFR § 75.11(e) and during periods of calibration, quality assurance, or preventative maintenance performed pursuant to 40 CFR Part 75, § 75.21 and Appendix B,periods of repair,periods of backups of data from the data acquisition and handling system or recertification performed pursuant to 40 CFR § 75.20 (40 CFR Part 75 § 75.10(d)). 6.2.3 Alternative monitoring systems, alternative reference methods, or any other alternatives for the required continuous emission monitoring systems shall not be used without having obtained prior written approval from the appropriate agency, either the Division or the U. S. EPA, depending on which agency is authorized to approve such alternative under applicable law. Any alternative continuous emission Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 31 monitoring systems or continuous opacity monitoring systems must be certified in accordance with the applicable requirements of 40 CFR Part 60 or 40 CFR Part 75 prior to use. 6.2.4 All test and monitoring equipment, methods, procedures and reporting shall be subject to the review and approval by the appropriate agency, either the Division or the U. S. EPA, depending on which agency is authorized to approve such item under applicable law, prior to any official use. The Division shall have the right to inspect such equipment, methods and procedures and data obtained at any time. The Division may provide a witness(s) for any and all tests as Division resources permit. 6.2.5 A file suitable for inspection shall be maintained of all measurements, including continuous monitoring system, monitoring device, and performance testing measurements; all continuous monitoring system performance evaluations; all continuous monitoring system or monitoring device calibration checks; adjustments and maintenance performed on these systems or devices; and all other information required by applicable portions of 40 CFR Part 60 Subpart A and Appendices B and F and 40 CFR Part 75. 6.2.6 Records shall be maintained of the occurrence and duration of any startup, shutdown, or malfunction in the operation of the source; any malfunction of the air pollution control equipment; or any periods during which a continuous monitoring system or monitoring device is inoperative (40 CFR Part 60 Subpart A § 60.7(b) and Colorado Construction Permit 02WE0228). 6.3 Data Replacement Requirements for each Turbine/I-MSG/Duct Burner CEMS For periods when quality assured data is not available from the continuous emission monitoring systems the data replacement procedures in 40 CFR Part 75 Subpart D shall be used for determining the total (annual) emissions. Although CO emissions are not specifically referenced in the Subpart D procedures, the CEMS data acquisition system is programmed to substitute CO emissions using the same procedures specified for NOx. Note that the replaced data shall be used to monitor compliance with the NOx and CO annual emission limitations. 6.4 NSPS Subpart Db Provisions for the Auxiliary Boiler NOx CEMS 6.4.1 The continuous emission monitoring system required by Section II, Condition 3.9 of this permit shall be operated and data recorded during all periods of operation of the affected facility except for continuous monitoring system breakdowns and repairs. Data is recorded during calibration checks, and zero and span adjustments (40 CFR Part 60 Subpart Db § 60.48b(c)). 6.4.2 The 1-hour average nitrogen oxides emission rates measured by the continuous nitrogen oxides monitor required by Section II, Condition 3.8 of the permit and Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 32 required under § 60.13(h) shall be expressed in ng/J or lb/mmBtu heat input and shall be used to calculate the average emission rates. The 1-hour averages shall be calculated using the data points required under § 60.13(h)(3) (40 CFR Part 60 Subpart Db § 60.48b(d)). 6.4.3 The procedures under § 60.13 shall be followed for installation, evaluation and operation of the continuous monitoring systems (40 CFR Part 60 Subpart Db § 60.48b(e)). The span value for nitrogen oxides is 100 ppm. 6.5 Recordkeeping and Reporting Requirements 6.5.1 The owner or operator of a facility required to install,maintain, and calibrate continuous monitoring equipment shall submit to the Division, by the end of the calendar month following the end of each calendar quarter, a report of excess emissions for all pollutants monitored for that quarter(40 CFR Part 60 Subpart A § 60.7(c)). This report shall consist of the following information and/or reporting requirements as specified by the Division: 6.5.1.1 The magnitude of excess emissions computed in accordance with 40 CFR Part 60 Subpart A § 60.13(h), any conversion factor(s) used, and the date and time of commencement and completion of each time period of excess emissions and the process operating time during the reporting period (40 CFR Part 60 Subpart A § 60.7(c)(1)). 6.5.1.2 Specific identification of each period of excess emissions that occurs during startups, shutdowns, and malfunctions of the affected facility. The nature and cause of any malfunction(if known), the corrective action taken or preventative measures adopted (40 CFR Part 60 Subpart A § 60.7(c)(2)). 6.5.1.3 The date and lime identifying each period during which the continuous monitoring system was inoperative except for zero and span checks and the nature of the system repairs or adjustments (40 CFR Part 60 Subpart A § 60.7(c)(3)). 6.5.1.4 When no excess emissions have occurred or the continuous monitoring system(s)have not been inoperative, repaired, or adjusted, such information shall be stated in the report(40 CFR Part 60 Subpart A § 60.7(c)(4)). 6.5.2 The owner or operator of a facility required to install, maintain, and calibrate continuous monitoring equipment shall submit to the Division, by the end of the month following the end of each calendar quarter, a summary report for that quarter (40 CFR Part 60 Subpart A § 60.7(c)). One summary report form shall be submitted for each pollutant monitored. This report shall contain the information and be presented in a format approved by the Division. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit # 05OPWE279 Page 33 If the total duration of excess emissions for the reporting period is less than 1 percent of the total operating time for the reporting period and continuous monitoring system (CMS) downtime is less than 5 percent of the total operating time for the reporting period, only the summary report form shall be submitted and the excess emission report described in Condition 6.5.1 need not be submitted unless required by the Division(40 CFR Part 60 Subpart A § 60.7(d)(1)). If the total duration of excess emissions for the reporting period is 1 percent or greater of the total operating time for the reporting period or the total CMS downtime for the reporting period is 5 percent or greater of the total operating time for the reporting period, the summary report form and the excess emission report described in Condition 6.5.1 shall both be submitted (40 CFR Part 60 Subpart A § 60.7(d)(1)). Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 34 SECTION III - Acid Rain Requirements 1. Designated Representative and Alternate Designated Representative Designated Representative: Alternate Designated Representative: Name: James Gooding Name: Jason Goodwin Title: General Manager Title: Director—EHS (Eastern Region) Phone: (303) 536-2550 Phone: (713) 570-4795 2. Sulfur Dioxide Emission Allowances and Nitrogen Oxide Emission Limitations Combustion Turbine 2007 2008 2009 2010 2011 2012 No.CT-01 SO2 Allowances,per 0* 0* 0* 0* 0* 0* 40 CFR Part 73.10(b), Table 2 NOx Limits This Unit Has No NOx Limits(See Section 5) * Under the provisions of§ 72.84(a)any allowance allocations to,transfers to and deductions from an affected unit's Allowance Tracking System account is considered an automatic permit amendment and as such no revision to the permit is necessary.Numerical allowances shown in this table are from the 1996 edition of the CFR. Combustion Turbine 2007 2008 2009 2010 2011 2012 No.CT-02 SO2 Allowances,per 0* 0* 0* 0* 0* 0* 40 CFR Part 73.10(b), Table 2 NOx Limits This Unit Has No NOx Limits(See Section 5) * Under the provisions of§72.84(a)any allowance allocations to,transfers to and deductions from an affected unit's Allowance Tracking System account is considered an automatic permit amendment and as such no revision to the permit is necessary.Numerical allowances shown in this table are from the 1996 edition of the CFR. 3. Standard Requirements Combustion Turbines CT-01 and CT-02 of this facility are subject to and the source has certified that they will comply with the following standard conditions. Permit Requirements. (1) The designated representative of each affected source and each affected unit at the source shall: i) Submit a complete Acid Rain permit application(including a compliance plan) under 40 CFR part 72 in accordance with the deadlines specified in 40 CFR 72.30; and ii) Submit in a timely manner any supplemental information that the Division determines is necessary in order to review an Acid Rain permit application and issue or deny an Acid Rain permit; Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 35 (2) The owners and operators of each affected source and each affected unit at the source shall: i) Operate the unit in compliance with a complete Acid Rain permit application or a superseding Acid Rain permit issued by the Division; and ii) Have an Acid Rain Permit. Monitoring Requirements. (1) The owners and operators and, to the extent applicable, designated representative of each affected source and each affected unit at the source shall comply with the monitoring requirements as provided in 40 CFR part 75. (2) The emissions measurements recorded and reported in accordance with 40 CFR part 75 shall be used to determine compliance by the unit with the Acid Rain emissions limitations and emissions reduction requirements for sulfur dioxide and nitrogen oxides under the Acid Rain Program. (3) The requirements of 40 CFR part 75 shall not affect the responsibility of the owners and operators to monitor emissions of other pollutants or other emissions characteristics at the unit under other applicable requirements of the Federal Clean Air Act and other provisions of the operating permit for the source. Sulfur Dioxide Requirements. (1) The owners and operators of each source and each affected unit at the source shall: i) Hold allowances, as of the allowance transfer deadline, in the unit's compliance subaccount (after deductions under 40 CFR 73.34(c)) not less than the total annual emissions of sulfur dioxide for the previous calendar year from the unit; and ii) Comply with the applicable Acid Rain emissions limitations for sulfur dioxide. (2) Each ton of sulfur dioxide emitted in excess of the Acid Rain emissions limitations for sulfur dioxide shall constitute a separate violation of the Federal Clean Air Act. (3) An affected unit shall be subject to the requirements under paragraph (1) of the sulfur dioxide requirements as follows: i) Starting January 1, 2000, an affected unit under 40 CFR 72.6(a)(2); or ii) Starting on the later of January 1, 2000 or the deadline for monitor certification under 40 CFR part 75, an affected unit under 40 CFR 72.6(a)(3). (4) Allowances shall be held in, deducted from, or transferred among Allowance Tracking System accounts in accordance with the Acid Rain Program. (5) An allowance shall not be deducted in order to comply with the requirements under paragraph (1) of the sulfur dioxide requirements prior to the calendar year for which the allowance was allocated. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 36 (6) An allowance allocated by the Administrator under the Acid Rain Program is a limited authorization to emit sulfur dioxide in accordance with the Acid Rain Program. No provision of the Acid Rain Program, the Acid Rain permit application, the Acid Rain permit, or the written exemption under 40 CFR 72.7, 72.8 or 72.14 and no provision of law shall be construed to limit the authority of the United States to terminate or limit such authorization. (7) An allowance allocated by the Administrator under the Acid Rain Program does not constitute a property right. Nitrogen Oxides Requirements. The owners and operators of the source and each affected unit at the source shall comply with the applicable Acid Rain emissions limitation for nitrogen oxides. Excess Emissions Requirements. (1) The designated representative of an affected unit that has excess emissions in any calendar year shall submit a proposed offset plan to the Administrator of the U. S. EPA, as required under 40 CFR part 77. (2) The owners and operators of an affected unit that has excess emissions in any calendar year shall: i) Pay without demand,to the Administrator of the U. S. EPA, the penalty required, and pay upon demand the interest on that penalty, as required by 40 CFR part 77; and ii) Comply with the terms of an approved offset plan, as required by 40 CFR part 77. Recordkeeping and Reporting Requirements. (1) Unless otherwise provided,the owners and operators of the source and each affected unit at the source shall keep on site at the source each of the following documents for a period of 5 years from the date the document is created. This period may be extended for cause, at any time prior to the end of 5 years, in writing by the Administrator or the Division: i) The certificate of representation for the designated representative for the source and each affected unit at the source and all documents that demonstrate the truth of the statements in the certificate of representation, in accordance with 40 CFR 72.24; provided that the certificate and documents shall be retained on site at the source beyond such 5-year period until such documents are superseded because of the submission of a new certificate of representation changing the designated representative; ii) All emissions monitoring information, in accordance with 40 CFR part 75, provided that to the extent that 40 CFR part 75 provides for a 3-year period for recordkeeping, the 3-year period shall apply. iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the Acid Rain Program; and, iv) Copies of all documents used to complete an Acid Rain permit application and any other submission under the Acid Rain Program or to demonstrate compliance with the requirements of the Acid Rain Program. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 37 (2) The designated representative of an affected source and each affected unit at the source shall submit the reports and compliance certifications required under the Acid Rain Program, including those under 40 CFR part 72 subpart I and 40 CFR part 75. Liability. (1) Any person who knowingly violates any requirement or prohibition of the Acid Rain Program, a complete Acid Rain permit application, an Acid Rain permit, or a written exemption under 40 CFR 72.7, 72.8 or 72.14, including any requirement for the payment of any penalty owed to the United States, shall be subject to enforcement pursuant to section 113(c) of the Federal Clean Air Act. (2) Any person who knowingly makes a false, material statement in any record, submission, or report under the Acid Rain Program shall be subject to criminal enforcement pursuant to section 113(c) of the Federal Clean Air Act and 18 U.S.C. 1001. (3) No permit revision shall excuse any violation of the requirements of the Acid Rain Program that occurs prior to the date that the revision takes effect. (4) Each affected source and each affected unit shall meet the requirements of the Acid Rain Program. (5) Any provision of the Acid Rain Program that applies to an affected source (including a provision applicable to the designated representative of an affected source) shall also apply to the owners and operators of such source and of the affected units at the source. (6) Any provision of the Acid Rain Program that applies to an affected unit(including a provision applicable to the designated representative of an affected unit) shall also apply to the owners and operators of such unit. Except as provided under 40 CFR 72.44 (Phase II repowering extension plans) and 40 CFR 76.11 (NOx averaging plans), and except with regard to the requirements applicable to units with a common stack under 40 CFR part 75 (including 40 CFR 75.16, 75.17, and 75.18), the owners and operators and the designated representative of one affected unit shall not be liable for any violation by any other affected unit of which they are not owners or operators or the designated representative and that is located at a source of which they are not owners or operators or the designated representative. (7) Each violation of a provision of 40 CFR parts 72, 73, 74, 75, 76, 77, and 78 by an affected source or affected unit, or by an owner or operator or designated representative of such source or unit, shall be a separate violation of the Federal Clean Air Act. Effect on Other Authorities. No provision of the Acid Rain Program, an Acid Rain permit application, an Acid Rain permit, or a written exemption under 40 CFR 72.7, 72.8 or 72.14 shall be construed as: (1) Except as expressly provided in title IV of the Federal Clean Air Act, exempting or excluding the owners and operators and, to the extent applicable, the designated representative of an affected source or affected unit from compliance with any other provision of the Federal Clean Air Act, including the provisions of title I of the Federal Clean Air Act relating to applicable National Ambient Air Quality Standards or State Implementation Plans; Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 38 (2) Limiting the number of allowances a unit can hold;provided, that the number of allowances held by the unit shall not affect the source's obligation to comply with,any other provisions of the Federal Clean Air Act; (3) Requiring a change of any kind in any State law regulating electric utility rates and charges, affecting any State law regarding such State regulation, or limiting such State regulation, including any prudence review requirements under such State law; (4) Modifying the Federal Power Act or affecting the authority of the Federal Energy Regulatory Commission under the Federal Power Act; or, (5) Interfering with or impairing any program for competitive bidding far power supply in a State in which such program is established. 4. Reporting Requirements Reports shall be submitted to the addresses identified in Appendix D. Pursuant to 40 CFR Part 75.64 quarterly reports and compliance certification requirements shall be submitted to the Administrator within 30 days after the end of the calendar quarter. The contents of these reports shall meet the requirements of 40 CFR 75.64. Revisions to this permit shall be made in accordance with 40 CFR Part 72, Subpart H, §§ 72.80 through 72.85 (as adopted by reference in Colorado Regulation 18). Permit modification requests shall be submitted to the Division at the address identified in Appendix D. Changes to the Designated Representative or Alternate Designated Representative shall be made in accordance with 40 CFR 72.23. A copy of the complete certificate of representation shall be submitted to the Division with thirty(30)days of submittal to the Administrator of the EPA. 5. Comments, Notes and Justifications Combustion Turbines CT-01 and CT-02 bum natural gas as fuel. The NOx limitations in 40 CFR Part 76 are only applicable to coal-fired utility units and thus do not apply to CT-01 and CT-02. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit/4 05OPWE279 Page 39 SECTION IV - Permit Shield Regulation No. 3, 5 CCR 1001-5, Part C, §§ I.A.4, V.D., & XIII.B and § 25-7-114.4(3)(a), C.R.S. 1. Specific Non-Applicable Requirements Based on the information available to the Division and supplied by the applicant, the following parameters and requirements have been specifically identified as non-applicable to the facility to which this permit has been issued. This shield does not protect the source from any violations that occurred prior to or at the time of permit issuance. In addition, this shield does not protect the source from any violations that occur as a result of any modifications or reconstruction on which construction commenced prior to permit issuance. The source did not specifically identify and justify any non-applicable requirements to be included in the permit shield. 2. General Conditions Compliance with this Operating Permit shall be deemed compliance with all applicable requirements specifically identified in the permit and other requirements specifically identified in the permit as not applicable to the source. This permit shield shall not alter or affect the following: 2.1 The provisions of §§ 25-7-112 and 25-7-113, C.R.S., or § 303 of the federal act, concerning enforcement in cases of emergency; 2.2 The liability of an owner or operator of a source for any violation of applicable requirements prior to or at the time of permit issuance; 2.3 The applicable requirements of the federal Acid Rain Program, consistent with § 408(a) of the federal act; 2.4 The ability of the Air Pollution Control Division to obtain information from a source pursuant to § 25-7-111(2)(I), C.R.S., or the ability of the Administrator to obtain information pursuant to § 114 of the federal act; 2.5 The ability of the Air Pollution Control Division to reopen the Operating Permit for cause pursuant to Regulation No. 3, Part C, § XIII. 2.6 Sources are not shielded from terms and conditions that become applicable to the source subsequent to permit issuance. 3. Streamlined Conditions The following applicable requirements have been subsumed within this operating permit using the pertinent streamlining procedures approved by the U.S. EPA. For purposes of the permit shield, compliance with the Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 40 listed permit conditions will also serve as a compliance demonstration for purposes of the associated subsumed requirements. Permit Condition I Streamlined(Subsumed)Requirements Turbines/IIRSGs/Duct Burners Section II, Condition Regulation No. 1,Section II.A.I.c[PM emissions shall not exceed 0.1 lb/mmBtu,based on the 1.2.2. average of three(3) 1-hr tests] Section II,Condition 40 CFR Part 60 Subpart Da§60.42a(a)(1),as adopted by reference in Colorado Regulation No. 1.2.2 6,Part A [PM emissions shall not exceed 0.03 lb/mmBtu,based on the average of three(3)2-hr tests]] Section II,Condition 40 CFR Part 60 Subpart Da§60.44a(d)(1),as adopted by reference in Colorado Regulation No. 1.5.1.1. 6,Part A [NOx emissions shall not exceed 1.6 lbs/MW-hr] Section II, Condition 40 CFR Part 60,Subpart GG §60.332(b),as adopted by reference in Colorado Regulation NO.6, 1.5.1.1 Part A [NOx emissions shall not exceed 102 ppmvd at 15%OZ and ISO standard ambient conditions] Section II,Condition 40 CFR Part 60 Subpart GG §§ 60.334(h)(3), as adopted by reference in Colorado Regulation No. 1.10 6,Part A [monitor sulfur content of fuel] Section II,Condition Regulation No.6,Part B, Section II.D.3.b[SO2 emissions not to exceed 0.35 lbs/mmBtu]-State- 1.4.3 only Requirement Section II, Condition Regulation No.6,Part B,Section I[general provisions]-State-only Requirement 1.11 Auxiliary Boiler Section II,Condition 40 CFR Part 60 Subpart Db §60.44b(1)(1) [NOx emissions not to exceed 0.20 lb/mmBtu,on a 3.3.1 30-day rolling average]. Section II,Condition 40 CFR Part 60 Subpart Db §60.48b(e)(2)[NOx emissions not to exceed 0.20 lb/mmBtu,on a 6.5.1 30-day rolling average]. Section II,Condition 40 CFR Part 60 Subpart Db§§60.49b(g),(h)and(i)[NOx span value shall be 500 ppm]. 6.4.3 Section V, 40 CFR Part 60 Subpart Db§60.49b(o)[retain records for 2 yrs] Conditions 22.b&c Section II,Condition Regulation No.6,Part B, Section I[general provisions]-State-only Requirement 3.7 Section II, Condition Regulation No.6,Part B, Section II.C.2 [particulate matter standard]-State-only Requirement 3.2.1 Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 41 SECTION V - General Permit Conditions 1. Administrative Changes Regulation No. 3, 5 CCR 1001-5, Part A, § III. The permittee shall submit an application for an administrative permit amendment to the Division for those permit changes that are described in Regulation No. 3, Part A, § LB.I. The permittee may immediately make the change upon submission of the application to the Division. 2. Certification Requirements Regulation No. 3, 5 CCR 1001-5, Part C, §§ 111.B.9.,V.C.16.a.&e. and V.C.17. a. Any application,report,document and compliance certification submitted to the Air Pollution Control Division pursuant to Regulation No. 3 or the Operating Permit shall contain a certification by a responsible official of the truth,accuracy and completeness of such form,report or certification stating that,based on information and belief formed after reasonable inquiry,the statements and information in the document are true,accurate and complete. b. All compliance certifications for terms and conditions in the Operating Permit shall be submitted to the Air Pollution Control Division at least annually unless a more frequent period is specified in the applicable requirement or by the Division in the Operating Permit. c. Compliance certifications shall contain: (i) the identification of each permit term and condition that is the basis of the certification; (ii) the compliance status of the source; (iii) whether compliance was continuous or intermittent; (iv) method(s)used for determining the compliance status of the source,currently and over the reporting period; and (v) such other facts as the Air Pollution Control Division may require to determine the compliance status of the source. d. All compliance certifications shall be submitted to the Air Pollution Control Division and to the Environmental Protection Agency at the addresses listed in Appendix D of this Permit. e. If the permittee is required to develop and register a risk management plan pursuant to § 112(r)of the federal act,the permittee shall certify its compliance with that requirement;the Operating Permit shall not incorporate the contents of the risk management plan as a permit term or condition. 3. Common Provisions Common Provisions Regulation, 5 CCR 1001-2 §§ ILA.,ILB.,ILC., II,.E., ILF.,II.I, and ILJ a. To Control Emissions Leaving Colorado When emissions generated from sources in Colorado cross the State boundary line,such emissions shall not cause the air quality standards of the receiving State to be exceeded,provided reciprocal action is taken by the receiving State. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 42 b. Emission Monitoring Requirements The Division may require owners or operators of stationary air pollution sources to install,maintain, and use instrumentation to monitor and record emission data as a basis for periodic reports to the Division. c. Performance Testing The owner or operator of any air pollution source shall,upon request of the Division,conduct performance test(s) and furnish the Division a written report of the results of such test(s)in order to determine compliance with applicable emission control regulations. Performance test(s)shall be conducted and the data reduced in accordance with the applicable reference test methods unless the Division: (i) specifies or approves,in specific cases,the use of a test method with minor changes in methodology; (ii) approves the use of an equivalent method; (iii) approves the use of an alternative method the results of which the Division has determined to be adequate for indicating where a specific source is in compliance; or (iv) waives the requirement for performance test(s)because the owner or operator of a source has demonstrated by other means to the Division's satisfaction that the affected facility is in compliance with the standard. Nothing in this paragraph shall be construed to abrogate the Commission's or Division's authority to require testing under the Colorado Revised Statutes,Title 25,Article 7, and pursuant to regulations promulgated by the Commission. Compliance test(s)shall be conducted under such conditions as the Division shall specify to the plant operator based on representative performance of the affected facility.The owner or operator shall make available to the Division such records as may be necessary to determine the conditions of the performance test(s).Operations during period of startup,shutdown,and malfunction shall not constitute representative conditions of performance test(s)unless otherwise specified in the applicable standard. The owner or operator of an affected facility shall provide the Division thirty days prior notice of the performance test to afford the Division the opportunity to have an observer present.The Division may waive the thirty day notice requirement provided that arrangements satisfactory to the Division are made for earlier testing. The owner or operator of an affected facility shall provide, or cause to be provided,performance testing facilities as follows: (i) Sampling ports adequate for test methods applicable to such facility; (ii) Safe sampling platform(s); (iii) Safe access to sampling platform(s);and (iv) Utilities for sampling and testing equipment. Each performance test shall consist of at least three separate runs using the applicable test method. Each run shall be conducted for the time and under the conditions specified in the applicable standard.For the purpose of determining compliance with an applicable standard,the arithmetic mean of results of at least three runs shall apply. In the event that a sample is accidentally lost or conditions occur in which one of the runs must be discontinued because of forced shutdown, failure of an irreplaceable portion of the sample train,extreme meteorological conditions,or other circumstances beyond the owner or operator's control,compliance may,upon the Division's approval,be determined using the arithmetic mean of the results of the two other runs. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 43 Nothing in this section shall abrogate the Division's authority to conduct its own performance test(s)if so warranted. d. Affirmative Defense Provision for Excess Emissions during Malfunctions Note that until such time as the U.S. EPA approves this provision into the Colorado State Implementation Plan (SIP),it shall be enforceable only by the State. An affirmative defense to a claim of violation under these regulations is provided to owners and operators for civil penalty actions for excess emissions during periods of malfunction. To establish the affirmative defense and to be relieved of a civil penalty in any action to enforce an applicable requirement,the owner or operator of the facility must meet the notification requirements below in a timely manner and prove by a preponderance of evidence that: (i) The excess emissions were caused by a sudden,unavoidable breakdown of equipment,or a sudden, unavoidable failure of a process to operate in the normal or usual manner,beyond the reasonable control of the owner or operator; (ii) The excess emissions did not stem from any activity or event that could have reasonably been foreseen and avoided,or planned for,and could not have been avoided by better operation and maintenance practices; (iii) Repairs were made as expeditiously as possible when the applicable emission limitations were being exceeded; (iv) The amount and duration of the excess emissions(including any bypass)were minimized to the maximum extent practicable during periods of such emissions; (v) All reasonably possible steps were taken to minimize the impact of the excess emissions on ambient air quality; (vi) All emissions monitoring systems were kept in operation(if at all possible); (vii) The owner or operator's actions during the period of excess emissions were documented by properly signed,contemporaneous operating logs or other relevant evidence; (viii) The excess emissions were not part of a recurring pattern indicative of inadequate design,operation, or maintenance; (ix) At all times,the facility was operated in a manner consistent with good practices for minimizing emissions. This section is intended solely to be a factor in determining whether an affirmative defense is available to an owner or operator,and shall not constitute an additional applicable requirement;and (x) During the period of excess emissions,there were no exceedances of the relevant ambient air quality standards established in the Commissions' Regulations that could be attributed to the emitting source. The owner or operator of the facility experiencing excess emissions during a malfunction shall notify the division verbally as soon as possible,but no later than noon of the Division's next working day,and shall submit written notification following the initial occurrence of the excess emissions by the end of the source's next reporting period. The notification shall address the criteria set forth above. The Affirmative Defense Provision contained in this section shall not be available to claims for injunctive relief. The Affirmative Defense Provision does not apply to failures to meet federally promulgated performance standards or emission limits, including,but not limited to,new source performance standards and national emission standards for hazardous air pollutants.The affirmative defense provision does not apply to state implementation plan(sip) limits or permit limits that have been set taking into account potential emissions during malfunctions,including,but not necessarily limited to, certain limits with 30-day or longer averaging times, limits that indicate they apply during malfunctions,and limits that indicate they apply at all times or without exception. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 44 e. Circumvention Clause A person shall not build,erect,install, or use any article,machine,equipment,condition,or any contrivance,the use of which,without resulting in a reduction in the total release of air pollutants to the atmosphere,reduces or conceals an emission which would otherwise constitute a violation of this regulation.No person shall circumvent this regulation by using more openings than is considered normal practice by the industry or activity in question. f. Compliance Certifications For the purpose of submitting compliance certifications or establishing whether or not a person has violated or is in violation of any standard in the Colorado State Implementation Plan,nothing in the Colorado State Implementation Plan shall preclude the use, including the exclusive use,of any credible evidence or information,relevant to whether a source would have been in compliance with applicable requirements if the appropriate performance or compliance test or procedure had been performed. Evidence that has the effect of making any relevant standard or permit term more stringent shall not be credible for proving a violation of the standard or permit term. When compliance or non-compliance is demonstrated by a test or procedure provided by permit or other applicable requirement,the owner or operator shall be presumed to be in compliance or non-compliance unless other relevant credible evidence overcomes that presumption. g. Affirmative Defense Provision for Excess Emissions During Startup and Shutdown An affirmative defense is provided to owners and operators for civil penalty actions for excess emissions during periods of startup and shutdown. To establish the affirmative defense and to be relieved of a civil penalty in any action to enforce an applicable requirement,the owner or operator of the facility must meet the notification requirements below in a timely manner and prove by a preponderance of the evidence that: (i) The periods of excess emissions that occurred during startup and shutdown were short and infrequent and could not have been prevented through careful planning and design; (ii) The excess emissions were not part of a recurring pattern indicative of inadequate design,operation or maintenance; (iii) If the excess emissions were caused by a bypass(an intentional diversion of control equipment),then the bypass was unavoidable to prevent loss of life,personal injury, or severe property damage; (iv) The frequency and duration of operation in startup and shutdown periods were minimized to the maximum extent practicable; (v) All possible steps were taken to minimize the impact of excess emissions on ambient air quality; (vi) All emissions monitoring systems were kept in operation(if at all possible); (vii) The owner or operator's actions during the period of excess emissions were documented by properly signed,contemporaneous operating logs or other relevant evidence;and, (viii) At all times,the facility was operated in a manner consistent with good practices for minimizing emissions. This subparagraph is intended solely to be a factor in determining whether an affirmative defense is available to an owner or operator,and shall not constitute an additional applicable requirement. The owner or operator of the facility experiencing excess emissions during startup and shutdown shall notify the Division verbally as soon as possible,but no later than two(2)hours after the start of the next working day,and shall submit written quarterly notification following the initial occurrence of the excess emissions.The notification shall address the criteria set forth above. The Affirmative Defense Provision contained in this section shall not be available to claims for injunctive relief. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 45 The Affirmative Defense Provision does not apply to State Implementation Plan provisions or other requirements that derive from new source performance standards or national emissions standards for hazardous air pollutants, or any other federally enforceable performance standard or emission limit with an averaging time greater than twenty- four hours. In addition,an affirmative defense cannot be used by a single source or small group of sources where the excess emissions have the potential to cause an exceedance of the ambient air quality standards or Prevention of Significant Deterioration(PSD)increments. In making any determination whether a source established an affirmative defense,the Division shall consider the information within the notification required above and any other information the Division deems necessary,which may include,but is not limited to,physical inspection of the facility and review of documentation pertaining to the maintenance and operation of process and air pollution control equipment 4. Compliance Requirements Regulation No.3, 5 CCR 1001-5,Part C, && III.C.9.,V.C.11.& 16.d., &25-7-122.1(2),C.R.S. a. The permittee must comply with all conditions of the Operating Permit. Any permit noncompliance relating to federally-enforceable terms or conditions constitutes a violation of the federal act,as well as the state act and Regulation No. 3. Any permit noncompliance relating to state-only terms or conditions constitutes a violation of the state act and Regulation No.3,shall be enforceable pursuant to state law,and shall not be enforceable by citizens under§304 of the federal act. Any such violation of the federal act,the state act or regulations implementing either statute is grounds for enforcement action, for permit termination,revocation and reissuance or modification or for denial of a permit renewal application. b. It shall not be a defense for a permittee in an enforcement action or a consideration in favor of a permittee in a permit termination,revocation or modification action or action denying a permit renewal application that it would have been necessary to halt or reduce the permitted activity in order to maintain compliance with the conditions of the permit. c. The permit may be modified,revoked,reopened, and reissued, or terminated for cause. The filing of any request by the permittee for a permit modification,revocation and reissuance,or termination,or any notification of planned changes or anticipated noncompliance does not stay any permit condition,except as provided in §§X. and XI.of Regulation No. 3, Part C. d. The permittee shall furnish to the Air Pollution Control Division,within a reasonable time as specified by the Division, any information that the Division may request in writing to determine whether cause exists for modifying, revoking and reissuing, or terminating the permit or to determine compliance with the permit. Upon request,the permittee shall also furnish to the Division copies of records required to be kept by the permittee, including information claimed to be confidential. Any information subject to a claim of confidentiality shall be specifically identified and submitted separately from information not subject to the claim. e. Any schedule for compliance for applicable requirements with which the source is not in compliance at the time of permit issuance shall be supplemental, and shall not sanction noncompliance with,the applicable requirements on which it is based. f. For any compliance schedule for applicable requirements with which the source is not in compliance at the time of permit issuance,the permittee shall submit,at least every 6 months unless a more frequent period is specified in the applicable requirement or by the Air Pollution Control Division,progress reports which contain the following: (i) dates for achieving the activities,milestones, or compliance required in the schedule for compliance,and dates when such activities,milestones,or compliance were achieved;and (ii) an explanation of why any dates in the schedule of compliance were not or will not be met,and any preventive or corrective measures adopted. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 46 g. The permittee shall not knowingly falsify,tamper with,or render inaccurate any monitoring device or method required to be maintained or followed under the terms and conditions of the Operating Permit. 5. Emergency Provisions Regulation No. 3,5 CCR 1001-5,Part C, &VII. An emergency means any situation arising from sudden and reasonably unforeseeable events beyond the control of the source, including acts of God, which situation requires immediate corrective action to restore normal operation, and that causes the source to exceed the technology-based emission limitation under the permit due to unavoidable increases in emissions attributable to the emergency. "Emergency" does not include noncompliance to the extent caused by improperly designed equipment, lack of preventative maintenance, careless or improper operation, or operator error. An emergency constitutes an affirmative defense to an enforcement action brought for noncompliance with a technology-based emission limitation if the permittee demonstrates,through properly signed, contemporaneous operating logs,or other relevant evidence that: a. an emergency occurred and that the permittee can identify the cause(s)of the emergency; b. the permitted facility was at the time being properly operated; c. during the period of the emergency the permittee took all reasonable steps to minimize levels of emissions that exceeded the emission standards,or other requirements in the permit; and d. the permittee submitted oral notice of the emergency to the Air Pollution Control Division no later than noon of the next working day following the emergency,and followed by written notice within one month of the time when emissions limitations were exceeded due to the emergency. This notice must contain a description of the emergency,any steps taken to mitigate emissions, and corrective actions taken. This emergency provision is in addition to any emergency or malfunction provision contained in any applicable requirement. 6. Emission Standards for Asbestos Regulation No. 8, 5 CCR 1001-10,Part B The permittee shall not conduct any asbestos abatement activities except in accordance with the provisions of Regulation No. 8,Part B, "emission standards for asbestos." 7. Emissions Trading,Marketable Permits,Economic Incentives Regulation No. 3, 5 CCR 1001-5,Part C, &V.C.13. No permit revision shall be required under any approved economic incentives, marketable permits, emissions trading and other similar programs or processes for changes that are specifically provided for in the permit. 8. Fee Payment C.R.S. §$25-7-114.1(6)and 25-7-114.7 a. The permittee shall pay an annual emissions fee in accordance with the provisions of§25-7-114.7. A 1%per month late payment fee shall be assessed against any invoice amounts not paid in full on the 91st day after the date of invoice,unless a permittee has filed a timely protest to the invoice amount. b. The permittee shall pay a permit processing fee in accordance with the provisions of§25-7-114.7. If the Division estimates that processing of the permit will take more than 30 hours,it will notify the permittee of its estimate of what the actual charges may be prior to commencing any work exceeding the 30 hour limit. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 47 c. The permittee shall pay an APEN fee in accordance with the provisions of§ 25-7-114.1(6)for each APEN or revised APEN filed. 9. Fugitive Particulate Emissions Regulation No. 1,5 CCR 1001-3, § III.D.1. The permittee shall employ such control measures and operating procedures as are necessary to minimize fugitive particulate emissions into the atmosphere, in accordance with the provisions of Regulation No. 1, § III.D.I. 10. Inspection and Entry Regulation No. 3,5 CCR 1001-5,Part C, §V.C.16.b. Upon presentation of credentials and other documents as may be required by law,the permittee shall allow the Air Pollution Control Division,or any authorized representative,to perform the following: a. enter upon the permittee's premises where an Operating Permit source is located,or emissions-related activity is conducted, or where records must be kept under the terms of the permit; b. have access to, and copy,at reasonable times,any records that must be kept under the conditions of the permit; c. inspect at reasonable times any facilities,equipment(including monitoring and air pollution control equipment), practices,or operations regulated or required under the Operating Permit; d. sample or monitor at reasonable times,for the purposes of assuring compliance with the Operating Permit or applicable requirements,any substances or parameters. 11. Minor Permit Modifications Regulation No.3, 5 CCR 1001-5,Part C, §§X. &XI. The permittee shall submit an application for a minor permit modification before making the change requested in the application. The permit shield shall not extend to minor permit modifications. 12. New Source Review Regulation No. 3, 5 CCR 1001-5,Part B The permittee shall not commence construction or modification of a source required to be reviewed under the New Source Review provisions of Regulation No.3,Part B,without first receiving a construction permit. 13. No Property Rights Conveyed Regulation No. 3, 5 CCR 1001-5,Part C, §V.C.11.d. This permit does not convey any property rights of any sort,or any exclusive privilege. 14. Odor Regulation No. 2,5 CCR 1001-4,Part A As a matter of state law only, the permittee shall comply with the provisions of Regulation No. 2 concerning odorous emissions. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 48 15. Off-Permit Changes to the Source Regulation No.3, 5 CCR 1001-5,Part C, &XII.B. The permittee shall record any off-permit change to the source that causes the emissions of a regulated pollutant subject to an applicable requirement,but not otherwise regulated under the permit,and the emissions resulting from the change, including any other data necessary to show compliance with applicable ambient air quality standards. The permittee shall provide contemporaneous notification to the Air Pollution Control Division and to the Environmental Protection Agency at the addresses listed in Appendix D of this Permit. The permit shield shall not apply to any off-permit change. 16. Opacity Regulation No. 1,5 CCR 1001-3, §§ I.,II. The permittee shall comply with the opacity emissions limitation set forth in Regulation No. 1, §§I.-II. 17. Open Burning Regulation No. 9,5 CCR 1001-11 The permittee shall obtain a permit from the Division for any regulated open burning activities in accordance with provisions of Regulation No.9. 18. Ozone Depleting Compounds Regulation No. 15, 5 CCR 1001-17 The permittee shall comply with the provisions of Regulation No. 15 concerning emissions of ozone depleting compounds. Sections I.,ILC.,II.D., III. IV.,and V. of Regulation No. 15 shall be enforced as a matter of state law only. 19. Permit Expiration and Renewal Regulation No. 3, 5 CCR 1001-5,Part C, §§ III.B.6.,IV.C.,V.C.2. a. The permit term shall be five(5)years. The permit shall expire at the end of its term. Permit expiration terminates the permittee's right to operate unless a timely and complete renewal application is submitted. b. Applications for renewal shall be submitted at least twelve months,but not more than 18 months,prior to the expiration of the Operating Permit. An application for permit renewal may address only those portions of the permit that require revision,supplementing,or deletion,incorporating the remaining permit terms by reference from the previous permit. A copy of any materials incorporated by reference must be included with the application. 20. Portable Sources Regulation No. 3,5 CCR 1001-5,Part C, § II.D. Portable Source permittees shall notify the Air Pollution Control Division at least 10 days in advance of each change in location. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 49 21. Prompt Deviation Reporting Regulation No. 3, 5 CCR 1001-5,Part C, § V.C.7.b. The permittee shall promptly report any deviation from permit requirements, including those attributable to malfunction conditions as defined in the permit,the probable cause of such deviations,and any corrective actions or preventive measures taken. "Prompt"is defined as follows: a. Any definition of"prompt"or a specific timeframe for reporting deviations provided in an underlying applicable requirement as identified in this permit;or b. Where the underlying applicable requirement fails to address the time frame for reporting deviations,reports of deviations will be submitted based on the following schedule: CO For emissions of a hazardous air pollutant or a toxic air pollutant(as identified in the applicable regulation) that continue for more than an hour in excess of permit requirements,the report shall be made within 24 hours of the occurrence; (ii) For emissions of any regulated air pollutant, excluding a hazardous air pollutant or a toxic air pollutant that continue for more than two hours in excess of permit requirements,the report shall be made within 48 hours;and (iii) For all other deviations from permit requirements,the report shall be submitted every six(6)months, except as otherwise specified by the Division in the permit in accordance with paragraph 22.d.below. c. If any of the conditions in paragraphs b.i or b.ii above are met,the source shall notify the Division by telephone (303-692-3155)or facsimile(303-782-0278)based on the timetables listed above. [Explanatory note: Notification by telephone or facsimile must speck that this notification is a deviation report for an Operating Permit.] A written notice,certified consistent with General Condition 2.a.above(Certification Requirements),shall be submitted within 10 working days of the occurrence. All deviations reported under this section shall also be identified in the 6-month report required above. "Prompt reporting" does not constitute an exception to the requirements of "Emergency Provisions" for the purpose of avoiding enforcement actions. 22. Record Keeping and Reporting Requirements Regulation No. 3,5 CCR 1001-5,Part A, § II.;Part C, §§ V.C.6., V.C.7. a. Unless otherwise provided in the source specific conditions of this Operating Permit,the permittee shall maintain compliance monitoring records that include the following information: CO date,place as defined in the Operating Permit, and time of sampling or measurements; (ii) date(s)on which analyses were performed; (iii) the company or entity that performed the analysis; (iv) the analytical techniques or methods used; (v) the results of such analysis;and (vi) the operating conditions at the time of sampling or measurement. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 50 b. The permittee shall retain records of all required monitoring data and support information for a period of at least five (5)years from the date of the monitoring sample,measurement,report or application. Support information,for this purpose,includes all calibration and maintenance records and all original strip-chart recordings for continuous monitoring instrumentation,and copies of all reports required by the Operating Permit. With prior approval of the Air Pollution Control Division,the permittee may maintain any of the above records in a computerized form. c. Permittees must retain records of all required monitoring data and support information for the most recent twelve (12)month period,as well as compliance certifications for the past five(5)years on-site at all times. A permittee shall make available for the Air Pollution Control Division's review all other records of required monitoring data and support information required to be retained by the permittee upon 48 hours advance notice by the Division. d. The permittee shall submit to the Air Pollution Control Division all reports of any required monitoring at least every six(6)months,unless an applicable requirement,the compliance assurance monitoring rule,or the Division requires submission on a more frequent basis. All instances of deviations from any permit requirements must be clearly identified in such reports. e. The permittee shall file an Air Pollutant Emissions Notice("APEN")prior to constructing,modifying,or altering any facility,process,activity which constitutes a stationary source from which air pollutants are or are to be emitted, unless such source is exempt from the APEN filing requirements of Regulation No.3,Part A, §II.D. A revised APEN shall be filed annually whenever a significant change in emissions,as defined in Regulation No. 3,Part A, § II.C2.,occurs;whenever there is a change in owner or operator of any facility,process,or activity;whenever new control equipment is installed;whenever a different type of control equipment replaces an existing type of control equipment;whenever a permit limitation must be modified;or before the APEN expires. An APEN is valid for a period of five years. The five-year period recommences when a revised APEN is received by the Air Pollution Control Division. Revised APENs shall be submitted no later than 30 days before the five-year term expires. Permittees submitting revised APENs to inform the Division of a change in actual emission rates must do so by April 30 of the following year. Where a permit revision is required,the revised APEN must be filed along with a request for permit revision. APENs for changes in control equipment must be submitted before the change occurs. Annual fees are based on the most recent APEN on file with the Division. 23. Reopenings for Cause Regulation No.3, 5 CCR 1001-5, Part C, &XIII. a. The Air Pollution Control Division shall reopen,revise,and reissue Operating Permits;permit reopenings and reissuance shall be processed using the procedures set forth in Regulation No.3,Part C, §III.,except that proceedings to reopen and reissue permits affect only those parts of the permit for which cause to reopen exists. b. The Division shall reopen a permit whenever additional applicable requirements become applicable to a major source with a remaining permit term of three or more years,unless the effective date of the requirements is later than the date on which the permit expires, or unless a general permit is obtained to address the new requirements; whenever additional requirements(including excess emissions requirements)become applicable to an affected source under the acid rain program;whenever the Division determines the permit contains a material mistake or that inaccurate statements were made in establishing the emissions standards or other terms or conditions of the permit; or whenever the Division determines that the permit must be revised or revoked to assure compliance with an applicable requirement. c. The Division shall provide 30 days' advance notice to the permittee of its intent to reopen the permit,except that a shorter notice may be provided in the case of an emergency. d. The permit shield shall extend to those parts of the permit that have been changed pursuant to the reopening and reissuance procedure. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit# 05OPWE279 Page 51 24. Section 502(b)(10)Changes Regulation No.3, 5 CCR 1001-5,Part C, §XII.A. The permittee shall provide a minimum 7-day advance notification to the Air Pollution Control Division and to the Environmental Protection Agency at the addresses listed in Appendix D of this Permit. The permittee shall attach a copy of each such notice given to its Operating Permit. 25. Severability Clause Regulation No. 3, 5 CCR 1001-5,Part C, § V.C.10. In the event of a challenge to any portion of the permit, all emissions limits, specific and general conditions, monitoring, record keeping and reporting requirements of the permit,except those being challenged,remain valid and enforceable. 26. Significant Permit Modifications Regulation No.3, 5 CCR 1001-5,Part C, § III.B.2. The permittee shall not make a significant modification required to be reviewed under Regulation No. 3, Part B ("Construction Permit" requirements) without first receiving a construction permit. The permittee shall submit a complete Operating Permit application or application for an Operating Permit revision for any new or modified source within twelve months of commencing operation, to the address listed in Item 1 in Appendix D of this permit. If the permittee chooses to use the "Combined Construction/Operating Permit" application procedures of Regulation No. 3, Part C, then the Operating Permit must be received prior to commencing construction of the new or modified source. 27. Special Provisions Concerning the Acid Rain Program Regulation No.3,5 CCR 1001-5, Part C, §§V.C.1.b.& 8 a. Where an applicable requirement of the federal act is more stringent than an applicable requirement of regulations promulgated under Title IV of the federal act,40 Code of Federal Regulations(CFR)Part 72,both provisions shall be incorporated into the permit and shall be federally enforceable. b. Emissions exceeding any allowances that the source lawfully holds under Title IV of the federal act or the regulations promulgated thereunder,40 CFR Part 72, are expressly prohibited. 28. Transfer or Assignment of Ownership Regulation No.3, 5 CCR 1001-5, Part C, § II.C. No transfer or assignment of ownership of the Operating Permit source will be effective unless the prospective owner or operator applies to the Air Pollution Control Division on Division-supplied Administrative Permit Amendment forms, for reissuance of the existing Operating Permit. No administrative permit shall be complete until a written agreement containing a specific date for transfer of permit, responsibility, coverage, and liability between the permittee and the prospective owner or operator has been submitted to the Division. 29. Volatile Organic Compounds Regulation No.7, 5 CCR 1001-9, §§ III&V. a. For sources located in an ozone non-attainment area or the Denver Metro Attainment Maintenance Area,all storage tank gauging devices, anti-rotation devices,accesses,seals,hatches,roof drainage systems,support structures, and pressure relief valves shall be maintained and operated to prevent detectable vapor loss except when opened, Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Rocky Mountain Energy Center, LLC. Colorado Operating Permit Rocky Mountain Energy Center Permit#05OPWE279 Page 52 actuated, or used for necessary and proper activities(e.g.maintenance). Such opening,actuation, or use shall be limited so as to minimize vapor loss. Detectable vapor loss shall be determined visually,by touch,by presence of odor,or using a portable hydrocarbon analyzer. When an analyzer is used,detectable vapor loss means a VOC concentration exceeding 10,000 ppm. Testing shall be conducted as in Regulation No. 7, Section VIII.C.3. Except when otherwise provided by Regulation No. 7,all volatile organic compounds,excluding petroleum liquids, transferred to any tank,container,or vehicle compartment with a capacity exceeding 212 liters(56 gallons),shall be transferred using submerged or bottom filling equipment. For top loading,the fill tube shall reach within six inches of the bottom of the tank compartment. For bottom-fill operations,the inlet shall be flush with the tank bottom. b. The pennittee shall not dispose of volatile organic compounds by evaporation or spillage unless Reasonably Available Control Technology(RACT)is utilized. c. No owner or operator of a bulk gasoline terminal,bulk gasoline plant,or gasoline dispensing facility as defined in Colorado Regulation No. 7, Section VI,shall permit gasoline to be intentionally spilled,discarded in sewers,stored in open containers,or disposed of in any other manner that would result in evaporation. 30. Wood Stoves and Wood burning Appliances Regulation No.4, 5 CCR 1001-6 The permittee shall comply with the provisions of Regulation No. 4 concerning the advertisement, sale, installation, and use of wood stoves and wood burning appliances. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendices OPERATING PERMIT APPENDICES A - INSPECTION INFORMATION B - MONITORING AND PERMIT DEVIATION REPORT C - COMPLIANCE CERTIFICATION REPORT D - NOTIFICATION ADDRESSES E - PERMIT ACRONYMS F - PERMIT MODIFICATIONS *DISCLAIMER: None of the information found in these Appendices shall be considered to be State or Federally enforceable, except as otherwise provided in the permit, and is presented to assist the source, permitting authority, inspectors, and citizens. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix A Inspection Information Page 1 APPENDIX A-Inspection Information Directions to Plant The facility is located at 6211 Weld County Road 51 (between Hudson and Keenesburg, east of !-76, accessible from the Kersey Rd exit). Safety Equipment Required Eye Protection, Hard Hat, Safety Shoes and Hearing Protection Facility Plot Plan Figure 1 (following page) shows the plot plan as submitted on March 14, 2005 with the source's Title V Operating Permit Application. List of Insignificant Activities The following list of insignificant activities was provided by the source to assist in the understanding of the facility layout. Since there is no requirement to update such a list, activities may have changed since the last filing. Insignificant activities and/or sources of emissions as identified in the Title V permit application: Units with emissions less than APEN de minims—non-criteria reportable pollutants (Reg 3, Part C.II.E.3.b) Two (2) 12,000 gal anhydrous ammonia storage tanks Fuel (gaseous) burning equipment < 5 mmBtu/hr(Reg 3, Part C.II.E.3.k) Water bath fuel heater Landscaping and site housekeeping devices < 10 hp (Reg 3, Part C.II.E.3.bb) Garden tractor Stationary Internal Combustion Engines- limited size or hours (Reg 3, Part C.II.E.3.xxx.(ii)) Diesel-fired emergency fire water pump (182 hp) Operating Permit Number: 05OPWE279 Issued: DRAFT 1 1 N � 0 a K7 CV I /11 :;, ii H I wz IMMO if 0 ® I ; i 1 1 , i - k i Vi 'a r o iT� I I IAA se, , • l f a� ., '. ` $ f m l �1 Ili I- Rso . 1 J i ; t n II � 0 g ® e �il�� - +X�t " $ a O4 *iO" w g it •— i © �._ li o® ® 11 1-5L1r— b r---- 0 ° ca[112 r- • 13 w...:S*' 1 I 1 J i7F- 1 ,00.00 L Z ---- . . 0,9Z.00 N Figure 1: Facility Plot Plan Rocky Mountain Energy Center Air Pollution Control Division Colorado Operating Permit Appendix B Monitoring and Permit Deviation Report Page 1 APPENDIX B Reporting Requirements and Definitions with codes ver 2/20/07 Please note that,pursuant to 113(c)(2) of the federal Clean Air Act, any person who knowingly: (A) makes any false material statement, representation, or certification in, or omits material information from, or knowingly alters, conceals, or fails to file or maintain any notice, application,record, report, plan, or other document required pursuant to the Act to be either filed or maintained(whether with respect to the requirements imposed by the Administrator or by a State); (B) fails to notify or report as required under the Act; or (C) falsifies, tampers with, renders inaccurate, or fails to install any monitoring device or method required to be maintained or followed under the Act shall, upon conviction, be punished by a fine pursuant to title 18 of the United States Code, or by imprisonment for not more than 2 years, or both. If a conviction of any person under this paragraph is for a violation committed after a first conviction of such person under this paragraph, the maximum punishment shall be doubled with respect to both the fine and imprisonment. The permittee must comply with all conditions of this operating permit. Any permit noncompliance constitutes a violation of the Act and is grounds for enforcement action; for permit termination, revocation and reissuance, or modification; or for denial of a permit renewal application. The Part 70 Operating Permit program requires three types of reports to be filed for all permits. All required reports must be certified by a responsible official. Report#1: Monitoring Deviation Report (due at least every six months) For purposes of this operating permit, the Division is requiring that the monitoring reports are due every six months unless otherwise noted in the permit. All instances of deviations from permit monitoring requirements must be clearly identified in such reports. For purposes of this operating permit, monitoring means any condition determined by observation,by data from any monitoring protocol, or by any other monitoring which is required by the permit as well as the recordkeeping associated with that monitoring. This would include, for example, fuel use or process rate monitoring, fuel analyses, and operational or control device parameter monitoring. Report #2: Permit Deviation Report (must be reported "promptly") In addition to the monitoring requirements set forth in the permits as discussed above, each and every requirement of the permit is subject to deviation reporting. The reports must address deviations from permit requirements, including those attributable to malfunctions as defined in this Appendix, the probable cause of Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix B Monitoring and Permit Deviation Report Page 2 such deviations, and any corrective actions or preventive measures taken. All deviations from any term or condition of the permit are required to be summarized or referenced in the annual compliance certification. For purposes of this operating permit, "malfunction" shall refer to both emergency conditions and malfunctions. Additional discussion on these conditions is provided later in this Appendix. For purposes of this operating permit, the Division is requiring that the permit deviation reports are due as set forth in General Condition 21. Where the underlying applicable requirement contains a definition of prompt or otherwise specifies a time frame for reporting deviations, that definition or time frame shall govern. For example, quarterly Excess Emission Reports required by an NSPS or Regulation No. 1, Section IV. In addition to the monitoring deviations discussed above, included in the meaning of deviation for the purposes of this operating permit are any of the following: (1) A situation where emissions exceed an emission limitation or standard contained in the permit; (2) A situation where process or control device parameter values demonstrate that an emission limitation or standard contained in the permit has not been met; (3) A situation in which observations or data collected demonstrates noncompliance with an emission limitation or standard or any work practice or operating condition required by the permit; or, (4) A situation in which an excursion or exceedance as defined in 40CFR Part 64 (the Compliance Assurance Monitoring (CAM) Rule)has occurred. (only if the emission point is subject to CAM) For reporting purposes, the Division has combined the Monitoring Deviation Report with the Permit Deviation Report. All deviations shall be reported using the following codes: 1 = Standard: When the requirement is an emission limit or standard 2 =Process: When the requirement is a production/process limit 3 =Monitor: When the requirement is monitoring 4 =Test: When the requirement is testing 5 =Maintenance: When required maintenance is not performed 6 =Record: When the requirement is recordkeeping 7=Report: When the requirement is reporting 8=CAM: A situation in which an excursion or exceedance as defined in 40CFR Part 64 (the Compliance Assurance Monitoring(CAM)Rule)has occurred. 9=Other: When the deviation is not covered by any of the above categories Report#3: Compliance Certification (annually, as defined in the permit) Submission of compliance certifications with terms and conditions in the permit, including emission limitations, standards, or work practices, is required not less than annually. Compliance Certifications are intended to state the compliance status of each requirement of the permit over the certification period. They must be based, at a minimum, on the testing and monitoring methods specified in the Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix B Monitoring and Permit Deviation Report Page 3 permit that were conducted during the relevant time period. In addition, if the owner or operator knows of other material information(i.e. information beyond required monitoring that has been specifically assessed in relation to how the information potentially affects compliance status),that information must be identified and addressed in the compliance certification. The compliance certification must include the following: • The identification of each term or condition of the permit that is the basis of the certification; • Whether or not the method(s) used by the owner or operator for determining the compliance status with each permit term and condition during the certification period was the method(s) specified in the permit. Such methods and other means shall include, at a minimum, the methods and means required in the permit. If necessary, the owner or operator also shall identify any other material information that must be included in the certification to comply with section 113(c)(2) of the Federal Clean Air Act, which prohibits knowingly making a false certification or omitting material information; • The status of compliance with the terms and conditions of the permit, and whether compliance was continuous or intermittent. The certification shall identify each deviation and take it into account in the compliance certification. Note that not all deviations are considered violations.' • Such other facts as the Division may require, consistent with the applicable requirements to which the source is subject, to determine the compliance status of the source. The Certification shall also identify as possible exceptions to compliance any periods during which compliance is required and in which an excursion or exceedance as defined under 40 CFR Part 64 (the Compliance Assurance Monitoring (CAM) Rule) has occurred. (only for emission points subject to CAM) Note the requirement that the certification shall identify each deviation and take it into account in the compliance certification. Previously submitted deviation reports, including the deviation report submitted at the time of the annual certification, may be referenced in the compliance certification. Startup, Shutdown, Malfunctions and Emergencies Understanding the application of Startup, Shutdown, Malfunctions and Emergency Provisions, is very important in both the deviation reports and the annual compliance certifications. Startup, Shutdown, and Malfunctions Please note that exceedances of some New Source Performance Standards (NSPS) and Maximum Achievable Control Technology (MACT) standards that occur during Startup, Shutdown or Malfunctions may not be considered to be non-compliance since emission limits or standards often do not apply unless specifically stated in the NSPS. Such exceedances must,however, be reported as excess emissions per the NSPS/MACT rules and would still be noted in the deviation report. In regard to compliance certifications, the permittee should be For example, given the various emissions limitations and monitoring requirements to which a source may be subject, a deviation from one requirement may not be a deviation under another requirement which recognizes an exception and/or special circumstances relating to that same event. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix B Monitoring and Permit Deviation Report Page 4 confident of the information related to those deviations when making compliance determinations since they are subject to Division review. The concepts of Startup, Shutdown and Malfunctions also exist for Best Available Control Technology(BACT) sources, but are not applied in the same fashion as for NSPS and MACT sources. Emergency Provisions Under the Emergency provisions of Part 70 certain operational conditions may act as an affirmative defense against enforcement action if they are properly reported. DEFINITIONS Malfunction (NSPS)means any sudden, infrequent, and not reasonably preventable failure of air pollution control equipment,process equipment, or a process to operate in a normal or usual manner. Failures that are caused in part by poor maintenance or careless operation are not malfunctions. Malfunction (SIP)means any sudden and unavoidable failure of air pollution control equipment or process equipment or unintended failure of a process to operate in a normal or usual manner. Failures that are primarily caused by poor maintenance, careless operation, or any other preventable upset condition or preventable equipment breakdown shall not be considered malfunctions. Emergency means any situation arising from sudden and reasonably unforeseeable events beyond the control of the source, including acts of God, which situation requires immediate corrective action to restore normal operation, and that causes the source to exceed a technology-based emission limitation under the permit, due to unavoidable increases in emissions attributable to the emergency. An emergency shall not include noncompliance to the extent caused by improperly designed equipment, lack of preventative maintenance, careless or improper operation, or operator error. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix B Monitoring and Permit Deviation Report Page 5 Monitoring and Permit Deviation Report - Part I 1. Following is the required format for the Monitoring and Permit Deviation report to be submitted to the Division as set forth in General Condition 21. The Table below must be completed for all equipment or processes for which specific Operating Permit terms exist. 2. Part II of this Appendix B shows the format and information the Division will require for describing periods of monitoring and permit deviations, or malfunction or emergency conditions as indicated in the Table below. One Part II Form must be completed for each Deviation. Previously submitted reports (e.g. EER's or malfunctions) may be referenced and the form need not be filled out in its entirety. FACILITY NAME: Rocky Mountain Energy Center, LLC OPERATING PERMIT NO: 05OPWE279 REPORTING PERIOD: (see first page of the permit for specific reporting period and dates) Deviations Noted Deviation Malfunction/ During Period?' Code2 Emergency Condition Reported Operating During Period? Permit Unit ID Unit Description YES NO ,"r,°,--r,n' 6 YES NO CT-01 One(1)Westinghouse,Model No. 501FD, Natural Gas-Fired Combustion Turbine, Serial No. 37A8191. The Turbine is Rated at 1785 mmBtu/hr(HHV at ISO conditions). The turbine is operated in combined cycle mode only and the heat recovery steam generator(HRSG)is equipped with a duct burner rated at 675 mmBtu/hr. The turbine drives a generator capable of generating 152 MW of power and the HRSG drives a steam generator rated at 326 MW (at peak capacity). CT-02 One(1)Westinghouse,Model No. 501FD. Natural Gas-Fired Combustion Turbine, Serial No. 37A8196. The Turbine is Rated at 1785 mmBtu/hr(HHV at ISO conditions). The turbine is operated in combined cycle mode only and the heat recovery steam generator(HRSG)is equipped with a duct burner rated at 675 mmBtu/hr. The turbine drives a generator • capable of generating 152 MW of power and the HRSG drives a steam generator rated at 326 MW (at peak capacity). S005 Caterpillar,Model No. 3512B, Internal Combustion Engine Driving an Emergency Generator, Serial No. 1 GZ01360. The Engine is Diesel Fuel-Fired and rated at 1810 hp and 6.51 mmBtu/hr. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix B Monitoring and Permit Deviation Report Page 6 Deviations Noted Deviation Malfunction/ During Period?' Code2 Emergency Operating Condition Reported Permit Unit During Period? ID Unit Description YES NO YES NO S004 Rentech,Natural Gas Fired Boiler,Rated at 129 mmBtu/hr,Serial No.2002-49. S006 Marley,Model No.F4910, 12 Cell Cooling Water Tower,Rated at 176,000 gal/min. General Conditions Insignificant Activities See previous discussion regarding what is considered to be a deviation. Determination of whether or not a deviation has occurred shall be based on a reasonable inquiry using readily available information. 2 Use the following entries,as appropriate: 1 =Standard: When the requirement is an emission limit or standard 2=Process: When the requirement is a production/process limit 3=Monitor: When the requirement is monitoring 4=Test: When the requirement is testing 5=Maintenance: When required maintenance is not performed 6=Record: When the requirement is recordkeeping 7=Report: When the requirement is reporting 8=CAM: A situation in which an excursion or exceedance as defined in 40CFR Part 64(the Compliance Assurance Monitoring(CAM)Rule)has occurred. 9=Other: When the deviation is not covered by any of the above categories Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix B Monitoring and Permit Deviation Report Page 7 Monitoring and Permit Deviation Report - Part II FACILITY NAME: Rocky Mountain Energy Center, LLC OPERATING PERMIT NO: 05OPWE279 REPORTING PERIOD: Is the deviation being claimed as an: Emergency Malfunction N/A (For NSPS/MACT) Did the deviation occur during: Startup Shutdown Malfunction Normal Operation OPERATING PERMIT UNIT IDENTIFICATION: Operating Permit Condition Number Citation Explanation of Period of Deviation Duration (start/stop date & time) Action Taken to Correct the Problem Measures Taken to Prevent a Reoccurrence of the Problem Dates of Malfunctions/Emergencies Reported (if applicable) Deviation Code Division Code QA: SEE EXAMPLE ON THE NEXT PAGE Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix B Monitoring and Permit Deviation Report Page 8 EXAMPLE FACILITY NAME: Acme Corp. OPERATING PERMIT NO: 96OPZZXXX REPORTING PERIOD: 1/1/04 - 6/30/06 Is the deviation being claimed as an: Emergency Malfunction XX N/A (For NSPS/MACT)Did the deviation occur during: Startup Shutdown Malfunction Normal Operation OPERATING PERMIT UNIT IDENTIFICATION: Asphalt Plant with a Scrubber for Particulate Control -Unit XXX Operating Permit Condition Number Citation Section II, Condition 3.1 - Opacity Limitation Explanation of Period of Deviation Slurry Line Feed Plugged Duration START- 1730 4/10/06 END- 1800 4/10/06 Action Taken to Correct the Problem Line Blown Out Measures Taken to Prevent Reoccurrence of the Problem Replaced Line Filter Dates of Malfunction/Emergencies Reported(if applicable) 5/30/06 to A. Einstein,APCD Deviation Code Division Code QA: Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix B Monitoring and Permit Deviation Report Page 9 Monitoring and Permit Deviation Report - Part III REPORT CERTIFICATION SOURCE NAME: Rocky Mountain Energy Center, LLC FACILITY IDENTIFICATION NUMBER: 1231342 PERMIT NUMBER: 05OPWE279 REPORTING PERIOD: (see first page of the permit for specific reporting period and dates) All information for the Title V Semi-Annual Deviation Reports must be certified by a responsible official as defined in Colorado Regulation No. 3, Part A, Section I.B.38. This signed certification document must be packaged with the documents being submitted. STATEMENT OF COMPLETENESS I have reviewed the information being submitted in its entirety and, based on information and belief formed after reasonable inquiry, I certify that the statements and information contained in this submittal are true, accurate and complete. Please note that the Colorado Statutes state that any person who knowingly, as defined in Sub-Section 18- 1-501(6), C.R.S., makes any false material statement, representation, or certification in this document is guilty of a misdemeanor and may be punished in accordance with the provisions of Sub-Section 25-7 122.1, C.R.S. Printed or Typed Name Title Signature of Responsible Official Date Signed Note: Deviation reports shall be submitted to the Division at the address given in Appendix D of this permit. No copies need be sent to the U.S. EPA. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix C Compliance Certification Report Page 1 APPENDIX C Required Format for Annual Compliance Certification Report with codes ver 2/20/07 Following is the format for the Compliance Certification report to be submitted to the Division and the U.S. EPA annually based on the effective date of the permit. The Table below must be completed for all equipment or processes for which specific Operating Permit terms exist. FACILITY NAME: Rocky Mountain Energy Center, LLC OPERATING PERMIT NO: 05OPWE279 REPORTING PERIOD: I. Facility Status During the entire reporting period, this source was in compliance with ALL terms and conditions contained in the Permit, each term and condition of which is identified and included by this reference. The method(s) used to determine compliance is/are the method(s) specified in the Permit. With the possible exception of the deviations identified in the table below, this source was in compliance with all terms and conditions contained in the Permit, each term and condition of which is identified and included by this reference, during the entire reporting period. The method used to determine compliance for each term and condition is the method specified in the Permit, unless otherwise indicated and described in the deviation report(s). Note that not all deviations are considered violations. Operating Unit Description Deviations Monitoring Was Compliance Permit Reported Method per Continuous or Unit ID Permit?2 Intermittent?3 Previous Current YES NO Continuous Intermittent CT-01 One(I)Westinghouse,Model No. 501FD, Natural Gas-Fired Combustion Turbine, Serial No.37A8191. The Turbine is Rated at 1785 mmBtu/hr(HHV at ISO conditions). The turbine is operated in combined cycle mode only and the heat recovery steam generator(HRSG)is equipped with a duct burner rated at 675 mmBtu/hr. The turbine drives a generator capable of generating 152 MW of power and the HRSG drives a steam generator rated at 326 MW(at peak capacity). Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix C Compliance Certification Report Page 2 Operating Unit Description Deviations Monitoring Was Compliance Permit Reported ' Method per Continuous or Unit ID Permit?2 Intermittent? Previous Current YES NO Continuous Intermittent CT-02 One(1)Westinghouse,Model No. 501FD, Natural Gas-Fired Combustion Turbine, Serial No.37A8196. The Turbine is Rated at 1785 mmBtu/hr(HHV at ISO conditions). The turbine is operated in combined cycle mode only and the heat recovery steam generator(HRSG)is equipped with a duct burner rated at 675 mmBtu/hr. The turbine drives a generator capable of generating 152 MW of power and the HRSG drives a steam generator rated at 326 MW(at peak capacity). S005 Caterpillar,Model No. 3512B,Internal Combustion Engine Driving an Emergency Generator, Serial No. I GZ01360. The Engine is Diesel Fuel-Fired and rated at 1810 hp and 6.51 mmBtu/hr. S004 Rentech,Natural Gas Fired Boiler,Rated at 129 mmBtu/hr, Serial No.2002-49. S006 Marley, Model No.F4910, 12 Cell Cooling Water Tower,Rated at 176,000 gaUmin. General Conditions Insignificant Activities°If deviations were noted in a previous deviation report , put an "X" under "previous". If deviations were noted in the current deviation report(i.e. for the last six months of the annual reporting period), put an "X" under"current". Mark both columns if both apply. 2 Note whether the method(s)used to determine the compliance status with each term and condition was the method(s)specified in the permit. If it was not,mark "no"and attach additional information/explanation. 3 Note whether the compliance status with of each term and condition provided was continuous or intermittent. "Intermittent Compliance" can mean either that noncompliance has occurred or that the owner or operator has data sufficient to certify compliance only on an intermittent basis. Certification of intermittent compliance therefore does not necessarily mean that any noncompliance has occurred. NOTE: The Periodic Monitoring requirements of the Operating Permit program rule are intended to provide assurance that even in the absence of a continuous system of monitoring the Title V source can demonstrate whether it has operated in continuous compliance for the duration of the reporting period. Therefore, if a source I) conducts all of the monitoring and recordkeeping required in its permit, even if such activities are done periodically and not continuously, and if 2) such monitoring and recordkeeping does not indicate non-compliance, and if 3)the Responsible Official is not aware of any credible evidence that indicates non-compliance,then the Responsible Official can certify that the emission point(s) in question were in continuous compliance during the applicable time period. 4 Compliance status for these sources shall be based on a reasonable inquiry using readily available information. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix C Compliance Certification Report Page 3 II. Status for Accidental Release Prevention Program: A. This facility is subject is not subject to the provisions of the Accidental Release Prevention Program (Section 112(r) of the Federal Clean Air Act) B. If subject: The facility is is not in compliance with all the requirements of section 112(r). 1. A Risk Management Plan will be has been submitted to the appropriate authority and/or the designated central location by the required date. III. Certification All information for the Annual Compliance Certification must be certified by a responsible official as defined in Colorado Regulation No. 3, Part A, Section I.B.38. This signed certification document must be packaged with the documents being submitted. I have reviewed this certification in its entirety and, based on information and belief formed after reasonable inquiry,I certify that the statements and information contained in this certification are true, accurate and complete. Please note that the Colorado Statutes state that any person who knowingly, as defined in § 18-1-501(6), C.R.S., makes any false material statement, representation, or certification in this document is guilty of a misdemeanor and may be punished in accordance with the provisions of§ 25-7122.1, C.R.S. Printed or Typed Name Title Signature Date Signed NOTE: All compliance certifications shall be submitted to the Air Pollution Control Division and to the Environmental Protection Agency at the addresses listed in Appendix D of this Permit. Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix D Notification Addresses Page 1 APPENDIX D Notification Addresses 1. Air Pollution Control Division Colorado Department of Public Health and Environment Air Pollution Control Division Operating Permits Unit APCD-SS-B1 4300 Cherry Creek Drive S. Denver, CO 80246-1530 ATTN: Jim King 2. United States Environmental Protection Agency Compliance Notifications: Office of Enforcement, Compliance and Environmental Justice Mail Code 8ENF-T U.S. Environmental Protection Agency, Region VIII 1595 Wynkoop Street Denver, CO 80202-1129 Permit Modifications, Off Permit Changes: Office of Partnerships and Regulatory Assistance Air and Radiation Programs, 8P-AR U.S. Environmental Protection Agency, Region VIII 1595 Wynkoop Street Denver, CO 80202-1129 Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix E Permit Acronyms Page 1 APPENDIX E Permit Acronyms Listed Alphabetically: AIRS - Aerometric Information Retrieval System AP-42- EPA Document Compiling Air Pollutant Emission Factors APEN - Air Pollution Emission Notice (State of Colorado) APCD - Air Pollution Control Division(State of Colorado) ASTM - American Society for Testing and Materials BACT- Best Available Control Technology BTU- British Thermal Unit CAA - Clean Air Act (CAAA= Clean Air Act Amendments) CCR- Colorado Code of Regulations CEM- Continuous Emissions Monitor CF - Cubic Feet(SCF = Standard Cubic Feet) CFR- Code of Federal Regulations CO - Carbon Monoxide COM- Continuous Opacity Monitor CRS - Colorado Revised Statute EF - Emission Factor EPA - Environmental Protection Agency FI - Fuel Input Rate in mmBtu/hr FR- Federal Register G - Grams Gal - Gallon GPM - Gallons per Minute HAPs - Hazardous Air Pollutants HP - Horsepower HP-HR- Horsepower Hour (G/HP-HR=Grams per Horsepower Hour) LAER- Lowest Achievable Emission Rate LBS - Pounds M - Thousand MM - Million MMscf- Million Standard Cubic Feet MMscfd- Million Standard Cubic Feet per Day N- Normal Operation, as referenced in permit limitation table in Section II.1 N/A or NA - Not Applicable NOx - Nitrogen Oxides NESHAP - National Emission Standards for Hazardous Air Pollutants NSPS - New Source Performance Standards P- Process Weight Rate in Tons/Hr PE - Particulate Emissions PM - Particulate Matter Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix E Permit Acronyms Page 2 PKo - Particulate Matter Under 10 Microns PPM- Parts Per Million PPMV - Parts Per Million, by Volume PPMVD - Parts per Million, by Volume, Dry PSD - Prevention of Significant Deterioration PTE - Potential To Emit RACT - Reasonably Available Control Technology SCC - Source Classification Code SCF - Standard Cubic Feet SD - Shutdown, as referenced in permit limitation table in Section II.1 SIC - Standard Industrial Classification SO2 - Sulfur Dioxide SU - Start-Up, as referenced in permit limitation table in Section II.1 TPY - Tons Per Year TSP - Total Suspended Particulate VOC - Volatile Organic Compounds Operating Permit Number: 05OPWE279 Issued: DRAFT Air Pollution Control Division Colorado Operating Permit Appendix F Permit Modifications Page 1 APPENDIX F Permit Modifications DATE OF MODIFICATION SECTION NUMBER, DESCRIPTION OF REVISION REVISION TYPE CONDITION NUMBER Operating Permit Number: 05OPWE279 Issued: DRAFT i•' io , ' I r3 AMICS METEOROLOGICAL AND AIR QUALITY MODELING • Rece I Aka II/PP March 10, 2005 j4 ' Mr.James A. King ` ,4 Jco Manager,Operating Permit Unit Colorado Department of Public Health and Environment 4300 Cherry Creek Drive, South APCD-SS-B1 Denver, CO 80246-1530 Subject: Title V Permit Application for the Rocky Mountain Energy Center Dear Mr.King: The Calpine Corporation and Rocky Mountain Energy Center, LLC, are submitting four (4) copies of the Title V permit application to the Air Pollution Control Division (APCD). Each application is signed, with one original and three copies. Also included are three (3) revised APENs and a check for $359.88. The revised APENs reflect a change in the manufacturer of the diesel fire-pump, the standby generator, and the cooling tower. These revised sources are of equivalent design to the currently permitted sources, and other than a change in the manufacturer, the emissions are identical to the previous APENs. Thank you for your attention in this matter. If you have any questions with regards to the application,please contact Gary Aron at(303) 536-2518 or Gregory Darvin at(805) 569-6555. Sincerely, Atmospheric Dynamics,Inc. Gregory Damn Cc: Gary Aron (RMEC) Enclosures 2925 Puesta Del Sol Road•Santa Barbara•(A•93105•(805)569-6555 fax(805)569-6558 Noses, 3 "Fit/SI'7 /tPrvf FaX' 7✓ .Pof' 8M*c 221 . W'-c2DNsa >.uxd. nln al:LB Ns' CHECK $ PAY—s - An-{ DOLLARS AMOUNT $ DATE. T H R OF DESCRIPTION CHECK NO. 3,7o-aS otos*** pen. of 1'tf)uc Hrn(Tft lt 3 $ 3.59 .19 seo r $ ifeuoi GOdv e��pp by Y I NMI WELLS FARGO BANK,N VVVVWWELLSFARGO.COM (33N333b 000 2 2 Liu' I: L 2 2000 24 7i: L004 is 340841' SECURI:v GLAT.Ri S MICRO PRIM FORCERS.COLORED SR ICE PATTERN-WATERMARK CN KVERSE SIDE-MISSING PEAT ORE INDICATES A COPY. TITLE V PERMIT APPLICATION ROCKY MOUNTAIN ENERGY CENTER WELD COUNTY COLORADO 7 t February 2005 , " / ,; cri Submitted on behalf of Rocky Mountain Energy Center, LLC C/O Calpine 6211 Weld County Road 51 Keenesburg, CO 80643 Prepared by r v :lW II.PddrP , ICS,L METEOROLOGICAL AND AIR QUALITY MODELING Atmospheric Dynamics, Inc. 2925 Puesta del Sol Rd. Santa Barbara, CA 93105 FORM 2000-100 Operating Permit Application FACILITY IDENTIFICATION FORM 2000-100 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE I. Facility name and Name Rocky Mountain Energy Center, LCC mailing address Street or Route 6211 Weld County Road 51 City, State, Zip Code Keenensburg, CO 80643 2. Facility location Street Address 6211 Weld County Road 51 (No P.O. Box) City,County, Zip Code Keenensburg, CO 80643 3. Parent corporation Name Calpine Street or Route 4160 Dublin Blvd City, State, Zip Code Dublin, CA 94568 Country(if not U.S.) 4. Responsible Name Jim Gooding official Title General Manager Telephone (303) 536-2550 5. Permit contact person Name Gary Aron Title Plant Engineer (If Different than 4) Telephone (303) 536-2518 6. Facility SIC code: 4911 7. Facility identification code: CO 1 2 3 1 3 4 2 8. Federal Tax I. D. Number: 7 7 -0 2 12 9 7 7 9. Primary activity of the operating establishment: Generation of Electricity 10. Type of operating permit be New Modified Renewal 11. Is the facility located in a "nonattainment" area: Yes ✓ No If"Yes", check the designated "non-attainment" pollutant(s): In attainment for all pollutants Carbon Monoxide Ozone PM10 Other(specify) 12. List all (Federal and State) air pollution permits (including grandfathered units), plan approvals and exemptions issued to this facility. List the number, date and what unit/process is covered by each permit. For a Modified Operating Permit, do not complete this item. 02WE0228 Issued July 15, 2004 Operating Permit Application FACILITY PLOT PLAN FORM 2000-101 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division Facility Name: Rocky Mountain Energy Center Facility Identification Code: CO 1 2 3 1 3 4 2 The operating permit must be prepared and submitted on forms supplied by the Division. Use of this form is required for all operating permit applications. The Division will not consider or act upon your application unless each form used has been entirely completed. Completion of the information in the shaded area of this form is optional. Use "NA" where necessary to identify an information request that does not apply and is not in the optional shaded area. In order for a comprehensive air quality analysis to be accomplished, a facility plot plan MUST be included with the permit application. Drawings provided must fit on generic paper sizes of 8 1/2" X 1 1", 8 1/2" X 14" or 11" X 15", as appropriate to display the information being provided. Include the facility name and facility identification code on all sheets. For facilities with large areas, sketches of individual buildings, on separate drawings, may be needed to allow easy identification of stacks or vents. Insignificant activities do not need to be shown. ✓ 1. A plant layout (plan view) including all buildings occupied by or located on the site of the facility and any outdoor process layout. ✓ 2. The maximum height of each_building Lxcluding stack height). ✓ 3. The location and coded designation of each stack. Please ensure these designations correspond to the appropriate stacks listed on the other permit forms in this application. The drawings need not be to scale if pertinent dimensions are annotated, including positional distances of structures, outdoor processes and free standing stacks to each other and the property boundaries. ✓ 4. The location of property boundary lines. ✓ 5. Identify direction "North" on all submittals. Are there any outdoor storage piles on the facility site with air pollution emissions that need to be reported? U Yes ✓ No If "Yes", what is the material in the storage pile(s)? Are there any unpaved roads or unpaved parking lots on the facility site? ✓ Yes n No Unpaved roads are on the west, south and east sides of the switchyard, but are normally not used. List the name(s) of any neighboring state(s) within a 50 mile radius of your facility: None Operating Permit Application SOURCE AND SITE DESCRIPTIONS FORM 2000102 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division Facility Name: Rocky Mountain Energy Center Facility Identification Code: CO 1 2 3 1 3 4 2 The operating permit must be prepared and submitted on forms supplied by the Division. Use of this form is required for all operating permit applications. The Division will not consider or act upon your application unless each form used has been entirely completed. Completion of the information in the shaded area of this form is optional. Use "NA" where necessary to identify an information request that does not apply and is not in the optional shaded area. 1. Briefly describe the existing Unit(s) to be permitted. Attach copies of Form 2000-700 as needed to provide the information. Process flow sheets or line diagrams showing major features and locations of air pollution control equipment can be most effective in showing the location and relationships of the units. Providing mass flow rates/balances at critical points on the diagrams is very helpful when developing an understanding of the processes involved. 001 Westinghouse Model 501 FD Natural Gas Combined Cycle Turbine and Heat Recovery Steam Generator with Duct Burner, 2,311 million British Thermal Units per hour (MMBtu/hr). 002 Westinghouse Model 501 FD Natural Gas Combined Cycle Turbine and Heat Recovery Steam Generator with Duct Burner, 2,311 MMBtu/hr. 003 John Deere, Model 6081AF001, 182 horsepower (hp) Distillate Fuel Oil fired Reciprocating Internal Combustion Engine powering an Emergency Fire Pump. 004 Natural Gas Fired Auxiliary Boiler 129 MMBtu/hr. 005 Caterpillar Model 3512B 1800 hp Distillate Fuel Oil fired Reciprocating Internal Combustion Engine powering an Emergency Electric Generator. 006 Hamon, 12 Cell, Evaporative Water cooling Tower, 166,166 gallons per minute. Each turbine is equipped with dry low NO. (DLN) combustion and Selective Catalytic Reduction (SCR) systems to control nitrogen oxides (NO.) emissions. Carbon monoxide (CO) is controlled with a Oxidation Catalyst. A low NOx combustion system is used to minimize (NO.) emissions from the boiler. The Cooling Tower is equipped with High Efficiency Drift Elminators to control particulate matter emission. Neither of the internal combustion engines have air pollution control equipment. A process flow diagram showing the above units is included in the Supplemental Information supplied in the Forms 2000-700 A. The plot plan showing the above units and exempted sources are shown in Appendix A. See additional source description of the Rocky Mountain Energy Center which may be found on Forms 2000-700. 2. Site Location and Description (Include instructions needed to drive to remote sites not identified by street addresses) 6211 Weld County Road 51 Keenesburg, CO 80643 SE/4 of SW/4 of Section 31, T2N, R64W in Weld County, Colorado. The site is located between Hudson and Keenesburg, east of 1-76, accessible from the Kersey Rd exit. 3. Safety Equipment Identify safety equipment required for performing an inspection of the facility: Protection V Other, specify Eye Protection V Hard Hat V Safety shoes ✓ Hearing Protection 0 Gloves Operating Permit Application SOURCE DESCRIPTION-APENS FORM 2000-1024 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division Facility Name: Rocky Mountain Energy Center Facility Identification Code: CO 1 2 3 1 3 4 2 NOTE: Each new or updated Air Pollutant Emission Notice (APEN) submitted must be accompanied by payment of$119.96 per APEN. 1. For each emission unit enclose a copy of the most current complete Air Pollutant Emission Notice (APEN) on file with the Division. If the most current APEN was not completely and correctly filled out, a revised APEN is required. List an APEN number, date, and a brief description of the unit/process covered by the APEN. (No filing fees are needed for these copies) APEN No. 1 OO1 Westinghouse Model 5O1 FD2 Natural Gas Combined Cycle Turbine and Heat Recovery Steam Generator with Duct Burner, 2,311 million British Thermal Units per hour (MMBtu/hr). APEN No. 2 OO2 Westinghouse Model 5O1FD2 Natural Gas Combined Cycle Turbine and Heat Recovery Steam Generator with Duct Burner, 2,311 MMBtu/hr. APEN No. 4 OO4Natural Gas Fired Auxilliary Boiler 129 MMBtu/hr. 2. No APEN exists for an emission unit. List the new APEN and the appropriate descriptive information here. Submit the APEN with a construction permit application. No new APEN is being submitted. 'ew APEN and permit application submitted 0 with this application OR 0 under separate cover to Construction Permits Section 3. A revised APEN was prepared and enclosed for an emission unit. List the APEN and the appropriate descriptive information here. A revised APEN is needed where a significant increase in emissions has occurred, or is planned; or a major modification of the unit has occurred or is planned; or the existing information needs correction or completion. A construction permit application may need to be submitted. Revised APEN submitted as part of this application: V Yes No ✓ Filing Fee Enclosed APEN No. 3 OO3 John Deere, Model 6O81AFOO1, 182 horsepower (hp) Distillate Fuel Oil fired Reciprocating Internal Combustion Engine powering an Emergency Fire Pump. APEN No. 5 OO5Caterpillar Model 3512B 18OO hp Distillate Fuel Oil fired Reciprocating Internal Combustion Engine powering an Emergency Electric Generator. APEN No. 6 OO6Hamon, 12 Cell, Evaporative Water cooling Tower, 166,166 gallons per minute. New permit application enclosed: 0 Yes ✓ No Permit modification application enclosed: 0 Yes / No NOTE: Use additional copies of Form 2OOO-7OO as needed to provide the above information. Operating Permit Application SOURCE DESCRIPTION -INSIGNIFICANT ACTIVITIES FORM 2000-102B Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division Facility Name: Rocky Mountain Energy Center Facility Identification Code: CO 1 2 3 1 3 4 2 4 NOTE: The operating permit must be prepared and submitted on forms supplied by the Division. This is a supplemental form for use only when necessary to provide complete information in the operating permit application.The Division will not consider or act upon your application unless each form used has been entirely completed. Certain categories of sources and activities are considered to be insignificant contributors to air pollution and are listed below. A source solely comprised of one or more of these activities is not required to obtain an operating permit pursuant to Regulation 3, unless the source's emissions trigger the major source threshold as defined in Part A, Section l.B.58 of Regulation 3. For the facility, mark all insignificant existing or proposed air pollution emission units, operations, and activities listed below. 0 (a) noncommercial fin-house) experimental and analytical laboratory equipment which is bench scale in nature including quality control/quality assurance laboratories, process support laboratories, environmental laboratories supporting a manufacturing or industrial facility, and research and development laboratories. (b) research and development activities which are of a small pilot scale and which process less than 10,000 pounds of test material per year. (c) small pilot scale research and development projects less than six months in duration with controlled actual emissions less than 500 pounds of any criteria pollutant or 10 pounds of any non-criteria reportable pollutant. 0 Disturbance of surface areas for purposes of land development, which do not exceed 25 contiguous acres and which do not exceed six months in duration. (This does not include mining operations or disturbance of contaminated soil). ✓ Each individual piece of fuel burning equipment, other than smokehouse generators and internal combustion engines, which uses gaseous fuel, and which has a design rate less than or equal to 5 million Btu per hour. (See definition of fuel burning equipment, Common Provisions Regulation). 0 Petroleum industry flares, not associated with refineries, combusting natural gas containing no H2S except in trace (less than 500 ppmw) amounts, approved by the Colorado Oil and Gas Conservation Commission and having uncontrolled emissions of any pollutant of less than five tons per year. ✓ Chemical storage tanks or containers that hold less than 500 gallons, and which have a daily throughput less than 25 gallons. ✓ Landscaping and site housekeeping devices equal to or less than 10 H.P. in size (lawnmowers, trimmers, snow blowers, etc.). 0 Crude oil or condensate loading truck equipment at crude oil production sites where the loading rate does not exceed 10,000 gallons per day averaged over any 30 day period. ✓ Chemical storage areas where chemicals are stored in closed containers, and where total storage capacity does not exceed 5000 gallons. This exemption applies solely to storage of such chemicals. This exemption does not apply to transfer of chemicals from, to, or between such containers. 0 Oil production wastewater (produced water tanks), containing less than 1% by volume crude oil, except for commercial facilities which accept oil production wastewater for processing. (Continues on other side) 0 Storage of butane, propane, or liquified petroleum gas in a vessel with a capacity of less than 60,000 gallons, provided the requirements of Regulation No. 7, Section IV are met, where applicable. ✓ Storage tanks of capacity < 40,000 gallons of lubricating oils. 0 Venting of compressed natural gas, butane or propane gas cylinders, with a capacity of 1 gallon or less. V Fuel storage and dispensing equipment in ozone attainment areas operated solely for company-owned vehicles where the daily fuel throughput is no more than 400 gallons per day, averaged over a 30 day period. 0 Crude oil or condensate storage tanks with a capacity of 40,000 gallons or less. ✓ Storage tanks meeting all of the following criteria: (i) annual throughput is less than 400,000 gallons; and (ii)the liquid stored is one of the following: (A) diesel fuels 1-D, 2-D, or 4-D; (B) fuel oils #1 through #6; (C) gas turbine fuels 1-GT through 4-GT; (D) an oil/water mixture with a vapor pressure lower than that of diesel fuel (Reid vapor pressure of .025 PSIA). 0 Each individual piece of fuel burning equipment which uses gaseous fuel, and which has a design rate less than or equal to 10 million Btu per hour, and which is used solely for heating buildings for personal comfort. 0 Stationary Internal Combustion Engines which: (i) power portable drilling rigs; or (ii) are emergency power generators which operate no more than 250 hours per year; or (iii)have actual emissions less than five tons per year or rated horsepower of less than 50. 0 Surface mining activities which mine 70,000 tons or fewer of product material per year. A fugitive dust control plan is required for such sources. Crushers, screens and other processing equipment activities are not included in this exemption. 0 Air pollution emission units, operations or activities with emissions less than the appropriate de minimis reporting level. NOTE: Material Data Safety Sheets (MSDS) do not have to be submitted for any insignificant activities. USE FORM 2000-700 TO PROVIDE AN ITEMIZED LIST OF THE SOURCES OR ACTIVITIES BEING IDENTIFIED AS INSIGNIFICANT ACTIVITIES. DO NOT ITEMIZE INDIVIDUAL PIECES OF LANDSCAPING EQUIPMENT. THE LIST IS NEEDED TO ACCURATELY ACCOUNT FOR ALL ACTIVITIES AT THE FACILITY FORMS 2000-200 Operating Permit Application STACK IDENTIFICATION FORM 2000-200 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 3a. Construction Permit Number: 02WE0228 4. Exhausting Unit(s), use Unit identification code from appropriate Form(s) 2000-300, 301, 302, 303, 304, 305, 306, 307 2000-300 2000-301 2000-302 2000-303 2000-304 2000-305 2000-306 001 2000-307 5. Stack identified on the plot plan required on Form 2000-101 D 6. Indicate by checking: I ✓ This stack has an actual exhaust point. The parameters are entered in Items 7-13. D This stack serves to identify fugitive emissions. Skip items 7-13. Go to next form. D When stack height Good Engineering Practice (GEP)exceeds 65 meters (Colorado Air Quality Reg 3.A.VIHI.D) data entry is required for Item 7. T :Discharge height above ground level:- 17.0 (feet) t 'S. lnsidc dimensions at outlet (cheek one and complete): ✓ Circular 18.5 (feet) • .0 Rectangular Tlen_gth (feet) wdrlth*feet) 9„ L 'Exhaust-flaw rate '?Normal 999445 (.AOFM) 5MaxuTium A �� `� � Q (FE'S) f✓WC t1 tilated L Stack Test f Y .nnr�i, r 161 (�F) r �� " x_31 , 3r ss mddrfS4abietffair•momstur xeat ✓ es D ' Io 3� err It ' e att t- as mo ture- ut: Normal 'l 7 e Gent ,\ 7 .g � _It � Iaxtrntun -pt~Tcet2t? 1 x, fi t as"discharge:;tlireLfaon ✓!Up " � SIi Down I or zoWn7 • 5 Nita ' t,144?l5i,et[tOpe4itySia ramhat or any:.ohstructton ith ie iow o f � in-Mt � e'Gleia r#��`^ �.1 fiS ✓r..i'.I(.� :.aK:r „P— 7y3 .3+,s..'h:a a..xrtM.. tst' • ta�aa. 7-�'+ t?E .�L .z.' �. # R *****Complete the appropriate Air Permit Application Forms(s)2000-300, 301, 302, 303, 304, ***** 305, 306, or 307 for each Unit exhausting through this stack. Operating Permit Application STACK IDENTIFICATION FORM 2000-200 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S002 3a. Construction Permit Number: 02WE0228 4. Exhausting Unit(s), use Unit identification code from appropriate Form(s)2000-300, 301, 302, 303, 304, 305, 306, 307 2000-300 2000-301 2000-302 2000-303 2000-304 2000-305 2000-306 002 2000-307 5. Stack identified on the plot plan required on Form 2000-101 0 6. Indicate by checking: ✓ This stack has an actual exhaust point. Thearameters are entered in Items 7-13. 0 This stack serves to identify fugitive emissions. Skip items 7-13. Go to next form. 0 When stack height Good Engineering Practice (GEP)exceeds 65 meters(Colorado Air Quality Reg 3.A.VIII.D)data entry is required for Item 7. ,ib p rifi'd Y Y 7,:a h ti°T)i l aY rge height above°groux1 level J�j1 5 yt t�tiy H! -8: i ttirmensions at nutlet(check,one and uomplE )^, - 7 ,r II ✓:Girt 18.5 (feet) . .� U ,t.i:;14„. � �� x f 1 i t a '-'1:::"-.‘t'.!ac.� 1 R. � ��t�,,. .-:.S - .. � ,,,,;42,0^."�� Wo. fr y;h' "a y, t}x -. -9 . .. J''f aS s ? to 3 v f' `t'".fi r.o°`, �P �6 k i' .4 f44 fi- E�..,, t 7' .; t ;:m.s; .3 .+Fi _, " - H s til�q��t'� i p rah r f e E P'' gr f 1sr ,i- as`a .+ y .' {r m:p i ZV ' If_` ' ,i, r+,ttt r P a F a41stei foko t i i 4f y"f I r ra-li ,, h us #�, r i I 41: ,',.z ,i lf-4;,c Ai -r 'k * ,.#� ,s'.„F.,,:.:4-F- '.i d. y ,1,..A E'�. f i r114 _. —_ .. __ dfP�,Y ; r.15§O11alrgertil.};c�ut�u I fi�at x �r4"„y dx c'+1"r -',.,,,,...-.-,.--T---',-;.,-,, YM r--J.-:',.,-. ,1 t4rr :'i ,,Sj T F '�d r� -�s4.�Y -r.f 4't� 'k.:..vtd>ti�I;kEfu.rAx L f 1s-',N" q.`t ](,�1 jC ti4 i;',•,,-„;21-43, �FI.Y pY73 f�Q C, r2 � �N►� S a 'i -- ,4 ,-; 1 -�S'''ta ,...7.--:-.,t.-,.,, g,"' >r y^� st• �t .IYa:. : fits �rf.j �•� ..'1,.1€ ; ...:, •:st .�a6.„3„�4-s x:.�'.e{yy-di a_— �-°:' .�I"+kfsi-r ��•,a $ .�1' {:.�,..,. ... ...... .. .... .. ..Y..ar:C, *****Complete the appropriate Air Permit Application Forms(s) 2000-300, 301, 302, 303, 304, ***** 305, 306, or 307 for each Unit exhausting through this stack. Operating Permit Application STACK IDENTIFICATION FORM 2000-200 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S003 3a. Construction Permit Number: 02WE0228 4. Exhausting Unit(s), use Unit identification code from appropriate Form(s) 2000-300, 301, 302, 303, 304, 305, 306, 307 2000-300 2000-301 2000-302 003 2000-303 2000-304 2000-305 2000-306 2000-307 5. Stack identified on the plot plan required on Form 2000-101 0 6. Indicate by checking: ✓ This stack has an actual exhaust point. The_paratneters are entered in Items 7-1 3. 0 This stack serves to identify fugitive emissions. Skip items 7-13. Go to next form. 0 When stack height Good Engineering Practice(GEP) exceeds 65 meters (Colorado Air Quality Reg 3.A.VIII.D) data entry is required for Item 7. ' 'Discharge height above round level' 11 4 `(feet) 4. ^- i , ;:: , 8. Inside ilinteta.s ons at outlet(check nrie and eatuplete) ✓Circular 0 42 (ft,et3�... d :431,,,,'",-;W:,,'+-4'44.*3 ' x..�41t� t 1eef) idt {.f=eet) 9. 1 't' u$t Io ra t'i Mo i ''#._Kr 4'V A'' 15'4'5} *'' ti%-. 'Maxi; i Y t � �� , t•xt�, (ACFM) Velocity. 92' ....:1!,..',„" {ET'.S),4 a t at d Stack 4w <�C , ; :, S 1 t j f } .,•,,z41,11,.. - ., 3 +a 5°+ t, T r ,r at 10_ Exhast_ as te. eratt.tc rmai) 1 fll. � 1-'1 t. 'e x4.1 c,.� sdd, n ,.\4;1,7-!4::ern , -'.':Iii'',',( ti,#4 a�a .[. r • rki1. s s rt r° :, . 311,E t� i� °ik"} I •:,',::... ..‘,-,-±1,t.,,A ,F a "i� t. Ci �cst�.t i�,.�n 11_ Dots.I ro es�'5l%o �'srm`l rei1t.at t i4tt'e Ma '�' 4- 4 r 1 ) k p �' ,t5 � n "tr4'��C�� Imo,. �,.ti '£ �' q , ,..,,,,,,..,..-c-,-,,,,,.'"Yx'' �r } . 'eai.'�S �ir"kx♦ ,,,`wk ; t� ..V`. {.f r'.-,i4.,,,-,.--!.-:.} ,1r r- •If "Yes",:er1idust bas moisterocer : ��a a� x i T f'��`: t ) y ty�2,f*i Z� 7 uT i } l ,t t, <F�ij ' 's. 1-ts rtig7 rii-. ..} #R 5 1 12. Exhaust bas discharg ttp sfb, 3�`' x��I 4,, ' �'` +� ,r 41 W,; .) li. •1s this stack egUipp C•ir aro . , t:! o tt�. � q, �� W F`t X��4u1s7.d r T'..,rr ,,,,»,,,L>i ��r--, a 1 Cttivay�`iS } e ..r L - 'G .ry t e L. -..0-t'`' t+' ! 1 d s p�'},tr} the exhaust gases front the stack9 4 e NQ s ' r ,r 1 �4 , .� µ, `}fi r `' rr C " J �J 1 - 4e 3 s PAD�"3, 'k .3. p ,r*s``rr �.., � ,s9 y � r. R.. i� .,�W��,d ;�� r.�t-ht, 11 }��* 'w"' -k *****Complete the appropriate Air Permit Application Forms(s)2000-300, 301, 302, 303, 304, ***** 305, 306, or 307 for each Unit exhausting through this stack. Operating Permit Application STACK IDENTIFICATION FORM 2000-200 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S004 3a. Construction Permit Number: 02WE0228 4. Exhausting Unit(s), use Unit identification code from appropriate Form(s)2000-300, 301, 302, 303, 304, 305, 306, 307 2000-300 004 2000-301 2000-302 2000-303 2000-304 2000-305 2000-306 2000-307 5. Stack identified on the plot plan required on Form 2000-101 0 6. Indicate by checking: ✓ This stack has an actual exhaust point. The parameters are entered in Items 7-13. 0 This stack serves to identify fugitive emissions. Skip items 7-13. Go to next form. 0 When stack height Good Engineering Practice(GEP) exceeds 65 meters (Colorado Air Quality Reg 3.A.VIII.D) data entry is required for Item 7. t +.�� r z t e pie .f-d3 r .�� ' : � ... �a lif }y,,�... t t Vie yF ppttqq ,i '₹ -!27 t I. :f,s ' i. ,:v'-,:"'"-' rs4.I.+ w.:.yw r r �tyi'r'�r� 11D1 a st `9��'�� iy S E�t t.r: U m� �.S'F irz rs .is� t S' t''� '- � �p µQ�s1� ��'�.'. I a�`.-s' y r� : ;�k.,.`st' i� r r r sx: ..4 . „i�'..:t�x�.-sf; 3.�S 6'Etli G ,Y.tt. . �`x-.. I t1'�h;S.tra k��` tt .r..rr�ic ..,�.st.. �.�.$.w't'.diw'�iwt ..✓s��;�. � Sf' r j7 1�! 1,--0--$41,44`44 nit rI �. ��rN r+f j "f € t(Ct ,•••_ . ...L , s 7 f iG _ yr'r.+ a�' r ,r N r f*s+t d'� �� i� ��I� Yl at 3 xt.r ''':N''.7-1'''4'..4-';--i. �' �9 '� �3 Sr� t 2, . ,4y e K .,f•�, ,F s+ -'—" *.,4,.2f,':.•••' X'J J ''.--4'' 3. c r b�i • -.i, K u1 J.C -rQ.,.l, m,1 �:..S .,' L' ' ,{8111y'{ti '� r;s T'<$d =r t n 1 a- 'x _ - - "{'' [ ire �~�"n ter' 95st , '''.9:'::. ' ' ..?' 1 S 0 ifs a ...fir J tOb 4S . t ,r s Y,. ,Ivt.v `7 a fiat `tea ?s Y; } i til G:x x7,,i, .•tr .{x*t yy 1 e 4gst I •tt.si'171,.-'.:,4, . *****Complete the appropriate Air Permit Application Forms(s)2000-300, 301, 302, 303, 304, ***** 305, 306, or 307 for each Unit exhausting through this stack. Operating Permit Application STACK IDENTIFICATION FORM 2000-200 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S005 3a. Construction Permit Number: 02WE0228 4. Exhausting Unit(s), use Unit identification code from appropriate Form(s)2000-300, 301, 302, 303, 304, 305, 306, 307 2000-300 2000-301 2000-302 005 2000-303 2000-304 2000-305 2000-306 2000-307 5. Stack identified on the plot plan required on Form 2000-101 0 6. Indicate by checking: ✓ This stack has an actual exhaust point. The parameters are entered in Items 7-13. 0 This stack serves to identify fugitive emissions. Skip items 7-13. Go to next form. 0 When stack height Good Engineering Practice(GEP) exceeds 65 meters (Colorado Air Quality Reg 3.A.VIII.D)data entry is required for Item 7. .�;�. `.rr „ , {#� y�7ti p;{�y+(�. µ�� ,, y -e.--v rr�,'y.r-,+ �`z ifr" ' 6 Vil; 1 .,,,''':',-1.".:,--(; -'11—,..f K6101' 1)0,.k YLj 7rt ititOl t .S}r ti. Mk-T'...4-4 tt °Yr :� i,r t t iv, .l{.._u, f�vi_ rye alf ., r a ,,,,-1;`,..1.,14:4,74,4.01,-,'-...41. 6E,,;VB "H dg -,r1:-(14i, 1:-(1:'}}t S-a. ',7-4'' ,, •i k :rrr .� .t ' .-_,,,---,,,, ,,„,f-,..:4,7 tl. FS"` -_ � 4.-r,. .pl t� , ! •';.•; ,.)i-41-'-F,^ -Am`8rW .W 4 i•,::,rr'�t 1 �" rld�ta-M �'. k..s � ,ti: � 4 may, lei,lj� 3 4 aM- �'f}" � � Y"? l+ �-- 5-d 'TM 1 1-f lt1,. :1 1, t 't .. t.... i'* h 4. -•S F 2 d' i rc t' , r xrSL.r i eras^ rr �.49't d y� '7 2b..y. 'ad a 'E .. r ,ret:u r`S° i_,- 's-IA �' r ..6 3, f x s ,e 1 �_a� rT rs tf x .�.ca pj d�� Sr - `_.. t)•*{Grttt y a3`�tt .e fa i3 E,, a .Aa r _ ` Fc `.`- e I1 ''' . Sr•. �2y, f, k �4• . ,•fait', 's g rE: a ' a W n ! � { w t +. .5-44'• , x+ t-,, `Z; uS ,+ r. ...{, .E r'prrf 'r +`� •}•e}-.>. .fir t``i.' t ;, it r - "{'%a. Y Z 1 e+ie 2 *x i F ., -rra# :mil • + v y" r:4;:c.'....s„ I! ', ' . ''h . ,i4- S i li vt,c a,r 1 s:$.0,as �"� c :...ii,, f stir v i z 1� ' P a%i l l x . +t sr t,i .i Val ' : '1014$t,11 '� '-'N/3,-,1`,,,s , , l tiiM.Or''-, .3�' .y-.'lr. yy.. u YrKp>�r ` .F `•..ir'.S rc r "k:"':','-',;':7.-'''''''' aa4 a; 3. S., � y � ale nr a ,.^�','. , 'txa.R +v?�;i i :f iLite ii,: •t S "9 R 2i - a I (.f"?‘411,1.- t ,p...,fit-, ' �. " % • c e 'tt*`.t4t}' Yh -- `�p - i, '-",:',-k---.—' yst tip,. a'S' ` II 1' `3u x� s al if�r es ciri a ,Et`i :=�f..' i �r tip` 5, .�' ` > °°` i itir`��ti : 11,.. is e?.S ., 4•, :.• n +1 `� i {t��a i t64r..�a• n{,r' {{{{ .t. �.':-�may{{ a _..+ [ m, f—d t a:i c�.••: rttl t':�tn :3�t^i. t�ti� y.imiiu.:¢r i.;° 4v Ei� t • f ; a --- ....4,...., .-.4.,,g-t-4„. ,,:.4:4-,2 JY t.rsn eta r. ..rn i' '�` •C .�i"'. ^r X ,.+, eye... -;y ,cz 7T ( t. y I J3. -''''4. C ' r::' f : 1 k'l:l: �c, t qtr x 1( If-��(t 5�?Y'a"t" , tt,3 s tiq z a �a� is °. * 4 a 4rL u�P'4 c,G5 � �'A ° �:; aa,f`'d'%,4t' �49 hfi Y }, % t Ylf 7- ills ..n.'M' r �-�P d1�tit 44$ s ,iv.74 � � .ti c, � r z•h_.�s u as s, w ..v.,?,,,;.,.... �. yN•p , r ''''''''."!;7'.-7-''''.‘14 >: *y: r�. -syrfr _} 7-t�. �i{>" a(, <: 11 t -e`�,� ' �,a'�Yrr¢?cis �k ula`� _ a� �c X41. v�'i neus+F+�a:� .'i.: -+ 4t g�" 'a t' tii vinbr . . t`'�?! " d'`? . .'r' -v•,:-,-4,5,,,,-• .- 3 ' '0--0,.<4,-T i s ,.E �,f 1 f � � rr E . t i�o ialo{ 8,..44 i F r' t,,, t ,.1;fe>e 7' 1 9 • rS,? :47: r. ,4 'i±�ijti! Y'f.<41 yi . ,1, L 'iv' atit Alm ,.... -."r t r i t'IA, t� ,,,4 - R Ga h (' � w'' s t,;,. �y ' } xI M . N.r,�; #E: c mac' .,/., 4 i .7. Fe.{'{ i g-6` .'a yr It . ;4411431*. . rte r,,pk:,.•.. t a r ., S }, q0-1. ,. .,�.i>� -..._ _.. „._, .. .. ,�_.._—. -_ _..._-___-..- '4�tr-.z'�b��6�`�•`'S.. ,rf r:7 x w�ltr��+ sel,��`' ,. �...... . *****Complete the appropriate Air Permit Application Forms(s) 2000-300, 301, 302, 303, 304, ***** 305, 306, or 307 for each Unit exhausting through this stack. Operating Permit Application STACK IDENTIFICATION FORM 2000-200 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S006 each of 12 cells 3a. Construction Permit Number: 02WE0228 4. Exhausting Unit(s), use Unit identification code from appropriate Forms)2000-300, 301, 302, 303, 304, 305, 306, 307 2000-300 2000-301 2000-302 2000-303 2000-304 2000-305 2000-306 006 2000-307 5. Stack identified on the plot plan required on Form 2000-101 0 6. Indicate by checking: This stack has an actual exhaust point. T he_paramerers are entered in Items 7-11 0 This stack serves to identify fugitive emissions. Skip items 7-13. Go to next form. 0 When stack height Good Engineering Practice(GEP)exceeds 65 meters(Colorado Air Quality Reg 3.A.VIId.D)data entry is required for Item 7. -1'1'4 t2 9-4 ,*BFtp1C��7 _{ N �'f 4 4 tY `y(i E3�" l .-f,y�' r 7 ..0` .41 � h .T. f �iflVBI f,x a � ) atikH .� :,xr fJ"`'�fikfr Y.�.i,bf^�u.`s+.kF 7 Et�ir �' ..:tE fs`:. f Yc�li. l')a a t Y� txF''ti�k y t �l 1f , f r , p r ' ,�a1 -J# iY t cr `a*r 6 { t a r. 6 F r ' F. C r-fir r 17 Kra ..�r .d Ft7 P�e�i �s. T _ ra �f ,. -. 1 ,.*,,, -4 '.4 - wwAt 4� 4t �S is A i 2� f �2 ttt `dtkYFi dli ,.liv"'�$ a LSS C 4.1- .,r f"C rs. X' kl' t Lg 'rfixl7. .i�A.n.... ,, :, h2'd�'a R�yt c�.� J :iii', f t4 t `iY- >t ; a s',',41v:1!.1 �.P.• { t ':f,�s ��f'' �`{` '.'-'O1:7.44f ., fd ,k�.. :h'..1'..`ty ask fl.....' .a :I.q.. kYa .:.sF �i,k71 , .:. •22;' f \`{{aei6 t ',.."-:6, .., ,u,„,„ c s'isp::17 at i�. y ''.,lye , ,-.A 6 ,�' - 1 ' . .„ : ,. , 71 I va,5 j :;e34,..1-;., §,,r , , .J . s '',.w...'-'0-1 410?a Ti., iftnFr'i, fro "WrI7 �t d / 4 �� 4 ss ..' i.._-n. ..,. .. . .,i.W.¢.:.1 astrm3.' '`-3#JL ..i.. f .. s..z. Yc't. *****Complete the appropriate Air Permit Application Forms(s)2000-300, 301, 302, 303, 304, ***** 305, 306, or 307 for each Unit exhausting through this stack. FORMS 2000-300 Operating Permit Application BOILER OR FURNACE OPERATION FORM 2000-300 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 Center 3. Stack identification code: S004 4. Unit code: 004 5. Unit description: Natural Gas Fired Auxiliary Boiler 6. Seasonal Fuel Dec-Feb: 40% Mar-May: 20% Jun-Aug: 20% Sep-Nov: 20% Usage(%) 7. Normal Operation Hours/Day: 24 Days/Week: 7 Hours/Year: 1900 8. Space Heat(%) of Unit 9. Indicate the boiler/furnace control technology status. n Uncontrolled 0 Controlled If the boiler/furnace is controlled, enter the control device number(s) from the appropriate forms: 2000-400 2000-401 2000-402 2000-403 2000-404 2000-405 2000-406 2000-407 10. Furnace type: Direct 11. Max continuous rating(mmBTU/hr): 129.0 12. Manufacturer: Rentech 13. Model&Serial#: M/N Rentech (no Model No.) S/N 2002-49 14. Date first placed in service: February 2004 Date of last modification: none 15. Fuels and firing conditions: Primary fuel Backup fuel#1 Backup fuel#2 Fuel name Natural Gas Higher heating value (with units) 1057 Btu/scf Maximum sulfur content (Wt.%) 0.05 Maximum ash content(Wt.%) 0.00 y rlyr rs�.xG�a�� e n.o ae " �§� ssb"v.� � Maximum hourly fuel usage (units/hr.) 136.353 MMscf/hr ***** For this emissions unit, identify the method of compliance demonstration by completing Form 2000-500, ***** DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 2000-500 and its attachment(s) to this form. ***** Please complete the Air Pollution Control Permit Application Forms 2000-600 and 2000-601 for this Unit. ***** Operating Permit Application INTERNAL COMBUSTION ENGINE OPERATION FORM 2000-302 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 3. Stack identification code: S003 4. Engine (Unitcode): 003 4a. Date first placed in service: Date last modified: 5. Engine use: Emergency Fire Water Pump 6. Engine Features: 2-Cycle ❑ 4-Cycle O Spark-ignition ❑ Diesel ❑x Standard rich burn ❑ Standard lean burn ❑ Air/fuel ratio controller ❑ Turbocharger ❑ Low-NOx design ❑ Other(Describe): 7. Emission controls: 0 No ❑ Yes- Attach control device form Non-Selective catalytic reduction ❑ Three-way catalyst ❑ Selective catalytic reduction ❑ Ammonia injected ❑ Oxidation catalyst ❑ Other: 8. Manufacturer: John Deere 9. Model No: 6081AF001 S/N: RG6081A159985 10. Max Fuel Design Rate: 0.5 11. Max Design: Site: 182 12. Heat Rate: 2747 13. Operating Temp: Min. Max. 14. Fuels: Primary Fuel Backup Fuel #1 Fuel Type: Distillate No. 2 Heating Value BTU/SCF 7,400 Btu/lb Sulfur Content (Wt.%) 0.05 Ash Content, (Wt.%) 0.0 Moisture Content (%) 1.5 Maximum Hourly Consumption 10 gal/hr Maximum Yearly Consumption 1840 gal/yr NOTE: Data entr below is NOT OPTIONAL if parametric monitorin: is used for compliance d @ I 41 y,.v nrym t F36 {i se t [ v v F _ th _wn9iZ 1 • i Ir 4 1 t +�p ,,j'i��✓hx ' a5a r �"id'dr �'s� r y_ ` `�s (�,'� z,7a�t.₹k,;fie '„•..t�'tF d„` r:fd`.">~is..wm ,t.- {we&u.t3.a„ .:. r•.:�& .<. a.....: 1-. 3i.. .5`+.'k, s,x ...'�,a.,a:�x.; ***** Identify, the method of compliance demonstration by completing Form 2000-500, ***** DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 2000-500 to this form. ***** Please complete the Air Pollution Control Permit Application Forms 2000-600 and 2000-601 for this Unit. *4444 Operating Permit Application FORM 2000-302 INTERNAL COMBUSTION ENGINE OPERATION Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 3. Stack identification code: S005 4. Engine (Unitcode): 005 4a. Date first placed in service: Date last modified: 5. Engine use: Emergency Electric Power Generator 6. Engine Features: 2-Cycle ❑ 4-Cycle ID Spark-ignition ❑ Diesel ❑O Standard rich burn ❑ Standard lean burn ❑ Air/fuel ratio controller ❑ Turbocharger ❑ Low-NOx design ❑ Other(Describe): 7. Emission controls: E No ❑ Yes- Attach control device form Non-Selective catalytic reduction CIThree-way catalyst El Selective catalytic reduction ❑ Ammonia injected ❑ Oxidation catalyst ❑ Other: 8. Manufacturer: Caterpillar 9. Model No: 3512B S/N: 1GZ01360 10. Max Fuel Design Rate: 5.0 11. Max Design: Site: 2000 12. Heat Rate: 2500 13. Operating Temp: Min. Max. 14. Fuels: Primary Fuel Backup Fuel #1 Fuel Type: Distillate No. 2 Heating Value BTU/SCF 7,400 Btu/lb Sulfur Content (Wt.%) 0.05 Ash Content, (Wt.%) 0.0 Moisture Content (%) 1.5 Maximum Hourly Consumption 100 gal/hr Maximum Yearly Consumption 4750 gal/yr NOTE: Data entr below is NOT OPTIONAL if parametric monitorin. ppis used for compliance k S t k 3 3 Jr �? Pt$ MA^'Rs 'P' ca1'Fi€5sY.6mttM X°°a .� ` q s rs- r 'r f �w , x P 1. • c^ I C �°"` ' _�, do- 'd^r„#'�"N 7 ***** Identify, the method of compliance demonstration by completing Form 2000-500, ***** DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 2000-500 to this form. ***** Please complete the Air Pollution Control Permit Application Forms 2000-600 and 2000-601 for this Unit. ***** Operating Permit Application MISCELLANEOUS PROCESSES FORM 2000-306 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 4. Process (Unit) code: 001 5. Unit description: Westinghouse Model 501FD, S/N 37A8191, Combined Cycle Natural Gas Combustion Turbine No. 1 6. Indicate the control technology status. d Uncontrolled V Controlled If the process is controlled, enter the control device code(s) from the appropriate form(s): 2000-400 C001, C003 2000-401 2000-402 2000-403 2000-404 2000-405 2000-406 2000-407 x Y . :.. c.. 1.d ,: 8. Date first placed in service: March 2004 Date of last modification: June 2004 9. Normal operating schedule: 24 hrs./day 7 days/wk. 8760 hours/yr. 10. Describe this process (please attach a flow diagram of the process). Attached? al Please See Form 2000-700 11. List the types and amounts of raw materials used in this process: Material Storage/material handling process " z ks ; s'" Maximum usage Units a ? ;;N u. K t, Clean-up solvents Other(specify) k `f` " 12. List the types and amounts of finished products: Material Storage/material handling process ta-t � r_l v r rr �,,5,c ' x.;' Maximum Units r`3...._.... .�„ s. amount produced t}ybV„IweM�5PYxvi SraprW`� �'. 13. Process fuel usage: Type of fuel Maximum heat input to tt v t + . ? ,# Maximum usage Units process c � f s ri million BTU/hr. r y .t,. r 2311 � $!� "'' `'• 2,186,376 scf/hr Natural Gas , . ras 14. Describe any fugitive emissions associated with this process, such as outdoor storage piles, unpaved roads, open conveyors, etc.: None ***** For this emissions unit, identify the method(s)of compliance demonstration by completing Form 2000-500, ***** DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 2000-500 and its attachment(s) to this form. ***** Please complete the Air Pollution Control Permit Application Forms 2000-600 and 2000-601 for this Unit. ***** Operating Permit Application MISCELLANEOUS PROCESSES FORM 2000-306 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S002 4. Process (Unit)code: 002 5. Unit description: Westinghouse Model50IFD, S/N 37A8196, Combined Cycle Natural Gas Combustion Turbine No. 2 6. Indicate the control technology status. D Uncontrolled ✓ Controlled If the process is controlled, enter the control device code(s) from the appropriate form(s): 2000-400 C002, C004 2000-401 2000-402 2000-403 2000-404 2000-405 2000-406 2000-407 f .. ' :. 2-117 1 'K 7t9r � + 47 w ,�,tt "."r.Ys�j.. : fs . -r,'� .. u�.. 8. Date first placed in service: March 2004 Date of last modification: June 2004 9. Normal operating schedule: 24 hrs./day 7 days/wk. 8760 hours/yr. 10. Describe this process (please attach a flow diagram of the process). Attached? Please See Form 2000-700 11. List the types and amounts of raw materials used in this process: Material Storage/material handling process Actual Visage Units Maximum usage Units Clean-up solvents ,any 4 Other(specify) 12. List the types and amounts of finished products: Material Storage/material handling process Actual amount ' Uttits Maximum Units produced amount produced 13. Process fuel usage: Type of fuel Maximum heat input to °r k f mts_t,R, Maximum usage Units process " • million BTU/hr. Natural Gas 2311 _ . 2,186,376 scf/hr 14. Describe any fugitive emissions associated with this process,such as outdoor storage piles, unpaved roads, open conveyors, etc.: None ***** For this emissions unit, identify the method(s)of compliance demonstration by completing Form 2000-500, ***** DESCRIPTION OF METHODS USED FOR DETERMINING COMPLIANCE. Attach Form 2000-500 and its attachment(s) to this form. ***** Please complete the Air Pollution Control Permit Application Forms 2000-600 and 2000-601 for this Unit. ***** FORMS 2000-400 Operating Permit Application CONTROL EQUIPMENT - MISCELLANEOUS FORM 2000-400 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: 2. Facility identification code: CO1 2 3 1 3 4 2 Rocky Mountain Energy Center 3. Stack identification code: S001 4. Unit identification code: S001 5. Control device code: C001 6. Manufacturer and model number: 7. Date placed in service: March 2004 Date of last modification: June 2004 8. Describe the device being used. Attach a diagram of the system. Selective Catalytic Reduction for NO. Emissions Control 9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below. El Documentation attached EITHER the outlet pollutant concentration OR the control efficiency must be provided. Pollutant Inlet pollutant Eznissia~ Outlet pollutant Control Efficiency (%) concentration n concentration capture• te'ftcienl,. gr/acf ppmv gr/acf ppmv NOX 90 i-i r 171§61>,§s hoW the coilec;ted material wc1 #or y�, Sip - `E ,H r ,� rr ii2 •-- .. '- '�,,..'..p �:. i-#n`"�.',+�w.r3T�9i�vw.'�i. �4Y ( fir e:.r. are a Malfunction preventroII,and,.�r bath"en..t r rr, t pia}�}i �b �es`not`have to be subinittetlil �` r Ito thefollowing: '77 � J1 a Ydl" canon of tlae indiv dual(s), by t tl ', 4414 YR• �V"., tr7u � by Cf'{7�$� ; �. • ... f�i>,{F qL . r n Pet": � �' iss. eS'such as tempera e a as {� r n� pa 's FYa rt t tj r t ugh,.the correct opt X ,Aqn � or sUrveillan 'pa 'Lri /'C' yy� R (�. .yyry... ry {.�7 fof momtormg equip ICYi �f� tf �' E ?r4r }�r a u � f 7L C.�ledujc a ld itC'ITIs o GF% qtr{i't+ " F y w �. s ,u•x..r't�i f tiS cur* Yi; • } r q g av 1able fonts � 4 its ,, t � . t t F d' i-la^r�rn xtr ni t, �'�*i`tr ' ( �i � ,it $ f '4! r y : +4 ,a.Y#n 'k f. • aid NOTE: COMPLETION OF INFORMATION IN SHADED AREA OF THIS FORM IS OPTIONAL Operating Permit Application CONTROL EQUIPMENT - MISCELLANEOUS FORM 2000-400 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: 2. Facility identification code: CO1 2 3 1 3 4 2 Rocky Mountain Energy Center 3. Stack identification code: S002 4. Unit identification code: S002 5. Control device code: C002 6. Manufacturer and model number: 7. Date placed in service: March 2004 Date of last modification: June 2004 8. Describe the device being used. Attach a diagram of the system. Selective Catalytic Reduction for NOx Emissions Control 9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below. O Documentation attached EITHER the outlet pollutant concentration OR the control efficiency must be provided. Pollutant It efr 'o c Outlet pollutant Control Efficiency (%) co cen on .;q ,, -`- concentration i.,,y: ,F Y ,stJ. s s yill gtr"Y tfr('gi �+i '3i, S' �.,F-filet Z 1,,,,,,...,-.,,,,,,,,, `T. `,, t6r .., ,,,,' i 4rl ac ; 1r '* Y` ` gr/acf ppmv r `ar ' i u :, {,yam ,. 1 90 NOx ,. Y , , ., ,j t ; illy. 1 V� *r , . r u ' f i r ti ��.J-r�'i:�'n r't't��i�t�e��ts� -+i `-'r�u K�t-11.1. ». r• - era . _ j. - i, t Y'1 f}f ]L .'..d.d� �' f .&.. � l't�� -,,t a of n Y aR &9t L yr N a ''tt ��''�it_ ;4,1,' i- i>_• s. r't. fA ....fir• ,... a▪ s ^'.Etta -0,...,f.-••,--A r`,t'i x.:, .�«T'. .7Y�f ti ,1°stf9i-�+r. rf; f:h i -.t• uF 14441 notit sm CT , • c�11O,w?ng �If' 1:4t '� =s°"" ,4 ` .. € ',A4'-''k400: 'alb rt a w y� o�'�thd`� � � D J,. r t• 4 � � ▪ a 't,i, iir4� x3,,�r 1 t 7�� ti� ,1)q-11:4i,Irea s o tt(5, 1 'w it r sa sue, 45s hallo '"o�oix+ t &,4• a It u L a.t .i1�3.a. ,Y' x,r. ' - - - r �, 6 bpi t li=st G it r!s tto Et'f�` efk. � r��h t.,,, t.�a.mot+ tor ,i. mef rt�ep+ c�}f� P .�i,= �! ,q4;,3141.0+4,.:. sensors E ,E_'{ �. a '� ,3 'a y `₹i,4L.,,,f� -.. l' NOTE: COMPLETION OF INFORMATION IN SHADED AREA OF THIS FORM IS OPTIONAL Operating Permit Application CONTROL EQUIPMENT- CATALYTIC OR THERMAL OXIDATION Form 2000-403 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE Section A 1. Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 4. Unit identification code: 001 5. Control device code: C003 6. Manufacturer and model number: 7. Date placed in service: March 2004 Date last modified: June 2004 8. Describe Oxidation system. Attach a diagram of the system. 9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below. ❑ Documentation attached EITHER the outlet pollutant concentral OR the control efficiency must be provided. Pollutant inlet pollutant t• Outlet pollutant Control Efficiency (%) �1,. concen.tratian .' ₹`� concentration gr/acf pinny;;,. gr/acf ppmv .,...,•,1111., sskou Pollutant Capture. :_ Destruction CO - :r.-: 90 10; Check one: OCatalytic n Thermal oxidizer 11 Discuss how �the-spent catalystrw be, d1red reus or,a .4 � f t} a A 5 ', 1 , .a It- .. 4 n �'I.5.4;:t; r h t r ? t i (-v-n.`✓ c.,il,,,,-.--, ... - a -r Sc gee r p� k -� y 7l -v r� r Wsi d ) 'MV''''',f t !,..s, v.4 i � ..,-� 12 nt % at Yt'{ Tnetionaire eru� S 9 t c; ipY' 4 2tt--81c�b it 0. , • n 4) rat.;,, j.'`,, . a11a �z?t ft �'V'4• z`.• �" r-T a dh 3-W'f ., .:,.r :.a +�� n -gra 9 i i �-,, r' i,.r s'S4ar-ss' h ty�,�- S�,(,� -d ,�.:. ...`fir� a �f�'�i .. �t k"Y r� t k�`r,�� f;, ^su`�m•. � .E3..'}t��`.'a -.�. . t' ,vaf4 ' ari , , ,,- r i it l., .43 � _ . t� i1!¢ ,Q., iii v f" ,,:e,:'iefF xe ,:, 5:'il at "{{ tS �j#�r r t i y,.777 { v ,,v €t4, ; X4.15 fi s n I ' S w > .r-"� Y �b, a:, u iU. mof'the uid Ilya .1 ,,"t wt 4 s L9t�rE 7 l., 2,₹i lm,ti r it 941 e+".,w �, i, is , 4..,. ,Y.,-,‘C-1`.', ore r ; '` r, F t r. -. dz in . f . a₹evice., r ,- .„,,,-,•••,:,..N.."%r-.--. oil ,,,-,, " �_ v.�fro 4 - lf, t,t � 1.;,.):,h.,,, ,,,x ; 4 -i �L t f. ts'�l 3 } Sy `r �� S P (�'� .y. mac ' i �t ;r b 4`.s ,. `� ' le,,...,,,,,....,I I '• r is R'a t1 '';.,,:wit.,(',,,,,' BS �f° �A f� 3. ai `� ' •S•�`::. 1 ,,.C.,..fli i; R t 7 bre n A. ,Q.,l ctl t1A"%�f i1, • g r' - a ,ii' aa. �r ,,„,,,h°':':,''''' .'�e�a SIg e,s i�� ? a i'Y .� , .� may, ,-F,--f- iCi#�'- � . C �h. � �, yip � ��m '��. zr fu i ,-„At;.-,..i:11,43:41,..„,..6. ,,e�JC.e uhf .,,,;,,+0-F44: Section B The following questions must be answered by sources installing new equipment or existing Units which canno document control efficiency of this device by other means. (Catalytic/Thermal dependent on item 10) Cat I � �t 2 r�� . . s f Thermal oxidation 1;3arxefr** - capes u , ,f,t , tiw � b. Operating temperature (°F): Max,,c€ r*.-}i -,7 4, z l a ;4 i Max s * "�{� +t j ^>a''"3t; d A fit . Min �t tai i % $ 'Y b. Combustion chamber volume (ft3)• • x �ro t , t ', > a� t: r b. Maximum gas velocity through the device { �� yl ��` "' .` �g (ft./sec): s , Type of fuel used: �" i'�N �� , , t+ fl ,, , K� ., : b. u .ximum used BTU/Hr 1.a. k i i�ence4in econd .5�°t c'4iA.�,≤" y ,c. '-: b. Residence time (seconds): NOTE: COMPLETION OF INFORMATION IN SHADED AREA OF THIS FORM IS OPTIONAL Operating Permit Application CONTROL EQUIPMENT -CATALYTIC OR THERMAL OXIDATION Form 2000-403 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE Section A 1. Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S002 4. Unit identification code: 002 5. Control device code: C004 6. Manufacturer and model number: 7. Date placed in service: March 2004 Date last modified: June 2004 8. Describe Oxidation system. Attach a d agrani of the system. 9. List the pollutants to be controlled by this equipment and the expected control efficiency for each pollutant on the table below. 0 Documentation attached EITHER the outlet pollutant concentratio OR the control efficiency must be provided Pollutant llut. f , Outlet pollutant Control Efficiency (%) i'�ttatiO - i ' concentration '� 41. i Ah gr/acf ppmv - 1, Pollutant ` . Destruction 71j .'t 1 90 CO2iy 1i . I ' 'i 11 • © • • 1 11 1 •1 11. Discuss how;"itlle spec •f.s, t,s " a h i s `a'1 l rt' i'* '®1 t+ i k ti x t A1,0"..',,If i r ,, t [� s a R -Ft i, 'x: 12 'prep', ' €c f5i4I1 .ii.'.`:).,�� ` 1, , tki .5''11 7 i .aF.�l have t :se sup i, s /, N 1,. , tr :„ i'&' -•, , --,,,4,-,,,:-.1,4 d3.v al& .s v1.r *e�f tr '. '',.,!1',1-14t4.' * `=4','T a t .,;!...1�jj a.., rt8 cry t t ,6t tt ,31 2- r.i Used `' *:443,-,A4'.','.Mk rr 4� 4 L{ N' '�5 ,:.<1;11,54..�''`i°+ t 0. }(..ni q L' °4'�E' )' P t 9 Sureili eegwroc'.iliregr?kti ',1`44t i _' l'� 1xrjtTt ,.•6••.,:‘,..t...t9tlt-.R ii -4,;- .,7+.a`- .:'''f R i.'1, -' .. �' t .-t t= z 4 • {�a v�4.,a �t lr�r�A''e��+'y�f�"zx} � .��` `t�:,�+.{3= a 1, g 5 ',, t, . 4:11`• p ';.a9a�SI0Y`1 r .E' d 1.-r r:�`a4 repla . ' :str '4 .,;" �� „� , fltIlGtltala �'19 1 1 a. Ri�a ; 1 ,'t3t. a. . y llr & Section B The following questions must be answered by sources installing new equipment or existing Units which cannot document control efficiency of this device b other means. (Catalytic/Thermal dependent on item 10) ' Mi F Thermal oxidation otdenrif n{ ty ::, r, '� ti b Operating temperature (°F): � Fu�rr� ` Max Min Flax, t i„ /.sb r t�� 14a. + s 1 1,A<JT fl t J'` b. Combustion chamber volume (ft3): 15a- :Cray ` Mty,s n '-+;.--(77- ,t1....:' ' �� b. Maximum gas velocity through the device ;. (ft./sec): condtfxpns�( � � .- �.. �,�_�, g��, z - �� l ta- ,. .t i t a O = rrd �� 1 b. Type of fuel used: "',, `. `7`— Maximum fuel used BTU/Hr f.44/011,4$ ; R � " � _ '` , . b. Residence time (seconds): X<. NOTE: COMPLETION OF INFORMATION IN SHADED AREA OF THIS FORM IS OPTIONAL FORMS 2000-500 Operating Permit Application COMPLIANCE CERTIFICATION-MONITORING AND REPORTING FORM 2000-500 Colorado Department of Public Health and Environment DESCRIPTION OF METHODS USED Rev 06-95 Air Pollution Control Division FOR DETERMINING COMPLIANCE All applicants are required to certify compliance with all applicable air pollution permit requirements by including a statement within the permit application of the methods used for determining compliance. This statement must include a description of the monitoring, recordkeeping, and reporting requirements and test methods. In addition, the application must include a schedule for compliance certification submittals during the permit term. These submittals must be no less frequent than annually, and may need to be more frequent if specified by the underlying applicable requirement or by the Division. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 4. Unit identification code: 001 5. For this Unit the following method(s) for determining compliance with the requirements of the permit will be used (check all that apply and attach the appropriate form(s)to this form). / Continuous Emission Monitoring (CEM) - Form 2000-501 Pollutant(s): NOR, CO and O2 0 Periodic Emission Monitoring Using Portable Monitors - Form 2000-502 Pollutant(s): 0 Monitoring Control System Parameters or Operating Parameters of a Process - Form 2000-503 Pollutant(s): 0 Monitoring Maintenance Procedures - Form 2000-504 Pollutant(s): • 0 Stack Testing - Form 2000-505 Pollutant(s Fuel Sampling and Analysis (FSA) - Form 2000-506 Pollutant(s): ✓ Recordkeeping - Form 2000-507 Pollutant(s): Fuel Usage, NO., CO and O2 ✓ Other(please describe) - Form 2000-508 Pollutant(s): Opacity 6. Compliance certification reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 12 months thereafter. (12 month maximum interval) Compliance monitoring reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (6 month maximum interval) NOTE: EACH APPLICABLE REQUIREMENT ON FORM 2000-604 NEEDS TO BE SPECIFICALLY ADDRESSED IN ITEM 5. Operating Permit Application COMPLIANCE CERTIFICATION-MONITORING AND REPORTING FORM 2000-500 Colorado Department of Public Health and Environment DESCRIPTION OF METHODS USED Rev 06-95 Air Pollution Control Division FOR DETERMINING COMPLIANCE All applicants are required to certify compliance with all applicable air pollution permit requirements by including a statement within the permit application of the methods used for determining compliance. This statement must include a description of the monitoring, recordkeeping, and reporting requirements and test methods. In addition, the application must include a schedule for compliance certification submittals during the permit term. These submittals must be no less frequent than annually, and may need to be more frequent if specified by the underlying applicable requirement or by the Division. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S002 4. Unit identification code: 002 5. For this Unit the following method(s) for determining compliance with the requirements of the permit will be used (check all that apply and attach the appropriate form(s) to this form). ✓ Continuous Emission Monitoring (CEM) - Form 2000-501 Pollutant(s): NOR, CO and 02 0 Periodic Emission Monitoring Using Portable Monitors- Form 2000-502 Pollutant(s): 0 Monitoring Control System Parameters or Operating Parameters of a Process - Form 2000-503 Pollutant(s): 0 Monitoring Maintenance Procedures- Form 2000-504 Pollutant(s): 0 Stack Testing- Form 2000-505 Pollutant(s Fuel Sampling and Analysis (FSA) - Form 2000-506 Pollutant(s): ✓ Recordkeeping - Form 2000-507 Pollutant(s): Fuel Usage, NOx, CO and 02, ✓ Other(please describe) - Form 2000-508 Pollutant(s): Opacity 6. Compliance certification reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 12 months thereafter. (12 month maximum interval) Compliance monitoring reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (6 month maximum interval) NOTE: EACH APPLICABLE REQUIREMENT ON FORM 2000-604 NEEDS TO BE SPECIFICALLY ADDRESSED IN ITEM 5. Operating Permit Application COMPLIANCE CERTIFICATION - MONITORING AND REPORTING FORM 2000-500 Colorado Department of Public Health and Environment DESCRIPTION OF METHODS USED Rev 06-95 Air Pollution Control Division FOR DETERMINING COMPLIANCE All applicants are required to certify compliance with all applicable air pollution permit requirements by including a statement within the permit application of the methods used for determining compliance. This statement must include a description of the monitoring, recordkeeping, and reporting requirements and test methods. In addition, the application must include a schedule for compliance certification submittals during the permit term. These submittals must be no less frequent than annually, and may need to be more frequent if specified by the underlying applicable requirement or by the Division. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S003 4. Unit identification code:003 5. For this Unit the following method(s) for determining compliance with the requirements of the permit will be used (check all that apply and attach the appropriate form(s) to this form). 0 Continuous Emission Monitoring (CEM) - Form 2000-501 Pollutant(s): 0 Periodic Emission Monitoring Using Portable Monitors-Form 2000-502 Pollutant(s): 0 Monitoring Control System Parameters or Operating Parameters of a Process -Form 2000-503 Pollutant(s): 0 Monitoring Maintenance Procedures- Form 2000-504 Pollutant(s): 0 Stack Testing - Form 2000-505 Pollutant(s 0 Fuel Sampling and Analysis (FSA) - Form 2000-506 Pollutant(s): ✓ Recordkeeping - Form 2000-507 Pollutant(s): Fuel Usage, hours of operation V Other(please describe) - Form 2000-508 Pollutant(s): 6. Compliance certification reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (12 month maximum interval) Compliance monitoring reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (6 month maximum interval) NOTE: EACH APPLICABLE REQUIREMENT ON FORM 2000-604 NEEDS TO BE SPECIFICALLY ADDRESSED IN ITEM 5. Operating Permit Application COMPLIANCE CERTIFICATION- MONITORING AND REPORTING FORM 2000-500 Colorado Department of Public Health and Environment DESCRIPTION OF METHODS USED Rev 06-95 Air Pollution Control Division FOR DETERMINING COMPLIANCE All applicants are required to certify compliance with all applicable air pollution permit requirements by including a statement within the permit application of the methods used for determining compliance. This statement must include a description of the monitoring, recordkeeping, and reporting requirements and test methods. In addition, the application must include a schedule for compliance certification submittals during the permit term. These submittals must be no less frequent than annually, and may need to be more frequent if specified by the underlying applicable requirement or by the Division. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name Rocky Mountain Energy Center 2. Facility identification code: CO 12 3 1 3 4 2 3. Stack identification code: S004 4. Unit identification code: 004 5. For this Unit the following method(s) for determining compliance with the requirements of the permit will be used (check all that apply and attach the appropriate form(s) to this form). 0 Continuous Emission Monitoring (CEM) - Form 2000-501 Pollutant(s): 0 Periodic Emission Monitoring Using Portable Monitors- Form 2000-502 Pollutant(s): 0 Monitoring Control System Parameters or Operating Parameters of a Process- Form 2000-503 Pollutant(s): 0 Monitoring Maintenance Procedures - Form 2000-504 Pollutant(s): ✓ Stack Testing - Form 2000-505 Pollutant(s): NOR, CO, VOC, PM & 502 0 Fuel Sampling and Analysis (FSA)- Form 2000-506 Pollutant(s): ✓ Recordkeeping - Form 2000-507 Pollutant(s): Fuel Usage, hours of operation ✓Other(please describe) - Form 2000-508 Pollutant(s): 6. Compliance certification reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (12 month maximum interval) Compliance monitoring reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (6 month maximum interval) NOTE: EACH APPLICABLE REQUIREMENT ON FORM 2000-604 NEEDS TO BE SPECIFICALLY ADDRESSED IN ITEM 5. Operating Permit Application COMPLIANCE CERTIFICATION-MONITORING AND REPORTING FORM 2000-500 Colorado Department of Public Health and Environment DESCRIPTION OF METHODS USED Rev 06-95 Air Pollution Control Division FOR DETERMINING COMPLIANCE All applicants are required to certify compliance with all applicable air pollution permit requirements by including a statement within the permit application of the methods used for determining compliance. This statement must include a description of the monitoring, recordkeeping, and reporting requirements and test methods. In addition, the application must include a schedule for compliance certification submittals during the permit term. These submittals must be no less frequent than annually, and may need to be more frequent if specified by the underlying applicable requirement or by the Division. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S005 4. Unit identification code: 005 5. For this Unit the following method(s) for determining compliance with the requirements of the permit will be used (check all that apply and attach the appropriate form(s) to this form). 0 Continuous Emission Monitoring (CEM) - Form 2000-501 Pollutant(s): 0 Periodic Emission Monitoring Using Portable Monitors - Form 2000-502 Pollutant(s): D Monitoring Control System Parameters or Operating Parameters of a Process- Form 2000-503 Pollutant(s): 0 Monitoring Maintenance Procedures- Form 2000-504 Pollutant(s): 0 Stack Testing - Form 2000-505 Pollutant(s 0 Fuel Sampling and Analysis (FSA) - Form 2000-506 Pollutant(s): V Recordkeeping - Form 2000-507 Pollutant(s): Fuel Usage, hours of operation ✓ Other(please describe) - Form 2000-508 Pollutant(s): 6. Compliance certification reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (12 month maximum interval) Compliance monitoring reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (6 month maximum interval) NOTE: EACH APPLICABLE REQUIREMENT ON FORM 2000-604 NEEDS TO BE SPECIFICALLY ADDRESSED IN ITEM 5. Operating Permit Application COMPLIANCE CERTIFICATION - MONITORING AND REPORTING FORM 2000-500 Colorado Department of Public Health and Environment DESCRIPTION OF METHODS USED Rev 06-95 Air Pollution Control Division FOR DETERMINING COMPLIANCE All applicants are required to certify compliance with all applicable air pollution permit requirements by including a statement within the permit application of the methods used for determining compliance. This statement must include a description of the monitoring, recordkeeping, and reporting requirements and test methods. In addition, the application must include a schedule for compliance certification submittals during the permit term. These submittals must be no less frequent than annually, and may need to be more frequent if specified by the underlying applicable requirement or by the Division. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S006 4. Unit identification code: 006 5. For this Unit the following method(s) for determining compliance with the requirements of the permit will be used (check all that apply and attach the appropriate form(s) to this form). 0 Continuous Emission Monitoring (CEM) - Form 2000-501 Pollutant(s): 0 Periodic Emission Monitoring Using Portable Monitors- Form 2000-502 Pollutant(s): 0 Monitoring Control System Parameters or Operating Parameters of a Process - Form 2000-503 Pollutant(s): 0 Monitoring Maintenance Procedures- Form 2000-504 Pollutant(s): 0 Stack Testing- Form 2000-505 Pollutant(s D Fuel Sampling and Analysis (FSA) - Form 2000-506 Pollutant(s): ✓ Recordkeeping -Form 2000-507 Pollutant(s): Pump Design Flow Rate 0 Other (please describe) - Form 2000-508 Pollutant(s): 6. Compliance certification reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (12 month maximum interval) Compliance monitoring reports will be submitted to the Division according to the following schedule: Start date: July 6, 2004 and every 6 months thereafter. (6 month maximum interval) NOTE: EACH APPLICABLE REQUIREMENT ON FORM 2000-604 NEEDS TO BE SPECIFICALLY ADDRESSED IN ITEM 5. Operating Permit Application COMPLIANCE DEMONSTRATION BY FORM 2000-501 Colorado Department of Public Health and Environment CONTINUOUS EMISSION MONITORING Rev 06-95 Mr Pollution Control Division An installation plan for each new(i.e.,proposed)Continuous Emission Monitoring(CEM)system shall be submitted with the permit application for Division approval. Installation plans for existing CEMs are not required to be submitted with the permit application. The installation plan shall contain the following information:the name and address of the source;the source facility identification code;a general description of the process and the control equipment;the pollutant or diluent being monitored;the manufacturer,model number,and serial number of each analyzer;the operating principles of each analyzer; a schematic of the CEM system showing the sample acquisition point and the location of the monitors; and an explanation of any deviations from the siting criteria in Performance Specifications 1,2,3,4,5,6 and 7 in 40 CFR part 60,Appendix B. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 4. Unit identification code: 001 5. Pollutant being monitored: (If other than opacity then item 6 or 7 will be required) CO a. Name of manufacturer: Siemens b. Model & serial number: M/N Ultramat/Oxymat Model 6E, S/N R3-952 c. Is this an existing system ✓ Yes ❑ No d. Implementation date: July 6, 2004 e. Type ❑ In situ✓ Extractive ❑ Dilution ❑ Other (specify) f. Very briefly explain the measurement design concept of the monitor: The ULTRAMAT 6E analyzer uses the NDIR techniques for CO detection. Stack flow rate is calculated using the fuel-specific F-factor from EPA's Method 19. g. Backup system: None h. ✓ The CEM system was certified by the Division on July 6, 2004 . ❑ The CEM system is not certified, but thi certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ✓ The plan is not attached but was submitted to the Division on October 22, 2004 . ❑ The plan will be submitted to the Division by the date shown it our monitoring/compliance plan. Diluent being monitored: See Item 5. above. a. Name of manufacturer: b. Model & serial number: c. Is this an existing system ❑ Yes ❑ No d. Date first placed in service: e. Type ❑ In situ❑ Extractive ❑ 02 ❑ CO2 ❑ Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certificatior package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. 7. Stack Gas Flow: See Item 5. above. a. Name of manufacturer: b. Model & serial number: c. Is this an existing system ❑ Yes ❑ No d. Date first placed in service: Type ❑ Differential pressure ❑ Thermal ❑ Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. Operating Permit Application COMPLIANCE DEMONSTRATION BY FORM 2000-501 Colorado Department of Public Health and Environment CONTINUOUS EMISSION MONITORING Rev 06-95 Air Pollution Control Division An installation plan for each new(i.e.,proposed) Continuous Emission Monitoring(CEM)system shall be submitted with the permit application for Division approval. Installation plans for existing CEMs are not required to be submitted with the permit application. The installation plan shall contain the following information:the name and address of the source;the source facility identification code;a general description of the process and the control equipment;the pollutant or diluent being monitored;the manufacturer,model number,and serial number of each analyzer;the operating principles of each analyzer; a schematic of the CEM system showing the sample acquisition point and the location of the monitors;and an explanation of any deviations from the siting criteria in Performance Specifications 1,2,3,4,5,6 and 7 in 40 CFR part 60,Appendix B. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 0 0 1 1 3 5 4 3. Stack identification code: S001 4. Unit identification code: 001 5. Pollutant being monitored: (If other than opacity then item 6 or 7 will be required) NOx a. Name of manufacturer: Rosemount b. Model & serial number: M/N 951C, S/N U1008049 c. Is this an existing system ✓ Yes ❑ No d. Implementation date: July 6, 2004 e. Type ❑ In situ✓ Extractive ❑ Dilution ❑ Other (specify) f. Very briefly explain the measurement design concept of the monitor: Chemiluminescence. Stack flow rate is calculated using the fuel-specific F-factor from EPA's Method 19. g. Backup system: None h. D The CEM system was certified by the Division on July 6, 2004 . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. V The plan is not attached but was submitted to the Division by October 22, 2004 . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. 6. Diluent being monitored: See Item 5. above. a. Name of manufacturer: b. Model & serial number: c. Is this an existing system❑ Yes ❑ No d. Date first placed in service: Type ❑ In situ❑ Extractive ❑ 02 ❑ C02 ❑ Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certificatior package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. El A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. 7. Stack Gas Flow: See Item 5. above. a. Name of manufacturer: b. Model & serial number: c. Is this an existing system ❑ Yes ❑ No d. Date first placed in service: e. Type ❑ Differential pressure ❑ Thermal ❑ Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. El The plan is not attached but will be submitted to the Division by . ❑ The plan will be submitted to the Division by the date shown in oul monitoring/compliance plan. Operating Permit Application COMPLIANCE DEMONSTRATION BY FORM 2000-501 Colorado Department of Public Health and Environment CONTINUOUS EMISSION MONITORING Rev 06-95 Air Pollution Control Division An installation plan for each new li.e.,proposed)Continuous Emission Monitoring (CEMI system shall be submitted with the permit application for Division approval. Installation plans for existing CEMs are not required to be submitted with the permit application. The installation plan shall contain the following information:the name and address of the source;the source facility identification code; a general description of the process and the control equipment;the pollutant or diluent being monitored;the manufacturer,model number,and serial number of each analyzer;the operating principles of each analyzer;a schematic of the CEM system showing the sample acquisition point and the location of the monitors;and an explanation of any deviations from the siting criteria in Performance Specifications 1,2,3,4,5,6 and 7 in 40 CFR part 60,Appendix B. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 4. Unit identification code: 001 5. Pollutant being monitored: (If other than opacity then item 6 or 7 will be required) 02 a. Name of manufacturer: Ultramat/Oxymat Model 6E b. Model & serial number: M/N 6E, S/N R3-952 c. Is this an existing system ✓ Yes ❑ No d. Implementation date: July 6, 2004 e. Type In situ ✓ Extractive 0 Dilution 0 Other (specify) f. Very briefly explain the measurement design concept of the monitor: The OXYMAT 6E uses the paramagnetic effect of Oxygen (Quinke effect)to make small pressure pulses with an electromagnet which are measured to determine the amount o Oxygen in a process stream. g. Backup system: None h. ✓ The CEM system was certified by the Division on July 6, 2004 . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ✓ The plan is not attached but was submitted to the Division on October 22, 2004 . ❑ The plan will be submitted to the Division by the date shown ii our monitoring/compliance plan. 6. Diluent being monitored: See Item 5. above. a. Name of manufacturer: b. Model & serial number: Is this an existing system 0 Yes 0 No d. Date first placed in service: e. Type 0 In situ❑ Extractive ❑ 02 0 C02 0 Other (specify) f. Describe how the monitor works: g. Backup system: h. 0 The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certificatior package was submitted to the Division on . O The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. 0 The plan is not attached but will be submitted to the Division by . 0 The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. 7. Stack Gas Flow: See Item 5. above. a. Name of manufacturer: b. Model & serial number: c. Is this an existing system ❑ Yes ❑ No d. Date first placed in service: e. Type ❑ Differential pressure ❑ Thermal 0 Other (specify) f. Describe how the monitor works: g. Backup system: h. 0 The CEM system was certified by the Division on . 0 The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by . 0 The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. Operating Permit Application COMPLIANCE DEMONSTRATION BY FORM 2000-501 Colorado Department of Public Health and Environment CONTINUOUS EMISSION MONITORING Rev 06-95 Air Pollution Control Division An installation plan for each new li.e.,proposed)Continuous Emission Monitoring (OEM)system shall be submitted with the permit application for Division approval. Installation plans for existing CEMs are not required to be submitted with the permit application. The installation plan shall contain the following information:the name and address of the source;the source facility identification code; a general description of the process and the control equipment;the pollutant or diluent being monitored;the manufacturer,model number,and serial number of each analyzer;the operating principles of each analyzer; a schematic of the CEM system showing the sample acquisition point and the location of the monitors;and an explanation of any deviations from the siting criteria in Performance Specifications 1,2,3,4,5,6 and 7 in 40 CFR part 60,Appendix B. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 4 . 3. Stack identification code: S002 4. Unit identification code: 002 5. Pollutant being monitored: (If other than opacity then item 6 or 7 will be required) CO a. Name of manufacturer: Siemens b. Model & serial number: Ultrmat/Oxymat M/N 6E, S/N R3-953 c. Is this an existing system ✓ Yes ❑ No d. Implementation date: July 6, 2004 e. Type In situ ✓ Extractive ❑ Dilution ❑ Other (specify) f. Very briefly explain the measurement design concept of the monitor: ULTRAMAT 6E analyzer uses the NDIR techniques for CO detection. Stack flow rate is calculated using the fuel-specific F-factor from EPA's Method 19. g. Backup system: None h. / The CEM system was certified by the Division on July 6, 2004 . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. i. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ✓ The plan is not attached but was submitted to the Division on October 22, 2004 . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. 6. Diluent being monitored: See Item 5. above. a. Name of manufacturer: b. Model & serial number: Is this an existing system ❑ Yes ❑ No d. Date first placed in service: e. Type ❑ In situ❑ Extractive ❑ 02 ❑ CO2 ❑ Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. i. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. 7. Stack Gas Flow: See Item 5. above. a. Name of manufacturer: b. Model & serial number: c. Is this an existing system ❑ Yes ❑ No d. Date first placed in service: e. Type ❑ Differential pressure ❑ Thermal ❑ Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. Operating Permit Application COMPLIANCE DEMONSTRATION BY FORM 2000-501 Colorado Department of Public Health and Environment CONTINUOUS EMISSION MONITORING Rev 06-95 Air Pollution Control Division An installation plan for each new(i.e.,proposed)Continuous Emission Monitoring ICEMI system shall be submitted with the permit application for Division approval. Installation plans for existing CEMs are not required to be submitted with the permit application. The installation plan shall contain the following information:the name and address of the source;the source facility identification code;a general description of the process and the control equipment;the pollutant or diluent being monitored;the manufacturer,model number,and serial number of each analyzer;the operating principles of each analyzer;a schematic of the CEM system showing the sample acquisition point and the location of the monitors; and an explanation of any deviations from the siting criteria in Performance Specifications 1,2,3,4,5,6 and 7 in 40 CFR part 60, Appendix B. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S002 4. Unit identification code: 002 5. Pollutant being monitored: (If other than opacity then item 6 or 7 will be required) NOx a. Name of manufacturer: Rosemont b. Model & serial number: M/N 951C, S/N U1008051 c. Is this an existing system ✓ Yes ❑ No d. Implementation date: July 6, 2004 e. Type In situ ✓ Extractive ❑ Dilution 0 Other (specify) f. Very briefly explain the measurement design concept of the monitor: Chemiluminescence. Stack flow rate is calculated using the fuel-specific F-factor from EPA's Method 19. g. Backup system: None h. V The CEM system was certified by the Division on July 6, 2004 . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ✓ The plan is not attached but was submitted to the Division on October 22, 2004 . ❑ The plan will be submitted to the Division by the date shown ii our monitoring/compliance plan. 6. Diluent being monitored: See Item 5. above. a. Name of manufacturer: b. Model & serial number: c. Is this an existing system ❑ Yes ❑ No d. Date first placed in service: Type ❑ In situ 0 Extractive ❑ 02 ❑ CO2 ❑ Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certificatior package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. i. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by . 0 The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. 7. Stack Gas Flow: See Item 5. above. a. Name of manufacturer: b. Model & serial number: c. Is this an existing system ❑ Yes ❑ No d. Date first placed in service: e. Type ❑ Differential pressure ❑ Thermal ❑ Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. Operating Permit Application COMPLIANCE DEMONSTRATION BY FORM 2000-501 Colorado Department of Public Health and Environment CONTINUOUS EMISSION MONITORING Rev 06-95 Air Pollution Control Division An installation plan for each new (i.e.,proposed)Continuous Emission Monitoring (CEM)system shall be submitted with the permit application for Division approval. Installation plans for existing CEMs are not required to be submitted with the permit application. The installation plan shall contain the following information:the name and address of the source;the source facility identification code; a general description of the process and the control equipment;the pollutant or diluent being monitored;the manufacturer,model number,and serial number of each analyzer; the operating principles of each analyzer; a schematic of the CEM system showing the sample acquisition point and the location of the monitors;and an explanation of any deviations from the siting criteria in Performance Specifications 1,2,3,4,5,6 and 7 in 40 CFR part 60,Appendix B. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S002 4. Unit identification code: 002 5. Pollutant being monitored: (If other than opacity then item 6 or 7 will be required) 02 a. Name of manufacturer: Siemens b. Model & serial number: M/N: Ultramat/Oxymat 6E, S/N R3-953 c. Is this an existing system ✓ Yes ❑ No d. Implementation date: July 6, 2004 e. Type In situ V Extractive ❑ Dilution ❑ Other (specify) f. Very briefly explain the measurement design concept of the monitor: The OXYMAT 6E uses the paramagnetic effect of Oxygen (Quinke effect)to make small pressure pulses with an electromagnet which are measured to determine the amount of Oxygen in a process stream. g. Backup system: None h. ❑ The CEM system was certified by the Division on . V The CEM system is not certified, but the certification package was submitted to the Division on July 6, 2004. ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ✓ The plan is not attached but was submitted to the Division on October 22, 2004 . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. 6. Diluent being monitored: See Item 5. above: Name of manufacturer: b. Model & serial number: Is this an existing system ❑ Yes ❑ No d. Date first placed in service: e. Type ❑ In situ 0 Extractive ❑ O2 ❑ C02 ❑ Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. i. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. 7. Stack Gas Flow: See Item 5. above. a. Name of manufacturer: b. Model & serial number: c. Is this an existing system ❑ Yes ❑ No d. Date first placed in service: e. Type ❑ Differential pressure ❑ Thermal 0 Other (specify) f. Describe how the monitor works: g. Backup system: h. ❑ The CEM system was certified by the Division on . ❑ The CEM system is not certified, but the certification package was submitted to the Division on . ❑ The certification will be submitted to the Division by the date shown in our monitoring/compliance plan. ❑ A CEM system Quality Assurance/Quality Control Plan is attached for Division review. ❑ The plan is not attached but will be submitted to the Division by . ❑ The plan will be submitted to the Division by the date shown in our monitoring/compliance plan. Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-507 Colorado Department of Public Health and Environment BY RECORDKEEPING Rev 06-95 Air Pollution Control Division Recordkeeping may be acceptable as a compliance demonstration method provided that a correlation between the parameter value recorded and the emission rate of a particular pollutant is established in the form of a curve or chart of emission rate versus parameter values. This correlation may constitute the certification of the system. For an existing program, the correlation demonstration must be attached for Division consideration for approval. If the correlation information has not yet been developed, please submit it within 60 days of the startup of the system. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 4. Unit identification code: 001 5. Pollutant(s)being monitored: 6. Material or parameter being monitored and NO„, CO and OZ recorded: Fuel Usage -Natural Gas 7. Method of monitoring and recording (see information on back of this page): CEMs for NO,. CO and O, Fuel meters for fuel useage. 8. List any EPA methods used: 9. Is this an existing method of demonstrating 10. Start date: compliance? ✓Yes ❑ No 11. Backup system: none 12 a. Data collection frequency: ❑ Daily U Weekly ❑ Monthly ❑Batch (not to exceed monthly) / Other- Hourly 12 b. Compliance shall be demonstrated: ❑ Daily U Weekly OMonthly 0 Batch(not to exceed monthly) /Other - Annual 13. Quality Control/Quality Assurance: The monitoring system shall be subject to appropriate performance specifications, calibration requirements, and quality assurance procedures. ✓ A quality assurance/quality control plan for the recordkeeping system is attached for Division review. Plan is not attached but was submitted to CDPHE on October 22, 2004. ❑The plan is not attached, but will be submitted to the Division by 14. ❑ A proposed format for the compliance certification report and excess emission report is attached. ***** The compliance records shall be available for Division inspection. ***** The source shall record any malfunction that causes or may cause an emission limit to be exceeded. ***** Malfunctions shall be reported to the Division the next business day. Hazardous air releases shall be reported to the Division immediately. Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-507 Colorado Department of Public Health and Environment BY RECORDICEEPING Rev 06-95 Air Pollution Control Division Recordkeeping may be acceptable as a compliance demonstration method provided that a correlation between the parameter value recorded and the emission rate of a particular pollutant is established in the form of a curve or chart of emission rate versus parameter values. This correlation may constitute the certification of the system. For an existing program, the correlation demonstration must be attached for Division consideration for approval. If the correlation information has not yet been developed, please submit it within 60 days of the startup of the system. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S002 4. Unit identification code: 002 5. Pollutant(s)being monitored: 7. Material or parameter being monitored and NO„ CO and O2 recorded: Fuel Usage-Natural Gas 7. Method of monitoring and recording (see information on back of this page): CEMs for NO„ CO and O, Fuel meters for fuel useage. 8. List any EPA methods used: 9. Is this an existing method of demonstrating 10. Start date: compliance? ✓ Yes ❑ No 11. Backup system: none 12 a. Data collection frequency: ❑ Daily ❑Weekly 0 Monthly ❑ Batch(not to exceed monthly) ✓ Other- Hourly 12 b. Compliance shall be demonstrated: ❑ Daily 0 Weekly ❑Monthly 0 Batch(not to exceed monthly) /Other— Annual 13. Quality Control/Quality Assurance: The monitoring system shall be subject to appropriate performance specifications, calibration requirements, and quality assurance procedures. ✓ A quality assurance/quality control plan for the recordkeeping system is attached for Division review. Plan is not attached but was submitted to CDPHE on October 22, 2004. 0 The plan is not attached, but will be submitted to the Division by 14. 0 A proposed format for the compliance certification report and excess emission report is attached. ***** The compliance records shall be available for Division inspection. ***** The source shall record any malfunction that causes or may cause an emission limit to be exceeded. ***** Malfunctions shall be reported to the Division the next business day. Hazardous air releases shall be reported to the Division immediately. Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-507 Colorado Department of Public Health and Environment BY RECORDICEEPING Rev 06-95 Air Pollution Control Division Recordkeeping may be acceptable as a compliance demonstration method provided that a correlation between the parameter value recorded and the emission rate of a particular pollutant is established in the form of a curve or chart of emission rate versus parameter values. This correlation may constitute the certification of the system. For an existing program, the correlation demonstration must be attached for Division consideration for approval. If the correlation information has not yet been developed, please submit it within 60 days of the startup of the system. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S003 4. Unit identification code: 003 5. Pollutant(s) being monitored: 8. Material or parameter being monitored and recorded: Fuel Usage -Distillate Fuel Oil 7. Method of monitoring and recording (see information on back of this page): Fuel meters for fuel useage. Counter for Hours of Operation(not to exceed 200 hours per year. • 8. List any EPA methods used: • 9. Is this an existing method of demonstrating 10. Start date: compliance? ✓ Yes ❑ No 11. Backup system: none 12 a. Data collection frequency: ❑ Daily ❑ Weekly 0 Monthly 0 Batch(not to exceed monthly) ✓ Other- Hourly 12 b. Compliance shall be demonstrated: ❑Daily ❑Weekly ❑Monthly ❑ Batch(not to exceed monthly) ✓ Other—Annual 13. Quality Control/Quality Assurance: The monitoring system shall be subject to appropriate performance specifications, calibration requirements, and quality assurance procedures. ✓ A quality assurance/quality control plan for the recordkeeping system is attached for Division review. Plan is not attached but was submitted to CDPHE on October 22, 2004. ❑The plan is not attached, but will be submitted to the Division by 14. ❑ A proposed format for the compliance certification report and excess emission report is attached. ***** The compliance records shall be available for Division inspection. ***** The source shall record any malfunction that causes or may cause an emission limit to be exceeded. ***** Malfunctions shall be reported to the Division the next business day. Hazardous air releases shall be reported to the Division immediately. Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-507 Colorado Department of Public Health and Environment BY RECORDKEEPING Rev 06-95 Air Pollution Control Division Recordkeeping may be acceptable as a compliance demonstration method provided that a correlation between the parameter value recorded and the emission rate of a particular pollutant is established in the form of a curve or chart of emission rate versus parameter values. This correlation may constitute the certification of the system. For an existing program, the correlation demonstration must be attached for Division consideration for approval. If the correlation information has not yet been developed, please submit it within 60 days of the startup of the system. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S004 4. Unit identification code: 004 5. Pollutant(s)being monitored: 9. Material or parameter being monitored and recorded: Fuel Usage -Natural Gas 7. Method of monitoring and recording(see information on back of this page): Fuel meter for fuel useage, Counter for Hours of Operation(not to exceed 1900 hours per year. S. List any EPA methods used: 9. Is this an existing method of demonstrating 10. Start date: compliance? ✓ Yes ❑ No 11. Backup system: none 12 a. Data collection frequency: 0 Daily ❑Weekly ❑ Monthly ❑Batch(not to exceed monthly) ✓ Other- Hourly 12 b. Compliance shall be demonstrated: ❑ Daily ❑Weekly ❑Monthly ❑ Batch(not to exceed monthly) ✓Other— Annual 13. Quality Control/Quality Assurance: The monitoring system shall be subject to appropriate performance specifications, calibration requirements, and quality assurance procedures. V A quality assurance/quality control plan for the recordkeeping system is attached for Division review. Plan is not attached but was submitted to CDPHE on October 22, 2004. ❑The plan is not attached, but will be submitted to the Division by 14. ❑ A proposed format for the compliance certification report and excess emission report is attached. ***** The compliance records shall be available for Division inspection. ***** The source shall record any malfunction that causes or may cause an emission limit to be exceeded. ***** Malfunctions shall be reported to the Division the next business day. Hazardous air releases shall be reported to the Division immediately. Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-507 Colorado Department of Public Health and Environment BY RECORDKEEPING Rev 06-95 Air Pollution Control Division Recordkeeping may be acceptable as a compliance demonstration method provided that a correlation between the parameter value recorded and the emission rate of a particular pollutant is established in the form of a curve or chart of emission rate versus parameter values. This correlation may constitute the certification of the system. For an existing program, the correlation demonstration must be attached for Division consideration for approval. If the correlation information has not yet been developed, please submit it within 60 days of the startup of the system. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S005 4. Unit identification code: 005 5. Pollutant(s) being monitored: 10. Material or parameter being monitored and recorded: Fuel Usage -Natural Gas 7. Method of monitoring and recording (see information on back of this page): Fuel meter for fuel useage, Counter for Hours of Operation (not to exceed 100 hours per year. 8. List any EPA methods used: 9. Is this an existing method of demonstrating 10. Start date: compliance? ✓Yes ❑ No 11. Backup system: none 12 a. Data collection frequency: ❑ Daily ❑Weekly ❑ Monthly ❑Batch(not to exceed monthly) ✓ Other- Hourly 12 b. Compliance shall be demonstrated: ❑ Daily 0 Weekly ❑Monthly ❑ Batch (not to exceed monthly) /Other- Annual 13. Quality Control/Quality Assurance: The monitoring system shall be subject to appropriate performance specifications, calibration requirements, and quality assurance procedures. / A quality assurance/quality control plan for the recordkeeping system is attached for Division review. Plan is not attached but was submitted to CDPHE on October 22, 2004. ❑The plan is not attached, but will be submitted to the Division by 14. ❑ A proposed format for the compliance certification report and excess emission report is attached. ***** The compliance records shall be available for Division inspection. ***** The source shall record any malfunction that causes or may cause an emission limit to be exceeded. ***** Malfunctions shall be reported to the Division the next business day. Hazardous air releases shall be reported to the Division immediately. Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-507 Colorado Department of Public Health and Environment BY RECORDKEEPING Rev 06-95 Air Pollution Control Division Recordkeeping may be acceptable as a compliance demonstration method provided that a correlation between the parameter value recorded and the emission rate of a particular pollutant is established in the form of a curve or chart of emission rate versus parameter values. This correlation may constitute the certification of the system. For an existing program, the correlation demonstration must be attached for Division consideration for approval. If the correlation information has not yet been developed, please submit it within 60 days of the startup of the system. SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S006 4. Unit identification code: 006 5. Pollutant(s)being monitored: 11. Material or parameter being monitored and recorded: Fuel Usage-Distillate Fuel Oil 7. Method of monitoring and recording (see information on back of this page): Design of Circulating Water Pumps. 8. List any EPA methods used: 9. Is this an existing method of demonstrating 10. Start date: compliance? ✓ Yes ❑ No 11. Backup system: none 12 a. Data collection frequency: ❑ Daily 0 Weekly 0 Monthly O Batch(not to exceed monthly) ✓ Other- None 12 b. Compliance shall be demonstrated: ❑ Daily 0 Weekly []Monthly O Batch(not to exceed monthly) /Other- Design 13. Quality Control/Quality Assurance: The monitoring system shall be subject to appropriate performance specifications, calibration requirements, and quality assurance procedures. ✓ A quality assurance/quality control plan for the recordkeeping system is attached for Division review. Plan is not attached but was submitted to CDPHE on October 22, 2004. O The plan is not attached, but will be submitted to the Division by 14. 0 A proposed format for the compliance certification report and excess emission report is attached. ***** The compliance records shall be available for Division inspection. ***** The source shall record any malfunction that causes or may cause an emission limit to be exceeded. ***** Malfunctions shall be reported to the Division the next business day. Hazardous air releases shall be reported to the Division immediately. Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-508 Colorado Department of Public Health and Environment BY OTHER METHODS Rev 06-95 Air Pollution Control Division 1. Facility Name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 4. Unit Identification code: 001 5. Pollutant(s) or Parameter(s) being monitored: Opacity 6. Description of the method of monitoring: EPA Method 9 (40 CFR 60, Appendix A) • 7. Compliance shall be demonstrated: (Specify the frequency with which compliance will be demonstrated) Initially Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-50S Colorado Department of Public Health and Environment BY OTHER METHODS Rev 06-95 Air Pollution Control Division 1. Facility Name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S002 4. Unit Identification code: 002 5. Pollutant(s)or Parameter(s) being monitored: Opacity 6. Description of the method of monitoring: EPA Method 9 (40 CFR 60, Appendix A) 7. Compliance shall be demonstrated: (Specify the frequency with which compliance will be demonstrated) Initially Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-508 Colorado Department of Public Health and Environment BY OTHER METHODS Rev 06-95 Air Pollution Control Division 1. Facility Name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S003 4. Unit Identification code: 003 5. Pollutant(s)or Parameter(s) being monitored: Opacity 6. Description of the method of monitoring: EPA Method 9 (40 CFR 60, Appendix A) 7. Compliance shall be demonstrated: (Specify the frequency with which compliance will be demonstrated) As needed. Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-508 Colorado Department of Public Health and Environment BY OTHER METHODS Rev 06-95 Air Pollution Control Division 1. Facility Name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S004 4. Unit Identification code: 004 5. Pollutant(s) or Parameter(s) being monitored: Opacity 6. Description of the method of monitoring: EPA Method 9 (40 CFR 60, Appendix A) 7. Compliance shall be demonstrated: (Specify the frequency with which compliance will be demonstrated) Initially Operating Permit Application COMPLIANCE DEMONSTRATION FORM 2000-508 Colorado Department of Public Health and Enviromnent BY OTHER METHODS Rev 06-95 Air Pollution Control Division 1. Facility Name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 13 4 2 3. Stack identification code: 5005 4. Unit Identification code: 005 5. Pollutant(s)or Parameter(s) being monitored: Opacity 6. Description of the method of monitoring: EPA Method 9 (40 CFR 60, Appendix A) • 7. Compliance shall be demonstrated: (Specify the frequency with which compliance will be demonstrated) As needed. FORMS 2000-600 Operating Permit Application EMISSION UNIT HAZARDOUS AIR POLLUTANTS FORM 2000-600 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 4. Unit identification code: 001 5. Unit material description: Burning Natural Gas 6. Complete the following summary of hazardous air emissions from this unit. Attach all calculations and emission factor references. Attached D Actual Emissions Data is for calendar year 19 Pollutant CAS Common or Generic r' f},! , Allowable OR r. Potential to emit Pollutant Name rtt lt, 1,f [f r. Quantity Measurement r, Units a itV t r sicP '� :. t ti::s _:u TPY 75-07-0 Acetaldehyde }-'` �`" -. 0.56 TPY ja. i " z 107-02-8 Acrolein '` ` - "rT4 ' ` V 't E', 0.05 TPY 7664-41-7 Ammonia 114.96 TPY 71-43-2 Benzene �yc , r .. 0.11 TPY 108-99-00 1,3 Butadiene .7',7:41124-4,,,x,--' z 2 , `r cp.i ii- },4, 0.00104 TPY ry i.11=:-44,t. o + 100-41-4 Ethylbenzene +r" F ° F :, 0.15 TPY 50-00-0 Formaldehyde °''''Tr! y 5 R,N` .:5" t ' 0.90 TPY { 110-54-3 Hexane1 q, F ` `' 12.11 TPY o ! 91-20-3 Naphthalene gig. `'� •••04M ,, -� P �, -. ,kx��J 0.0135 TPY PAH (5) 'a , r^t ., —$, c lam, �'s . 0.00538 TPY pC a A Propylene 5 is ri-�.r r`� TPY C` (p 6.28 75-56-9 Propylene oxides y 4'a k` 0.39 TPY 108-88-3 Toluene ` H ' ` ` a� i"a` ' 0.58 TPY 108-38-3 Xylene A1+'�` t `"`�", ' 0.21 TPY 'a., i,A ,h-7 4 ° ,i r,3 ii r + 1, TPY . F .y `t hf ! s rte. F',..,;1`1',2 ^ �1, .. { i + }z F,. TPY rho, :e4.4 ��t}l.4,:z. "PF��gy��' kr ,.. 5 �� TPY ! 'i�r7;r.:; t,,;f' t4 i• TPY i 1 .0.7gtr § TPY 4 ₹.¢ t'r',i ,,I ,7 TPY a4' t ` Axi,₹,trr. ,, 'ttpp,p El TPY 1. It }tv... 4* �. ,a tA}d f�� t -;,'1.,'-`,44- 11:-;''.y : TPY NOTE: If there is a permit for this unit, the permit limits are the same as the potential to emit. Operating Permit Application EMISSION UNIT HAZARDOUS AIR POLLUTANTS FORM 2000-600 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: 5002 4. Unit identification code: 002 5. Unit material description: Burning Natural Gas 6. Complete the following summary of hazardous air emissions from this unit. Attach all calculations and emission factor references. Attached❑ :Actual Emissions Date 1stig_ alcndar�ear_19 Pollutant CAS Common or Generic ' ` r:i + rti t ;r " 'i Allowable OR t"�. f x� a 4' Potential to emit # ! .k(:':-:ti. ;` i 'axe til Pollutant Name ,aa4 "I Quantity Measurement a ,a s`t`d Units s 'str ' tN TPY 75-07-0 Acetaldehyde ₹` � t t. 0.56 TPY 107-02-8 Acrolein lv s t t ;;: . T 0.05 TPY spit i .. -:!rti4" :,,• ✓ a*" r: 114.96 TPY 7664-41-7 Ammonia ,:t „mot .4,7atstri4.3.L'oF2ttei.<43,1%;:i4rre,i'llkr.. :4 pCrrrt eiMwYM t ti 71-43-2 Benzenes 0.11 TPY 108-99-001,3Butadiene 2 0.00104 TPY 100-41-4 Ethylbenzene ref t x 4',51z t : it 0.15 TPY k g�si vt w �"Ir }tg'" "in±�I . 50-00-0 Formaldehyde r . 0.90 TPY 110-54-3 Hexane 2.11 TPY 91-20-3 Naphthalene _ 0.0135 TPY k9:� k ca vn:qpM wrt 7§'F*e;fz x a H'f e PAH (5) t,ezM„L 8 a 0.00538 TPY ttfitNPN+ ' r d (tF5".'4 Propylene > r " 6.28 TPY 75-56-9 Propylene oxider3 N I 0.39 TPY 3iitta 4 ti ear nt i,sf, 0.58 TPY 108-88-3 Toluene ^t t z , 108-38-3 XyleneV?: a a 0.21 TPY ' ` sA ;„r -td ,-t n• irn TPY ktd t� i Ncitt ;$5:1 '• r; r wt n;^Mnua 4 * t TPY ., ; g TPY r ,ti E",k" rt₹v tF," {* r� TPY a R r TPY ` Ppt' w i r r. TPY (� Y, *1 - , ',7',...,,-... v TPY �y - i""— i•t te''�p'Sr Lsrt 'js" s TPY r *o, .. 4 ,,,,.s ,-,t w , the potential to emit. NOTE: If there nit is a permit for this u , the permit limits are the same as Operating Permit Application EMISSION UNIT HAZARDOUS AIR POLLUTANTS FORM 2000-600 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S003 4. Unit identification code: 003 5. Unit material description: Burning Distillate Fuel Oil 6. Complete the following summary of hazardous air emissions from this unit. Attach all calculations and emission factor references. Attached ❑ Actual Emissions Data is_fi» calendar}t,u_ 19 Pollutant CAS Common or Generic ' 4'.; " ` ^• s a • . Allowable OR Potential to emit Pollutant Name a, Quantity Measurement ' 14 i4s': ,t , € rt ,t f ii `s e Units t °` za -#se .7 ate. C'K'yl v y'4pW 4£/'f s£ 1 > , ° TPY IMVIt: t. 1 ai r• to None Above Bin Reporting Levels .- r x' , e. ,yta TPY :. :. ' s�w � "yam a � TPY sFN` ' , TPY i.s .tzt i' rar k • b r ^ TPY t " � - r y TPY okra 'q ':+ vi T17v77)y7 ' , 4' r a%is, s+ s via. a M.x.. ..., TPY ifn > .4n TPY 4�" Ik! -. : :. TPY �, sit'' 'xv{..,,`T . ,, N . < _6°9": TPY "�j ,"1n `� .,r TPY "�. }� ' ;t �" TPY <°ii' b'�r P >Ea5 &a • �, TPY � � �xIT Y art TPY £ �.Y^ d F v§ S� 4a i" : . TPY + 'C' sgx`�i , x �" �, a3 ,... " , a a TPY rz � * IGsr TPY °txs ` s v r ,.f`"e ,3x z5�r"r''.= TPY P' ." ;` x`k: TPY TPY rgi77,-.:-.7.7,. ..,......?..,...- rs v' TPY &.eua rl;. a as °r. D7..;;;;'„.,x't" :....:,...:i.-. 3., ,,_ �r' °t s +!..),,.....".;;;:....--;.,::.': 't '.`- �'vi. TPY '' ;;x _ , ,mss rte. r ` t, a*-n x �#r `V Y+ gym TPY NOTE: If there is a permit for this unit, the permit limits are the same as the potential to emit. Operating Permit Application EMISSION UNIT HAZARDOUS AIR POLLUTANTS FORM 2000-600 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S004 4. Unit identification code: 004 5. Unit material description: Burning Natural Gas 6. Complete the following summary of hazardous air emissions from this unit. Attach all calculations and emission factor references. Attached 0 Actual EmissionsData is for calendarsca≤ RI Pollutant CAS Common or Generic a r;y- Allowable OR a Potential to emit Pollutant Name r Quantity Measurement Units TPY ? ;r None Above Bin Reporting Levels ` - =F a ,:-;:-.,/: -.:,-ATPY TPY F- TPY l.a 'Ir:?: a`F ?":-/:,.,:?7,..,;:"4.; l' i �_ pTPY .P :,' i c; iz , pfir ,�jlt#i'it ., ri 7° }1 TPY '�„ 1 TPY Li?:-...'5 a x a TPY �k ta 7 k r�.r� t ' r 3rh' :2::.t:',-,' 4 TPY < TPY f =t t TPY t � t ,i Mq TPY :a TPY TPY TPY TPY 6 � i r .., TPY v TPY -' � ,P . TPY r v TPY i ti TPY a [ �r u TPY tJ {s JY 11s vn 7 y. t 13u."y TPY a p z= . ,� 85 NOTE: If there is a permit for this unit, the permit limits are the same as the potential to emit. Operating Permit Application EMISSION UNIT HAZARDOUS AIR POLLUTANTS FORM 2000-600 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: COI 2 3 1 3 4 2 3. Stack identification code: S005 4. Unit identification code: 005 5. Unit material description: Burning Distillate Fuel Oil 6. Complete the following summary of hazardous air emissions from this unit. Attach all calculations and em scion factor references. Attached❑ ?ctual Emissions Dalai fincalendar year 19 Pollutant CAS Common or Generic x.y aw s Is �n t Allowable OR Potential to emit Pollutant Name a r t ' Quantity Measurement tta` :r: siti Units ,je� kl t��yye,r�,. ,'t ? ��v TPY . nt . :1;..,”:.-..1",„.1..-?t, �� None Above Bin Reporting Levels 4.;14 1 $k 1 . .- TPY ref, -'A 6n "� '� TPY o' r b of ",� r yll�, '� 5x� s mu i TPY "'"tp � v y is' eizrei s TPY "r ,yryhy . �. ,r�l,�i=.,�4w. 4.sv,°" }. TPY .fir TPY t, 's-.�. 'r - e k -s "'". "� .n TPY Itr e '..a ` :I3_ .w.:::-.1ar...i.....Tt s"�.��.,. nZ r ' i Ni" TPY +31,'.i .4.14,.c\ ,,?,j�l.,,It'll ,-,,' tto 'i S `t i '. yet : �,a- .�. a r e+ ,.�e" TPY s °''7 it,om }� H1q ...C* °�. , TPY _h ' `'.1 k ", r''', ,� av TPY iq is xr 3..dr t'x' * +e S4 TPY 4 ' Y .. ..fit �4a v4 G ,i TPY 4 , ate, g it TPY rt#araJ ,:'i�r`,'.n4,xarrts.t-4,:44 ixirr t' sti :rEm,, nvs « TPY te ; ' TPY 1M4III 4 Il'iiraaix m.. '` : s1 I 4( TPY T,p ft�S 4 &,Ali 4'IS :i, ! °t a t TPY 1 SsL °4 ”r TPY Ip dYwrf pt� l ilrx .4 TPY Ilid ₹ k a ; I r d TPY trt. xl ;.9i Ili-, ;" fl xr =,i ,P r1.,; . " i,�,#.�^',^.+ n. TPY sxi:x .. FN,t NOTE: If there is a permit for this unit, the permit limits are the same as the potential to emit. Operating Permit Application EMISSION UNIT HAZARDOUS AIR POLLUTANTS FORM 2000-600 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 4 3. Stack identification code: S006 4. Unit identification code: 006 5. Unit material description: Water 6. Complete the following summary of hazardous air emissions from this unit. Attach all calculations and emission factor references. Attached ❑ Actual Emissions Data is forealendaryear_19 Pollutant CAS Common or Generic M 1 .1/' , Allowable OR Potential to emit Pollutant Name hR l` Quantity Measurement s :rt ;t ; Units 7664-41-7 Ammonia �„ utligl Nl 0.00137 TPY „ m� TPY ts. 7 'rr i4 rr , ',iv il a .^i TPY h i'ri 4 ;r� t + ; ; ilq TPY v 4^ro 9 . ` TPY ra ....„:"A TPY TPY 'ry TPY } & ,„P # TPY ' TPY x TPY lG tisi i 0. l� Mtn ; iii 4"" 'Np .rmo . TPY TPY iP 3 3xv ':1_,'.7.' ' TPY a r` TPY •- TPY :v r ,t iP. r r. ? TPY . ., n xr TPY ru' �,l 4,' „ +++1.41? TPY TPY rv , grof m TPY +.1.:+,;,:,'.1,4++4,+.+,';',. it 5: , � r '�5't ill '..e.:-.++14+1;"11+ P tt t, t'Hr t: rt%,;, „p tx +,4 i, TPY t `,i �t TPY "fi{.,,,yr.r.aa m,.,,.- ire. ,-;,�zw NOTE: If there is a permit for this unit, the permit limits are the same as the potential to emit. Operating Permit Application EMISSION UNIT CRITERIA AIR POLLUTANTS FORM 2000-601 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 J. Stack identification code: S001 4. Unit identification code: 001 5. Complete the following emissions summary for the following pollutants. Attach all calculations and emission factor references. Attached ✓ Air pollutant sza� Potential to emit Maximum allowable TPY Particulates (TSPI 63.4 TPY � PM-10 s 1 . ' .� .4 TPY �+'�°k=r r x „ 63 t ri seh y�r.iAt 1.�.i R C Nitrogen oxides , 120.2 TPY Volatile organic � � 1` compounds l 25.3 TPY P 5 ,gam; , i A hi l.ti' kk yr l A! Carbon monoxide : x r 91.1 TPY ,� ' Lead �° . 4 � � � TPY 4 w Sulfur dioxide €4 ' iti4r1 ( a li If'� 4 5.9 TPY F at , m PCT + >w`§ :s w,c Total reduced sulfur .., x ]t k , 9 TPY Reduced sulfur E ` �� " TPY ompounds • 1 Hydrogen sulfide TPY Fcr'III i w.giLy f< a1 r i 4r ,a Sulfuric Acid Mist t: r TPY Fluorides 6 TPY ��t{ vita vn`rvi , t c �_e '1.14 Rfm! TPY '" TPY } : TPY G SF 5 s + " TPY Units (U) should be entered as follows: 1 = lb/hr 2 = Ib/mmBTU 3 = grains/dscf 4 = lb/gallon 5 = ppmdv 6 = gram/HP-hour 7 = lb/mmscf 8 = other(specify) 9 = other (specify) 10 = other(specify) Operating Permit Application EMISSION UNIT CRITERIA AIR POLLUTANTS FORM 2000-601 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 13 4 2 Stack identification code: S002 4. Unit identification code: 002 5. Complete the following emissions summary for the following pollutants. Attach all calculations and emission factor references. Attached ✓ ¢ Air pollutant Potential to emit Maximum allowable U TPY Particulates (TSP) * 63.4 TPY PM-10 r' 63.4 TPY Nitrogen oxides as 120.2 TPY 1s r l' 25.3 TPY Volatile organic r ik compounds `sue i Carbon monoxide s� 91.1 TPY w i ,k a Q � ri TPY Lead k Sulfur dioxide "' z IV i ' 5.9 TPY Total reduced sulfur a TPY Reduced sulfur a # TPY ,mpounds 5Aft,, . _ » a r TPY Hydrogen sulfide Sulfuric Acid Mist f TPY TPY Fluorides TPY TPY frtifilciii TRY TPY Units (U) should be entered as follows: 1 = lb/hr 2 = lb/mmBTU 3 = grains/dscf 4 = lb/gallon 5 = ppmdv 6 = gram/HP-hour 7 = lb/mmscf 8 = other(specify) 9 = other(specify) 10 = other(specify) Operating Permit Application EMISSION UNIT CRITERIA AIR POLLUTANTS FORM 2000-601 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 12 3 13 4 2 Stack identification code: S003 4. Unit identification code: 003 5. Complete the following emissions summary for the following pollutants. Attach all calculations and emission factor references. Attached ✓ Air pollutant M tt> 'r ° =' Potential to emit Maximum allowable t ��xt o f y4 1 U TPY Particulates (TSP) v. * 11 * r 0.01 TPY PM-10 „1, . g u t � ` � 0.01 TPY 1h - �,it Nitrogen oxides • S` •>- 0.236 . iiib f` m TPY J Volatile organic 0.029 TPY compounds • t( °, n e l . Carbon monoxide t ,� - 0.142 TPY �1 Lead • t. i t �L"4 TPY Sulfur dioxide i i 4a 0.0063 TPY Total reduced sulfur laViweiw Vragnitileggay �- "s's( vsanga yl TPY Reduced sulfur TPY TPY impounds t. i , "' t Po r: Hydrogen sulfide °�• �-, '° ityatailiht y i j�c ' r TPY Sulfuric Acid Mist TPY Fluorides i fi&r*„ At O' TPY �Se,te) c i:si P il:r .1), ' rx s(6 r41 u'.` TPY - 4 »d :ry..,ry x to a iv TPY ,, ,,w °'zr"' TPY;;,aarie9b$1:4 414444%)S1 TPY Units (U) should be entered as follows: 1 = lb/hr 2 = Ib/mmBTU 3 = grains/dscf 4 = lb/gallon 5 = ppmdv 6 = gram/HP-hour 7 = lb/mmscf 8 = other(specify) 9 = other (specify) 10 = other(specify) Operating Permit Application EMISSION UNIT CRITERIA AIR POLLUTANTS FORM 2000-601 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 Stack identification code: S004 4. Unit identification code: 004 5. Complete the following emissions summary for the following pollutants. Attach all calculations and emission factor references. Attached ✓ ,z f . Potential to emit Maximum allowable Air pollutant 51: • YZ % s : U TPY Particulates (TSP) 2.28 TPY �" t, `` 2.28 TPY Nitrogen oxides ':;' `+s* a �j� 4.7 TPY �� ,.; Volatile organic 'r ". d ,. t' 0.57 TPY compounds = r 4 'i aim % :f e _ c. Carbon monoxide t•, 2.75 TPY Lead t• " TPY Sulfur dioxide 4. a e �. 0.05 TPY Total reduced sulfur . ;i r TPY s Reduced sulfurklit .,. ;. '€ TPY Impounds 2.._ .�a `x s TPY Hydrogen sulfide ; 7,2.41431. ';-�+r ,Itit "Ca*yam.. TPY Sulfuric Acid Mistaitiatli-4,t x Fluorides ; . §t 'k`1 ry TPY e 1 TPY .., , r kix a.r. '4F t� �' 1,. TPY tsidft '.- 1 -₹p I F�i r 4 tic,,, .c oirs4a'3 s,�'.;' �i TPY iiikife s tom° ° � i' ' •� aM TPY ;744.14Art Units (U) should be entered as follows: 1 = lb/hr 2 = lb/mmBTU 3 = grains/dscf 4 = lb/gallon 5 = ppmdv 6 = gram/HP-hour 7 = Ib/mmscf 8 = other(specify) 9 = other(specify) 10 = other (specify) Operating Permit Application EMISSION UNIT CRITERIA AIR POLLUTANTS FORM 2000-601 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 13 4 2 Stack identification code: S005 4. Unit identification code: 005 5. Complete the following emissions summary for the following pollutants. Attach all calculations and emission factor references. Attached ✓ Air pollutant l '"t , !i'i. ', Potential to emit Maximum allowable "t 'I'' l -x 1 7f Ryy , i.� rw _1 r °"= U TPY 44 'v".bsx4i . ,xepw,,'i'' ..:, Particulates (TS P) `- aria 0.044 TPY r�rt PM-10 '�ar 0.044 TPY Nitrogen oxides '7.'a I ki w 1 x9 4'1". 0.75 TPY Volatile organic t ' f i 0.12 TPY compounds • la ti i Carbon monoxide . 4 # °k ' . 2.75 TPY • , I y, , Lead -�- TPY P y Sulfur dioxide p � ra acsa 0.05 TPY nr„itTotal reduced sulfurcfr ,S'I tlSk �t < TPY Reduced sulfuribm l,,�� . Fl TPY Impounds *': 4,- `" ' 5 N 5 rut, �} k° T !� Yi, t"9I{14�1�" Hydrogen sulfide 7: i,� w ,Fiiii ,, , ; TPY ate{... ,;` F 6 °i Sulfuric Acid Mist n `t ,x TPY Fluorides ° t TPY C4 i p *'pf a , ,5;��y.��' §gam'' TPY � ; �, A TPY 9 .,- YN *bSl tl. .iietq i'.�- TPY a v tea . °"" �x 4 TPY Units (U) should be entered as follows: 1 = lb/hr 2 = lb/mmBTU 3 = grains/dscf 4 = lb/gallon 5 = ppmdv 6 = gram/HP-hour 7 = lb/mmscf 8 = other(specify) 9 = other (specify) 10 = other(specify) Operating Permit Application EMISSION UNIT CRITERIA AIR POLLUTANTS FORM 2000-601 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 Stack identification code: S006 4. Unit identification code: 006 5. Complete the following emissions summary for the following pollutants. Attach all calculations and emission factor references. Attached / Air pollutant & yti v Potential to emit Maximum allowable �r < U TPY Particulates (TSP) y t '' * 19.1 TPY 19.1 TPY PM-10t a� u a . $ ai Igrt ! a TPY Nitrogen oxides e ...fit+k rxd P ,.r x r• TPY Volatile organic { compounds re'.i1.114; r faf r ` s f Carbon monoxide l TPY Lead TPY fib d Y Sulfur dioxide ra s TPY Total reduced sulfur TPY Reduced sulfur � � � F� �,a 9t � xtb� ae TPY impounds t-ie 1 *r(ie )rlK. TPY Hydrogen sulfide ", : f kilt ? Sulfuric Acid Mist TPY r k� sc + t i �A rte' s4 , TPY Fluorides , . :f ¢ TPY TPY F � wa g s TPY V . al i l o 4,v TPY Units (U) should be entered as follows: 1 = lb/hr 2 = Ib/mmBTU 3 = grains/dscf 4 = lb/gallon 5 = ppmdv 6 = gram/HP-hour 7 = lb/mmscf 8 = other (specify) 9 = other(specify) 10 = other (specify) Operating Permit Application PLANT-WIDE HAZARDOUS AIR POLLUTANTS FORM 2000-602 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. Complete the following emissions summary for all hazardous air emissions at this facility. Calculations attached. Attach a copy of all calculations to this form. Attached ✓ See Supplemental Information Form 2000-700 Pollutant CAS Common or Generic N r or Itt<s + ' Allowable OR � fig c f °` Potential to emit Pollutant Name � I I z � '.:� Quantity Units " TPY tp "a' m x i ritil. .,..%.0,. ITN til'; p' 75-07-0 Acetaldehyde to y � 1.18 TPY 7664-41-7 Ammonia I "w r I u, ' I , 249.6 TPY II 1� i + 50-00-0 Formaldehyde 1.88 TPY F...:3:44,'..:,.-..:. ...1 t:-? f4;O1C. a .. 75-56-9 Propylene oxide ritit �, yy ,` : .: 0.82 TPY ; ty TPY t tea" TRY 4 fi rt ,imS .,.. TPY .:'u TPY s ta>u l aka TPY P `r.'I E l5 n`".,S-1 w y ., ; TPY idviiie it f, , ~ ,; TPY P ^r4K -� ' g a ��. ,�a� TPY 3c � .. x. TPY 1.,. . #-b Y. . TPY it = `, TPY '''144-4':1 ,I r' TP` Y ..:/:2,/,',;..:1,,,,,,S,"7 + TPY I ‘-`41:47;.4.<0 � [ TPY (ry, Fi c j 4,1 fi�y. . ,y h , x p ' -r-a TPY { dry 5% l. TPY " ' 'ki" `- TPY .t t il4f1. sl ^�, s'I ` z i say a k 8� TPY t "r e Lis #d y •'' TPY i. ill 5-a■ I ,t P 9 i i {'^ ? �� TPY NOTE: If there is a permit for this unit, the permit limits are the same as the potential to emit. Operating Permit Application PLANT-WIDE CRITERIA AIR POLLUTANTS FORM 2000-603 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Complete the following emissions summary for the listed emissions at this facility. Air pollutant t:r µ Potential to emit Maximum allowable !s_ TPY TPY Burning Natural Gas in a" Turbines and Boiler ' M Particulates (TSP) ¢ �t 146.6 NA d � F �x PM-10 ' :. fr 146.6 NA srr Nitrogen oxides .' „ 246.6 NA 3Gy119+' LJJe a Volatile organic compounds g 51.3 NA Carbon monoxide 785.1 NA g ..1 i sa. Lead ry Sulfur dioxide 94 1 4 1 W r , 11.9 NA Total reduced sulfur hr Reduced sulfur compounds #'`per " " Hydrogen sulfide Sulfuric acid mist �3 , p Fluorides 'knee, a l M('l' �p„p 'yi�'�'° tZ� 1 Ya 3` 3 Operating Permit Application APPLICABLE REQUIREMENTS AND FORM 2000404 Colorado Department of Public Health and Environment STATUS OF EMISSION UNIT Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S001 4. Unit identification code: 001 5. Pollutant 6. Colorado Air Quality 7. 8. Limitation 9. Compliance Regulations State Status or Only IN OUT Construction Permit Number PM Reg. 1.III.A.C.c(Section * PE = 0.5(FI)-°2° Smoke and Opacity Reg. 1.II.A.1(Section II.C) <20% Opacity * EPA Method 9 NO, 40 CFR60 Subpart Da PM <0.03 lb/MMBtu * Smoke and Opacity 40 CFR60 Subpart Da <20% Opacity except 1 —6 min <27% per hour NO, 40 CFR60 Subpart Da NO, <0.2 lb/MMBtu SO2 40 CFR60 Subpart Da SO2 <0.2 lb/MMBtu Turbine NO,,CO, VOC and NO, <0.01394 lb/MMBtu PM Control Equipment BACT CO <0.04537 Ib/MMBtu Limits PM <0.00735lb/MMBtu VOC < 0.04537 Ib/MMBtu NO, Reg. 6, Part A, Subpart GG Hourly NO, @15% O2 * <102ppmvd burning NG, Hourly SO2 @15% O2 SO2 Reg. 6, Part A, Subpart GG <150ppmvd or sulfur content, * in fuel < 0.8%v, SO2 Reg. 6, Part B,II,D,3,b *. Hourly SO2<0.35 lb/MMBtu (Section II.D) NO, & CO Permit 02WE0228 Mod 1 * CEMS with QA/QC Plan Odor Reg 2.A.2 * Detection after 15x dilution 10. Other requirements (e.g., malfunction reporting, special operating conditions from an State Only Compliance existing permit such as material usage, hours of operation, etc.) Status IN OUT General Provisions (40 CFR 60 Part A), Subpart Misc. Startup, shutdown excess emission reporting * Permit 02WE0228 Condition 10 Fuel Usage Limit * Permit 02WE0228 Condition 13 Initial Performance Stack Tests APEN Reg.3 Annual Reporting if changed * * ****USE FORM 2000-700 TO EXPLAIN HOW COMPLIANCE WAS DETERMINED FOR EACH APPLICABLE REQUIREMENT**** Operating Permit Application APPLICABLE REQUIREMENTS AND FORM 2000-604 Colorado Department of Public Health and Environment STATUS OF EMISSION UNIT Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S002 4. Unit identification code: 002 5. Pollutant 6. Colorado Air Quality 7. 8. Limitation 9. Compliance Regulations State Status or Only IN OUT Construction Permit Number PM Reg. 1.III.A.1.c(Section * PE = 0.5(F1)-0.26 II.C) <20% Opacity Smoke and Opacity Reg. 1.II.A.1(Section II.C) EPA Method 9 NO, 40 CFR60 Subpart Da PM <0.03 lb/MMBtu <20% Opacity except 1 —6 * Smoke and Opacity 40 CFR60 Subpart Da min <27% per hour NO„ 40 CFR60 Subpart Da NO, <0.2 lb/MMBtu SO2 40 CFR60 Subpart Da SO2< 0.2 lb/MMBtu NO,< <0.01394 lb/MMBtu Turbine NO,t,CO, VOC and CO <0.04537 Ib/MMBtu * PM Control Equipment BACT PM <0.00735 lb/MMBtu Limits VOC <0.04537 Ib/MMBtu Hourly NO„@15% O2 * NOx Reg. 6, Part A, Subpart GG <102ppmvd burning NG, Hourly SO2 @15%O2 SO2 Reg. 6, Part A, Subpart GG <150ppmvd or sulfur content, in fuel < 0.8%w Reg. 6, Part B,II,D,3,b Hourly SO2<0.35 lb/MMBtu SO2 (Section II.D) NO, & CO Permit 02WE0228 Mod 1 * GEMS with QA/QC Plan Odor Reg 2.A.2 * Detection after 15x dilution 10. Other requirements (e.g., malfunction reporting, special operating conditions from an State Only Compliance existing permit such as material usage, hours of operation, etc.) Status IN OUT General Provisions(40 CFR 60 Part A), Subpart Misc. Startup, shutdown excess * emission reporting Permit 02WE0228 Condition 10 Fuel Usage Limit Permit 02WE0228 Condition 13 Initial Performance Stack Tests APEN Reg.3 Annual Reporting if changed ****USE FORM 2000-700 TO EXPLAIN HOW COMPLIANCE WAS DETERMINED FOR EACH APPLICABLE REQUIREMENT**** Operating Permit Application APPLICABLE REQUIREMENTS AND FORM 2000-604 Colorado Department of Public Health and Environment STATUS OF EMISSION UNIT Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Stack identification code: S003 4. Unit identification code: 003 5. Pollutant 6. Colorado Air Quality 7. 8. Limitation 9. Compliance Regulations State Status Or Only IN OUT Construction Permit Number F.O. Fired Engines BACT Limit hours of Operation to * 100 hr/yr Smoke and Opacity Reg. 1.II.A.1(Section II.C) * <20% Opacity * Odor Reg 2.A.2 * Detection after 15x dilution 10. Other requirements (e.g., malfunction reporting, special operating conditions from an State Only Compliance existing permit such as material usage, hours of operation, etc.) Status IN OUT General Provisions Condition 10 (40 CFR 60 Part 1, Subpart A) Misc. Startup, shutdown excess emission reporting Permit 02WE0228 Condition 10 Fuel Usage Limit * APEN Reg.3 Annual Reporting if changed ****USE FORM 2000-700 TO EXPLAIN HOW COMPLIANCE WAS DETERMINED FOR EACH APPLICABLE REQUIREMENT**** Operating Permit Application APPLICABLE REQUIREMENTS AND FORM 2000-604 Colorado Department of Public Health and Environment STATUS OF EMISSION UNIT Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE I. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 13 4 2 3. Stack identification code: 5004 4. Unit identification code: 004 5. Pollutant 6. Colorado Air Quality 7. 8. Limitation 9. Compliance Regulations State Status or Only IN OUT Construction Permit Number PM Reg. 1.III.A.1.c(Section * PE = 0.5(FI)-0s6 * II.C) <20% Opacity Smoke and Opacity Reg. 1.II.A.1(Section II.C) EPA Method 9 NOx 40 CFR60 Subpart Da PM < 0.03 lb/MMBtu Restricted to 1900 hours per Hours of Operation 40 CFR60 Subpart Da year operation 40 CFR 60 Part 1, Subpart Misc. Startup, shutdown * General Provisions A excess emission reporting Odor Reg 2.A.2 * Detection after 15x dilution APEN Reg.3 * Annual Reporting if changed Aux Boiler NOx and CO NOx<0.038 lb/MMBtu * Control Equipment Limits CO <0039 IbIMMBtu BACT . BACT Restricted to 1900 hours per F.O. Fired Engines year operation 10. Other requirements (e.g., malfunction reporting, special operating conditions from an State Only Compliance existing permit such as material usage, hours of operation, etc.) atus IN OUT General Provisions Condition 10 (40 CFR 60 Part 1, Subpart A) Misc. Startup, shutdown excess emission reporting Permit 02W E0228 Condition 10 Fuel Usage Limit APEN Reg.3 Annual Reporting if changed ****USE FORM 2000-700 TO EXPLAIN HOW COMPLIANCE WAS DETERMINED FOR EACH APPLICABLE REQUIREMENT**** Operating Permit Application PERMIT SHIELD PROTECTION FORM 2000-605 Colorado Department of Public Health and Environment IDENTIFICATION Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Specify Emission Source: 001 4. Do not use 5. Pollutant, 6. Colorado Air Quality 7. Equipment, Regulations State or Only Process See Attached Form 2000-700 8. Other requirements (e.g., malfunction reporting, special operating State Only conditions from an existing permit such as material usage, operating hours, etc.) NOTE: REQUESTS FOR THE SHIELD MUST BE FOR A SPECIFIC REQUIREMENT IN THE REGULATIONS. USE FORM 2000-700 TO PROVIDE AN EXPLANATION OF WHY THE SHIELD IS REQUESTED Operating Permit Application PERMIT SHIELD PROTECTION FORM 2000-605 Colorado Department of Public Health and Environment IDENTIFICATION Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE - 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Specify Emission Source: 002 4. Do not use 5. Pollutant, 6. Colorado Air Quality 7. Equipment, Regulations State or Only Process See Attached Form 2000-700 8. Other requirements (e.g., malfunction reporting, special operating State Only conditions from an existing permit such as material usage, operating hours, etc.) NOTE: REQUESTS FOR THE SHIELD MUST BE FOR A SPECIFIC REQUIREMENT IN THE REGULATIONS. USE FORM 2000-700 TO PROVIDE AN EXPLANATION OF WHY THE SHIELD IS REQUESTED Operating Permit Application PERMIT SHIELD PROTECTION FORM 2000-605 Colorado Department of Public Health and Environment IDENTIFICATION Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Specify Emission Source: 003 4. Do not use 5. Pollutant, 6. Colorado Air Quality 7. Equipment, Regulations State or Only Process See Attached Form 2000-700 8. Other requirements (e.g., malfunction reporting, special operating State Only conditions from an existing permit such as material usage, operating hours, etc.) NOTE: REQUESTS FOR THE SHIELD MUST BE FOR A SPECIFIC REQUIREMENT IN THE REGULATIONS. USE FORM 2000-700 TO PROVIDE AN EXPLANATION OF WHY THE SHIELD IS REQUESTED Operating Permit Application PERMIT SHIELD PROTECTION FORM 2000-605 Colorado Department of Public Health and Environment IDENTIFICATION Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Specify Emission Source: 004 4. Do not use 5. Pollutant, 6. Colorado Air Quality 7. Equipment, Regulations State or Only Process See Attached Form 2000-700 8. Other requirements (e.g., malfunction reporting, special operating State Only conditions from an existing permit such as material usage, operating hours, etc.) NOTE: REQUESTS FOR THE SHIELD MUST BE FOR A SPECIFIC REQUIREMENT IN THE REGULATIONS. USE FORM 2000-700 TO PROVIDE AN EXPLANATION OF WHY THE SHIELD IS REQUESTED Operating Permit Application PERMIT SHIELD PROTECTION FORM 2000-605 Colorado Department of Public Health and Environment IDENTIFICATION Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Specify Emission Source: 005 4. Do not use 5. Pollutant, 6. Colorado Air Quality 7. Equipment, Regulations State or Only Process See Attached Form 2000-700 8. Other requirements (e.g., malfunction reporting, special operating State Only conditions from an existing permit such as material usage, operating hours, etc.) NOTE: REQUESTS FOR THE SHIELD MUST BE FOR A SPECIFIC REQUIREMENT IN THE REGULATIONS. USE FORM 2000-700 TO PROVIDE AN EXPLANATION OF WHY THE SHIELD IS REQUESTED Operating Permit Application PERMIT SHIELD PROTECTION FORM 2000-605 Colorado Department of Public Health and Environment IDENTIFICATION Rev 06-95 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO 1 2 3 1 3 4 2 3. Specify Emission Source: 006 4. Do not use 5. Pollutant, 6. Colorado Air Quality 7. Equipment, Regulations State or Only Process See Attached Form 2000-700 8. Other requirements (e.g., malfunction reporting, special operating State Only conditions from an existing permit such as material usage, operating hours, etc.) NOTE: REQUESTS FOR THE SHIELD MUST BE FOR A SPECIFIC REQUIREMENT IN THE REGULATIONS. USE FORM 2000-700 TO PROVIDE AN EXPLANATION OF WHY THE SHIELD IS REQUESTED Operating Permit Application EMISSION UNIT COMPLIANCE PLAN FORM 2000-606 Colorado Department of Public Health and Environment COMMITMENTS AND SCHEDULE 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE .Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 .:enter 3. Stack identification code: S001 4. Unit identification code: 001 5. For Units that are presently in compliance with all applicable requirements, including any monitoring and compliance certification requirements of Colorado Air Quality Regulation 3, Part C that apply, complete the following. These commitments are part of the application for operating permits. ✓ We will continue to operate and maintain this Unit in compliance with all applicable requirements. • ❑ Form 2000-604 includes new requirements that apply or will apply to this Unit during the term of the permit. We will meet such requirements on a timely basis. 6. For Units not presently fully in compliance, complete the following. ❑ This Unit is in compliance with all applicable requirements except for those indicated below. We will achieve compliance according to the following schedule (If more space is needed attach additional copies of Form 2000-700): Applicable Requirement Corrective Actions Deadline III 2. 3. rogress reports will be submitted: Start date: and every six (6) months thereafter Operating Permit Application EMISSION UNIT COMPLIANCE PLAN FORM 2000-606 Colorado Department of Public Health and Environment COMMITMENTS AND SCHEDULE 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE . .Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 Center 3. Stack identification code: S002 4. Unit identification code: 002 5. For Units that are presently in compliance with all applicable requirements, including any monitoring and compliance certification requirements of Colorado Air Quality Regulation 3, Part C that apply, complete the following. These commitments are part of the application for operating permits. ✓ We will continue to operate and maintain this Unit in compliance with all applicable requirements. ❑ Form 2000-604 includes new requirements that apply or will apply to this Unit during the term of the permit. We will meet such requirements on a timely basis. 6. For Units not presently fully in compliance, complete the following. ❑ This Unit is in compliance with all applicable requirements except for those indicated below. We will achieve compliance according to the following schedule (If more space is needed attach additional copies of Form 2000-700): Applicable Requirement Corrective Actions Deadline 2. 3. Progress reports will be submitted: Start date: and every six (6) months thereafter Operating Permit Application EMISSION UNIT COMPLIANCE PLAN FORM 2000-606 Colorado Department of Public Health and Environment COMMITMENTS AND SCHEDULE 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE .Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 Center 3. Stack identification code: S003 4. Unit identification code: 003 5. For Units that are presently in compliance with all applicable requirements, including any monitoring and compliance certification requirements of Colorado Air Quality Regulation 3, Part C that apply, complete the following. These commitments are part of the application for operating permits. ✓ We will continue to operate and maintain this Unit in compliance with all applicable requirements. ❑ Form 2000-604 includes new requirements that apply or will apply to this Unit during the term of the permit. We will meet such requirements on a timely basis. 6. For Units not presently fully in compliance, complete the following. ❑ This Unit is in compliance with all applicable requirements except for those indicated below. We will achieve compliance according to the following schedule (If more space is needed attach additional copies of Form 2000-700): Applicable Requirement Corrective Actions Deadline 2. 3. Progress reports will be submitted: Start date: and every six (6) months thereafter Operating Permit Application EMISSION UNIT COMPLIANCE PLAN FORM 2000-606 Colorado Department of Public Health and Environment COMMITMENTS AND SCHEDULE 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE .Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 Center 3. Stack identification code: S004 4. Unit identification code: 004 5. For Units that are presently in compliance with all applicable requirements, including any monitoring and compliance certification requirements of Colorado Air Quality Regulation 3, Part C that apply, complete the following. These commitments are part of the application for operating permits. ✓ We will continue to operate and maintain this Unit in compliance with all applicable requirements. ❑ Form 2000-604 includes new requirements that apply or will apply to this Unit during the term of the permit. We will meet such requirements on a timely basis. 6. For Units not presently fully in compliance, complete the following. ❑ This Unit is in compliance with all applicable requirements except for those indicated below. We will achieve compliance according to the following schedule (If more space is needed attach additional copies of Form 2000-700): Applicable Requirement Corrective Actions Deadline 2. 3. Progress reports will be submitted: Start date: and every six (6) months thereafter Operating Permit Application EMISSION UNIT COMPLIANCE PLAN FORM 2000-606 Colorado Department of Public Health and Environment COMMITMENTS AND SCHEDULE 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE .Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 Center 3. Stack identification code: S005 4. Unit identification code: 005 5. For Units that are presently in compliance with all applicable requirements, including any monitoring and compliance certification requirements of Colorado Air Quality Regulation 3, Part C that apply, complete the following. These commitments are part of the application for operating permits. ✓ We will continue to operate and maintain this Unit in compliance with all applicable requirements. ❑ Form 2000-604 includes new requirements that apply or will apply to this Unit during the term of the permit. We will meet such requirements on a timely basis. 6. For Units not presently fully in compliance, complete the following. ❑ This Unit is in compliance with all applicable requirements except for those indicated below. We will achieve compliance according to the following schedule (If more space is needed attach additional copies of Form 2000-700): Applicable Requirement Corrective Actions Deadline 2. 3. Progress reports will be submitted: Start date: and every six (6) months thereafter Operating Permit Application EMISSION UNIT COMPLIANCE PLAN FORM 2000-606 Colorado Department of Public Health and Environment COMMITMENTS AND SCHEDULE 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1 .Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 Center 3. Stack identification code: S006 4. Unit identification code: 006 5. For Units that are presently in compliance with all applicable requirements, including any monitoring and compliance certification requirements of Colorado Air Quality Regulation 3, Part C that apply, complete the following. These commitments are part of the application for operating permits. ✓ We will continue to operate and maintain this Unit in compliance with all applicable requirements. ❑ Form 2000-604 includes new requirements that apply or will apply to this Unit during the term of the permit. We will meet such requirements on a timely basis. 6. For Units not presently fully in compliance, complete the following. ❑ This Unit is in compliance with all applicable requirements except for those indicated below. We will achieve compliance according to the following schedule (If more space is needed attach additional copies of Form 2000-700): Applicable Requirement Corrective Actions Deadline 2. 3. rogress reports will be submitted: Start date: and every six (6) months thereafter Operating Permit Application PLANT-WIDE APPLICABLE REQUIREMENTS FORM 2000-607 Colorado Department of Public Health and Environment Rev 06-95 Air Pollution Control Division FORM NOT REQUIRED FOR ALL FACILITIES - SEE INSTRUCTIONS #3 AND #8 ON REVERSE SIDE IF FORM 2000-607 IS USED; FORM 2000-608 MUST ALSO BE COMPLETED 1. Facility name: Rocky Mountain Energy Center 2. Facility identification code: CO CO 1 2 3 1 3 4 2 3. Pollutant 4. Colorado Air Quality 5. 6. Limitation 7. Compliance Regulations State Status or Only IN OUT Permit Number Fugitive PM No. 1 * 20% Opacity Odor No. 1 * No nuisance odors 8. Is this facility subject to the provisions governing prevention of accidental releases of hazardous air pollutants contained in section 112(r)(7) of the Clean Air Act? ❑ Yes 0 No Has a prevention plan been prepared? 0 Yes 0 No Has the plan been submitted to the regulatory agency? 0 Yes ONo What Agency? Date submitted: 9. Other requirements (e.g., malfunction reporting, special operating State Only Compliance conditions from an existing permit such as material limitation, hours of Status operation, etc.) IN OUT N/A **** USE FORM 2000-700 TO EXPLAIN HOW COMPLIANCE WAS DETERMINED FOR EACH APPLICABLE REQUIREMENT. THIS FORM IS NOT A SUBSTITUTE FOR FORM 2000-604 Operating Permit Application PLANT-WIDE COMPLIANCE PLAN FORM 2000-608 Colorado Department of Public Health and Environment COMMITMENTS AND SCHEDULE Rev 06-95 Air Pollution Control Division USE THIS FORM ONLY IF FORM 2000-607 USED SEE INSTRUCTIONS ON REVERSE SIDE 1.Facility name: Rocky Mountain Energy 2. Facility identification code: CO 1 2 3 1 3 4 2 Center 3. For facilities that are presently in compliance with all applicable requirements, including any monitoring and compliance certification requirements under Colorado Air Quality Regulation 3, Part C that apply, complete the following. These commitments are part of the application for operating permits. ✓ We will continue to operate and maintain this facility in compliance with all applicable requirements. Form 2000-607 includes new requirements that apply or will apply to this facility during the term of the permit. We will meet such requirements on a timely basis. 4. For facilities not presently fully in compliance, complete the following. This facility is in compliance with all applicable requirements except for those indicated below. We will achieve compliance according to the following schedule (If more space is needed attach additional sheets.): Applicable Requirement Corrective Actions Deadline 1. 2. 3. Progress reports will be submitted: Start date: and every six (6) months thereafter THIS FORM IS NOT A SUBSTITUTE FOR FORM 2000-606 FORMS 2000-700 FORM 2000-700 Source Description Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 12 3 1 3 4 2 3. This form supplements Form 2000 - 102 for Emission Units Rocky Mountain Energy Center Additional Information, Diagrams Item Number Rocky Mountain Energy Center • Source Description (Page 1) 1.0 INTRODUCTION Rocky Mountain Energy Center, LLC (RMEC)has built a new power generating facility near the town of Hudson, Colorado. The project is called the Rocky Mountain Energy Center(RMEC). The plant site is located just east of the town of Hudson and is bounded by CR 49 to the west, CR 16 to the north, and CR 51 to the east. The site location in Universal Transverse Mercator(UTM)coordinates is 534491 meters easting, 4437767 meters northing. Figure 1 shows the general site location of the power plant. The power plant site is currently zoned agricultural with a Use by Special Review Permit and is located adjacent to an existing commercial/industrial area of the town of Hudson to the west and agricultural land uses with scattered residences to the east and west. The RMEC has the capacity to generate a nominal 600 megawatts (MW)of electrical power, with a peak capacity up to 630 MW. The facility is a major source of oxides of nitrogen (NO,), carbon monoxide (CO), particulate matter with an aerodynamic diameter of 10 microns, or less (PMto), and volatile organic compounds (VOCs). Emissions of sulfur dioxide (SO2)are expected to be minor. Following Colorado State Regulation No. 3, Part B IV.D.3 and 40 CFR Part 52, these emission rates triggered the requirements of the Prevention of Significant Deterioration (PSD)permit program. The Project comprises two (2)Westinghouse 501 F combustion turbine(CT) units, two(2) heat recovery steam generators (HRSG), a twelve (12) cell cooling tower, one(1)condensing steam turbine generator (CSTG), a 129 MMBtu/hr(HHV) natural gas fired auxiliary boiler, and a diesel fueled emergency generator and fire pump. Except for the emergency equipment, the facility is fueled exclusively by natural gas. Each HRSG will have the capacity to fire up to 659 MMBtu/hr(HHV)of natural gas. Each of the two (2) combustion turbines incorporates dry low-NO,combustion systems that limit NO,emissions to 25 ppmv. Each HRSG incorporates low NO,burners and Selective Catalytic Reduction (SCR)system to further control NOx down to 3.0 ppmv. Each turbine/HRSG combination also incorporates a CO catalyst that will limit CO emissions to 9 ppm,. The auxiliary boiler incorporates low NO,burners to limit emissions of NO, to 30 ppmv. Steam produced in the HRSGs is used to drive the CSTG, which can produce additional electric generation. 2.0 PROPOSED PROJECT DESCRIPTION The energy facility consist of two (2)Westinghouse 501 F natural gas combustion turbines (CT), two (2) 659 MMBtu/hr supplementary fired heat recovery steam generators (HRSG)each equipped with duct burners (DB), one (1) condensing steam turbine generator(CSTG), a twelve (12)cell cooling tower, a diesel emergency backup generator, and a diesel fired fire pump. The CTs is operated in a combined cycle configuration. The combustion turbines and duct burners is fueled exclusively by natural gas. As shown, steam produced by the three HRSGs is directed to the CSTG. The RMEC facility has a gross electric generating capacity of up to 630 MW. Electricity generated by the combustion turbines and the CSTG is distributed to the local utility electric power grid. A diesel fuel-fired 1800 horsepower(1250 kW) emergency backup generator is used to maintain power to the facility during utility outages. A small (182 horsepower)diesel fuel-fired fire pump is also be located on site and will be deployed only in case of a fire at the facility. The emergency generator and fire pump is periodically tested at least one hour per week. A plot plan is included at the end of this section. Equipment not shown in detail on the plot plan but included in the project is the electrical switchyard and electrical equipment such as transformers, transmission lines, and switchyard interconnections, and other miscellaneous equipment and facilities. Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 102 for Emission Units Rocky Mountain Energy Center Additional Information, Diagrams Item Number Rocky Mountain Energy Center Source Description (Page 2) 2.1 Proposed Project This section presents additional details regarding the combustion turbines/heat recovery steam generators, cooling tower, and condensing steam turbine, as well as equipment configuration and operation. 2.1.1 Combustion Turbine/Heat Recovery Steam Generator The two (2) new CTs are Siemens Westinghouse 501 FD gas turbines equipped with dry low-NOx combustion systems. The heat input rating for each CT at ISO conditions is approximately 1785 MMBtu/hr(HHV). The hot CT exhaust is ducted to its associated HRSG, where the exhaust heat is used to generate up to 2,300 psia steam for electric power generation via the CSTG. Auxiliary or supplemental duct firing is included as a part of each CT/HRSG. The rated heat input capacity of each duct burner is 659 MMBtu/hr(HHV). Auxiliary duct firing is used to increase electric power production during periods of peak electric demand. Based on design information, the total steam production from both HRSG is 1,600,000 and 760,000 lbs/hr for operation with and without duct firing, respectively, with the CTs operating at average ambient conditions. A selective catalytic reduction (SCR) system and CO catalyst is used control emissions from the combustion turbines and duct burners. The plot plan at the end of this section presents the basic configuration diagram of the CT/HRSGs. 2.1.2 Cooling Tower A cooling water system provides cooling to condense the steam coming from the steam turbine. The cooling water system uses a 12 cell, induced draft cooling tower with a circulating water flowrate of 166,166 gpm, operating at up to 10 cycles of concentration. The water that is circulated through the cooling tower is considered non-contact cooling water. A high efficiency mist eliminator with a typical drift rate of 0.0005 percent of the water circulation rate is used to limit emissions of PM1e. Cooling tower PM 1e emissions were calculated based on the total dissolved solids in the circulating water and the drift rate. EPA's AP-42' provides available particulate emission factors for wet cooling towers. AP-42 states that"a conservatively high PM10 emission factor can be obtained by(a) multiplying the total liquid drift factor by the TDS fraction in the circulating water, and (b) assuming that once the water evaporates, all remaining solid particles are within the PM10 range." (Italics per EPA). As this overestimates the total PM10 formation, it was assumed that fifty percent of the total PM would be in the form of PM10. If TDS data for the cooling tower are not available, a source-specific TDS content can be estimated by obtaining the TDS for the make-up water and multiplying it by the cooling tower cycles of concentration. [The cycles of concentration is the ratio of a measured parameter for the cooling tower water(such as conductivity, calcium, chlorides, or phosphate)to that parameter for the make- up water.] Using AP-42 guidance, the total particulate emissions (PM) (after the pure water has evaporated) can be expressed as: Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 102 for Emission Units Rocky Mountain Energy Center Additional Information, Diagrams Item Number Rocky Mountain Energy Center Source Description (Page 3) PM =Water Circulation Rate x Drift Rate x TDS [1] Then, in the calculation of PM1e, fifty percent of total PM was assumed to be PM10. For the proposed project, the cooling tower with a water circulation rate of 174,268 gallons per minute (gpm), drift rate of 0.0005%, and TDS of 10,000 ppmw produces an emission rate of 8.71 lb/hr. On an annual basis, this is equivalent to 38.15 tpy. However, as stated above, only a very small fraction is actually PM1e. Therefore, hourly PM10 from the cooling tower is 4.35 lb/hr, while on an annual basis, this is equivalent to 19.07 tpy. 2.1.3 Steam Condensing Turbine A new condensing steam turbine/electric generator rated at 326 MW is included as part of the proposed project. Steam produced by the HRSGs is be used to drive the CSTG. 2.1.4 Ancillary Equipment In addition to the above devices, the following ancillary equipment will also be located at the existing facility: 2.1.4.1 Emergency Backup Generator A 1800 horsepower(1250 kW)diesel fuel-fired generator is used to provide power to the facility during utility outages. This unit only operates when both (2)CTs are not operating and there is no power available from the grid and during periods of periodic testing.. 2.1.4.2 Firepump One (1) 182 hp diesel fuel-fired firepump will only be used in the event of fire and there is no power available from the grid, and during periods of periodic testing. 2.1.4.3 Auxiliary Boiler One(1) 129 MMBtu/hr(HHV)auxiliary boiler is included for the project. The auxiliary boiler is only used when one or more of the CT/HRSGs are not operating. The purpose of the auxiliary boiler is to maintain a temperature in the steam condensing turbine and HRSGs and vacuum in the condenser, thus allowing the facility to be started quickly. 2.1.4.4 Ammonia Storage Two anhydrous ammonia tanks with a maximum capacity of 12,000 gallons each is located on site. 2.2 Fuels The combustion turbines and duct burners are fired exclusively with natural gas. Table 2-1 presents the natural gas properties used as the basis for this application. rnlnradn nenartment of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 12 3 1 3 4 2 3. This form supplements Form 2000 - 102 for Emission Units Rocky Mountain Energy Center Additional Information, Diagrams Item Number Rocky Mountain Energy Center Source Description (Page 3) TABLE 2-1 Typical Chemical Characteristics and Heating Value of Natural Gas Constituent Mole% Nitrogen 0.857 CO2 1.98 Methane 89.6 Ethane 5.857 Propane 1.14 n-Butane 0.19 Isobutane 0.146 n-Pentane 0.042 Isopentane 0.057 n-Hexane 0.057 BTU/SCF 1057 FORM 2000-700 Site Location Map • t i0•44„,„ T .s< te' v - • N mlYni $tld'�� } >�. �.- r L•, WNI Fel o h !1a /f . �'S ' spY1 r•'..�'7 . o >• ms. 7 > e.', �"'" ate' Le l! d , ' .� ; __ 1 ,mow • ei �. wA- .. 3..- - ci { I ` ;). ygygyg 't� r .F ,^.1 j.,10 r. l .'J e// '1 G® J� L y .�^y �Ge it / r I i .1 1 ` 2 • n F .? ' F}r ,I. .;r y }t `# / t ;,3,,t.±, V I f 5 1 .I .)4�ufb I i Y\ -' 1 1 p ti "`\,;� I/ [' .,�' \3 f �IVN9i 17 `" e' er �' - " • II Plathni9e i`- %' f \ „f. t w Ili 1 ,� I z ` \ A �•, El:jcm \ -- r ; ,• IR t - i { e K +4 . • ' _ --_ Ill I `r .'`{ li �. 'e wenreerg i 'i� f i 3P �� ' 'I-777:- e ' I L _ r ate �.� ' � ' `i'w el .t '' r i �JI „• r Irk .;, -r•,� �TF rtre Il I \I + T " ' ,1 a ll Il`� lilt r `\ �' ` ' <q. 13r1t ,- Legend T E IP IlNlalllll Fealties Rocky Mountain Energy Center Gas Pipeline 0 1 2 3 Mies waieempelNe Project Location Son:USGS 1,100,000 Greeley r ga r. o ORG. Figure 2-1 C:\Ascent Images\Release to Hard Drive\00001 BEC.TIF FORM 2000-700 Process Flow Diagram a rr O H .., 1:, .,, ipHco F- IX w 1 M gQ 4F—Q U 119`' Q .diutF .., F v V 4S.L.LYMO U)i 000`OOI Tsik 1 1p .0I. s a);r 4.N f.. N qf� 'N 1'1 9E 1N U O ,-a ii' g s Lam a� ' t3 ' w W Y �O ?� w '4 w*,1,;(" z v4 o cnm §i, ;11 m= 20 x Z R. t.) Z U3 (. `" 3 ti W z us o ww t-c"' t-o z ri N US o- C.) ¢ t7 x o ' ac �" LLJ. Q ; O xw . t i i t if W j odsiv rrz rstwezFMar akmat F tali 'JS �r' z ml F , Lj la C5 III ' 1,-V7 m 4 - oow.-CT 3 S9 1N z W ,..,,. ,.., 0cc tW- .�.I 2 O Q' C W o V w Z0 t- en T ~p22 W ma°' �+ m d W a .C .: m F- Q0 to O CI CC Wz O.4-1 emu.. _ -4.-- QE x >1 E co z4 O Ammismo n z ., O �� u us Ow 10 W 1I �7J IL S W ' Cr 7 y z W R',-t i W Q J (.) t l t z �+1t CC WSag `'i Q LJ > u„ -4i'1#11141i#i#IFP P"Z FORM 2000-700 Emission Estimates Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 102 for Emission Units Rocky Mountain Energy Center Additional Information, Diagrams Item Number Rocky Mountain Energy Center Emission Calculations (Page 1) 2.3 Project Emissions Natural gas combustion results in the formation of NOR, SO2, VOC, PM1e, and CO. Because natural gas is a clean burning fuel, there will be minimal formation of combustion PM10 and SO2. The combustion turbines will be equipped with dry low-NO,combustors that minimize the formation of NO, and CO. To further reduce NO,emissions, selective catalytic reduction (SCR) control systems will be utilized. Similarly, the duct burners and auxiliary boiler will also be equipped with a low-NO,burner design that minimizes NO, formation. A CO catalyst will be incorporated into the turbine/HRSG in order to further reduce emissions of carbon monoxide. Various noncriteria pollutants will also be emitted by the facility, including ammonia (NH3), which is used as reactant by the SCR system to control NOR, and sulfate(or secondary particulate matter) due to the oxidatio of the SO2 emitted by the facility. Emissions of all of the criteria and noncriteria pollutants have been characterized and quantified in this application. 2.3.1 Criteria Pollutant Emissions The emissions sources at the RMEC include two gas turbines with heat recovery steam generators equipped with supplemental burners (duct burners), and a wet, mechanical-draft cooling tower, plus minor auxiliary equipment(emergency generator and fire pump engine). The actual operation of the turbines will range between 70 percent and 100 percent of their maximum rated output. Supplemental firing will be provided by the duct burners as needed to achieve the required power generation level. Steam injection into the combustion turbines (power augmentation, or PAG)will also be used to increase power output under certain conditions. Emission control systems will be fully.operational during all operations except during startups and shutdowns. Maximum annual emissions are based on operation of the RMEC at maximum firing rates and envelope the expected maximum number of startups that may occur in a year. Each turbine startup will result in transient emission rates until steady-state operation for the gas turbine and emission control systems is achieved. Ambient air quality impact analyses for the site have been conducted to satisfy the Air Pollution Control Division (APCD)requirements for criteria pollutants (NO2, CO, VOC, PM10, and 8O2)on a pollutant-specific basis. It should be noted that the operational scenarios having the highest emissions rates do not necessarily produce the highest ambient impacts. The gas turbine, duct burner, and auxiliary boiler emission rates have been estimated from vendor data, RMEC design criteria, and established emission calculation procedures. The emission rates for the combustion turbines alone, the combustion turbines with duct burners and power augmentation, the auxiliary boiler, and the IC engines are shown in the following tables 2-2 through 2-6. Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 102 for Emission Units Rocky Mountain Energy Center Additional Information, Diagrams Item Number Rocky Mountain Energy Center Emission Calculations (Page 2) Table 2-2. Maximum short term pollutant emission rates—each gas turbine'. Pollutant ppmvd @ 15%O2 lb/MMBtu` lb/hr NO, 3.06 0.0134 24.0 CO 9.006 0.0241 43.0 VOC 2.00 0.0025 4.5` PMfo 0.0062 11.0 SO2' 0.120 0.0007 1.3 • Basis: 'Emission rates shown reflect the highest value with no power augmentation, and no duct burners at any operating load except startup and shutdown. bRMEC design criteria. `Pounds per hour provided by vendor; ppm and lb/MMBtu calculated from lb/hr. d100 percent of particulate matter emissions assumed to be emitted as PMfo; PMfo emissions include both front and back half as those terms are used in USEPA Method 5. eBased on maximum fuel sulfur content of 0.25 grains/100 SCF. Table 2-3. Maximum short term pollutant emission rates—each turbine with duct burner and power augmentation. Pollutant ppmvd @ 15%O2 Ib/M11.1Btu` lb/hr NO, 3.0' 0.0108 25.0 CO 9.0' 0.0199 46.0 VOC 2.0 0.0025 5.86 PMta` - 0.0076 17.6 SO2d 0.12 0.0006 1.4 Basis: 'RMEC design criteria. 'Pounds per hour provided by vendor; ppm and Ib/MMBtu calculated from lb/hr. c100 percent of particulate matter emissions assumed to be emitted as PM-10; PMfo emissions include both front and back half as those terms are used in USEPA Method 5. °Based on maximum fuel sulfur content of 0.25 grains/100 SCF. Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2OOO-7OO Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 102 for Emission Units Rocky Mountain Energy Center Additional Information, Diagrams Item Number Rocky Mountain Energy Center Emission Calculations (Page 3) TABLE 2-4 Maximum Pollutant Emission Rates Auxiliary Boiler' Pollutant ppmvd @ 3% O2 lb/MMBtu lb/hr NO„ 30" 0.0380 4.9 CO 50` 0.0388 5.0 VOC 10" 0.0047 0.6 PM,° N/A 0.0186 2.4 SO; 0.359` 0.0007 0.09 Notes: 'Emission rates shown reflect the highest value at any operating load, excluding startup"Vendor guarantee. `MEC specification. d100 percent of particulate matter emissions were assumed to be emitted as PM,;PM10 emissions include bott front and back half as those terms are used in USEPA Method 5. `Based on maximum fuel sulfur content of 0.25 grains/100 SCF. Table 2-5. Maximum pollutant emission rates—emergency generator set(1984 hp). Pollutant g/bhp-hr Ib/hr tons/yr NO, 6.9 31.7 0.75 CO 8.5 39.05 0.9 VOC 1.0 4.59 0.115 PM1e 0.40 1.84 0.044 SO2 Neg 0.654 0.0163 Notes: Emission rates shown reflect the highest value at any operating load per vendor guarantee. Tons/yr based on max operation hours of 30 minute tests at 50% load and 200 tests/yr. 100 percent of particulate matter emissions were assumed to be emitted as PM10; PM10 emissions include both front and back half as those terms are used in USEPA Method 5. EPA AP-42, Table 3.: 2. SO2 emissions based on maximum fuel sulfur content of 0.05%wt. Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code:CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 102 for Emission Units Rocky Mountain Energy Center Additional Information, Diagrams Rocky Mountain Energy Center Item Emission Calculations (Page 4) Number Table 2-6. Maximum pollutant emission rates—fire pump engine(182 hp). Pollutant g/bhp-hr lb/hr tons/yr NO, 5.89 2.36 0.236 CO 3.55 1.42 0.142 POC 0.73 0.29 0.0290 PKo 0.25 0.10 0.010 SO2 neg 0.063 0.0063 Notes: Emission rates shown reflect the highest value at any operating load per vendor guarantee. Tons/yr based on max operation of 200 hrs/yr. 100 percent of particulate matter emissions were assumed to be emitted as PMto; PMfe emissions include both front and back half as those terms are used in USEPA Method 5. SO2 based on maximum fuel sulfur content of 0.05%wt. The maximum firing rates, daily and annual fuel consumption rates, and operating restrictions define the allowable operations that determine the maximum potential hourly and annual emissions for each pollutant. These allowable operations are typically referred to as "the operating envelope" for a facility. The maximum heat input rates (fuel consumption rates) for the gas turbines, and gas turbines with duct burners, and the IC engines are shown in Table 2-7. Table 2-7. Maximum device heat input rates(HHV)(MMBtu). Gas Turbines w/Duct Gas Turbines w/o Emergency Generator Emergency Fire Period Burners' Duct Burners" Set Pump Per Hour 2311 1785 —6.51d —1.26 Per Year' 10,630,600 6,611,640 -1301d —252 Notes: a Based on maximum heat input for full load operation at 90 deg. F plus duct burner with power augmentation. Based on maximum heat input for full load turbine operation at 3 deg. F. `Daily and annual heat input rates are highly variable due to the wide capability of the turbines and duct burners to operate at various loads on a daily and annual basis. d Emergency generator limited to 30 minute tests. Natural gas @ 1057 btu/scf(HHV), #2 diesel fuel @ 137,000 btu/gal (EPA AP-42), see App A, Table A- 9 for approximate fuel use calculations. Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code: CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 102 for Emission Units Rocky Mountain Energy Center Additional Information, Diagrams Item Number Rocky Mountain Energy Center Emission Calculations (Page 2) Table 2-8. Maximum facility startup emission rate?. NO, CO POC Cold Start, lb/hour 80 838 16 Cold Start, lb/start° 240 2,514 48 Hot Start, lbs/start` 80 902 16 aEstimated based on vendor data and source test data. See Appendix B °Maximum of three hours per cold start. `Maximum of one hour per hot start. The analysis of maximum facility emission levels was based on the pollutant emission factors shown in Tables 2-2, 2-3, and 2-4; the RMEC operating envelope shown in Table 2-5; and the RMEC startup emission rates shown in Table 2-6. The annual emissions for the turbines were calculated based on turbine capacity factor of 100 percent, with 456 hours in startup mode. For some pollutants, turbine emissions vary based on ambient temperatures. Annual emissions have been calculated assuming an average ambient temperature of 50 degrees Fahrenheit for 5,360 hours. It was assumed that up t 4,600 hours of duct burner and power augmentation would occur and this is typically associated with high temperature conditions. In addition, up to 456 turbine start hours (52 cold starts and 300 warm starts)were included in the annual emissions profile. Base mode operation (no power augmentation and duct burner operation)would occur for 5,360 hours per year. The maximum annual and hourly emissions for RMEC are shown in Table 2-9. Detailed emission calculations appear in Appendix B. o the construction permit application. Emissions from the cooling tower were calculated from the maximum cooling water TDS level and assumed 8,760 hours of operation. Auxiliary boiler emissions characteristics are also shown in Appendix B. FORM 2000-700 Supplement to Form 2000-605 Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09.94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code:CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 605 for Emission Units 001 Additional Information, Diagrams Item Number Pollutant Colorado Air Quality Regulations Criteria and non-criteria pollutants Reg No. 1 (5 CCR 1001-3) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 3, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-5) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 4, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-6) Criteria and non-criteria pollutants Reg No. 5 (5 CCR 1001-7) Criteria and non-criteria pollutants Reg No. 6 (5 CCR 1001-8) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 7 (5 CCR 1001-9) Criteria and non-criteria pollutants Reg No. 8 (5 CCR 1001-10) Criteria and non-criteria pollutants Reg No. 9 (5 CCR 1001-11) Criteria and non-criteria pollutants Reg No. 10 (5 CCR 1001-12) Criteria and non-criteria pollutants Reg No. 11 (5 CCR 1001-13) Criteria and non-criteria pollutants Ambient Air Quality Standards (5 CCR 1001-14) Criteria and non-criteria pollutants Reg No. 12 (5 CCR 1001-15) Criteria and non-criteria pollutants Reg No. 13 (5 CCR 1001-16) Criteria and non-criteria pollutants Reg No. 14 (5 CCR 1001-17) Criteria and non-criteria pollutants Reg No. 15 (5 CCR 1001-18) Criteria and non-criteria pollutants Reg No. 16 (5 CCR 1001-19) Criteria and non-criteria pollutants SIP and Listed Nonattainment Areas (5 CCR 1001-20) Criteria and non-criteria pollutants Reg No. 18 (5 CCR 1001-22) Criteria and non-criteria pollutants Reg No. 19 (5 CCR 1001-23) Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code:CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 605 for Emission Units 002 Additional Information, Diagrams Item Number Pollutant Colorado Air Quality Regulations Criteria and non-criteria pollutants Reg No. 1 (5 CCR 1001-3) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 3, Part B, 4 IV.D.2-3, and X-X1 (5 CCR 1001-5) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 4, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-6) Criteria and non-criteria pollutants Reg No. 5 (5 CCR 1001-7) Criteria and non-criteria pollutants Reg No. 6 (5 CCR 1001-8) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 7 (5 CCR 1001-9) Criteria and non-criteria pollutants Reg No. 8 (5 CCR 1001-10) Criteria and non-criteria pollutants Reg No. 9 (5 CCR 1001-11) Criteria and non-criteria pollutants Reg No. 10 (5 CCR 1001-12) Criteria and non-criteria pollutants Reg No. 11 (5 CCR 1001-13) Criteria and non-criteria pollutants Ambient Air Quality Standards (5 CCR 1001-14) Criteria and non-criteria pollutants Reg No. 12 (5 CCR 1001-15) Criteria and non-criteria pollutants Reg No. 13 (5 CCR 1001-16) Criteria and non-criteria pollutants Reg No. 14 (5 CCR 1001-17) Criteria and non-criteria pollutants Reg No. 15 (5 CCR 1001-18) Criteria and non-criteria pollutants Reg No. 16(5 CCR 1001-19) Criteria and non-criteria pollutants SIP and Listed Nonattainment Areas (5 CCR 1001-20) Criteria and non-criteria pollutants Reg No. 18 (5 CCR 1001-22) Criteria and non-criteria pollutants Reg No. 19 (5 CCR 1001-23) Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code:CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 — 605 for Emission Units 003 Additional Information, Diagrams Item Number Pollutant Colorado Air Quality Regulations Criteria and non-criteria pollutants Reg No. 1 (5 CCR 1001-3) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 3, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-5) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 4, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-6) Criteria and non-criteria pollutants Reg No. 5(5 CCR 1001-7) Criteria and non-criteria pollutants Reg No. 6 (5 CCR 1001-8) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 7 (5 CCR 1001-9) Criteria and non-criteria pollutants Reg No. 8 (5 CCR 1001-10) Criteria and non-criteria pollutants Reg No. 9 (5 CCR 1001-11) Criteria and non-criteria pollutants Reg No. 10 (5 CCR 1001-12) Criteria and non-criteria pollutants Reg No. 11 (5 CCR 1001-13) Criteria and non-criteria pollutants Ambient Air Quality Standards (5 CCR 1001-14) Criteria and non-criteria pollutants Reg No. 12 (5 CCR 1001-15) Criteria and non-criteria pollutants Reg No. 13 (5 CCR 1001-16) Criteria and non-criteria pollutants Reg No. 14 (5 CCR 1001-17) Criteria and non-criteria pollutants Reg No. 15 (5 CCR 1001-18) Criteria and non-criteria pollutants Reg No. 16 (5 CCR 1001-19) Criteria and non-criteria pollutants SIP and Listed Nonattainment Areas (5 CCR 1001-20) Criteria and non-criteria pollutants Reg No. 18 (5 CCR 1001-22) Criteria and non-criteria pollutants Reg No. 19 (5 CCR 1001-23) Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 0994 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code:CO 12 3 1 3 4 2 3. This form supplements Form 2000 - 605 for Emission Units 004 Additional Information, Diagrams Item Number Pollutant Colorado Air Quality Regulations Criteria and non-criteria pollutants Reg No. 1 (5 CCR 1001-3) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 3, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-5) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 4, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-6) Criteria and non-criteria pollutants Reg No. 5 (5 CCR 1001-7) Criteria and non-criteria pollutants Reg No. 6 (5 CCR 1001-8) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 7 (5 CCR 1001-9) Criteria and non-criteria pollutants Reg No. 8 (5 CCR 1001-10) Criteria and non-criteria pollutants Reg No. 9 (5 CCR 1001-11) Criteria and non-criteria pollutants Reg No. 10 (5 CCR 1001-12) Criteria and non-criteria pollutants Reg No. 11 (5 CCR 1001-13) Criteria and non-criteria pollutants Ambient Air Quality Standards (5 CCR 1001-14) Criteria and non-criteria pollutants Reg No. 12 (5 CCR 1001-15) Criteria and non-criteria pollutants Reg No. 13 (5 CCR 1001-16) Criteria and non-criteria pollutants Reg No. 14 (5 CCR 1001-17) Criteria and non-criteria pollutants Reg No. 15 (5 CCR 1001-18) Criteria and non-criteria pollutants Reg No. 16 (5 CCR 1001-19) Criteria and non-criteria pollutants SIP and Listed Nonattainment Areas(5 CCR 1001-20) Criteria and non-criteria pollutants Reg No. 18 (5 CCR 1001-22) Criteria and non-criteria pollutants Reg No. 19 (5 CCR 1001-23) Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code:CO 1 2 3 1 3 4 2 3. This form supplements Form 2000 - 605 for Emission Units 005 Additional Information, Diagrams Item Number Pollutant Colorado Air Quality Regulations Criteria and non-criteria pollutants Reg No. 1 (5 CCR 1001-3) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 3, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-5) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 4, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-6) Criteria and non-criteria pollutants Reg No. 5 (5 CCR 1001-7) Criteria and non-criteria pollutants Reg No. 6 (5 CCR 1001-8) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 7 (5 CCR 1001-9) Criteria and non-criteria pollutants Reg No. 8 (5 CCR 1001-10) Criteria and non-criteria pollutants Reg No. 9 (5 CCR 1001-11) Criteria and non-criteria pollutants Reg No. 10 (5 CCR 1001-12) Criteria and non-criteria pollutants Reg No. 11 (5 CCR 1001-13) Criteria and non-criteria pollutants Ambient Air Quality Standards (5 CCR 1001-14) Criteria and non-criteria pollutants Reg No. 12 (5 CCR 1001-15) Criteria and non-criteria pollutants Reg No. 13 (5 CCR 1001-16) Criteria and non-criteria pollutants Reg No. 14 (5 CCR 1001-17) Criteria and non-criteria pollutants Reg No. 15(5 CCR 1001-18) Criteria and non-criteria pollutants Reg No. 16 (5 CCR 1001-19) Criteria and non-criteria pollutants SIP and Listed Nonattainment Areas (5 CCR 1001-20) Criteria and non-criteria pollutants Reg No. 18(5 CCR 1001-22) Criteria and non-criteria pollutants Reg No. 19 (5 CCR 1001-23) Colorado Department of Public Health and Environment SUPPLEMENTAL INFORMATION FORM 2000-700 Colorado Department of Public Health and Environment 09-94 Air Pollution Control Division SEE INSTRUCTIONS ON REVERSE SIDE 1. Facility name: Rocky Mountain Energy Center 2.Facility identification code:CO 1 2 3 13 4 2 3. This form supplements Form 2000 - 605 for Emission Units 006 Additional Information, Diagrams Item Number Pollutant Colorado Air Quality Regulations Criteria and non-criteria pollutants Reg No. 1 (5 CCR 1001-3) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 3, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-5) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 4, Part B, § IV.D.2-3, and X-X1 (5 CCR 1001-6) Criteria and non-criteria pollutants Reg No. 5 (5 CCR 1001-7) Criteria and non-criteria pollutants Reg No. 6 (5 CCR 1001-8) Except as listed on Form 2000-604 Criteria and non-criteria pollutants Reg No. 7 (5 CCR 1001-9) Criteria and non-criteria pollutants Reg No. 8 (5 CCR 1001-10) Criteria and non-criteria pollutants Reg No. 9(5 CCR 1001-11) Criteria and non-criteria pollutants Reg No. 10 (5 CCR 1001-12) Criteria and non-criteria pollutants Reg No. 11 (5 CCR 1001-13) Criteria and non-criteria pollutants Ambient Air Quality Standards (5 CCR 1001-14) Criteria and non-criteria pollutants Reg No. 12 (5 CCR 1001-15) Criteria and non-criteria pollutants Reg No. 13 (5 CCR 1001-16) Criteria and non-criteria pollutants Reg No. 14 (5 CCR 1001-17) Criteria and non-criteria pollutants Reg No. 15 (5 CCR 1001-18) Criteria and non-criteria pollutants Reg No. 16 (5 CCR 1001-19) Criteria and non-criteria pollutants SIP and Listed Nonattainment Areas(5 CCR 1001-20) Criteria and non-criteria pollutants Reg No. 18 (5 CCR 1001-22) Criteria and non-criteria pollutants Reg No. 19(5 CCR 1001-23) FORM 2000-800 Operating Permit Application TABULATION OF PERMIT APPLICATION FORMS FORM 2000-800 Colorado Department of Health 09-94 Air Pollution Control Division Facility Name: Rocky Mountain Energy Center Facility Identification Code: CO 1 2 3 1 3 4 2 — — I. ADMINISTRATION This application contains the following forms: ✓ Form 2000-100, Facility Identification ✓ Form 2000-101,Facility Plot Plan ✓ Forms 2000-102,-102A,and-102B,Source and Site Descriptions II. EMISSIONS SOURCE Total Numt DESCRIPTION of This Fort This application contains the following forms ✓ Form 2000-200,Stack Identification 6 (one form for each facility boiler,printing ✓ Form 2000-300,Boiler or Furnace Operation t ✓ Form 2000-301,Storage Tanks ✓ Form 2000-302, Internal Combustion Engine 2 ❑ Form 2000-303, Incineration ❑ Form 2000-304, Printing Operations ❑ Form 2000-305, Painting and Coating Operations ✓ Form 2000-306,Miscellaneous Processes 2 ❑ Form 2000-307,Glycol Dehydration Unit III. AIR POLLUTION CONTROL Total Numbi SYSTEM of This Fon This application contains the following forms: V Form 2000-400,Miscellaneous 2 ❑ Form 2000-401,Condensers ❑ Form 2000-402,Adsorbers ❑ Form 2000-403,Catalytic or Thermal Oxidation 2 ❑ Form 2000-404,Cyclones/Settling Chambers ❑ Form 2000-405,Electrostatic Precipitators ❑ Form 2000-406,Wet Collection Systems ❑ Form 2000-407,Baghouses/Fabric Filters IV. COMPLIANCE Total Numb DEMONSTRATION of This Fon This application contains the following forms ✓ Form 2000-500,Compliance Certification-Monitoring and Reporting 6 (one for each facility boiler,printing ✓ Form 2000-501,Continuous Emission Monitoring 6 ❑ Form 2000-502,Periodic Emission Monitoring Using Portable Monitors ❑ Form 2000-503,Control System Parameters or Operation Parameters of a Protect ❑ Form 2000-504,Monitoring Maintenance Procedures ❑ Form 2000-505,Stack Testing ❑ Form 2000-506,Fuel Sampling and Analysis ✓ Form 2000-507,Recordkeeping 6 ✓ Form 2000-508,Other Methods 5 I VI. SIGNATURE OF RESPONSIBLE OFFICIAL - FEDERAL/STATE CONDITIONS A. STATEMENT OF COMPLETENESS I have reviewed this application in its entirety and,based on information and belief formed after reasonable inquiry,I certify that the statements and information contained in this application are true, accurate and complete. B. CERTIFICATION OF FACILITY COMPLIANCE STATUS-FEDERAL/STATE CONDITIONS(check one box only) /// I certify that the facility described in this air pollution permit application is fully in compliance with all applicable requirements. ❑ I certify that the facility described in this air pollution permit application is fully in compliance with all applicable requirements,except for the following emissions unit(s): (list all non-complying units) WARNING: Any person who knowingly,as defined in§ 18-1-501(6),C.R.S.,makes any false material statement, representation, or certification in,or omits material information from this application is guilty of a misdemeanor and may be punished in accordance with the provisions of§25-7 122.1,C.R.S. Printed or Typed Name Title James Gooding General Manager Signature,/ Date Signed ,4/1-7 d63 ,Vros-- 95 Operating Permit Application CERTIFICATION FOR STATE-ONLY CONDITIONS FORM 2000-800 Colorado Department of Health 09-94 Air Pollution Control Division agility Name Rocky Mountain Energy Center Facility Identification Code: CO 1 2 3 1 3 4 2 VI. SIGNATURE OF RESPONSIBLE OFFICIAL- STATE ONLY CONDITIONS A. STATEMENT OF COMPLETENESS I have reviewed this application in its entirety and,based on information and belief formed after reasonable inquiry,I certify that the statements and information contained in this application are true, accurate and complete. B, CERTIFICATION OF FACILITY COMPLIANCE STATUS FOR STATE-ONLY CONDITIONS(check one box only) I certify that the facility described in this air pollution permit application is fully in compliance with all applicable requirements. ❑ I certify that the facility described in this air pollution permit application is fully in compliance with all applicable requirements,except for the following emissions unit(s): (list all non-complying units) WARNING: Any person who knowingly,as defined in§ 18-1-501(6),C.R.S.,makes any false material statement,representation, or certification in,or omits material information from this application is guilty of a misdemeanor and may be punished in iccordance with the provisions of§25-7 122.1,C.R.S. Printed or Typed Name Title James Gooding General Manager Signature Date Signed /ll�� SEND ALL MATERIALS TO: COLORADO DEPARTMENT OF HEALTH APCD-SS-B I 4300 CHERRY CREEK DRIVE SOUTH DENVER, CO 80246-1530 96 1 N N N10 N O M N II II w z a 1 i 16:6 )14:4 li. ;lel jitPt el:-I In5411 gilt .....4: III 4144' 4* g Or* 04 I j ��$ ® '®ma e i ® esL n _1 ... __ ...-.� s a ,re._ L . F a �i�{W �r i i .e, o fb .--1:kJ ,-, : i _» I 1 ° � f a ® � ®ltdll _]S % .*. W 1 6.I. d mts 3Cg � r �.Y .- g V6 ® 09 ® �UGO '� �� MC . ®- 4 1 3 1 I (\t 1 I I ...... 00 00 G Z _ __---- „c0,9Z000 N Appendix A Site Plot Plan .1 t 1 m,- x ` ET, „ �•& t ` ' `a $n �i'•- - p 3 9 E a. €a A PN < < N E o ❑ � < .e vp 0- s < ` tr, • g` :e �r- o pp c E.O a N y y c j C 6 C ' r� I W 2 t N 03 i 8 E 3 it h v. S mB •i m5 Egizq 'F ,E '? .E K �' d N a d g.e 2 a c 13 8•� _� 16 Ga u' x < C.o'5 n5'o CO i Z yob 4 N UT4'_Og F.3 Gh " •P: -yy 6 .50 {{{{11 ga} 3 Z :n& U G O '4 g< Q '° o u.fi m"'�o-. 6�`o, n0-m3 y�yQ ur f7 .ret r a•5 ti-C.... o > ' dud u q s '°t5o u �j O W� 6.0g'gu P.C.O.[' >- Q J c CL u u0. Y 3 $ 13 u S0C" ev3EEEg `$$ O .Z. l'' 'cQ ZK2�F...w C�'000 ppC4 tSC a b 6 o 0000 ❑oo• 00 dlgl o a•y a N o z chi ca0 • th 0 o� 0 8 5 0°0 o m artg8 O a 2- a ag o 6 ° Z a • S = > h QQ > a o� F. f'n C m V . 9 V 9 L 0 4 zi <n aj 9 •Amp P° a O 2 5g E u 0 � ° oo a Z 3 r z'' _ scm > > > > > > a p d rq.Fe L' .� �' O W L1• w co 8 c „ a X �n 3�. Z O awv F -Yr. w % ray "� � a E 0 9 u0 ow ! .Z'Q N g •i oo .6.:c a Q q f/�j Jz Z Eon tcp 6 m a.. u ° a {.j Mm a al .2 • N G YY aV `" E A. ,y. ,,,. y (off S oit _ �w o n' C .gN iY 1E Y 'Zx 0 Oa> zr N O F a , .E o 3 Na'a 0a d h .n O W W t< o Cu g S ❑5 en e4 aW 5z H 00 E U iu8 co 8 E -K O O W Z3 g?& " m E a o ? `• Fwd x Pi-j,- 't5-° 2P1 2 H-++ „ a„� n ty � o Vaa POM � > 01 �,b� d 2 1 .24 4g 2 O .a °u ° ag g N ... 7, g ` T 833- �B W s m F/'�I ... 'v "� m"s' ,"C HI Y giro N � r I 81. CA ±), < I� Fk a . -oz., Xt..] tri ��r C mx rs O Caw ax> es F� O 6O o 0r WU°q igi ..>,01, `O ; 8 mtn tsi W ;lisiS42.5 ° • ate v 0°t a 1�� • al .5.0 4.00.. •E ri F - E $Cj {i.'', X ag- Z . Y '� <Z Z x n c C F " 6 a: E s Elf ` w F a c Dart F'..C E • I H �,, uo z a b V a _ _ Su mO040.rxEems ` t. 0 6,, o gig 2 r O 'c YEpO "ad -. O0, 0a 10 mKZ < . 4O= O 3 g o a m to E k. -a 5. ZZOi nt, . ��.... 0 u yy (6) !A° a.<O H' ieL O wnH Fy.elt3 .1-4 C k ej C cS f v 2 U 0 5 0 0 O ! gYn� nj td Jwa N 206-' a a O U k ... .n `o z Z z z z 0 �FZ y . „ -0 4' 7, Oi Car ,-4g d f-• o o 10 U Ta & $ o g" 6 u 3 3 o A 0a1-1-• i Zsd3 iii zoz z w a .. n .c 4 b A c .e b `I ,2 E a <.°iib 9: ^C;. y p• t a j....l "JJ uJFZ 0 y .ur l l0` C n b °: — u 2. °' o 5 2 0 0 0 0 .]°0 0, F" <g Kmm • < ro 00. A w a 0. _tea ,n_z > ua.aa_N 1-'• W Xa. 01 >.O ---.. . C:\Ascent Images\Release to Hard Drive\APENCTG2.TIF E #5 z z z z Z z Z Z Z z z z Z i 2 tn 6 O - . w or n CO N ii -13 1„Ea o a Q O C. - V ~ N Q V 3 1E 151 a g p• s s pH >0 in w Y in U v u o u N O a a a a a a `� ,a a a a u o A Z Q en A .O ,� D L L L D L D .O W N Z .a N r g a a n m m n m a a N A u F O 14 ry 5 o t�r Qy, A A �Q.1 A Q A uuQ.. Q c Ay A a N0 0 P.' v 'E N F F a a iz W 4] y Eri W R L0 a u u a a a a a a 6 6 6 6 a F 6 u ° z'z' U 0i q H m a I 0. c`ri N Xc, N 0 N 0 0 o g N N N b :+f O. b N 0 0 0 b W CO p W �j9 G W W v- �. rt Ni N -. vi m b N b a Qm �E ti W C b b O .. ... cV .. b 7 I� N a m S ff ' a n e g J° c y. V OO n T a = O. 12 ci Q'` gg Q u z a s W a ° -J .a .s m F F ti amaaUaaUavw ¢ 00 • e U U z IX PO. c a u p w a a 3 a. x W x�5 '.11 a 0 ° o ce g N 0 0 0 -0 o 0 O Z i7� .0C k m O °� % v r9 W C 12 0 -2 6 ¢ O a a xi w o x pi. a. a F x 5 u l"' w 0. .0 JO a 073 all re t ° 'd 0 I'd u g..) z g a o Z ° O w U m C .o CI p o 8 a a 2 Z p Ay $ a ° 0. U F. W k5 t o 'a ''^ m a p h o a r 0 0 M y E N r .v. .O O o a N in 0 € O N <z= r ,..9 ^ r o o v1 ti O\ N a M M1�. 0 7.E sg o Q 2 C:\Ascent Images\Release to Hard Drive\APENCTG2.TIF I. I1 ii .X. .. (jo �� '$v p°'d A Dm a. I 4C' ,$A d ELI < x z 2<o r _ a O �, N 6 a u 11 < o a 43 w cn cc' 1 ti lilt- Sg E c 3 ..{ g 4 Y ` X N 2 'I' F � uS Le Vl gg U Ong < �° E ! ? A 25I1.11 A o , s I E ,IC; )C7.1 8 d !d a K z o c y a t 5 S O c p (1S a to 2 < y= o..E' � D� '“�' C• � & 6 t2@�S. $ € !' 6 a s Z °yy -8 v' . ill?' „ ° 3V I -'aa i n 0.' a 'q f r o Ji. i » 4F0. 3Umw no YS' Can° w_°2 r°� 4 y 3 < g uSc R6 > $a§ EEa o&8 o 1 a °° zxur-��s�. o❑ ' -.Sag `•;;;G qcq g o LL ❑ODD ❑oD .Oa V <: . co o `.2 C o kit Z 0. Z (J P. W A 9xi ° 3 Fo w u<e& < �'c M 0.F > ° 4 n �'i o o e o FWe+ p H ro h po e Fp7 grzN to 1 2 -51 '2 .] Op 'q �i e e '� ^ 2 4 J'o h o . CNN g Ws • .�z Oei iM` N` a a oo e..rra c A ` °� Y zVW 4 r^a g V'v ° (Sim S woo o a X I<W � 4.1 < 0 4 S 0� x Y N ay< V Q e N 0 ta . Eno w o 0 0'�° t >'^ d: 3 a- ueiFG�+ v •o ri .k. m c i I--1 c 0 5 ,2a a °a Y L. R A r2 d a<^r�i u w s S W E 6 o 'a ° <irt pi '.'� S O O l '��'p �...t _g p° -g m B V c Fr p" s ° v m .g e" II < F d g ,Toll e ° 6 z µ� 5 w'n F .� g ` 11 p OZ Nen U kl Vs Z Q q �Q% Li G 4,'= C - o � ".” �1---1 CID -' :2,---, N °w a vl �' y° 4- ao r4 e-� rG_L'.0 Cd V1 N " co t �L•• ,tJ W — OOUtWil .�1. xW 9iNw V 6 O az, I 3 E ❑ wuo Efi3 Ozs Tpa m x rdo a HFO.ii O a x �' 0KF ' .at W 3 �6 _• 5 dan i• eS FF a W- y _ r� ° g 1= Nr ZOrA v F E 0"I. o C0F y ti yC F-r . u z z 0! `t HZ s 4 das 6x CF z 2 = = z au �. oa s wag 00 Ouc7i0 r Obi Ed'^ ° O m . F ° o °yy O°oaal S +F.CC.ou. v F CZ; 2 O°-° p - a a i tom- c 9 _0ZO <o#r. � 3< m �i F i m 4 u si uox Y_ >r1d °(-p1 « O fil c s$ �p ° "5 p 0 ya J! p� 8,00 f'0 �h.,T e�d OLoci?) °p z.U . a o 2 .`. k 4 _ z ,Z ,Z 1Z Z V wisp, 1 i Witco.g n/� W -, z 4 ,rj F+( 0< F n CC+ �L ° e c • w .. 0 7Q< a °'a7 rag zoz Wok w o ° Z z° w� a 4 Nw$ _ . e 33 H •C rz Wn o Nf� LL 0 0 Tc 4 Y1< 4 n 0000 .100 tint. . ag mww a ws - r : u E ® Pi °z X N, ` W 5 a. O1 M.d W a 4 4 N Z > V 44 w y Flu C_ C:\Ascent Images\Release to Hard Drive\APENCTG1.TIF I o Ma G < < < < < < < < < < < < < " Z z z Z z z z z Z Z Z Z Z f W g 2 N wi%� a O m Z N p p N W Z O Igi .0 O N 9. O °° r 1.2 Vs p CI q 2 N a N N O _ V N — NO3 _ R cc N Q U P. �" N V Q qy o N 6 C F to y o O tP N m N y y w y u v to N y `ilu N To' Z a1 b A N N 9 N N u O v ❑ a M u .0 F A A ? ? .a a ? .0 .0 a N '�+ °- Y n m N is m n q q n .�v N' Q °� F. Z � � cc)❑ ❑ Q{r, ❑ ❑ Q Q Q o ❑ Q ❑ 0 o 0 O 3ry .Pt � iwww ("(�7 24 12, a. E F F F F F F r-* F F F F F d o fn t a F 'U < a < < < a < < < < < < {A o 00 0000U00000 ?" 2 z' Ili .6 n ' N m '^• N V N .-+ m NNN b u_o o o swpoZ 0 0 0 0 0 0 0 9 0 0 Z e m ? P9'. rmi r- q O rt _ N b `R m 0 G n •t{ E S W 'A O .y ti .. .. N .r b C r N2. jo E Sq J O p -' b 1 O°0 n V O.8 w 5 WC b E 4 c o Q u z U - o Ill ato 7, CO d g'0]' < C �4 a�gi 3 L a o 8i v g pU, ,u�, `a a. u. 6 Q v .�a > y 01 co1 Di. .Y" �.lo' �y J. o k v u ill Z C5 grsioo Q v u < a < m f' o z P<+ o f a v F w w731 5 r u p re i 'o d U .. 9 O t'w V a m o a P O Z o r tis 51 4.< 0 o 0 rd 0 0. o Z pp n u G o oa r. o v o m m rn °" o `o m �, V w a w a E 0 o $ Q o o 0 0 N m p qj € o 'eZ b G Z 1� y r O; r .mm. ' PUi O v o e > E V V Q C:\Ascent Images\Release to Hard DriveWPENCTG1.TIF m m N U a\ ype2q, g s .s `6` ,�I 6�1 3 M Z ,n b 6 Io d at" g °d \ o o X £ N szn �' 5 a 1 R -c DC ,�.h dos ° 2> Q /� S W..]Lpsg �oj5 — a�� 'ETD yH col e� Z 3. ° k `�1SZ 5II.� �ie 3 dS 81 ; gN allWp,lL. ilkt 8E '2=1R 0.ci a SC P N m ,Y°, o, m p z l 0.e g C 0.10 EA Eon i m t 0 r-, .8 z x o I E 4444 Ma Fes' F Vl el e at G e� a taf 001, = mdd g & taw o. e-§HIe E1 z E op < 2 o Uaf°g. ❑ Cb $ F �� .ti aY T .. N '' Z TV o i C, e Y L, d° - w O .°p! 0 o za v oo EN h • 3 x o : S OWE 92 Hw' •e U a ,n 11 'a O z p X •C en I I p 'c , o : a ei a. RI e 71 L1-� Y = a. Pr4 2 V ,Wu=. C7 F i.@ O W g .4 L1 C�' E 6 O $ O 9 0 `ab O ;,,I g I P Xa 2 a a U & Z U F o g z c z rz y 5 °a 1�-�j 3' a � 3'� = ate x b ^ U w iape f• U B_I 4 8 °Z4 b '0 .. o a e r ❑ Ai: H 3$ �Id F ere.E 2 2 leg rfi .gmay 41 C/D v � z € £ L Ov UP Fl s9 NUS a at gg5gg z4z cps I - j 'Ea - fig W 4 1 2 O_E le L -i.v V {- go oy ❑ x• S 'nS4 )- n ` jI . i� fz zg W y F� V WW OJN ' F Ft 1] wF�—"'�� ' ' 3 X. 0 6 1'• O c j P o W t liZ Z 0 gin- 8 8 sip � o i z or ¢g I I _1 lei gilppa i 1 >0�0°v., y ydi gpZU o u tn 0. Z of �7 Sc gj at ^ C7QFj Kd m E. O O Mg O 0 o '0�-0 0f ° .. O u"7a' u U�U' ,Z, d❑ 0@g-0 a II-J c m $ 0 i, c hgami 7 o li p�O�e2 � o Ez � w8 F Olin Ql. Fd ClIao��_ C:\Ascent Images\Release to Hard Drive\APENAB.TIF • i i f , z z z z z z z z z z z I 0 a Q o o Zen r1 I kil W IC p o M i ^ CO r1 N — N O b N Gam. L� E t b O��4 Q C C C Q p O O Q IQJa; :14l40 ��L++ W W W u2 W Lr7 •LjL*J W O k. �. O� �D O o Ch �O Off. c+') 6O N 1 Q U (41 I N — _ N Q V' N M o0 .-4 r1 N Ili U ...:4Z c1 Q 1 v ON Lit w r. w w w ..14, :Li :.L u. V. g Z t--' H H H H H i- H H — \ U .� Z 13 rn rn € U U U U U R C� U C� R U A 0,r u r 661 Cn Q d Q Q ¢ Q < Q < Q Q o a U 'v U U O D U U U U U W4 v r1 f 7 ' t'7 r1 M 'I"N r1 � i-I . I ' 9 4 w9 4 4 w w 4 w 4 4 Z- 1 o a o 0 0 0 0 0 0 0 0 j To A z C O o c h v1 on oO 0o r•� CI Q• 5 M cv o+ a J5 1 Jt u a O2 n r x E 1 I q _WP v t Q .: i z sr r m u go , I t = U < a ¢ < < uUUi¢ s Ir-. v y CDu o=o a 0— .�i U T.1. U C 0 y O W CN C4 reO O v) p c d] 'tl �Q C! 3 Q O O N 'O 5 O• x Q :3 c7 IX E� O/ n Q `� xc Nd 4 U < (, .o X = g C • n� W z F r \O J 44 0 z ,z ¢ O v U L l7 E.7 a. ai E 74 Ce w m a '' c w V O c u ,E O Z z '" u .2 r _ $ Z 8 0 :v n $ . O �, b r+y C co N O Q. M �O r'� C L:4 ss U D. a.. Fti 1S N a V 3 w 'I0 aG NO h n ,. O m I 1 vt. O. 15 I C/3 y 8 E 72 in z 44 C:1Ascent Images\Release to Hard DriveAAPENAB.TIF I S 0 - F o G > 6o 00 V a n u L 00 y J- � C - t Ott m� Oar ❑ .Fa o. 'AN z • .!,,:4, ..g J .. ❑ o E , a =' °� o 0. ¢ p. 0 t .2 � o H Z —o ct O DJ tit, c 0 - 90 — F- o. 0 0 z 5.c .� '` a 0 -CJi L O h m O N 9 W v % �.N x v ° °'B a v = y. a o2 "> vr W _0 E m ° a w u �C::s°J° 2m� ��85 F ; o v`ni .. v E K .1 ° ° o W ca u Q •E CC ti 2 '� 8°:.°E o.c 6C4 a• g� o U C OU V] To O G .° x � ucr Guommu `°u S ovo `a' 4 'L ti w >,�. o FesF .=.y d'n� 3 a F = Q N O 0.2 U.°$'y °uZi[� `� ma°i.00 c0 0 u.4 o� h s wn 00.u °5"--^J0)001 Q m VO�e W o 0 O 0 D0 i" 0.0 P. 0 L O W CO J-°QO O Q u Z`.1.5ca'- } 0 a m O Z7 `y' s'q Era E " � aai &000 � oov.00 :° ,a c ZCUE-do C4 IS000 'UUE O O d NN.,\< •0 A O U v di z N C N U 0a.00 O y n on Vp pa p0v O 0 m E FO - v 41: UavO 00 3 c Q o c ti 0 0 0 0 �W., Z Iii W N > o . u m z a CO W H E_ u 1 Orr++� 0 P�. N `` z 1 S— t4. b r7 V ij O z O U _ Vcy en W O c h N 0 w 0 h b a O Wy o (J IC p Q �']/V] Q' 0 Yam W W J .CV 0 y u `O N O .Z. "' s °a., 0 m cm o c >= o = FS- I:- F car: O 00 \ e a n v Q n v u a E O k 0 V E Z v rv 'N v .5 E U m z .E . W v m F `J F ,o HN C T '� GO C 0o ^ m T s �¢ oa� Uo¢A a p r]Z v v o n - U 73 O O rn 414 W o s` o v c N W vU E W rn F o .J ca. r, o 0 n z 0`Q' 0 a = 0 Z - rN u n.° u tnw 0 - O a w N v o v w < d m d co OO -.2OW V] U w m 8 u K a .- G< O W S �... _ W .00 o e u m 0, ,0 W F-0 W v u 1--I N v C-: W 6. O N -� C a {Oy a f W v) a E, N R w v Q g o y O x y Q o f z °,,' O yb JWo o cm S o � "� O o o QQaak °o= Z m .J ' v, o ur w' Z Z Z z U. a F m `C ,.. W rn E. t._ urn `-° a .° Z Z W oca Kf"" c uN41 rev v : G 1° Eo O O U W u Ett Z .U-7 U s °° u 3 _o o. I:4 I-.! 0 3 v fir' O O a'2 0 „ w -- nS c' i y g F-�� `� 3 " u o v •y -m Q °o s g rr�/ can:: c.6 n— y z X00 ; � CI)V1 a0+ � b (nom t ₹ twit °�� ≥- 9 tY' [— yy v 'L qv e0 Vl NCv Wz Om .`0 Wv OUW C:QW F-IUx � � Z gar- ; WUO uEC 0000 aTn OF E o :° aV< m .> 00 I... ty ZU o. T u v Q k aWz 0 m 8...8 W e O O 7 Z E a E °- m e rn c a O a v, >. tt) H C n c F v,jN_ `o v o r o. v W a J a E 13 Roo S Z c-t z 'E v, eCOP u Lt.= C K° . u: E- _� Z [� y F Z 9 Ci 'Ji-�E m °' 0a O o m u e6 2 �.' U Kvr F a C cE � ° K K �S 5a5 .. _ 0..0 �Q IA S Cu≥ U = F Ow vG c z w o `° J O Oau.. ,y, vp OO [- `a. � ° ,2 v t' c .c Z,74 a u WwuU 0 3 ¢ 'j u O 4 • ro tr., O ° N I - E .E .E 'z z O n rep,' �o OF x F- F .0 0 o E.. o o a c 0°�oqz = > wma O W H a0 Za x ° w °- U a o aCO 5 a CO^3 to°. Y- O v, .� re O U p' C S Q Z ,[Z[,Z..,,r W J 00. /� < v, W H O W a o w „_,L) t 0 v, a v _ Ocht �6 a U as Ni w Z O OFO W U o o d CW �F°- o d 7 z p °' W v g Oowe OZ Z z 6 W .2 € Z U .o. 0 Z .4' = ve, Z zc$a aF do U ti -a vd. 'a w G ;a O _ = U W.a7.,7 A u hC t < a4W .„ P] 2v V O Z v, ca Og � v, w o �A 0. 0 0 O 0 .100 Z6 wz d° .e _ n woe?, m w NZ > Uaaaz F ou0i l V s y N .o a 0 N O *E>" al E00 -aA D a N M Vy W o 0 o v a oo c7 = a Ea a a) x u.1 ...P.:4 y < ° �' .1) JD U d 7.--, I W cr 4) U x u U 1— ci Z N .c C U CC s... 3 rn o o E ° M c,, C N ICn L CU V V/ '.O C C o w f o—to H a = v _CC N G 7 td y am E .5 = I-- > a• = m u A Jo Jy V Q v O u a O m II, O oW U WE U O 0 0 Q � z o v` O - W a 0 - _ s J ', Ci a m g c I"" U -• til p C a `d IX °° U n O E w ° o a c _ o p W cd 7 u o n��/ o a; q L Ii = U E „ = o o b o is 0 aci Q 3 ¢ @� z 5• ca a "1 N E mai 4) g y H o W z AG ‘o C7 co u.0 a " cc HTo U_ Q R • 8 r o p u g o Zr,70 0 Z Z -411U m c a o O CO .. ¢ E a c z la. 17. -, c el cn O• °' O E oG a o a a W U y � w 0 a r4 2 w QZ v? i ° V c U io C) cu E u a E g U vp z s m^ I I Z 5 v n OF, 5 a I $Q >_ 00 ti 6a t� 'C 'll Ctn ._-> -g -a Q '� E a E$ m o v Z °QO J ❑ o E m Q ��„ 3 n v N d ..O. ❑ t- z o I 72 Vl 0Q ❑ E C 9 o d L. e m v E- n ° ❑ $ J 'it' Q HJ o _ a. E o 0 cd < V Z �0 c a` m S. aw y a q0..'Q F c yy�� H yW J.5 U O J o U 'a OU v• A c d X aIt a E c�u w a E m Ct E W 0 ,„ a O' 03°,,t m ti 'C�A 8 F=- 3 2 h . , m e g c0. i N C ..] O E o �'.c v ° > c v = `o c O A V] �° v Z ° ti U >.v°—. o= v y.y A u E u 3 2 00 `- Q " 0.ten cc 0 • , N W_9'» vvp ._ nJ,,o,r K " csc A Qmod rr+ `� U.? °cLE o o�[v `°�'_r O O ° °r,om . P. g W co t O -0 .- 0 . w v `v E 0 "c4`v v v o W m J-po A o z '� o v Q O `c i rt. a.° i.UEEEO Y C acob U 22m g u 3 .t^q 3 ... _ . UEr a000 °a `o o`.°a 4. O, q (� 9 Ecii ZC0F'�.c.rG�000 aU L.) d F Q., a s 5 o w ❑ ❑® ❑ ❑❑ ❑` ❑ ❑ oaE't (5 Q Z ▪ J o5s < °r O c S ti O "� (--1 m p U U z h LIi Lb Z °v9 C. p U o°'o > Er c q A ed .. v O 5 a -5,05 4U t-mv J A o �O m m rt m m m UQv0 cky e a 00 >.. ocam a o 58 'E w 0 0 O 0O g Ca iG N °. > SF h� c c c c c • c. F Z W W I: w e1 O Q 5L it W ° , Tit N > > > > > > ° a 8 H nN 0 U o. 0' v W � ti� w o ti� a Wg c:4 ° z o c ", z d -)Z o 2 �a s Cl J 00 O •o u a._ c y m F 'II- WW1 3 C o < = _— .< d> 0`=j9 Zr Ww y Z e ce g .22 z E=2 QCo O W WV E 5 -,N a E ? `° °my w2. `� G VF. `'°' V o E a o g V S _ .z.0 E V q .7Z Oct i U UQw a E W,"C a �e wv Tp, zIt g a W e°0 0 rec., v e0 n° C :4 tiW 9 Z c a O L•',c-O G v O C 0 0> Z i-i ...ice c 0 00.0 h o O. ¢ m v h 8(0�p O 00 OO _ _ ,0 a an (%] W 5 H t > C 2 t Q m u, c., m 0 n ct - U 000 � u., o vN u m v u:I— o 0 0 - o o W uo wo ---d v C a ON d m a tG 0¢F W 'n - ^ ' E= O �, E ° E m d '- Tr O .o.�.o w c 2 o 'oJ W �v�. J ;_ v z -� c o cm w c F O 0 00 .. Zya o R N ° cov F ° cLa d j F, Q y 3k `° c W Z W n a= ° F 3 a V z =o _ p 2 u v�o t_ �c v °? G a. O 00 00 — N _ U w • `a `V U° 3 N `� N V O O O t9 ❑ V J a U ry .5 g 3 .O m c o 0 0 - c o a u w• ►a O a u 0 emu. T. m V L a 3. Fj' O f �= a E-' Vl P: p y q L 'J I-1 c W 2 '� m ...! ° ; O �r^^ 14 U Q W y �o v'� 8°ii V1 N 5 m z o &.... 6ow < • 'Q9a Das 1--••i U � 0 ,c O z 0 3 P. 'awe ' 5 a ..i O FO Ual uJ �. ,?.9 '� 2 t v o Po QF.q - m -... C W W in 0 Om F0' Pam oo4o > ycv U � u, E02, :LI E € aim a O. e x z z •d. ,a2Fz Zrx 9 F5 " a0000 a=`- g z z LU w z 2 "e_g q 9 o v m o w -� a = w'E`" L o .o .- H 3 n aF o i v m z - Pw °w $ 0 8 oa�� a '� >,_ z o 7o H O g^ ° rg h ° '- • 0 z a T v WLL� V .�OO W 0Z ¢ " � 0 .o m F c 0 �' E ZQO m CO e2 ;.. w � �a o ° ° u�0Q2c o i ma =r O o �' m O Z m y a wyai i:Li "' w O� Uvi 0 w o U o _c4 Ts 0 m • A. U�o"' w ,7� O u0000 L., U 0 'o a V C g q w o g oowo r',r//' �-+ Z Q w n z O n z m ct z z 2 brrs F-i G � Z O2. V F. ... a v "- i N `a ° ,v U Waa v pa � r' ¢ Q rata a wx = ct o w 1 I a oz I ti a ± 6600400 . „ie .� r,iw ._ r. C. 0 a 00 Z > U 00.0. m F ,F+vv0i V L O a ti : a a a a a ¢ ¢ a a a a ¢ ¢ a a a a a a .y 0ZZZZZZZZZZZZZZZZZZZ E ' w •2 lO p Vl Q N O Z M M C 0 W m O 0 o n. Q o0 M :,, Ni — N N N O — O — — E ' O 0 o O o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0. Q o K w 5` W W W W W _c,:' W W W W N w W W W W W W W cz Q 21 ct U w v a r N �N p N N CO N O 0 . ^ M O Oo v, O 9 �y M O N CO N 00 O N V CO icr,n cs.o l� O Q _❑. 8 v O\ — ‘O M — .-. 7 M vt N — C N N — M N N W N r z U a O °^ F I 0 v, W k. O. k. LE-, [LE k., n. W W W W W W k. P. Is. W G. .c L1 c Z N O W W W W W W WWW W W W W W W WWWW U 1/41, G H H H H H H H H H H H H H H H H H H H ro O °' Z v rn a g -2 -2 Q Q Q Q < ¢ Q Q Q d Q Q < Q Q Q Q Q To- F d m g U U U u U U p O� Cp U �Uq 0.U (Uq U �Uq U U U U u U u „ O 3 F..,' ,22o 9 R+ W R' K d. W Cr, C E ¢ Q < Q Q < Q -2 < Q Q Q < d Q a ¢ d Q c C GJ a o w U U U V V U U U U U U U U V V U U U U y, V Cn e 0 ' V A' 2 z Wmc 4 g000000000000a9 9999 Zw 3 0 vW) o o r r W 0 0 0 o rn o ,W 0 0 0 0 0 0 5 i0 ‘O r V o W — C — — M )O O — co on N Q E c as — M — '. V1 M N — — — — rn N rn N I 'm w .. v. c I Jo o J " _ o ce O2 6 U C y O.V til w V 2 —` C.3 t w c W z 0 0 a W u L W N O - o0 9p ..Jr En- N Q oa. U P7 U Q Q Q Q Q U U V < < 6 Q 6 Q Q 4 9 Op a C co I- 00 a) z p N C n U c O N C v 00 C W C73 o Q. a C• x g a o 3 a; o W N 7 v,_ ,C N a) 01 C v o ce co O p, F m .p 0 a C:4 g i3 ,2 0 o O N C d S c N y N O E '7 y E O " °J C ?U 0 ��0\ z E ro c v r y a> v aci c ❑ '2 .-- p •o c a ' p a1 W z a4 a C7 a = W W ¢ a co C a H J( "'� ¢ U v z aco ) U Z s x a a L •• c O U U 0. o .. c cli a) i E O C a Q Z z b m o O CN O Q C0 a. y a Z a C 0 'C y v' C~ R. O• C d � .Vo C O N ("1 M O b 00 N V w W• 'O CL C_) a a W ' EN oo N �O O N '71-VI — 0 0 Vin) W co rn 8 E O O `° V y C N a) • E U 7 co z 1 m^ _ T ° V m > >= 0 U no° .§-1"--8 c 45 2n > �G 23 Q a €,o c H z v'i ¢Q0 . H- g EE a z Sr,. 3 ° N W u Q c W H 6 ° E T., Q € ° ° h. z €i Q °,2 L Q .n a > `w42 Q V `" O a .°, y d tic- c o cm) U oi K h .c PP c oU ° >x co� -E u X $ 0 I o c >$u W 00 m a E m o T 2 V9 v. 0- • 0.07 4°,-0 xreb " u .00 v.� e F 3 a ° me. CO C fV 4; J�7 O C O �.`v p,> °u x p > ° Q ti — .c. g u. 2 Q e.?$ _nc'yw ua•� u U - tU a V] N '04 O o D U ° `pct ° �°nm .. € v ° Q- �/ Z W Ty:,N n' F.? u t O rn °°' N v xo$..4 E3 °w E mach" O �000 O o � �+ ° ° F U.� Eo `�aw .a—t u. C m.h�n_ U x m o „, ,,,o,...2< 8 m 4'� 3 u.=° WIvi a,c n.E•c o > „ ,-,u u `2 Q ° y°..a W z � p ¢ O d ° o � m4, n,0 �'u ao.o.ep > Q a2y no F .Z. Q �Zy U HQ v VL - 9 N n0 0 0 0. °° ,0 �¢., a � �+ f9 y E ZCUF�a CNUUU yUU . up a. L4,' H .7 Q w c 2 C0 0® lD U' o V' " x1-1 0._Z^p Z '� v O 05 to N o z 0. p; N d ?� 1 mao v c .C u c nn nn o PS 3 .� 5 '3 m A ims p W �COp I� UQv 3 w F. w a w o Q o o o o >4 O 0 O 5: .'O a ti v v v e o° v z F W > NE-. W c c F c e c p Q V O H .2 hN u w 0 co t 0a aG 4• °. Z ° ^ � ¢O p F -► .- m o 's X > F F Ww f-" *, = 51 2 ��m Q o°°' E O E Wr.V E ciN '� c *PEm Z' �— � W,C 0 CJ F;, w 41 n " 4n. .E °Qa C ZrO t al g t°, �2 0 U -g; O F .a z o 0 �, Q a1 rn cx x ,.� t N m u ° u, w 'S 1 \o U 0 F e [i . pTp, w FH z oQ `c 000 rry ,� ta DA vis K MW o° OU y x g c m v v-,a0 0 < ^ �W up `0 y ut°. o > vii C 0 N a' 0 _ 0 o rn cN o 0 U ,,Z o00000 w uN u m u ,.“-n a O a O G G 1 u T o LL 1?q F^W Q a Viihs-- a 6'm tA 2-51 Z p0 t3 o o u eP W y c F�� O °4.-oc U F = u n 'a cn W Z Z .W R 9 e o 3 0 ° , 4 v o F7 O 0. UV 3� '° K in ?: 'd U F' 088 8 g o o U W =Lt. 4 C-J c0.4 , a 0 0 0 0 0 U au"' T: S y° 3 -_ e O "1 O u ciS -se 'I."- Li. r nF in K c as 5 up N m .16 i z a ti tai] % (� 'e a ! I U cW � OzO o °N 3 .W7R7 9Ee x.c out.) a m 2 c n o �, <"F Q A 8 Q;' Fn W p o' Ow a ,�, troGyy 5 -0 0OF. Q vigo rm W o H 0 ,,, @ c v F Q E 0. ° i°41-1 c v L 0. f-� w+ c c4 W U z ‘o w F z o U wig. O U U a N a c v c •- '� O W a O b p y�y^] N 1._ C qC, O O O f[:-S1�p'6 O .§ a G u E > z p � o i " c E z .. ow U$w�!Fa $ U Sao^ . ‘.-1 ,(I `n [3j O N O ai O 0 P. ,..1 ° t' Z'.7..] v ,:m1-$F. U N W C Z Q R 'Z O N . m 0 ' E Ogla T P V O e ¢¢� F O O c O ❑v ,?C r z W a c° .42). .. O [i] C Qa i o A Ow S U a W O F .�3° u y-1 a OU a 0O U �-°, n. z CQ�+ '° W;twa /� Q `w E. U W 0 U. o _ y o _ 0 N Q a0 U s o`^ . 1--I vl O Q c w c o e a c p W w ° °' $ d d a 5 Oo ° P QE. ao 6 _ a z e zaEmW XL'O rn .0 a a v d C. ,3 O 2 .: 1.7.7 n u z=c° to � .iaQ m56 aim = cs Q w a oz a o 5 ooaOapo K n w k7 a a s to z > U A.P.O. cn F 0 -Q.�O F^W" UOt�+ WlH s 2D O ce 6 -EH 4=,G E. i. W 5 HO ¢ F = OOU W ' as DOE O..r4 �C t�T'Cw9G',�y Ov] w O ,.n....; d G ccll L i; QF5 2= i—wctv1 e, m C ;a cOU >F k '3S..W OF C4' Bc a°UO E Ug L rt as OU£ ZZW .2o. auwF{�7 o '� 2et = V) -Mg j . avc.7W 3d4 O7Q0 7F u Q 4 aEe c4 Q Ww>y ay! .' T-� O ..p aWoa MO EW ct<aHx w o WW „4ULGW > c H O.7W .7 ..z c OaA0 gt bonm 3q� 3 $r s kiiiW7 w 2c s av°y p''L4G ,�c/'` 'I VA 'ilk. 04 w a( =U� a oWo,,� b A d. zyk)-„ mZ V>CS ;4*aE Q ma En8 _.,.7C4 44,, ¢��-g ** vA aQ a o. 1 Wo1; 5 5 4Q 5�°0',44.1 dj o_v- �r C;Pnp; 0.O WW o,40 h� =,..=opera '�•-o ,t ". pEV wUO OF y0. m Q a 61Fo o '-P.ha m u>v 0-o A '>'->' Rp2^ �oQ,i4mQwr, In6o-fiche r > >U '.74. WZ�FS. Ed. Q'a0,w c w,„tq.G; O oLy5 ' an a°4w wa OaOo z7WUC 49 Z1wx0.0 Z vc4 .. ac mQa z-ciz o6'Q E-5/g224)%3 WE4 Gs © c.o s ..zgti EI w cdL (4 0.11 c�o`>.3 -^c ^ .3e u y g = uo.v _o ,9 •ov. .o^,n.... WWWZk i . Eoc E_ 0 0 ord '.e -0, o..-E - Ny 00 o o-a W = v O . . �.., v S yr e o e'r `c o c E rZ'COypa �i s�.4 s`•�U e'i 4n 9 =8 ,., _ `°0u 0.E-. cv v =o c -2:ate`e F o,., o 'gn vo. _ .5 o ot.- c c cE_ cH 0 F W ogE _ '4`;'8;5 o "Aa _ m._=uu p uy _ 3,_-cc DZ 42H.,4- Es-E .. big uc. L',"y EE,�- m o.,n-Oc V.. Q�., doo o°��ra2 yw.3 two -�'°m� ,o avC -25E oa V .2o'u'= wo cooO9°E QO,,tC: oow >U t° o 0 w.d g s °'y cc b 04 °.v.'=ccd. °'ooro V ovos9n U4CWU0 ww 5 �'E ..Y4 u c'- 5v L>; m--= Z We o-ou ag,., E xc o_c o� cu. —n '1`v 'Su 1° x o_>rE O `�i -0c ..a.0Eg O c €. w ...L'ou.v u 06 '0 co``5.E .°on o�g vK Er. L_.--sg= FwcS4 �i tE °rm.c3 m -v, 5n= u. 6 o u'a 'c°`0$c °).:° V,u zEvot of o> to o8w-��'E.E O�wZF O _ 5=v c•- o E c c °dy 'cm 0n. o A0 aO . , Ev v , '5" 5 e� o,� kjW'O 'cm L y .F `7 ^ '- 5 it- oc 7 suuoa Z ooE.oO 90 ng Em. rn .npQ. W c•.° 0E., o c BE c c u IA ya uU m"3c_ U =eT U- .c,8 m1 =vc 7 ° a. n-via Eyo, v yo—. 3 g cv _vuyW c.- urv^^ca'- �fXWW�( W ' Ln Z. ,.= F-wun . .. c LnE n.. m n.`.> s .oT n"..v1 a.g E�9Hc?:E Op�Z n ^r%-E "c ^� o q- u. v�2E W o"g=v cr G V `v g= Rynosv ° .5 a�� m .- c o'n m r°.$- -;:c3g E on o o`E ay c E5 - to. vu O mp g c c 0- O v r c `v ca o,g oo 'c vLAcn WrnK, nog Q E c o-^ wo v e E $ .- dIfi n ac �u cos- c C �-• °>`a 'vog °o� o U o5 �O pt ` c0..�'� v.. • a U' cm ov "ms Tacrc °n = cd4 S,nWFm es 0 Aga) a .. `0E o ai _u._yc 'a^' d N E-mem c.� �1 _ ,a u v cg"G�u-u F.. 7`_ U vu C C ° V t , F 'J�, A L o... :: m y u x Tn va o cL o-_no_- '0 'mE4-'> F- '°,•w.g E u E S _� ._�0.c "a o,..E v� oy s n 3048 AL ki .-.1 p_m n m" O' yc rn5 1 uo..ouo F01 V u c 0=44,��7 rig o'- u.�« Z n .. p mma n == W 'Egad," ..0 uy U-u Z .22; W _ Z€ E 0E.= ��`�,,; `E= v �A -wc� O cg J.. §'0'0' off..._- a soya U� c .ec ° ; uy E.. 9u $.-51 ° u °-! c> -^u 5 cm xaEoa s Q� 4w`• a` 1 co ,.`7). vn z 'w..�°o gg om O v1 drat g4 a u >vc uC 2 m .- G z n�5 'r.-a'a TZ c2 ue H2 Z asgraar E°o'1 4= -Eig.7o yn O gg'tc n cu . cEa 3OaZ0.FE C),16:'5 =$ v-o o,_u 2• $m.. . .-13::: o c �a .ouAn" n°„ nc o' .°`3 Eoc u " ro3 R Q�. °o a-v ° .ncCxa 5,nW`� °s' 'c`° c n '-1 4 . o�. .. ..oho- 4s.O. �`. v Q � Em oc9 ON `v, ° sop = v a Z- ��>� ._ c u >> a �"•' fig. ENm .va 8 c o Pc u..`2 c `� n cAo- a o .4'6 2" E . g O ° yoc c4 a' u 2 U. cA U0.v^cicg .o' -c SEo, m o v v f] ..9u 0 w Oo v qa V w�ouc o> m� c.. _U k: Cn- u-._ E Tizn u E .�v o EE$E" E OW"7 :;711),.g . ° E67g U ..uvd H .`5.4. 5g U * 1 osm�4 O.E,>.2 n 1 L' o° z omc�v 'oo v"cca m .7..V,OQC c '>^o .r4. o y v C u = s c '$n"-8c- m o o�g ,- 5 c o F� b c o w'5 Ai `• v g,u 0.m UE - coxcN5=v n u°, o, oEdfi > 6 7 "4o v vswu vi ono.. `u ev>ZZ> ro i O 10_5°>} o` wuEcucE 0.`nCSZ 4.)4" ;Wco._ 4 ,-, u U5 °u - 'E y 5-5m° r c o o W° C E E U ca' UE c oasg-g. .tEx OL .03�'- c c dS cccy a1 w5`•o o° 5c.... E uE u�.E�.?c ° �o'y'ii o c =X,co1` l' ._ou„� 'd 4 yE r1 oc�"Q `v Nc��'^_� WWV`n�„iL z =u_ ". 4.0 'cgs c ,2 °� 4,2:467-E a ,un plc cu E ._ a vu2E� .`i Es a W`�W t 3e�l cIuv Z`c>c v E u '23 d 12 mg, v1"+n 5g g 5 E0' Qgt. c m d o v o o�ycov g vE5 n 5c c 'c_'� p goon ≥ Ec"vn nu ySOS..t 5mg OfE�Ca._Z 0 04 v ¢ 3 x N rn rn5 Nro w._^,.. 0. WucE C w':5E O 4.E 0. F nEr1 Oc' wcc`.dw Ac F.7UOi Q 'gEn E y- G 4 nvC , *4 ”D *4 ""No °v C,� 2. O O O NTU O N� =c0 u6 ' y 2L'�'- it oZ1. =.Ten v, ,.:,g" ,� oa s— u� 1Eg = asr E o E— �°a.= .n .. c•og d onr,`v, u a`�m= s v,`d rog g co 44 ..l2- Ec `n F2;t: c w .EO Eau o u>aniu c 3030' of O2>- ° .ME . `v .' � ZZZ E.._c `u .. .s v, v ..tb ' nuE s3 ors 2 .° o. a a' ,c6 ,ea' v—co o c v .uRs E"' w o—.` >` -.2gce'o '9 y.E 2EE 8 oa o re a-=r � aE� TE uNnO�°--, o v €E 3vu 'E0 u 13c D`�wc o co =L ^5�+�[i E gF € .0 u. le, Nyvy �i `°u'°. a m nc.� .Li.�t .v.H Tcus5 �m5� c„ vu NEo u"Z °c ` o cW Q3'> %� a'iyEo A E vs g :?r `�$._u ? h.≥v° O.v a� ..c� C c0 x*...m �`s ° Ed c m 001 SE.m"ni ' = 33; o> ihen ..,'U soar go' z —� o ≥ u°` Su= °ng W .c u0"c - az 41,.-0.0 gE ys v o> c a W Ov.c a� g-Er vc �y Z3u Sg >...og vc v U0. g T s` z eat >ZE g3A.m oEn >. °= vd `ou 4.x-00 v3 oom �° o= 0004 c vd E `o v c ?°N W `u.°i`cc 'E �A g> 'nT- E'L vim_ m' a' cE o'u soy o m n = m .. .70 'Z-�n2 >o v 8v ° o, 8E 0- °u.3' °oc'm c0 nmoo t...m be "s'`ct O E .2t) E " o E* " wa . vac ao .`o_ c— 5 .g Ec o. a u- c-v' gu,�n > 'e ° 2 c_v _ ry '°> a y u s °,v. u -rag. i.,°, o2 5 o.`°.'-'v O4- o o o rr 0: cL �. ; .Et Q'» girl- ug c oc °o n';' ,y .°c'? TE Ow nE. v o '',1 Eg c axr u E an .n Eg a .o °'.`-' Eic'0_ 'G couc .it. z . M$ 5 0' 0 E w ° .'5.. nm 52 a 'e a u .. 9c_ --g c w C E _5„E g ° a �i Fo.°> .Y4.o ->'r .Eno a Eg .° a '.3 \ 5 8• c`o c ti 5&.-u+ E o r. L e+4,o Zc.� a'n5i° y_ y g0. EE=q.°. —= HZ$^ C,1n c$.ow o€- �_'`'> O vQ 9' °° o Z �.�- c. • mJ-u y g., j'H.-y ou sN G .Ear OP =Q yo p.-. :cz,cc y._v ' ..SQL 5o x 300 o,°a eg o .nu 0] - 4$.. t§ ag a' 2 3 L 2 *. ti ,.. ≥,., 17;gb .m a gL° av2.`EE o '.oyg Za`nr 'E9€C ogo R ou, ' SE 8k F c� �� m V 5 •_ ECi 6=° j= u .p EyaT T uQCC �.,Ta O oo -ti 9 a� LA o G T 80 -o0 5$ E...N,.7 E,' c �v -sA vo ug>>c v2 ua.o 8 W o`m u cp xuHa We° Nvo ¢o1w fG E ^' o ` o O Wsu =as a.5 acroo quo 'w.` "5,' nag, 3� 3go 3d El._¢c o,-, C O > .:3 . `c. °H F'x a Z W at.= o >. Q=Eno^ c .4: S .eh..— `nu g o y;E o W �E AAu x .`v. o mh v Lr - rwncm Tut 21`°5-0 O vg c ogo< gam, E- o go 00 ,40..E 5>O Z o.e °v�E a v p"= �� Ec 3n oA .. 2 Q1g QE� >nn.n U o oen oc ogeg o0: .n•`d� °o_ v_r W €=Iv v'�3sv F .•33axr cm crpr -2 o ,� n '>0 uo u`o `m '>n .`,a '>d=g co.. vo..o._ coo cc4-.'^m W U Z g co&-..a co Y F- —g >g 2 a . .7>"_ C_.,-,.O a::.c„ov a?r as a4 a°aR nCv..E .; m ri U y � h } ZZZZZZZZZZZZZZZZZZZ E s n 2 o ? � 0 O v; Z Mtr) W y O m 'E r% 0 9 9 0 0 — 9 0 0 9 0 0 0 0 0 0 0 0 o Q Q U [i th ca c O N. rn o W �'? 0 0 0 cc k o 0 o W vvn `° ry Q N N ^ M v1 '. .r ,D 7 vi vi M N O, •,O ^ b LU 4 Oo v R a (J N z ^ a Dccu 0 Co F L R rt; w w w w w w w w w w w w w w w w w c.1. w .C ^ C N p w w w w w ww w w W1 w w w w w w w W w wU y R N Z .b F F F F F F F F F F F F F F F F F F F �c .. Zii en LtF'a ,o0. • 0 U U U U U U U U U U U U U U U U U U ,. m F co w Q a Q Q a a a Q a a Q Q a a Q Q a Q Q d U o U U U U U U U U U U U U U U U U U U U y z'2 U U W cC000000000000oao0000 Z▪9 I w o 0 0 o rn o vW o 0 0 0 0 Z u w• = b b r V o 0C 7 ^ ^ M b o o O, N r g �v O ^ ^ ^ ^ ^ M. ,O M v-, m VDN ^ M N N drc m.II DE. m O JO C J 2 V 0 6 u N O U S u 2. Id.C U uc orCL 2 alo c Q a U o w4al J 0 m m O UU 0 - ucaUQaaQ ¢ UUUaQaaQaaa o R Q Oq u c F. co x E p U re N W G E 0 Oa. E u U W 'co JG D a `D U W 3 E c UP4 = z .C is K v '? v ,a ^> v ❑ R G 'E D m g Z .II '7 4 a Q a Q = - 7 ro o t FRF o o >, 0 -a c o S o y ce a 0 N n u [i n ..c $ a co C P`. F, X '.� Q U x Z `� a ° d W z Ri C7 m t`J Z W Q �y ° .� .a.¢ R e O O U_ CC L 9 U d Q N N N L U I E z G v u, O Z R O D ~ 0 O Z R U a Z g ,0. o T U p Z a `� cc x a R G d E N OF n Z M wr O °° N O O\ M O M w w' 'G C 0 U 0.. 0. W .z � N O O N r OO r O M , �°. co 6 D w U D N N N pJ U m m E m 3 cn --. Z U u o o c 9v 0 A o v c E 0 2 Z a 8 E S cn ° U U s v o a 1 Q 2 c 7 ° 2 c t.-).' o 8- 7 a •6 C C O o T O O m 3 y .. E _ o 4 a ••2 a 6 6 .. • s s ° a o 0 r a E _ 0 ° u y 3 r'J .4. 23 0 E o .,$) ' $ 'c a. A c - . v 3 e c Z Z ro H O A u € 8 2 KC � a o ii c ' t9 w W 3 2 2 .y c o c V n o i° 5: ` g' V.W.1 F z ... .D t. ._ c rn pE., o v v .Sa E ro °c O a Z `o E m E u 1° ° m o a T. a 5 E r d o O w it 'C, v o �' $ m .O (-/1 z oco T $_ c u E .y r8 2 L w 0 O 0 v b' l o. '2Li WW W v 'W .2 ° v 5 .O (J - 6 U C L .. "- F L R tn N T 0. k g E- 1-2 • o 0 8 — E 8 � 0 a E' A € 2 as >. a Pt a OD v t8 a `� _q Z o..• v .E c o a q z r o g c° a_ a per, c v a y v E Q c 'S c C E `5 to v .° o Pa▪ 'E a v u € o a. e C E C H c O V O T 0 6 C Kj OCO C O C y O2 F1 O {6. E u 4N°i .0 w a O U 00 OL1 L4 a i° • [-• 'E ° • $ U d S 2 _ U _ 2. 9 -it w., E64 d 3 v) 3 ° E . E 0.1 go F Q C $ Z ro H ( g h ct y i U . m c .y .E .o v V y VQ '� y '° .� E v o o Z O = °- a.. 10-1 a c X v m v 3 0 z v c u� u a a pWO qW OfZ a, c • o m c i° Eo Q Q u o. '`�loo .v. ._ v tt) ca',L Z n o .� m 'o . c O u d v o E dc F z o 62 . g 0 w E 0 0 s o ° wF y w• C m i *'J Oy ` 2 . CG u.. 0.. y� d N O -Z a yQ v u $v $ v 39 a. x y o $ v o= E •v a g m U m n s �• `° ° E m H C b m E Q `u - g u '� ' c .0a t n pj W o b y 2 E 5 a W ° ° E c ° Z O z ° = 0 .= a E n _ A taa .M a 6 v c E fi a a `u c O o 0 O. o a w s av.2 a. v u C', E a 9 a ° a vE £ u 7 W v pE a.o W E Q c u c= o° fs7 0 o y E .. o E r ° = ffi v u o ti >' v E a o v t a C .. c a O C •E c a y z a c u o o e uT� a r ' U W a c. U W e W = c a !" Appendix B Existing and Revised APENS Appendix C Current Permit JUN 23 2004 4: 43PM CALPINE MARKETING AND SAL 720-283-1607 p. 2 • • STATE OF COLORADO COLORADO DEPARTMENT OF PUBLIC HEALTH AND ENVIRONMENT AIR POLLUTION CONTROL DIVISION Mc TELEPHONE: (303) 692-3150 ��Y 1896 x CONSTRUCTION PERMIT ERMIT NO: 02WE0228 INITIAL APPROVAL DATE ISSUED: June 23, 2004 MODIFICATION- 1 ISSUED TO: Rocky Mountain Energy Center, LLC THE SOURCE TO WHICH THIS PERMIT APPLIES IS DESCRIBED AND LOCATED AS FOLLOWS: Electric power generation facility, known as Rocky Mountain Energy Center, located at 6211 Weld County Rcad 51,in the Southeast'G of the Southwest%of Section 3',Township 2 North, Range 64 West, in Weld County, Colorado. THE SPECIFIC EQUIPMENT OR ACTIVITY SUBJECT TO THIS PERMIT INCLUDES THE FOLLOWING: This is a facility-wide permit covering all equipment / activities at this facility. Details of equipment/activities are given in Attachment A. THIS PERMIT IS GRANTED SUBJECT TO ALL RULES AND REGULATIONS OF THE COLORADO AIR QUALITY CONTROL COMMISSION AND THE COLORADO AIR POLLUTION PREVENTION AND CONTROL ACT C.R.S.(25.7-101 et seq),TO THOSE GENERAL TERMS AND CONDITIONS INCLUDED IN THIS DOCUMENT AND THE FOLLOWING SPECIFIC TERMS AND CONDITIONS: All previous versions of this permit are canceled upon issuance of this permit. 2 Within one hundred and eighty days(180)after commencement of operation, compliance with tie conditions contained on this permit shall be demonstrated to the Division. It is the permittee's responsibility to self certify compliance with the conditions. Failure to demonstrate compliance within 180 days may result in revocation of the permit. (Information on how to certify compliance was mailed with the permit) 3. The manufacturer, model number and serial number of the subject equipment shall be provided to the Division prior to Final Approval. (Reference: Regulation No. 3, Part B, IV. E.) 4. AIRS ID numbers (for example, "AIRS ID: 002") snall be marked cn the subject equipment for ease of identification. (Reference: Regulation No. 3, Part 8, IV. E. (State only enforceable) 5. Emiss cns of hazardous air pollutants shall not equal or exceed the thresholds for applicability of Federal Maximum Achievable Control Technology(MACT) standards. Prior to reaching these thresholds, this permit shall be suitably modified, and standards complied with. AIRS Facility ID /23/1342 ver. 2/00 JUN 23 2004 4: 43PM CALPINE MARKETING AND SAL 720-283-1807 p- 3 Rocky Mountain Energy Center, LLC - Rocky Mountain Energy Center Permit No. 02WE0228 Initial Approval- Modification-1 Colorado Department of Public Health and Environment Page 2 Air Pollution Control Division 6 Visible emissions shall not exceed twenty percent(20%) opacity during normal operation of the source. During periods of startup, process modification, or adjustment of control equipment visible emissions shall not exceed 30%opacity for more than six minutes in any sixty consecutive minutes. Opacity shall be measured by EPA Method 9. (Reference: Regulation No. 1, Section II. A. 1. 84.) 7. The emission sources are subject to Regulation No. 6 -Standards of Performance for New Stationary Sources, including, but not limited to, the following: Part A- Federal Register Regulations Adopted By Reference Turbines referenced under AIRS IDs: 001 and 002 are subject to Subpart GG- Standards of Performance for Stationary Gas Turbines: Concentration of Nitrogen Oxides in the turbine exhaust shall not be in excess of 102 parts per million,volume, dry basis, at 15%Oxygen. Concentration of Sulfur Dioxide in the turbine exhaust shall not be in excess of 150 parts per million. volume, dry basis, at 15% Oxygen, or the fuel combusted shall not contain sulfur in excess of 0.8°/0 by weight. Duct burners referenced under AIRS IDs: 001 and 002 are subject to Subpart Da -Standards of Performance for Electric Utility Steam Generating Units for Which Construction is commenced After September 18, 1978: Emissions of particulate matter shall not be in excess of 0.03 pound per million BTU heat input. Gases discharged into the atmosphere shall not exhibit greater than 20 %opacity (6- minute average), except for one 6-minute period per hour of not more than 27 %opacity. Gases discharged into the atmosphere shall contain less than 0.2 pound Sulfur Dioxide per million BTU heat input. Gases discharged into the atmosphere shall not contain Nitrogen Oxides in excess of 0.2 pound per million BTU heat input. Auxiliary Boiler referenced under AIRS ID: 004 is subject to Subpart Db -Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units: The boiler operates exclusively on natural gas, and the operation does not exceed 1,900 hours per year. Gases discharged into the atmosphere snail not contain Nitrogen Oxides in excess of 0.2 pound per million BTU heat input. AIRS Facility IC: 123/1342 ver. 2/00 JUN 23 2004 4: 43PM CRLPIME MARKETING FIND SAL 720-283-1807 p. 4 Rocky Mountain Energy Cen:er, LLC - Rocky Mountain Energy Center • Permit No. 02WE0228 Initial Approval-Modification-1 Colorado Department of Public Health and Environment Page 3 _ Air Pollution Control Division Part B • Specific Facilities and Sources, Nan-Federal NSPS Turbines referenced under AIRS IDs: 001 and 002 are subject to Section II - Standards of Performance for New Fuel-Burning Equipment, • C -Standard for Particulate Matter. Discharge into the atmosphere shall not exhibit greater than 20%opacity. Particulate matter discharged into the atmosphere shall not be in excess of the rate calculated by the equation. PE = 0.5(FI)-°'2° Where: PE is the allowable particulate matter emissions in pounds per million BTU heat input Fl is the fuel input in million BTU per hour. D - Standard for Sulfur Dioxide. 3 -Combustion Turbines: Sulfur Dioxide discharged into the atmosphere shall not be in excess of 0.35 pound per million BTU heat input, Auxiliary Boiler referenced under AIRS ID: 004 is subject to Section II - Standards of Performance for New Fuel-Burning Equipment, C-Standard for Particulate Matter. Discharge into the atmosphere shall not exhibit greater than 20 % opacity. Particulate matter discharged into the atmosphere shall not be in excess of the rate calculated by the equation: • PE =0.5 (FI)'o.2s Where: PE is the allowable particulate matter emissions in pounds per million BTU heat input Fl is the fuel input in million BTU per hour. In addition, the following requirements of Regulation No. 6, Part A, Subpart A, General Provisions, apply a. At all times, including periods of start-up, shutdown, and malfunction, the facility and control equipment shall, to the extent practicable, be maintained and operated in a manner consistent with good air pollution control practices for minimizing emissions. Determination of whether or not acceptable operating and maintenance procedures are being used will be based on information available to the Division,which may include, but is not limited to, monitoring results, opacity observations, review of operating and maintenance procedures, and inspection of the source. (Reference: Regulation No. 6, Part A. General Provisions from 40 CFR 60.11 b. No article,machine, equipment or process shall be used to conceal an emission that would otherwise constitute a violation of an applicable standard. Such concealment includes, but is not limited to,the use of gaseous diluents to achieve compliance with an opacity standard or with a standard that is based on the concentration of a pollutant in the gases discharged to the atmosphere. (§60.12) c. Written notification of construction and initial startup dates shall be submitted to the Division as required under§60.7. d. Records of startups, shutdowns, and malfunctions shall be maintained, as required under§60.7. e. Written notification of continuous monitoring system demonstrations shall be submitted to the Division as required under§60.7. • AIRS Facility ID: 123/1342 ver. 2/00 JUN 23 2004 4: 43PM CALPINE MARKETING AND SAL 720-283-1607 p. 5 Rocky Mountain Energy Center, LLC -Rocky Mountain Energy Center Permit No. 02WE0228 Initial Approval - Modification-1 Colorado Department of Public Health and Environnent Page 4 Air Pollution Control Division f. Written notification of opacity observation or monitor demonstrations shall be submitted to the Division as required under§60.7. g. Excess Emission and Monitoring System Performance Reports shall be submitted as required under§ 60.7. h. Performance tests shall be conducted as required under§60.8. Compliance with opacity standards shall be demonstrated according to§60.11. k. Continuous monitoring systems shall be maintained and operated as required under§ 6013. A copy of the complete applicable subpart(s) is attached. 0. Best Available Control Technology(BACT) shall be applied for control of emissions of: Nitrogen • oxides. Carbon Monoxide, Particulate Matter(and PM-10), and Volatile Organic Compounds. The following have been determined as BACT, and shall be complied with' Combined-Cycle Gas Turbines(AIRS IDs: 001 and 002): Nitrogen. Oxides: Dry Low NOx(DLN) combustion systems in combination with Selective Catalytic Reduction(SCR)tolimit the hourly average Nitrogen Oxides concentration in the exhaust to 3 ppmvd at 15 % Oxygen during normal operation. During startup(a maximum duration of four(4) hours for cold startup, and one(1) hour for warm startup), and shutdown (a maximum duration of one(1) hour) concentration shall not exceed 300 ppmvd (hourly average) at 15 % Oxygen. Annual emission limits include the startup and shutdown emissions. Monthly average emissions of Nitrogen Oxides shall not exceed 0.01394 pound per million BTU heat input. Carbon Monoxide: Good Combustion Control Practices in combination with an oxidation catalyst to limit the hourly average Carbon Monoxide concentration in the exhaust to 9 ppmv during normal operation. During startup(a maximum duration of four(4) hours for cold startup, and one (1) hour for warm startup)and shutdown (a maximum duration of one (1)hour),concentration shall not exceed 1,000 ppmvd(hourly average). During the first hour of cold startups, average concentration shall not exceed 2,000 ppmvd. Annual emission limits include the startup and shutdown emissions. Monthly average emissions of Carbon Monoxide shall not exceed 0.04537 pound per million BTU heat input. Particulate Matter(and PM-10k Use of pipeline quality natural gas and application of good combustion control practices. Emissions of Particulate Matter shall not exceed 0.00735 pound per million BTU heat input. Volatile Organic Compounds: Use of pipeline quality natural gas, application of good combustion control practices, and oxidation catalyst(used for control of Carbon Monoxide). Emissions of Volatile Organic Compounds shall not exceed 0.00293 pound per million BTU heat input. Auxiliary Boiler(AIRS ID: 004): Operation of this emission source shall not exceed 1,900 hours per year. Nitrogen Oxides: Dry Low NOx(DLN)combustion system. Emission of Nitrogen Oxides shall not exceed 0.038 pound per million BTU heat input AIRS Facility ID: 123/1342 ver. 2/00 JUN 23 2004 4: 44PM CALPINE MARKETING AND SAL 720-283-1607 p. 6 Rocky Mountain Energy Center, LLC -Rocky Mountain Energy Center Permit No. 02WE0228 Initial Approval - Modification-1 Colorado Department of Public Health and Environment Page 5 Air Pollution Control Division Carbon Monoxide: Good combustion control practices. Emission of Carbon Monoxide shall not exceed 0.039 pound per million BTU heat input. Evaporative Water Cooling Tower(AIRS ID:006): Particulate Matter(and PM-10. Particulate Matter less than 10 micrometers aerodynamic diameter): High efficiency drift eliminators to limit the drift to 0.0005%. Emission of Particulate Matter shall not exceed 0.42 pound per million gallons of water circulation. Distillate Fuel Oil Fired Engines for Emergency Generator and Fire Pump: Proper maintenance and operation for all pollutants, Emergency generator engine will be operated far a maximum of 100 hours per year, and the fire pump engine will be operated for a maximum of 200 hours per year. 9. Prior to final approval being issued, the applicant shall submit to the Division for approval an operating and maintenance plan for all control equipment and control practices, and a proposed record keeping format that will outline how the applicant will maintain compliance on an ongoing basis with the requirements of this permit. (Reference: Regulation No. 3, Part B, IV, B. 2) 10. This facility shall be limited to a maximum fuel use rate as listed below and all other activities, operational rates and numbers of equipment as stated in the application. Monthly records of the actual consumption rate shall be maintained by the applicant and made available to the Division for inspection upon request. (Reference: Regulation 3, Part B, Ill. A. 4.) Consumption of natural gas for combustion in the two combined-cycle turbines, together, shall not exceed 32,625,000,000 SCF per year. This is based on a gas heat value of 1,057 BTU per SCF. Consumption of natural gas for combustion in the auxiliary boiler shall not exceed 231,882,687 SCF per year. This is based on a gas heat value of 1,057 BTU per SCF. Consumption of distillate fuel oil for combustion in the emergency generator engine and emergency fire pump engine, togetner, shall not exceed 6,620 gallons per year. Wales circulation in the evaporative cooling tower shall not exceed 91,595,260,800 gallons per year. Compliance with the yearly consumption limits shall be determined on a rolling twelve (12)month total. AIRS Facility ID: 123/1342 ver. 2/00 JUN 23 2004 4: 44PM CRLPINE MARKETING AND SRL 720-283-1607 P- 7 Rocky Mountain Energy Center, LLC - Rocky Mountain Energy Center Permit No. 02WE0228 Initial Approval-Modification-1 Colorado Department of Public Health and Environment Page 6 Air Pollution Control Division 11 Total facility emissions of air pollutants shall not exceed the following limitations(as calculated in the Division's preliminary analysis): Compliance with the annual I'mits shall be determined on a rolling (12) month total. By the end of each month a new twelve month total is calculated based on the previous twelve months'data. The permit holder shall calculate monthly emissions and keep a compliance record on site for Division review. (Reference: Regulation No. 3, Part B, Ill. A. 4) Particulate Matter: 146.6 tons per year PM-10(Particulate Matter<10 µm): 146.6 tons per year (includes condensables) Sulfur Dioxide: 11.9 tons per year. Nitrogen Oxides: 246.6 tons per year. • Volatile Organic Compounds: 51.3 tons per year. Carbon Monoxide: 785.1 tons per year. Formaldehyde: 2.D tons per year. Total of All Hazardous Air Pollutants: 10.2 tons per year. 12. For each combined-cycle turbine, a continuous emission monitoring system(CEM) shall be installed, calibrated,certified, maintained, and operated to measure and record: Hourly concentration of Nitrogen Oxides in the turbine exhaust, ppmvd, corrected to 15% Oxygen; Hourly concentration of Oxygen in the turbine exhausts, percent; Emissions of Nitrogen Oxides, tons per month, and tons per rolling 12-month periods; Hourly concentration of Carbon Monoxide in the turbine exhaust, ppmvd, corrected to 15 % Oxygen; Emissions of Carbon Monoxide,tons per month, and tons per rolling 12-month periods; Fuel flow rate, SCF per hour for natural gas. Quality assurance/quality control shall conform to: 40 CFR Part 60, Appendix F,and Subpart A, 40 CFR Part 75, and Division approved plan. 13. Source compliance tests shall be conducted, on the two combined-cycle gas turbines and auxiliary boiler, to measure the emission rate(s)for the pollutants listed below in order to,show compliance with the emission limits/standards for pollutants not continuously monitored, verify and certify the continuous emission monitoring systems, and demonstrate that Maximum Achievable Control Technology (MACT)is not triggered. The test protocol must be in accordance with the requirements of the Air Pollution Control Division Compliance test Manual and shall be submitted to the Divsion for review and approval at least thirty(30) days prior to testing. No compliance test shall be conducted without prior approval from the Division. Any stack test conducted to show compliance with a monthly or annual emission limitation shall have the results projected up to the monthly or annual averaging time by multiplying the test results by the allowable number of operating hours for that averaging time (Reference: Regulation No. 3. Part B. IV. H. 3) Particulate Matter using EPA approved methods. Sulfur Dioxide using EPA approved methods. Oxides of Nitrogen using EPA approved methods. Volatile Organic Compounds, and speciated for Formaldehyde, using EPA approved methods. Testing for other Hazardous Air Pollutants(HAPs)may also be required if the Division determines that the emissions of Formaldehyde is high enough that total HAPs may trigger specific applicabilities. Carbon Monoxide using EPA approved methods. AIRS Facility ID: 123/1342 ver. 2/00 JUN 23 2004 4: 44PM CRLPIME MARKETING AND SAL 720-283-1807 p. 8 Rocky Mountain Energy Center, LLC -Rocky Mountain Energy Center Permit No. 02WE0228 Initial Approval-Modification-1 Colorado Department of Public Health and Environment Page 7 Air Pollution Control Division 14. A Revised Air Pollutant Emission Notice (APEN) shall be filed: (Reference: Reg. 3, Part A, Il. C) a. Annually whenever a significant ircrease in emissions occurs as follows: For any criteria pollutant: For sources emitting less than 100 tons per year, a change in actual emissions of five tons per year or more, above the level reported on the last APEN submitted; or For sources emitting 100 tons per year or more, a change in actual emissions of five percent or 50 tons per year or more, whichever is less,above the level reported on the last APEN submitted;or A change in actual emissions, above the level reported on the last APEN submitted, of 50 pounds of lead For any non-criteria reportable pollutant: If the emissions increase by 50% or five(5) tons per year, whichever is less, above the level reported on the last APEN submitted to the Division. b. Whenever there is a change in the owner or operator of any facility, process, or activity; or c. Whenever new control equipment is installed, or whenever a different type of control equipment replaces an existing type of control equipment; cr d. Whenever a permit limitation must be modified; or e. No later than 30 days before the existing APEN expires. 77, r , 41/11 Ram N. Seetharam Roland &-Hea, P.E. Permit Reviewer Unit Leader Permit Histo : —Date Action Description This issuance IA Modificaticn-1 Stack height and PWPMIO emission factors change for Auxiliary Boiler(AIRS PT ID:004); Stack height and emission fector changes for Firepump Engine(AIRS PT ID:003)Stack hei ht and emission factor changes forEmergency BackuuGeneraror(AIRS PT ID: 005) July 15,2002 IA Initial Approval. Emission limits(pounds(mmBTU)for turbine emissions were corrected on December 11 2003. AIRS Facility ID: 123/1342 ver. 2/00 JUN 23 2004 4: 44PM CALPINE MARKETING AND SAL 720-283-1607 p• 9 Rocky Mountain Energy Center, LLC - Rocky Mountain Energy Center Permit Na 02WE0228 • Initial Approval-Modification-1 Colorado Department of Public Health and Environment Page 8 Air Pollution Control Division Notes to Permit Holder: 1) The production or raw material processing limits and emission limits contained in this permit are based on the production/processing rates requested in the permit application. These limits may be revised upon request of the pe•mittee providing there is no exceedance of any specific emission control regulation or any ambient air quality standard. A revised air pollution emission notice (APEN) and application form must be submitted with a request for a permit revision. 2) This source is subject to the Common Provisions Regulation Part II, Subpart E, Upset Conditions and Breakdowns. The perrnittee shall notify the Civision of any upset condition which causes a violation of any emission limit or limits stated in this permit as soon as possible, but no later than two(2)hours after the start of the next working day, followed by written notice to the Division explaining the cause of the occurrence and that proper action has been or is being taken to correct the conditions causing said violation and to prevent such excess emission in the future. 3) This facility is classified as a: Major Source for Prevention of Significant Deterioration(PSD) applicability Major Source for Operating permit applicability c) This source is subject to the provisions of Regulation number 3, Part C, Operating Permits (Title V of the 1990 Federal Clean Air Act Amendments). The application for the Operating Permit is due within one year of commencing operation. 5) The following emissions of non-criteria reportable air pollutants are established based upon the operation indicated in this permit. This information is listed to inform the operator of the Division's analysis of the specific compounds. This information is listed on the Division's emission inventory system. • C.A.S.# SUBSTANCE EMISSIONS(LB/YR) 75-07-0 Acetaldehyde 2,360.0 7664-41-7 Ammonia 499,200.0 5C-00-0 Formaldehyde 3,760.0 75-56-9 Propylene Oxide 1,640.0 • • AIRS Facility ID 123/1342 ver. 2/00 JUN 23 2004 4: 44PM CALPINE MARKETING RND SRL 720-283-1607 p. 10 Rocky Mountain Energy Center, LLC - Rocky Mountain Energy Center Permit No. 02VVE0228 Initial Approva'- Modification-1 Colorado Department of Public Health and Environment Page 9 Air Pollution Control Division ATTACHMENT A DETAILS OF EQUIPMENT/ACTIVITIES COVERED UNDER THIS FACILITY-WIDE PERMIT AIRS DESCRIPTION PT MAKE,MODEL,SERIAL NUMBER, DESIGN RATE,CAPACITY, REMARKS/ DIMENSIONS,CONSTRUCTION DETAILS,THROUGHPUT, _ID CONSUMPTION,EMISSION CONTROLS,AND EMISSIONS SPECIFIC PROVISIONS 001 WESTINGHOUSE,MODEL:501FD,SIN:NOT AVAILABLE,NATURAL GAS SUBJECT TO BACT. FIRED,COMBINED-CYCLE TURBINEAND HEAT RECOVERY STEAM GENERATOR WITH DUCT BURNER.TOTAL HEAT INPUT RATED AT COMPLIANCE PLAN. 2,311,000,000 BTU PER HOUR. THESE ARE EQUIPPED WITH DRY LOW NON COMBUSTION SYSTEMS. IDENTIFIED ASURBINE No.1. COMPLIANCE TESTS. EMISSICNS OF NITROGEN OXIDES ARE CONTROLLED EY A SELECTIVE TURBINE SUBJECT TO NSPS,GG. CATALYTIC REDUCTION(SCR)SYSTEM. EMISSIONS OF CARBON MONOXIDE ARE CONTROLLED BY AN DUCT BURNER SUBJECT TO NSPS,Da OXIDATION CATALYST. Ir 002 WESTINGHOUSE,MODEL:501FD,SIN:NO-MAILABLE, NATURAL GAS SUBJECT TO BACT. FIRED, COMBINED-CYCLE TURBINE AND HEAT RECOVERY STEAM GENERATOR WITH DUCT BURNER,TOTAL HEAT INPUT RATED AT COMPLIANCE PLAN. 2,311,000,000 BTU PER HOUR. THESE ARE EQUIPPED WITH DRY LOW NOx COMBUSTION SYSTEMS. IDENTIFIED ASTURBINE No. 2. COMPLIANCE TESTS. EMISSIONS OF NITROGEN OXIDES ARE CONTROLLED BY A SELECTIVE TURBINE.SUBJECT TO NSPS, GG. CATALYTIC REDUCTION(SCR)SYSTEM. EMISSIONS OF CARBON MONOXIDE ARE CONTROLLED BY AN DUCT BURNER SUBJECT TONSPS, Da OXIDATION CATALYST. CONSUMPTION LIMIT: TOTAL NATURAL GAS CONSUMED IN THE TWO COMBINEDCYCLE TURBINES SHALL NOT EXCEED 32,825,000,000 SCF PER YEAR BASED ON A GAS HEAT VALUE OF 1,057 BTU PER SCF. • EMISSION LIMITS:TOTAL EMISSIONS FROM THE TWO COMBINED CYCLE TURBINES SHALL NOT EXCEED: PARTICULATE MATTER(AND PM10): 126.8 TONS PER YEAR. NITROGEN OXIDES: 240.4 TONS PER YEAR. CARBON MONOXIDE: 782.2 TONS PER YEAR. VOLATILE ORGANIC COMPOUNDS: 50.6 TONS PER YEAR. SULFUR DIOXIDE: 11.8 TONS PER YEAR. 304 RENTECH, MODEL AND S/N:NOT AVAILABLE.NATURAL GAS FIRED SUBJECT TO BACT. BOILER,HEAT INPUT RATED AT 129,000,00C BTU PER HOUR. HEAT IS USED TO MAINTAIN TEMPERATURE IN THE STEAM TURBINE MAXIMUM OPERATDN: 1,900 HOURS CONDENSER. IDENTIFIED ASAUXILIARY BOILER LOW NOx PER YEAR. LOW NOx SYSTEM. COMBUSTION SYSTEM IS USED TO MINIMIZE EMISSION8DF NITROGEN OXIDES. CONSUMPTION LIMIT: NATURAL GAS: 259,070,700 SCF PER YEAR. SUBJECT 70 NSPS,Db. EMISSIONS LIMITS: COMPLIANCE PLAN. PARTICULATE MATTER(AND PM70): 0.6 TON PER YEAR NITROGEN OXIDES: 4.7 TONS PER YEAR CARBON MONOXIDE: 2.8 TONS PER YEAR ATTACHMENT A CONTINUED... AIRS Facility ID: 123/1342 vet-. 2/00 JUN 23 2004 4: 45PM CALPINE MARKETING AMP SAL 720-283- 1607 P- 11 Rocky Mountain Energy Center, LLC - Rocky Mountain Energy Center Permit No. 02WE0226 Initial Approval -Modification-1 Colorado Department of Public Health and Environment Page 10 _ Air Pollution Control Division ATTACHMENTA DETAILS OF EQUIPMENT/ACTIVITIES COVERED UNDER THIS FACILITY-WIDE PERMIT AIRS DESCRIPTION PT MAKE,MODEL.SERIAL NUMBER,DESIGN RATE,CAPACITY, REMARKS/ DIMENSIONS,CONSTRUCTION DETAILS,THROUGHPUT, ID CONSUMPTION,EMISSION CONTROLS.AND EMISSIONS SPECIFIC PROVISIONS 003 CUMMINS,MODEL:6BTA. OR EQUIVALENT, S/N: NOT AVAILABLE, COMPLIANCE PLAN. DISTILLATE FUEL OIL FIRED RECIPROCATING INTERNAL COMBUSTION ENGINE,SITE OUTPUT RATED/Y 182 HP, POWERING AN EMERGENCY BACT:PROPER MAINTENANCE AND FIRE PUMP. OPERATION. LIMITED OPERATION OF - THE EQUIPMENT. EACH ENGINE 005 CATERPILLAR,MODEL:35128,OR EQUIVALENT, SIN:tOT AVAILABLE, ' ANTICIPATED TO RUN A MAXIMUM OF DISTILLATE FUEL OIL FIRED RECIPROCATING INTERNAL COMBUSTION 200 HOURS PER YEAR. ENGINE, SITE OUTPUT RATED AT 2,000 HP, RUNNING AN EMERGENCY ELECTRIC POWER GENERATOR. CONSUMPTION LIMIT: TOTAL DISTILLATE FUEL OIL(LOW SULFUR)CONSUMED IN THE TWO ENGINES SHALL MDT EXCEED 6,620 GALLONS PER YEAR. EMISSION LIMITS: TOTAL EMISSIONS FROM THE TWO ENGINES SHALL NOT EXCEED: PARTICJ_ATE MATTER(AND PM10): 2.4 TONS PER YEAR. I1 NITROGEN OXIDES: 1.5 TONS PER YEAR. 006 MARLEY. MODEL: F4910/13 CELLS,OR EQUIVALENT S/N:MDT COMPLIANCE PLAN. AVAILABLE,EVAPORATIVE WATER COOLING TOWER,DESIGN RATED AT A CIRCULATION RATE OF 174,268 GALLONS PER MINUTE. THIS IS BACT: HIGH EFFICIENCY DRIFT EQUIPPED WITH HIGH EFFICIENCY DRIFT ELIMINATORS FOR CONTROL ELIMINATORS, MAXIMUM DRIFT: i OF PARTICULATE MATTER EMISSIONS. 0.0005%. PROCESS RATE LIMIT: DOCUMENTATION FOR DRIFT ELIMINATOR EFFICIENCY. TOTAL CIRCULATION CF W WATER: 91,595,260,800 GALLONS PER YEAR EMISSION LIMIT: I PARTICULATE MATTER(AND PM10): 19.1 TONS PER YEAR. END OF ATTACHMENT A. • AIRS Facility ID: 123/1342 ver. 2/00 JUN 23 2004 4: 45PM CRLPINE MARKETING AND SRL 720-2H3- 1807 p. 12 Rocky Mountain Energy Center, LLC -Rocky Mountain Energy Center Permit No. 02WE0228 Initial Approval -Modification-1 Colorado Department of Public Health and Environment Page 11 Air Pollution Control Division GENERAL TERMS AND CONDITIONS: IMPORTANT! READ ITEMS 5.6.7 AND 3 1. This permit is issued in reliance upon the accuracy and completeness of information supplied by the applicant and is conditioned upon conduct of the activity, or construction,installation and operation of the source,in accordance with this information and with representations made by the applicant or applicants agents. It is valid only for the equipment and operations or activity specifically identified on the permit. • • 2. Unless specifically stated otherwise,the general and specific conditions contained in this permit have been determined by the APCD to be necessary to assure compliance with the provisions of Section 28-114.5(7)(a), C.R.S. 3 Each and every condition ofthis permit is a material part hereof and is not severable. Any challenge to or appeal of, a condition hereof shall constitute a rejection of the entire permit and upon such occurrence, this permit shall be deemed denied al)Mille. This permit may be evoked at any time prior to final approval by the Air Pollution Control Division(APCD)on grounds set forth in the Colorado Air Quality Control Act and regulations of the Air Quality Control Commission(AQCC), including failure to meet any express term olcondition of the permit. If the Division denies a permit, conditions imposed upon a permit are contested by the applicant, or the Division revokes a permit, the applicant or owner or operator of a source may request a hearing before the AQCC for review tithe Division's action. 4. This permit and any required attachments must be retained and made availacle for inspection upon request at the location set forth herein. ✓ith respect to a portable source that is moved to a new location,a copy of the Relcation Notice(required by law to be submitted to the APCD whenever a portable source is relocated)should be attached to this permit. The permit may be reissued to a new owner by the APCD as provided in AQCC Regulation No. 3 Part H, Section III. B. upona request for transfer of ownership and the submittal of a revised APEN and the required fee. 5. Issuance(initial approval)of an emission permit does not provide"final"authority for this activity or operation of this source. Final approval of the permit must be secured from the APCO in writing in accordance with the provisions of 25-7-114.5(12)(a)C.R.S. and AQCC Regulation No. 3. Part B, Section IV.H. Final approval cannot be granted until the operation or activity commences and has been verifiedby the APCD as conforming in all respects with the conditions of the permit. if the APCD so determines, it wig provide written documentation of such final approval, which does constitute'final"authority to operate.Compllance with the permit condltlors must be demonstrated within 180 days after commencement of operation. 6. THIS PERMIT AUTOMATICALLY EXPIRES IF you(1)dc not commence construction or operation within 18 months after either the date of issuance of this permit or he date on which such onstruclion or activity was scheduled to commence as set forth in the permit,whichever is later,(2)discontinue construction for a period of 18 months or more; or(3)do not complete construction within a reasonable time of the estimated completion date. Extensions of the expiration date may be granted by the APCD upon a showing of good cause by the permittee prior to the expiration date. 7. YOU MUST notify the APCD at least thirty days (fifteen days for portable sources)prior to commencement of the permitted operation or activity Failure to do so is a violation of Section 257-114.5(12)(a), C.R.S.and AQCC Regulation No.3, Part B,Section IV.H. 1 , and can result in the revocation of the permit. You must demonstrate compliance wifh the permit co'ibons within 180 clays after commencement of operation as stated in condition.5. 8. Section 25-7-114.7(2)(a j, C.R.S. requires that all sources recuired to file an Air Pollution Emission Notice(APEN) must pay an annual fee to cover the costs of inspectims and administration. If a source or activity is to be discontinued,the owner must notify the Division in writing requesting a cancellation of the permit. Upon notification, annual fee billing will terminate. 9. Violation of the terms of a permit orot the provisions of the Colorado Air Pollution Prevention and control Act or the regulations of the AQCC may result in adrninistrative. civil or criminal enforcement actions under Sections 28-115 (enforcement),-121 (injunctions).-122(civil penalties)„-122 1 (criminal penalties).C.R.S. • AIRS Facility ID: 123/1342 ver. 2/00 JUN 23 2004 4: 32PM CALPINE MARKETING AND SAL 720-283-1607 p. 13 • STATE OF COLORADO Bill Owens,Governor h♦', Jane E.Norton,Executive DireclDirector }_. •.,1. Dedicated to protecting and improving the health and environment of the people d Colorado * 49 4300 Cherry Creek Dr.S. Laboratory and Radiation Services Division ♦ • r Denver,Colorado 80246-1530 8100 Lowry Blvd. •reva• (303)e( 3)692-2000 Denver,Colorado 8023D-6928 CoO iado D TDD Line(Gle Glendale, Co0lorado (303)692-3090 Health aninent Located in Glendale,Colorado and Environment http✓/www.cdphesnre.co.us SUBJECT: Instructions for Obtaining Final Approval of the enclosed Initial Approval Construction Permits Dear Permittee: Under the provisions of a new law passed by the State Legislature,the method by which a facility operator(a"source")demonstrates compliance with the provisions of an initial approval Construction Permit has been revised. The provisions of this bill became effective July 1, 1996. Beginning July 1, 1996, and until further notice,the Colorado Department of Public Health and Environment,Air Pollution Control Division(Division)will not conduct any final approval inspections. Previously,the Division was required to conduct a Final Approval inspection of the source prior to issuing the Final Approval permit. Under the revised statute,new sources are required to demonstrate to the Division,compliance with the terms and conditions of the Initial Approval permit within 180 days after commencement of operation. If you cannot demonstrate compliance with all of the provisions of your permit,you should contact the Division immediately at the number listed below. Guidance to self-certify compliance with permits is included with this letter. The Division is available to provide assistance on self-certification of permit compliance,which may include providing assistance to sources in the form of a site visit, at the express request of a source. However,please be advised that all time spent by the Division or its agents will be charged to the source at the rate of$59.98 per hour. To request any such assistance with self-certification please either write or call me as soon as possible after you receive this letter to discuss your needs. To self-certify,submit a Final Approval Certification Form,signed by a designated Responsible Official (as defined in Regulation No. 3,Part A,I.B.54-see attached) for the facility, indicating that the source is in compliance with all of the conditions of the initial approval permit. A separate Final Approval Certification Form along with the associated documentation is required to be submitted for each individual Initial Approval permit. This includes"dash numbered"permits(e.g. 96WE199-2). Copies of those initial approval construction permits in need of final approval are attached for your reference. Please submit the information directly to me at the address below. Certification that you are currently meeting all terms and conditions of the initial approval permit does not in any way preclude the Division from taking any action against your facility for violations of permit terms and conditions. ,E:I FOR4fS I SELFCERT.d oe JUN 23 2004 4: 32PM CRLPIME MARKETING AND SRL 720-283-1607 p. 14 Final Approval Permit Issues Page 2 Please feel free to call the Final Approval Coordinator at(303)692-3189 if you have any questions concerning this letter. Thank you for your cooperation. Sincerely, 6..114/ Stationary Sourc ro Air Pollution Control Division Attachments Mailing Address: Colorado Department of Public Health and Environment APCD-SS-B1 Attn:Final Approval Coordinator 4300 Cherry Creek Drive South Denver,CO 80246-1530 2 JUN 23 2004 4: 34PM CALPINE MARKETING AND SAL 720-283- 1607 p. 21 ' M a li ' -)1J • HI x - g , xiiT A 'O u li • • y■ Mr O L 4 14 I-1 M : 11102 A R. 0 s 1 1 A IIIM • 111 • • ea b C A ITINT.CENTER All ® -r Tr:\��ctNre [D CALPINE` -, IMO HC) ION.TBSAS T0112 -13JS30rdnuO '13.AAu1001 (F X March 20, 2007 Attention: Jackie Joyce Colorado Department of Public Health and Environment APCD-SS-B 1 4300 Cherry Creek Drive Denver, Colorado 80246-1530 RE: Rocky Mountain Energy Center, LLC—Keenesburg, Weld County, Colorado Draft Operating Permit Comments (Permit No. 05OPWE279) Dear Ms. Joyce: Rocky Mountain Energy Center, LLC, is hereby submitting the attached revised APENS per the request of the Colorado Department of Public Health and Environment. Calpine appreciates your time and consideration. Please contact Ryan Bowles at 713.830.8347 if you have any questions regarding the attached information, to coordinate a meeting and if you require any additional information. Sincerely, Rocky Mountain Energy Center, LLC .N c�4 D� f �. s 4P2D eallonary n M. Goodwin, P.E. Sources- irector—Environmental, Health & Safety Calpine Eastern Power Region M:ARyan Bowles\Rocky Mountain\Rocky Mountain - Draft Title V Revised APENS Cover Letter.doc cc: Ryan Bowles, Calpine EH&S (Houston, TX) Jim Gooding, RMEC (Keenesburg, CO) Gary Aron, RMEC (Keenesburg, CO) File, RM-A180 C.) • b0,--, 1{ 7—TT Cg- U In 'mil '� Q i III C E ¢ '° `- .--Y a sZr .a N Q d ` E SS F .. z 0 c, oa y 50') ) n. ' Z. R.✓ ac. Q o w Y." j < ' 0 c 0 Q O. �'C ❑ 'L L'•• M oo -o H o m Q 00 N e v ¢ _ i Q k CA 0 M O c N b F 3 u O} '' ° g v, _ 3 dC a ^ u .o �u o u y F' 5 Z }y ce j r-- O y W _.E Yn C U 'm c t Q0 _c U X H = = ^ aU LW E en = 3 x A s C 00 O a oZ1 W N w 5 CC em u " o E= F•� '3 o vii 0 oo ` m g = w ad w o0o u uE > O N .L- C., 0L u. -a u . I F 3 5 o c U C;) „, .4 0 I . . ¢ 'E• as cy U g w y c = R Yr o x . vi 4 W Q (J u� J• a �;" vl u ?.c.. o r z* o ea "3 a L ►$ o = 2 F co a r 3a W O 8O u�oN N n ❑ . `t o c U > ca o Q O E u. 0'~ x.vJ— = O0a a a.c oo�a `o o Q v2 a❑.-v ci O� u Q u `o c J 6.,N= u Gt] A cg�o 1 3 L � u` ? ❑ yco Z � u vvr ril o � °-' E oouv cp Zr ° E ,, ti UFzO z ��o �UUW ><0 r..) Z ' `_ F— 0 0 o 0 ' cn C U 15 _ 9'00U ca z s F Q G c m c h D al o UQSCI a o. F 0 n 0 5 �.. W O WWO v: O Z > t 01 Fa- o ° ❑ • 'n v v 40 .o .o F Z F o W ° ‘..g. o-2.01 — a c c g c c O Q 0^' Y...1 ^ 1.2' �▪v vfYi �/Q W >Z _ 7. z F {s7 W o a - � °>' III � O O p t W fs. 3 a — — ¢ z z 4.fs7 a C° 0. ' � C -� wwy_ a o EaQ. J � > Fo cpQ' W O71„.... o Rv U_ az` � y ° w E �.�a� �o �^ _ oU iii C N ' ; C O ON W O Yn o te 70 g i .O o „ g O_.> z '3 f./i7 yq O ;, o u .1.,;,) f^� U <rs, OVe � > n CL 3 =QZvaQ M � W V'1 LJ.1 F vl N (7 w _ G. N T.? R AL a O F eel W Yu 0 :i7 v) I ET: c of I � C7 -� ❑ a ; ?� U U •w ..:tee L.0 w `» `o Q o f h Q¢ w _ z U G �� zJt w O I °J n O i/ }Y O YYY a p'u a� Y Z a u��^ H LUr2 R '2'.a.P, EI -- u 3 n eV W 3 IL.' ��+ v •-. L) r a g r V W l O 131.. C� 4' >U u. Os Z`d ❑ o o v N re,c1-I ON ❑ aw= I� Y 0 `Q ti v m c•••) d; co u MS �s`u Uy V H u y R C Y V g j �j = y Z ry g 3 w W u C O Us„b u 111 d } O W u 0 O w Ol=L O 3-. >. L3] c ❑n 3 ` Liu.) Cx� 1. oou w — = ti o TJ A U u^E° 00 o O R _0 E.' _ Qt..04 -� `° E I Mf rr a �' O is ❑ v c _ 0.r Q 3 v L •cd C iu L a u fl.' d C 0: T v' E� 0. nt E,..3 C a) o u o a z 0 o °-c E w t"2.1 0. o` o c o U. F E u ocF, = Q�- > wcz y F Z E w w Q i,z S r c \, x z y O 3 y ❑ o g o w Gr.E> --- Le) Q CG �a. y" t=- �' O E j o _O 'c a u` "' U �" Z O a a°i O U a ¢ w Yd '-. = p ° C Q s z R L • C.) O oo Z °D E" u > Z.'�1 A D >r O o c c a L p O Q a E C13 U dCiJ u 'U ei �� u u cdi z^ < 3 x Yi Z r i p o AGzcla u A i=�^ H • OJ v < oe z >Lu c 2 o r-4 WO 2 UO zu a wO0 . 1- 3 o, GQ OQ W o : U �' d wCE �" Z w z on x Qdv) vo °Q7 io z u m O R. ov,u cr o O d W[-.[.. v c o W:S°a QI c H o le z cam o w 0 • F rnZZ ?- al ^9 AYh z Z m ¢ z `� .1 0� _ ° J o .. ° ❑ _ d�1Q o E.. � coG i s r- w O dQ W < W O. . z O a z -) R 's] m'� z.=u p J z N , 0 t_. .0 co OO .'7. -d u �. V .-.I a j to = Z O Z Cal; �3 1 4 f ¢ < p w E • w tt. u r m O .r 0. v m •c, a .Y = U W.-d.� c u `Raz = �I U z = x a C7 _ Cr ❑i=2 z cn ^.� ❑ z Z n �i y a O Z O Q 4 Ca.O c � ��as. — L N Co 7 T O v — CO Q -a C N C Z Z Z Z Z Z Z Z Z Z Z Z Z G 7,2 0 i C 0 O a V E z cv 0 . W co a c N o 0 N N .N L 0 Q E c0 O I O O CD 0 0 7 LU cu N CV el M O N N OM Nt N T- ONO N W D L D I` CO - - N v m _ cti S 0 O co Qz co Z vs c.,5 U) VI U) U) U) (1) U) � U) Z ti ti o = � NU- a) u_ NL � L � iv � 1LLgiu_ Nu_ NUNL � O _ Nc° w cnw m w alw cyw c0 H w c) w caw row caw caw ca _ (I) F— 1] H la H r] F— .a H ID Y F- la F- sa H .0 F- s) F- 0 H c_ E L L E p Q c0Q (o < a) < ft) < (0 0 < (0 < (0 < N < (moo < ca < CO V/ O a) 076076 076 C.) f0 U fU O f0 U f0 U (v C� (0 C� N o 7U N = _o _ w c0 O O O O d 55 O O O O O O O E E w U = Z Z ` W c a) x ° a _ �' a C LPL IUD 0 15a w t., o 15o 13o 1-) o co o 150 13 cq o 46O No(NI o ca, wEwE E wEwEW EW wEwEwEwEwEW E It Q v a C ) MERE COQ € N E °' ECO °0,' E � EcQ E °�° E0E � E C J0 O N E w -� i J � U O O CO II) 4 L C , 0- o c c E r a) N cu a ,,p a, U a) To 17 c i: U 5 0 ` l i b w : IY a) o w Way c 3 Ec p —I '� w u� O 0 Q mu) co U CO 00 _ Et Wig 0 < < O < < 0 < O m < < O O r o co CL N . O CC W 0 V3 Et rY 4- s w a) a) a) tJ o >' C 0 E C c o 0 X re Z r c E C TJ N L C 00 O C 7 N CD a) 0 CI) (0 C a) ro co a. a) a) Cl)_ Lci W I N 'O O E C 5 a) To ',1<, y I C 7 I Q) T } may .52 0 E _ < 5. X m LL C Q Q m " W `o z d o O r a (0 o Z 6s N j �; 0 z E Z O O a) � p C U @ Z N- Z 0 U a) 3 o N N Zr CO O O co O O 0 Cl) .4 CO _1 O <— E U to N co ,- 8 O O O O Uf) CO CID OM CC a) Ea �, 0 (6 .0 ca u) I-- O ((O N O i, r a) r O,_ c E E c E 0 Q a O a_ a LL Q (i m CO @ c w a o 2-2 Q a) 5 a C —°° = 0 0) m E _ L" 0 a a ` a) O U o a) o a) E W a O CO -m0 CO m m 0 C c D a) aai c C aa)) C m Q° E m a) O) m U f. J r a) G a T ❑ «� .X a) r to 0 C ` CO C C U D N U -O > a) o) O m 0 O a O Q J (D C Q) `) a O _C U O N U N O a >. iii Z fn _� p_ O >, J E a) O W J 0 — C a n a) a m 0 O O L a 'O 0 p C CD 0 "O p, U 0 E a l0 Q m a C m CO- C > a r 0 co a) O a) c o 0 0 a) m m ° Q OO cad a< m a oo E �.� % a o a m co o W I E c m a` a a) CO 5 N a= U o J O 0 N E O a m D. N C0 cu N N w C .(no N E a Dx a ° a) m C N O O I C "' co m a) a) ° a C U O O 'o O o E ca n a0 m o a) m x O O Z rn m m m C >^ a) a) a) Z T., S O o a N N Z E a) - Ec -or ₹ o t c -, cc E Q CO w+ _ _0 0 N -c O al D Z c 0 a) CO a) c O HO Co o m = ° m L 0 C U N a = a) c a) o) •c mO t E m t Q D c as L c N a) O O -0 C J 0- W N N a) m a ° N a)co E (6 p a 0 D C O >. N E 0 m co Z v .0 D m a) E o " m ° CC c o o a) co E c E -C o t a Y J a m U a) Q a E to f— ocN �° £ C a a Z › o a`) a m = o Q >-. Q ,n CO r CO Z C. r o a m N 0 D c a) N .L.. ° 0 E a: c6 J 2 0) c E .� o .o a) 0 0 I) w -- oa ` O a JE .N 0 o mm " o ` (nos- o N O D x x c a) .oD E E a o m � w 6.a m ow O N O c u°), r c `m to r Jo c° D Q fn m E = m COo . N m ° a yr w m m LJJ m C O E a) 11 a N >. a) + 'U s N C a J O 'x N U - 0 a 0 3 -~ co a) CO a) Co N o O c _C CO y C U w 0 D O L ° . . — c Oa M 0 O 0 L -O fn C I a) - u) 0 O 'O N a E 3 Q � a -o o m 0 m rn_0 .00 a a a u, E y 'u) .a C O Q' EC E E a- as a m ° C C E C 0 O ED m 0 a M O O 7 0 _0 0 c -- 0 w L a .N -- a) ,n N a a) U' a -0Q ° LL- a) E m ° m � m .n E c E o > N W m � Y E J ° m a L CO E o m o w m c 07 ?� m a) co -C l0 on C Ce as Ne m can a) aD E .c m r) N o o c •° m _oCOJ3 E a) a t mv) m` m O O Q Q M a AU D .40o _E � ca) r m o (q 0 C _CD CO tl C N m 0 m a) a) o (6 U O CO Y O O C C = �O = -> a) 0 J N Ea O H •o m Y a) m u) L a a) 3 t a® 0 -ID m m � m C Z m > r _ O m CO c �. m E 0 r. a) a) c c I c aC co> ala) O < w y -o o C -o CO o o `o)a) CO o c a) U o � a v a c .m o CO a m W 0C fa > -o a J C 0 CO o N E J a Z •N C CO C m .C 'N N 0 m O N O O N O - — _a 4J co •._ C O O Z O C CO O) t.. O) Y co O 0 J C0 a COO m O N Q co O co Z W m 0 .0 c m m " L f > E m w c ± c C a) ° 4I �? U O C C I— 0 O O w 0- O — a E . m a) .n w `0 a) o a a o 0 w C . .— . CL O H C a a Z .N C to D < c m U C C C m C C co O O X m L a O CO �. @ tL o f Q E N aa)) a c c -o ,°° °) y a o a E .a D U a O Oo 0 aLU O o E a) Of a) a0 a) O) L -o 0 y N0 N O - t 0 Q C a) a 3 E .C < o m e .N a) m c a) m o s _ Cl) O n 3 m o m a) a 3 E d d m m D = D m O 0 O ar z Z Zt ° � O � a ° a CC -c Q av CC c •a N D to 0 o in aD o 000 , m � .� ca CO to C 0 C a LOL a) O m _m •o N M C LE 0CC am U E a `m ,c o m c > > 0 .o o m v rn W . - 0a y a) Comm o a fa CO c0 w ID c m O O CC o a C < 3; v) Z a) a� ? •a co .E C C C o a.o O CC '� U E Ea) -0 m m N foil C ci,> 0 >' N U 0 U 0 •m 0 0 Z - m m C O p0_, °C z Q V c c x C N 0 O N a C fn CO CO N W 0 > O c6 O U c O — -o m r a t c —y o •O co o o cCC a c E E co a) E -- o rt O aL. N CU o r 0a - CO r m a CD 0 ® w c u E II CO Z Z o a Q < .CO U a a' < K ° 0 -0 c U a t° --.:' 7 HA I , I I O - a — > [N t (1= �: V c 2' — u 4 G) V�C�� n c N O j E o ° aA \ 2 Q-_3" Q — cy o M O O " Z vi c Q❑I J F E Q a oo to col w N Q c c c 'Q L Y °� n „--'' O o c� c N Q m � ,C <n d T_ - _ C c Q O vii v r Oil Q < � n S 0• a ° X 0 Vi o c e-, v I .• 0 00 O v, ~ = .. 'O o s < ` V] a v F oo Q m _ :i n C .F n o � 5 0, m = m •≥'IC 0o 00 0 W o — N 6 o a >L 2 07 ❑ ce N Y m C _ I 1 t7 Q � E.z 1 " na oo T m d7 a Ca O2 z. ^ O O LL V >`W O .Z O m 3 DO s ..- 3 Lu O V Z ¢ o N u S ° o .`N' i 0. C o S.0 N O ° � Q "� a U u E E 6 Q - C ° m - �'o r ❑ a [i] L e 0.° a °F° E o cu o. .. Q °;5 B❑'cry Z M = LL _ N N N • v L 2 LL 0❑O 52 8^ O 3 a e^ N Oee 'L Ai o L .'U_. 0 0 N'O N Z 1 '''re- .1 za' UF- ZO Z c.- aUU2 N LL ❑❑❑❑®❑ - ❑ A d v o _ o E N [(i Z J O O N V U F� a O Z o a O Z - `o 4-0, a — ❑ — O 0 o._�c o Q E - °o— K o d F Z 55 c.. IX _ >U o 8, 7 W _ ry < o < O l o u - Ct 2 o` o `o moo` `o — z H o co • V F =IO- i V w u v = v c o a-avr _ ❑ 24 © uZ] 0 _a\m F. > > > > > > 2' 51 «O O m 7:fl im C x gee,r au r.- 10Z O 7 z.W Z Q m 'm"oL. v c r0 7]. .V Q i Z W W x W ?o °gym Q nvu ¢jN `O— f'. kW.0 a' 1- O 'o C F. - o E = Qy o )0A Q W m = �Z v co - O - U u.. ,y m ✓ F. ` R - U i<8 08 O r0 S is !s x a (I) r - H.. .� rn U E a� • F' is 0 o .a S 7 X)`2 O o a v y o, O en O S C n ..a o o • ry A = — 0—> z 5 z v,0 E °� o c o Q ' 'o rn 0 0 O - _ 4I Vi v ro -H v c ✓i o a 3 u:Ho O ry _ y _ a i-❑ ❑ 4,_ 'E. a. ❑ry d — cog C AQF. V r >v z o LL 4a C en ¢<W ❑ o r oco 44O Z m `0 2 ofC, o _3 ,_ y O iii C9mtai _ H t ° v sO -, Y m 41`� H Hi ti0 3h 0z rn n 2, C OUvmNo 5. _ ' c ;Lz N a a a y o n v ea ❑ a i u O a-' C' C7 _ - a =.�I —' 3 n c C C o H. o; y30 'Z N O a0 u d a mom N -CO v ��m ,____ O '7' G - v o `v v' ._ c zZ o._ �' Y N o >. _ Um ta QS_ �o O04 0.1 c Or ; :.�:!' •" E„� 0 4 V� — anal N o `v .� 3 .= C Cr ,', E t o C v ° 2N g `.. � ..l Eyd Po � � ._ .o O=_ n CcA C ' re _ ❑ •0 5Z zuz 0 0 - ~ LIJ 7 O j 04 LL Z S N o '� F' rn C o d• = O z H v: < e N o• O Z v, Z >a L0U)7 a 'l._ x H O > < Le P.8 O E o �zm m ≥% � m a o U ¢ U m ''� o z O c.d o "� C E - �I X_ z v)ae ZO 22,. v - 0 Z — po GJ u uLV ¢ ° � xt L .-G v Q o i F O a r O o ..t o a. E - z .� = ` O ' 3' 6 c 0 0 0 o d z - o o ` a c C4 a' E m u o - p • k • � ..J � ; z �a z0 H I- ZF- a`. OC E ..Qa 'v° J ' jL �a 6 Z1 7 o 0 2 c Z > C K o F. 3 I Z a` o"' 'x ¢QOV Ion wu�y z1 O 2 v, � O O h J O LL `0z0 a cc o O -]a4 O IF,— ` mU U� mri 0 om OW Z 5C�_ o e o f- o QQ o f Fo-e ° r o `a , O LI'7 Y o2C4' tec o ° o O uFF m OoE z 0 Z m ~ z u L 'a' .. Z a Z .j _ h,o , Z o z,.. °=.67,' 3 N C < z W O Ls ILs o Q = Li L - — C - VO _ d„ m 9 m y c o m `..i O < j O _ "J L. o 2 OO OO O 0 -1 O O .°0 ,, , L=5 S �1 V 2 d x a O ¢ rc S U O f-2 7 vi m a2 22c 2 ri°'i [y a a a V z > U i o.c. v> r t N v- T co m 0 >, CO U Q P " Q Q Q ¢ < < < < < < < < < L'' ,2,2 ZZZ 2 Z Z 2 2 Z Z Z Z Z T? O v? N 6. o E O Z O O w — LU 71. U ^ a 0 C'') Ts O Q 1O in M O O 00 C4 O W Q .. N N N CO 2 0 N C) �t N N 0 N r 4. O � � M a N I— IY E > co LC) Ukl O Q M M 0O M l w 2 Z M M I a) vt Z .c-- i U) u) to n to in U) N N U) (n O N. I ON U (D u.. m w m w (a w I-- w N LL CU CD N tl CU CU W W Cl)ff F- .Of- .O F- .OI- � H .n ..x h .oFF.- _oI--- _0H �'Hna � � 4 � o a L. L Eo IQ � Qro < < CII < m 1) QcoQmQroQroQ (aQ (a (/) `a C _0 � wti I0 ris 0U0 UO 0 003 O co ill(I) U0 U0U0Ua a a W Z Z 1� X(13 U d .i I f Q cU c j N j '- N j V. U N V Tr V M V 13 N ...) N ., N ,C) i Z E I LLD d to O u) cn O N O N O N O O m O u) c) u) 9 N p N 9 N o _c - ca, LL EWE E WEWEwE wEWEwEWEWEW E, v o ti rn a LQc � � � � aMENE � E IS f-- O i � U � � Is O - � � : 11 • IS nj li li co Q � � � IS N _Ci i '- C r r) U g 0 E I Ui J J V U --- co M J 5 O) O N a 3 co c O c a E . 5 tea) U a) T tn a3 0 _ C a �1 Q a)a) >, a) V 6� W U W `) Y r J ' w to 0 0 _Cr � N - = Q W �° 1.' a Z Q < 0 < Q U < 0 CO < < 0 O (� N > CO W o o f Ce cc 4- < E a) a) y a) /y O Ca) a) x co O LL, z L c C C '5 N t a) a) 0 0 a) a) o a) °) O C a) c O c N m P —o E N .. CD v m m a a) a.) c U I td Q E m co aa) = aa) - 3, to Ce a) -cQ CD M _c = ro < a X (`o I U Q W Z LO 7� C U a Z i CD-) N (6 0 o Q) v N a Z Z U a Z � Z >-• Q o P 0 a) E O °° N • • o E . Q E Q. U 0_ Li Qv 8 ai 11111 lii @ o N v0 C ca T Ja)@ c_ `_ rb o 0 C N m § T U a) 2 a) In C O X CD in O C TUO > m O -O ca Eo c N CC ca _ a0 T 'O o oN C b N O W J5 Q 0 a@ N > O @ C_ N O "Oo a)d L Q 'O y N E Q N C U a d 0 CO a) a o C E ° @ ° a a L d a) .L co -E a p- V) N Q to O _T.c o = E Q ctS o W I E c o o E o a m - a `m co m is o CIS 2 n U_ o °� Em Xa ° aU) a) `o @ o a u) a) CIS O LIJ N co @ a) O o a c o N X c L N H C E c a@@ 0 co rn 0 O E O Q' O O E T a) a) a) Z N N J J O CO N O �0O Z N a m •e @ .L- L" N c co `) 0 0 @ N _ 'O E O O 7 V E 4 0 L O D D H Co a) N ° a CO m E a) E a) ± o- -O H N N v a = a C0 -5O a W a) a a) c - L 2 ro 0 m E >. '� c -oo - 0 c E m m @ C o Wg a@ a o f o g m 0 ��° oo E co o �` ? Lo• O °- U N N ?� C -O C Lc— J a) O O o Z E E oc � L a) y a a t 2 .0 n0 a3 4 a E m @@ F o o 0 o c' Q N @ Z c o FJ o a a am v -- No D - a) 0 _ ° 0 T K cc@) J ° m E 'U C F:3 T-3.- ' a O T N N ° O 0 J c N JE o ca) E o c @ � � o � U C O 'O '!) X C L a) O ° a) a -O o O O p) Q1 N a' N d 0 o Q ° °-r o N o J _co cn `" N Q RS a' O 0to o U o m a `0 o r o o a) c co = N o r @ @ O U Q N c ° E J o iw a° a ao t w � c o E c c v W O m .O N in OU a @ 3 w j U? U) a M in r O Q) .0 .> J m w = o y O � . . — c o + o f CO m -o o L o w - u, o m . o c c n o O o a a Q fL- @ -p o N@ as rn.n O CO a a N E 2 N 'J aa) c F a O E o ` o E -o CU`c .. y c_ c `o a) o v a o O Ce Q E a a) a CV _0 a) .E ° ° a) to m g °) & U c O as a) E a) � . Oa) U a E c of m o o c a c C L.L. E J .° a>i 00 L CV E o en r y o @ c a .o N -c.- 0aa Y c ea 0 n c E m m c , c 0 `J' = C < m @ < v o W o o J `- r O -C ur o oc a O Q W C a to U ° Ul w a) N N m O U y a) m N @ _ or -p ^ LL m O Q N -, .0 c c @ N m O O J m C C U O N C O m@ > 'O O a C O co O m _a CO> ja N C tf)c c la .C C in O N O) L O` ca ON y co «O ° N J L y0 N O "° ° .�O O a m N .� r -O > ECU 0 = t = CO co o C cr O 1. C o Z W CD y E o cF o an n o o N = a o °v m a . . .0 O G O" < Z E O tT o X a) L C O -O O E O -O --9 U O N O CO LL J@ Q N a) °' C -C •-O N .m @ a a a a N a) C N M O 'U in O E E Q N a) �O O@ O) L O 0 N o 0 O "' Y N to p '� N U a•h. 0 o a V }Lo a a.c -° •u) @ 0 @ @ u 9 N •N L N 1 - n W O Z Q O a 3 v N o a <_ Oa 3 r • - 'E aoi TO c o -ill oo a c � ' UFE5 a N 0 o 03 a) Z •Z - .o 2 O Cr; o 0 ` 0 � .. Q jai � � Q .CC Z 0 6 � O f0 O O CO @ @ .o .c J r N M is U a 03 • C O a o LL .. a) i6 c O O 0 •V C 0 --5 w. . CD 3 0 o �' a U O E a •,`a c o o c .≥ •L ;c roc i_ o 0 'Oa@ A o O tT m • O -° to to to w E o 0 m o (n O Y CC t° E � Lo, Q @ (O to ur c a>i in o 'C @ CON <O a c'O L .0 CD c •c u « rnm ma)ca .— in o .0 w 0 c > G O r C Z Z A C X C Z N O 0 a C C O . 0 ._- c O Y p .O U C 't-. "O C y 2 p m O O C 'y @ �' @ c N U c D '° •E @ o m o o 'm n a = a o E O C c ` a oN c `o EU c c ? o a a cam° o o o E a `O 0) 2 a, 0 L t- < N r O tli a a) O Q) C' (n -) Z Z O a. Q Q ( 0 a CC .< K 2 O -o d' 0 a W@ a p - v ,� , 2 = _ CI > > .2 tiLu c (V O r•G ? .on qq w m •-, — n < a «.c c € F Z crn o , m co O =a. �. :. J c. a �. a p U a _- _ _ LL N O W r O X ° . a _ — v o. v F=- o w o _ v o 00 o` c Q JO r�a < .. =, o H 5 0 0 8) -w a, A F U X E. TL_ LL] c 0] 00 K G E.4 LL o, o a` m = y _ N O m T C - m` C J o co o °a°i `v E F 3 > O 0 p Y ` C - J ac ` . n =.0 0 Ll W w O a c E . c$ o ° U = y N S z Z o Y `° c t o 0 2 m aJ a o u z ¢ O a u c o z m 3 s e t. N O g �' .n o 2 1; 12- ao ,.v.- 5 vo v = o p r El <oo ac V � E Eo ¢ v;' � E O _ry .u,v) a o o. n '- a c o o mn vf 8n c " E a o2 V C-=e O .. _ .° - „ t,- 80, o` a. _ ry V W � Y 3 Q - h ° _" _� u `v " •' > Gs-°m A o 3 LAC A '.O o f E o 0 °' EE E 'c o y ..ax vt s LU Z� UFZO * RUC X� C ZL] o ❑®❑❑®❑ o=9U H- U O E o o° v ;n ac� mU < F E Z U Z '7,t-,-.)`u < pa — �A 0p Q occ ca= ¢� A ° -�4 o f Fo a m Vaeo ≤ � J a v »� ? a 7r2- rz . . < o < our v n oa O � U F =m� < o - o r•2 F m ry=' G o to 5 vlry r- -,s n^ ..] d a E 1. 1 a � C C W O w °v ¢5 y v U a CWL - CC Z eo = + v = z O v v m w 5 i� ,� F 4- z -1 _ a r Z v) o w m in F cn F o >. o o O V A Q W E a O a `° .2 U m 2 a w F F Z a0i r 7 -- o N Q z Gr.= n u ro ,�,_�'� v F F .�U E ZI v,� m m .= = n 2 m Z U u] F-. to y� -p o 2 v a t O O `v p y � Hilt ��O L - s 2 8 0 x Q Ca U a o e m o'rn E ¢,Ha m C a` Div _ v C . �.w w v y W a m ° Z L VW J a U v O F'} O Y � 'az o = — U b 4i 0 0 O'8 v' - y - 4 ,t4 _ r :, ys 3 LL Z ❑ OU o H z �'� -°'"u mom NS ?4; o c .- Oo� C =t 00 Law g or 3 U� == 4 > =-2-8 .0C z o c m o ` wpm \ --gE_ ^i Vl ° p. m L. ^.Lx. O a a o 3 �Vi . _ a O E O'� � u � w E 'o aF m E o a°'� n Ccc c WTI g O C 0 Z 2r e o n v !xlw'] on <° O C"" > 0 h r O U w w <CP.C h '_ a r ° e �,C 6'u m ¢ F U a. o C'eH ti j_ r. Li 0 ¢c4 I- O -, <<, ry a = W C z ro .i< x O p z O gS = z _ d U ry;iQ o , Cv E ? C r. o O O p �' O to O _° < at = C r. c c `� 0 0, >• C 3 J IL C1�i r ¢ _ o C F.- F �' - :J 2 r- — E 'E Z Z O TI., O J _� ro SJ u U a.. a v v z d — - n Lti L - 2 c I` L+ a �' >La _ o o o ul m (jc�C J �.E 8-.2 ca.. ai O Nez o y J cG o U Z �_ c U u� C `�O o j=,0 tow 4_ O a z w a a' L.L. = N o� i C (] D t.�F lam- - -Er Uw94 Y O G A ,r J LL1 ° [� 0 2 L VJ Z Z v v a [n ` �- w - 'y s LL] Z O $ .. Z J m WF'F 0 Oov ° z _w z w O '_cn m � v d. .. ,J `w U.�U Z Z m'= a 2 ¢ w < V , o - 2 N a v _ _ " _ U toil ..] E o a �- ¢ U 2 2 C7 = 2 U < L v� a z �j a 6i Z ou UC d d a 'm '8.-.)7L' -5 m h - C _al • co j c)co v < .0 < a1 In 6 z O p c 0 o of O o o w W c a m - N N m 0 O T I I CD O N < Q oc co Q 06 W Cl ;.: -o ti co 2 .2 1- _ ✓ a� 2 ( o c3CI W • N O Dw ii N O Z I U RI a) a) M M U Q j (C L- Z N. r` c o ' i o _T.:" a O -- N w r V) O a`) a`) _ ° ( w O CO u C _o O t O = n I- W m - ZZ o aU C V _� co > } o_ O LL LLD W cn cu Z o c ii, I^— o oM I Ta JO n a) 0 OU al o wv 0 J ?5 U — C .r g,) C m c a) D. p C C Q E ?. O to RS 73 a I • I •► cc a) U a) >' U > o Q C Q a°�i w( Z co D 4-, to oa W Y � � c J a� o W LLc) o O o m 0 C Ct C o Q Uj co co 0 v N C c O Ce O O Z - W �" O 073 Q O N C> CL N - CO 4-,W f O O V .C 1L . N CU o Z O M E CV W U_ a (NI a) � •E LL1 co Ct r . U °' U v o O � —° C. . I j cn § iii Z L ai cts ;ri - - -v ca O CD E C 4C V) N ` U O O E c3 o o Q) a� o Z z z U ° a`) E M O) u) >. U o -O O C .> ZCU J C Q a 0 z p f�6 c w E o c (9 •c6 C P cn co a C E E Q a) a� O a� Q CL •ii) a 0 a_ a. LU -O ?` c+) U T v D @ j '� c co a c O CO a •> CO _� O co N E - O Q a) > E @ U _ a -o L-• v @ O T N O U O O aJ v to .> a O 0) @@@ y O - 'C LCO @ a ° C a a ° v Q @ ° E ._ C v D a E m ca' ° c m r ° - v 5 o E ` N a m L O O @ N j m Y O 'N O L O E 'T c a) .x N _ 0 0 a > y — r0 0 E C v p m > m o @ ii, o a W @ E ° c v °- c L D m D U Z o ova >, ° .� ° E a° '- E y >-. — c O W a Q cn anion 0 o° o u) o v @v p @ o a@ c o o o c r u m C @ C ° En 4 m 0 a oo E .@m o n no a o La 4 o unca a U o c o v ,X o o co n ri N et -E o E NF- m y 0 0) v o a c O @ o `o C v - v 'm aEi �' O o E E ca a@ CO .o '0) O x CL C Z 0 m v m C >, v 0 ai Z °� m O E o U v E o •- 0to a 0 @ L L 0 N ° a 0 o a) w Z E v -c • E D E m oen ° a) a) o N > a w 0 v n v � z C5 N vo a E Uc o aaQ CO r a N O m E L 2.): _m u' .� -C o .N 3 en E z fn a = v c v a) c a`) O a) E v ? a- -° H N a a) a = v v en ur CO o � c a Ili a w m m v v . 'E O c °m a) W o v a a E a ° ° en' o • moo m -@0 ea ca v L Y w l- a) vi-a Z t6 If y °o o °� '� 3 m D - E C o D O co Ce 175 CD z c c Q a E E H a' c v o a' ,co CO _0 @ m H _o o a F- E n. c L o '�' ° .0 'a? @ >' CO Z v c=i w E o ° p o a v0 a -- yc >` v ,ED ° ari E wm w v Nu J 0 m c o o o aDi cu o v m o a - CO - u, O D m aE o vo E -- ° C v aa) a 0 CO cu D co >, aa) d 'x axi U °' oa o v a- .°a -@0 5 0 `O co ai a U �, m o a C ° U o m uv, C .- `m a) a �° a aa'i C Z '� T D Q 0 in C O E a @ a .N N @ a L N r N N N o = N N v •J X - 0 N ° n >� w @ v to v CO N CO o C O .> o p C -0 C m I n `o 0 D v a.) o = r C n now a) m ❑ - v a' v 4 h C a y c - v -o c a o o n ! v ? a s `� o c'crL a s aa) E �" a o o a@i r .�D `m '°- v C a 0 ur E ur c .C aa) C a @ 5 o.E- ce E Q E d v a 0 v C c p O v o o ° Cr a% ° Q a Q O O O L v _C v w L a .N vin v a O - U . . v W d v Q j0 a v E @ 0 u°, - U 0 aa) E c E E - v C a m o co a) 0 W 0@ Y E C - v to v O) .c N E co O 0 O C f0 '- a D C >,.J •O a c cac co Z (n a C E m c o c m o •c co 0 v 0 @ U Q Q [MIli .� N ` D " Ct U CO V! N U CO L@@ O w L '� N v U U E D D L.. ° c m C = v «) a •� a «O < 5 0 a) F 0@ 'L" v C Cu) L U 3 L >a) O •- •- v con @ CO -a v 0 U > O Z a v > C = 0 co to c -- v E v 2 a v • v L (0 c v c c aaj coco O Q T.) D o c 0 o o m y m o m o a v o 0 O a v •O v 0 .w o 5 s n a v L c 0 @@ o ,a Q Z — C m v) f00 -E O -w al 0 OL N O c o o 3 an d .. > U C @ v y .- c O O ° c Q 0 0) y @ ON O O . U@ C @ O a 0 N O D o `) 0_ ov@ v m Y oco ° ua ° L o v � C .o (6 Z w o v c m .c H o o E @ N a ? a o N v c o -v� r o @ i� N Q' _ o • a = o m cvi .� _0 ° o m a cn a�i a ° v°i aai N d. urn a m @ a� .. � w = E a� O ..r c a Q Z N O O)D X v L U C C C m C v o 0 C O C O CD C LL 7@ Q ... n C U C Oa '° .O E "O D ` U N ._ - W N c .0 O v N @ n n n CO a U ao ci et v oomm r — o vv vv _� uv ° oY LOy. .� E c • E wen N 0 ZQ Qaa) a 3 •UE L mQo _ .� a�� cc co TT) v wcll .N w ° > caE a N@ 75- N Z to L co) O a a L., a p a) v a) O y@ .yO L o CO 5 a O fn v O U O 0 _c coITEI r N •• 'ix � v N W e m -, @ 7 c C7 cv ° ao v ° �° m o ' ., 0 am O mpp wa o a � U °m E a `: -E a c > ≥ o 0 O ° c@ a co o a 0 o' N .0 .. a, a v c 0 al @ O D CO CO f0 4-- .2) C U U X U @ N a m a Q a .0 Z v n v a o m t c c c p E o @ o Q v c p r .0+D E v d ,J o v a @ a >. C a) v ° d C.0 U 0 CO N U 0 .O C U C C „' L. 0 Z y Q r m m al m 'C N N • (0 Co Co A Q•-00 <L @ jL C y O Q O O O O Z U C c _x c N N O v a C • W W 2)_ c L c@ p a 0 a E E cov v o v m a c v a' a a = a N - .�? - w O N N � 0 L o a a N -a 5 d a a 7' C@ a) 0 ` a o U E C .E E Z z o a < ¢ .N U a a < a o ° -0 K U n w o 11EJ D aa) U aai u°. O - m o U Z in c 0 - - y V C - d N G a - „ . 00- "0 Q c 9 F =t EL A OS c ., " C = n �i r O Q 03 4 O Q a 1 F4 o U Q a Vl . ` v O 2 0 O O p0 > H c TJ CA oN V] 0 N 9 -11 04. J U u - l—ir G L C ut u = o , u =0 0 H -� T c c" 0 o N v0 ro C N av' _ ° c o i F s S o w u N _ _ 2 n n o 0 2 m 4 O O c v Y om sc z = Z O w (V w - � W* C o " z O ``2 b N % 2 c ° ow �N z5%.2 N o 2 F `n vJ a .r ° .. G .. E py�� o ,� >_ u� co r ❑ i • - Q 22 - ooJoUn 0 6 v2 ZC OW s 3 Q o s - 3 —= 0 E I o E E oov8 N Z �y >, 'E_O Z ^' O Z O Z p,o nL)J g c-,,- D w ❑❑❑❑®❑ •♦ co_O ,O Q O = y? O O U la-) v �, 7 2 o Y' o U v F 3 O Zo d m O Z C U 8 O.a z o O _o .. v.. H0 G SO c U2o0 0 2 a= ri > z o > .1 n J —4)2C Y = W O w`0 D O _ Q c0]2 0.l o 'nom -°c o a v 25: Q Z H2 C .. U w o J c c < O O V Z o ��m 3- .a-- =' > > > > > > F' a C.;--F v a Q ^ F M Z -661 0, �' Q C. U c. Ge W II w c ^ v _ v: O Z o > o v > ,� z W H co Z _ m m o c > v O Q W W c'lig r n J E 2 „ J v U c j = s^ o E EQ A oHA Q W O 4 .]Z ° x on a o n U4m C W y - a a� I^ 2 m U • n v '30 2 W ,oU N F=Jo ? v IL d �- c o -J0 y' 0 C11.17 J , L< Q O c 2N m v O V' , 0 Z jw M �C a v A y, c fn., 5 a Oa-- Z �O Z G N '� O p L 6 �i 3, O O p0. JQ f n " (3/1 0 0 Y. O L o ai a, a, 0v > 0,,` LYE \l/ 2 s Z G 7 ry rv - .o - > ' 07 c n w'7 C C r c O W � �ri v % 5 �¢N C 7• .7a E. o G J — w o Vl E O .) E w w Qce- 2, w z 27C U O G 1/4E, J 9 �4w � 'Y' 0 ,J o Cm N v, 0 3Vi O W (2,74 dC h U N 0 L> v Y y A 'a u'7 z .,L' G v o 8lz" t f- 2 a ,^ U W z .J ic U r vr4r) _ N oN ❑ _ Fa Ni 2 no vAr 3 z= ' Ora 3C7 Jo = w caF N — o ' V ' v .. c O m on 3 v' m o ?oaco ^ - rdon z Coaz v < v H 'c.9 C'C.. 0.3',.-2 = 4.1 0_u O o.) >- o >. uw Q—>O V N F ^ > c3 32 0Om ; U WQW .` C Cr o m -m 37 co F a n ,,-'_ .C CkI!Jd ! ' c c O � �` � u JI Oa.`7. `7L.. cR c E �..: m 'o ooc ti Z _N .� �c.. 6 w e m n o m r a 13 Q C o CW. 5 .� ' 0 m o 2 G $ O'V J o O au G AC ro� s z O rLLd Z = w UL Q wss: 0 °' 0 H O • •Q m C % E ZZO O wE - H z z z cC F- F c 2 S Z O'aC U .�'E �_ °� t �..I [� O O s O O c = v� i o r z a o 0 2 i < c — > S o Z o. U QQm 2. '00 W :-c= 0 r c d 8 °' Z F�. a. U (-)7c7.n 1�, v zo C O o 3 o O v'ZZ o " O z "i .23 Lu o U) o c d w J H 022 o E 2. O o'° = 3 ON ? 0 5 LL ° c w u .) 2 o u o o a " - w�E- ` z - 7- c z o r „ a z a w n _ Z O .a.. - Z w � c Q..1.� A v � vi ' F J g ' ¢ r _ O E CwJ m = y ci v .a i u Y v r- O P ._ U W-3-4 -. _ J� m n s s w w o . . o IP„ 0 2 O O o O ..tO O on _L�. C 4 ` L p w Q mS Li 0 2 2 3, o 02 2 kla a. a. v: z > Uac.a. 3 r �I U 2a. T c O STATE OF COLORADO Bill Ritter,Jr.,Governor James B.Martin,Executive Director of cod Dedicated to protecting and improving the health and environment of the people of Colorado 4300 Cherry Creek Dr.S. Laboratory Services Division \� x% Denver,Colorado 80246-1530 8100 Lowry Blvd. rage x� Phone(303)692-2000 Denver,Colorado 80230-6928 --- TDD Line(303)691-7700 (303)692-3090 Colorado Department Located in Glendale,Colorado of Public Health http://www.cdphe.state.co.us andEnvironrnent March 22,2007 Mr. Jason Goodwin,P. E. Director—Environmental,Health and Safety Eastern Power Region Calpine 717 Texas Avenue, Suite 1000 Houston,TX 77002 RE: Rocky Mountain Energy Center,FID# 1231342, OP#05OPWE279 SUBJECT: Response to Comments on Draft Operating Permit Dear Mr. Goodwin: The comments you provided on the draft Operating Permit(05OPWE279)and Technical Review Document for the Rocky Mountain Energy Center were received on November 17, 2006. Based on the Division's review of your comments, our discussions in a meeting on December 12, 2006 and the additional information you submitted on January 19 and March 21, 2007,your comments were addressed as indicated in Attachment 1. The next step for this draft permit will be to put it out for a 30-day Public Comment period. After that,the proposed permit will go to EPA Region VIII for a 45-day review period. The regulations also require that the applicant receive written notice of their right to a formal hearing before the Air Quality Control Commission at the same time that the Public Comment packet goes out. You will receive a separate letter containing that information. We appreciate that you took the time to thoroughly review this draft. Please feel free to call me at(303) 692-3267 if you have any further questions. Sincerely, ` , 0 C>ricJacqueline Joyce Permit Engineer Operating Permit Unit Air Pollution Control Division cc: Gary Aron,Rocky Mountain Energy Center,LLC Ryan Bowles, Rocky Mountain Energy Center, LLC - N O y a)) G N a) ri w • U T `° F •v 0 a t^ q W m c b "' Z a Z a a) E u o _ a � • s ; av a ° . � a, .4- g' ¢ a %.7. E —, Q aQ5a o « n v d w $ av '5 w o v .5 w v •5 w 05 y 0 :3 •o •> '« .b w o E a c y N co y a°i 00 .3 3 C C C ° W • N rC y F Z .5 Y r4 �cid - 1t] Y 61 F Y v5 5Q 0 v ≥, a? C .� � Q $ Q 0 .52 a) O) 0 a) 5 coo co. N 4 .2 C y eau Cl. bp a) a v aai • as > t° « N Q v E > 5ra > 5 g C ro ga i° v a5 . F aQz5 .o ? FazE= 04 $ a a s m 4 N Q `)' rn y a a) a a = U o .E c r �y � � o F .5 P, F .5 g ,, a . 3 •3 C y a0 .5 y.. �' T 0 Cg L). « '« ... W 7 >, w = T w eU0 a) U a)0.0 a) c , 'gig CD T = w '9 ., z •E5 a>) 03w o3w ov a 0 OA .y Q a 'v .V .V.. 4J I-' "' T ° V T ° U TO > C) O tJ U Q ... qq ,.C FF FF a' A N E- A .5 H y .50.1 y aFaA .5 HA .5 aa)i O O v A g y as m lo v o O d O F o F o 0 5 It 3 •oo 0 0 °' ' °e. ° M ° ol E. EL ei ° a 4. o a o a o S aF S V QV a" Aar A � o N W U a c a i OR Qo o a a w co) 0 0 ° A Q c� .5z Q UU U a a •o0 0'.. 0 G to m n CO v C C C C C > i°. C 4 4 4 a) U •5 Q p O iG Ern O O O & O A N N b o 0 o f m y u7 V b N x o 0.. v o F �-�' an O .° �>j-. .+ 1in 0 Cy L, i7 = 'x o •5 Q a • W , O a) 3 Q U a y m V o c c p o ..... 5 5 z o mti Q .0 efi ❑ .n �° 01 w w o U U Q cn U ,z A r• O o >, C v L ") o O ° t v a� a E o v a v .5 5 ' m pp C a T) Ti.) C U_ 4 'N" OCR. aa0i `. E d a0i y ai 4 «' .ro o v w° ° . 0 .n a a) v y a0 k, U e ? Vic ' a � - p •5 A" a U 90 0 5 . y 3 3 m ° -- ' z .^� a z z ..'�'. L al v w y a 3 C a a E A ti d co o 3 U •E Q Q .: c an a co 8 z A z z g w C) C) 0 v N en V h b F > > > C M o m a a)i a) a5) a) ,5, o w U U v g m U Q — 0 O C 0 w r O ct *am y g _ a v P r E E U 0 N � c0• • y o o - 0 0 0 5a: o 0 qa, •v ❑ 0 o y 0 04.? o f u U 0 °U' ° a�i U G •.- 0._ 'c 0 o .7, '3 o >-, 0 a W ❑ `° ado a .0 9 t ti •ti v) in E ,O a O u u ,G ❑ 0 w v 0 V m 00 U �O„ a) m 0 F • taC C 7 .O ,,, O O 0 O al 0 .. 5 -..q. ❑ 4+ a) 0 W A T V A O 0 0 0 U a, 0 7G e S `I- o a E c^ 0 en v •w b 3 .0. a' o• o' 0 0 5S w e m ,o 33 v : 0 .°'. .0. 0... I.. 0E 0 .500 ari ao o y � . �'� ^ Porn m ro v) m ro y ISO PI p1 5 ° 5 y c "• I. CO `o m s .5 0 18 E .5 •3 O ' 0 0 0 0 0 0 'S •' coti m o °' 'o m p a 3 �a a m ❑ 0 0 n 0 0 .5' .ct � 0i ,i 'A 5.', 1«t -ca ry U, w •„ 0 o « 'a o ti00 0 5 E E E E o a 8 .-. `' 0 • y° anCo � .5 � o � obA ^ .5a 0 0 p 50N ❑ aoS ? a s � 0 .NU w 2 :° r. aN .C O .G ≥` 3 3 3 3 '3 n•Gr- •A� , ^'o O 0 « .- 'Se .5 'a o 0 x ,5 0 " 0 0 0 0 0 .. 0 0 p — CG ° �^ 0y .5 .50o � T0 - o to to al) e❑n a. cc = '� 5 � .Fp. r NW pyPN � � 00 id p g g g � d U � G, to y HfQ 3 A °CC°'•= o o b ° ,'o', o v •❑C❑C '5 0 0 0 o a p w .5 0 ,0, aoi i U TA O ^ % .p. L 0 0 0 .5 0 ° E 8 ro 0 0 0 0 0 F O P.o w a v 0 A F w is y a Q 2•� U � v, -� 0 x a U -49. F 0 - . a.6 .O. Q c a O 2 v m v 0 N is N m aa) .~% 0 ;..cit 0 1_, .`°. ti o e• 0 0E• o o 0 0E. o fr. o Ea, 0 0E. C 0 0 W o W o W ° 0 WW $ 0 �WW, a 0 0 x 0g x g a. o a o a .5 a .5 o a .5 O Q c A C Q 0 a c Q c .a G •° s Q c 0 '2 U U r_ U :s U U U ,s U U R. U U R U U d '_' N O O O a a O N t° P. °'cii O O O O O O O O U to 0 .. a. n OO w C 3 3 �, ., 0 U et db = Q N N kin �q y O Cel M M F4 .0 ti u c. E• c .5 .° d 3 .5 m A •o .: M '^ n 5 b nO , f? U 0 y 0 'y ❑ v "Cl 0 ios 3 N •r O. .D.; .d aa>i o ro a ° ° .O F o 0 o E W G Y U U y d, u) O O id a) 5 O O o- C 0 R h. U a pC .5 .p .' 40 00 0.0 O C .0 U u d b p . U O p0 p , .0 ✓ ON •C 0 p N 0 a;` 0 .0` 0 0 a 0 . o o O O O d o h C •5 to'- bp'c, rs 0 .0 ^" U O „, ... a0 .5 5- A „ a � ro Vo 05nbo 000 U 00 t>rG O F •E 0a N U y U .d t0 0 ,�, ., 0 W0S� • r- rUa .� E 00 ON 05 ..-0 U •O . 00 a : a : E F ❑ o 0 ✓ 3 m = g 6 rs co CO<n w o ON O r, o b 0 U U N O O 0 .0 O D L 0. FU FU Fvoi E-- y) FO FEil O 0 .• .. `O .. b .. • ... b ... .-, COcn v) 0 Ct U 4 0 -. In rn cn rn R 7 0 C70 Q - - N O 0 0 p 'J 0 C ,g ..T `O o tC O 01 o 'g' a 0a m o > v1 0 �`+ ,Ct o N 'S 0 ° 4-. .`4-1 °� .. .' .S -5 . .t°c /. I E ri LI .S a �':o• a w0 mu HoN. o c . V•) o O v dr .ti .S a d m v .S o m 0 p °° coo °' v ,"' 80 '5� o V te a« v •0 M g .S «'� pp O N m N S W •S U .��j N O '0 v W 0 0 tu w 'Rs of 0 OD O m U u, VI -. r. ti .S .D S CO 0 vial or N 5 m C 4 U m d V O 'o > y Low N ° C U O N •• P. � m A a .gaCT: 44 ?9, -o m0 va oo; « 0 0 .o .0 a._ 0 0 0 N 0 0 a) S F .g N o ‘~ C . Coa °V'• 'v A 0 yv .5 Sw 8 � .TO '« . '^ rn a a q m ;: 3 O o .0 y m o a S S aa. .S `� o o • A °L' 0`n. y 'i_� g ," 0 v C "q 'k. C v' a'� j N C C L 0 0 •> •r� o C F _c. = fn 'O 0 U IN 11yy Q ; to S o O y — _ Y N O xi N N ' a) .� 0 'Y d 0 3 3 3 •o 5 'y o 0 w o. .S Co eo ra •« c a.'ra' 'a 4 �. .y• L0 a) •n C „ a) o ME .ca o C o >a 3 « 0 0 0 g c°° 0 m o °' 0 n ao m o C o La b -S y o vi o `Y S i° o °o - a.T o f r''. g g `� C o o B g .5 CO :� '� G v v DO o ti C �., w aCi o, q�q .pp' u u 40 o °°'i o o S y 'S W > y .o w °' « 2 2 W o .">.! °° ` ,00 > ea C C o 0 o 'a 7 .d. o� m 'o u U A v .- 'o .o 3 o :O V .°°. A F �3 °; = mn. a gaol)• = a� ea 6 d 'g O 0 U ' c So 5 >°, o QUO o 0 p 0 3 .S ° L 1.� L °) L N I 0 0 • .(n .0 N fa L L 5c « a « o2. o o o 5' a 0 0 4 .o. - 0 C WW w 0m w W 0 Wo u o - 2 w o o a e av p� o a o p 5 a .S D O ° O. m o A A ,� A ,� A o a '° ,� A 'd V c q v V U ono . . o a V a> U .0 Q a. U Ly d C C 0 N C C co CO 0 O O O 0 0 0 M 0 c R .o .S U po o a .C S m 0) U O >.J. p d P. >. C v 'E a) o $5 o ^ z m 7 N a W y O _ .0 yahCO '10 b a.0t 0 0 00 � O . r W 0 Q "n �0 .C 0 N `V L>�i °L' Q' `'aLa o -a O o 0 `° y o •5 a, m 0o y b .Oo..0 ,°°, o .0 ^ T, x 0.i 0.•a^O, k\" y 5 x 0 o .� O 0 o .5 Urn M o o la o °y°�"i z 7 N (n .5 .y 1] (.7' O �a pr., N — o V L .S 0 � c /-. U L M +•+ ` 0 y., a '^ .o J I-H C ^ �a to aa P' co to•O Li O O M 0 o C o w) a° « 0 00 « = S •d0Oa L m'H >ro 0 '5 V in 0 co c'ii LN Vl o 'd f.1 L L .2"J. N - M C as J 6j` F.Or o a .C o a o o 0 'o S o 0 o w G 'P. m o m w v 0 m ' SO a> v, x z ^ ❑ 0,S W `C'^ 0 0 M .0 N .O .0 m O S w C :S �j- • , O 0 'O � 0 o ro tn a .. o w o ea d 3 t'A ro Z .S a1. °o °m .E NO 'o 6'0 U . v Cwy . apn L DO. 6 0 .0 G 0'J? o Si �aC. O G. o 2 3 o m_ Q a~ N l ca C °e 'N ...0-.H x T o a a T ao ,c w " w a° • .c r° .a o a. a>i W U = mU y F C F� O E O F LF ., m o $ .5 O a' ,: U ca U U an a' V 0. na V M N E o a HZ - - a � ° 4. _a G — .. _ _ N M rn A ti L .0 -- a - .0 = M o r�, G7 O O cn an v G 0 '^ rn o a "10 N y C. N N U ro Q. N b i o o 0 « a c _ ❑m o o a " c ▪ u a ri a) « C ti .« U t- U r b 0 C ° 9 U E44., N U 7 °—c' 3 o .n>Th.3 ai yU o `"' 0 W m 0 .E 3 `° aa)i c a 0 4., aa'i ... « ` = pp cd q .k .c ° U ≥ G w ti .5 .S.� o w a ° v' a 0 et on c o . o en ,5 opt E A ti o_ .o a 2 0 c i W ¢ 0 8 N a W .0 '5 y _ - c ,a o , o c. c o • a) R y 0 a W U « Or r O 0 -c .0 m U U .0 O a) c E p « U b 'pp p y P. « O G O y X E U itl A .`9 �. �' y s « d 0 W O tU. G aC� O^ y C O C M W W .b 30 . i0 al U C ' a 0 .0 0 0 0 0 O v ° w0 a a' x '_ .x o f 5 Q « E o c' a> a O Y a p. ' m c ❑ « « '°o ' pp 4 m w •t( La .-0 0 0 E v aJ U -0 'o E Y 3 c « r°'. s m 0 0 a"i w c v Cc m ° °° „ 0 ,44 ... 0 ›. 04.... .."^a U U m 11:10 `pp" c a' l-. 'O y L 0 0 U W k O O .5 " •0 Wtop —U' L 0 - rn en 7` U .O b 4 gm 0 c 5 CI) `° .�.� ? c v o w .° d � _ . � `� � .5 'E C.) ° ,� nu 0 .ro o ,00C] .5U3 .cch E « " .5 0 ,x .0 � ¢ .= .a 4xg 0 W r .N c. o ce " o W o y « a) 5 UN m x d a y a o o 70 c .c°. c CL 0 0 c C] ip c « n .E w ... y z b O 0 t E 'o b d .� 3 0 .0 c o '� c a •a x ' 'v 0 3 SIP g .5 00. ti) y U W 2 act 3t '≥ >. o ° o g a v x ? o a u y A 0 0 a 3 ?> ca, N o .5. en u Y. 0 a °U 5 d >•o.. 5 'y g y A b v .> 0 ro < ro.� G�. ° o a"i .5 o c 5 U cis as �• '5 .r .� .� d °▪ v y x v A F .� Q rna E « d o o P. 0 a CO '0 0 3 « C -0 m .5w °_' 5 o d m « 3 3 a) 0 0 0 y 0 0 vy = �' O " O o O i' 0¢« O Q. O EL .N, 0 O O O 0 o O y .r (2 E• •••• 00 ^ 00 ^-' 04.) 0' '3, o m . c • a ,c5 c a . a .5 c ax. c ID a 5 ID p. •5 °° tic =CI c � c � 'U' `� 'o 'o U �U U C]V c U �V . v WV 'o 0 Q o uU .cv o 2o a0 0 0 0 0 0 0 a a a a O¢ Oa v an O O O O 0 C ... a« eu y >' o c 5,.3 o U o .: 0 .9 a In o. .0 -0 0 0 >' c° 0 c r c E E N 6) ° bp ° 0 o o a " r� ; vi E a, v p � .5 « 'n .a -E 5 < - ot < vo A $ '9 .E0 > 5 �° m d v c « o c ' « « 1.1 Q VI ` C 0 ° .0 0 y :0 y0 C a) 0 m '0 . « 0 a -20 00 ,d, 7 0 5 y cl L' 0 U N U 7 cis U y r. o O T 0 .5 N i. N r 0 0 Y 0 C Q 'E c c o o .C M c a a) y •.r 5 .5 c d u o 3 0 • a °°4,40 ca on c -Goo C „ y 3U a E °°c m y b •y w ,... 2 ti o o OWE o an m '° E c •a«i m ° 0' y.4 Gc`C Ca 0 v d « « x' v .G G 5 L xrri a) .L' N N m ' 3 0 0 0 ° '-0 'o U < � U X -o U x an $ � 3 « ' = 5 H d W U _ v (.) U U cn i° O ry O v - Cr, F ro F > v J`D U .▪ r-. M .r-. R a" 7 ,- .� 7 .r-i ‘cc C a) 0-0 C N N N N N N a d N d N O T k O VO OCV 0 Vl . q d o '• .o o E o o o .E O .a. 6 o rt .o r Z .a'. v o .S `j o : nc. � 3 � y 072 .90 ° ° a . vo: 2 0 ca gi. `- w .5 v q &I o > ; awEi -c N N > 5 N « � rte. .4 to � ' U � 'qq '�' e o ° d w .� o 0 q qa} tp 000 ONm 0 oov �, a � b .S o °' c a gp q q a. 1 y 0 0 O O N ,$ G N L R y 0 N w > e in 9y -, coq ra raa.. r a .. rr aw3c .� b p>pca m q q o b •p V ° O O •'g <tl . d Oa O G .aa. J+ v w N •> m a, y U ��' •y k y a.`,3 9 O ur w O m U y o �c m u o m o m c..N ra q y.vi Z 7 e E . S G N 7 w A v .q a O .o w AU v a NO a � C•1 a >° � a^ u a� c4 3 .p o .5AU « A 3 co °� 7. C4 y ti ° 73 A K d p A .? v n a) p,p o p. a) O G y p q ' q 7 as .y a O H o Z;op 'y q .E• q aC ti > O a'a' 2 ° '^ w v .. O v a m a U 4 y O A g U n.9 « Q age '2 Q g 'J gU d ,Z aa°'. Zc:i &°.. 'az ID d °2 v ° m v v m m '> co y > « as a > o > a, .. q h O L. o w o q'O r o C 3 W 0 0 e. O Ea O e- C O S E' a) �i] F. �Wy O W O O h.. E P. 7 .7 a S ao ,g to a' ao U u Wx A a> o A •� °' A •o g q •o 7 to g g qv 7 U U 7 2 U u U � '0 U o u i> U 7 u O 0 O a O 0 0 O 0. a 0P. °' v O a e Po 00 .. O g O PO. 'o as « w w U .y o .'^ p, o ae. 1/4O a o A - 1-. 0 '-' 4-' < < , > 5 o > en 'd .° m 'S cgi q •�' v o .j .' w .a vi la 32 A d O a v y e .q « a) .p U 4r o 0 0 ,o d r :� y0 �' •5 ` q o c O d o 0 « E d h oo a .0 .q u art ro v•o o ° ,� o •• .4 in '5 0 E 0 o o •� a 'tea ? v .. • N O vi N M V >. E E p « y ^ T.Y F X a 'S q q r� N `3 ,° ° O 0 n .9 3 ? •p O OA N o 0 « z O a� F4 T c v'O 0 U q 0 0 - et O c Z N ,0 - '7' q co « N a U g 5 7 a co cr y 2 2 O o o N < 'o v '6 d o o m %.. C A a m .. U 8 U g < Rl Q LG 3 o C ti m s . a yU `9 N q ry N g A. M O .. b a. ,46H U b‘16 CO O- P. O C ro N O a '. N •p0 O 0 N a. M en en M Q .I�q a. V o Q 1 Q o o Ni N 0 0 ) \ ) \ ( 0 0 0 0 0 VI \ \ \ \ 0 ! ! \ \ 0 0 \ \ ) 0 0 / ! & ! � 20 ( \ \ 2 \ } , \ 00 O0 @ -0 ° @ ® ca \ ® / § % / uu ; ) u ; eu § auee ) \ \ / i a. 4iffs .0 CO \ to ea \ . < ) cs » \ 0 . \ / O ; / ) in / ! ) /» § o ca a. \ H - ) \ ) ) ( ) \ ) \ / cn 01 m ea z z a a \ . Q. \m \_ \° @ O. # P. P. C. ; ®' ® CALPINE CALPINE CENTER C® A' 717 TEXAS AVENUE �(J, SUITE 1000 tr. C� \ HOUSTON,TEXAS 77002 �y 713.830 2000 3 e, 713.890,2001(FAX) January 18, 2007 Attention: James A. King Colorado Department of Public Health and Environment Air Pollution Control Division Stationary Sources Program 4300 Cherry Creek Drive Denver, Colorado 80246-1530 RE: Rocky Mountain Energy Center,LLC—Keenesburg,Weld County, Colorado Draft Operating Permit Comments (Permit No. 05OPWE279) Dear Mr. King: On behalf of Rocky Mountain Energy Center, LLC, Calpine Operating Services Company, Inc. (Calpine) is hereby submitting the attached draft Title V operating permit comments. Per our discussion on December 12, 2006 Calpine is providing the below comments to specific aspects of the proposed conditions in the draft operating permit. In addition Calpine has attached adddtional data clarifying our postion with respect to our comments. NSPS Subpart Da NOx Limit Clarification Calpine agrees with the Colorado Depai talent of Public Health and Enviomment(CDPHE)that the 3 ppmvd @ 15% O2 NOx BACT limit is more stringent than the NSPS Subpart Da NOx limit of 1.6 lb/MW-hr and should be streamlined to the 3 ppm limit. To justify our postion concerning the NOx BACT limit being more stringent the the Subprat Da limit, we have attached example calculations showing NOx emissions at various load conditions well within the Subpart Da limit. Chloroform and VOC Emissions from the Cooling Tower Calpine does not agree that a chloroform and VOC emission limit is applicable to the Rocky Mountain cooling tower. One basis for this position is that the Micheletti letter the CDPHE is using as the method of determination is not applicable to the cooling tower at Rocky Mountain. Specifically, the Micheletti study was performed on once through-cooling towers, which is a fundamentally different process than the closed loop wet mechanical draft cooling tower system used at Rocky Mountain. hi addition,Calpine attempted to identify another method for determining chloroform and VOC emissions from wet mechanical draft cooling towers using the U.S. Environmental Protection Agency's(EPA)AP-42 emission factors. After review of the methodology provide by the EPA Calpine can not find any details on chloroform and VOC emissions form wet cooling towers. Therefore, we consider the proposed chloroform/VOC emission limits to be inappropriate and not applicable to the equipment at the Rocky Mountain Energy Center, and they should be removed from the operating permit. Auxiliary Boiler NOx Analyzer Span Value Clarification The Rocky Mountain Energy Center has an auxiliary boiler on site in addition to the two combustion turbines. Per the requirements of 40 CFR Part 60.48b(e)(2)the span value for a NOx analyzer shall be 500 ppm. The span value of the NOx analyzer on the Rocky Mountain auxiliary boiler is 100 ppm. After review of actual emissions from the boiler, Calpine is able to confirm that all NOx emissions from the boiler fall within the 100 ppm span value. Calpine has also attached an EPA applicability determination confirming the EPA will accept the use of alternative span values for NOx monitors associated with auxiliary boilers. Accordingly, Calpine maintains that the 100 ppm sapn value is appropriate and that the Title V permit should be modified to allow this option. Diesel Fired Emergency Generator Status Change Per the requirements of APEN Exemptions in Colorado Regulation No. 3,Part A Section the emergency generator at the Rocky Mountain facility is an insignificant source due to the fact it is rated at less than 2000 hp and runs less than 100 hr/yr. Calpine has attached vendor provided data demonstrating the source is rated at 1810 hp, which is less than the 2000 hp exemption threshold. Calpine appreciates your time and consideration with regards to our questions and comments. Please contact Ryan Bowles at 713.830.8347 if you have any questions regarding the attached information,to coordinate a meeting and if you require any additional information. Sincerely, e Oper g ervices Company, Inc. Jason M. Goodwin,P.E. Director—Environmental,Health& Safety Eastern Power Region On Behalf of Rocky Mountain Energy Center,LLC M:\Ryan Bowles\Rocky MountainkRocky Mountain - Draft Title V Comments Cover Letter revl.doc cc: Ryan Bowles, Calpine EH&S (Houston, TX) Jim Gooding, RMEC (Keenesburg, CO) Gary Aron, RMEC(Keenesburg, CO) File, RM-A180 ROCKY MOUNTAIN ENERGY CENTER, LLC DRAFT OPERATING PERMIT 05OPWE279 COMMENTS Cover Status Comments Letter Item 1 The definitions for startup should be revised per Open CDPHE to Review and comments in the Permit Body below Incorporate Item 2 New APENs to be submitted Closed Attached Item 3 RMEC will submit a demonstration. Will clarify Closed RMEC to submit demo and Divisions needs on this. CDPHE to Incorporate Item 4 New APEN will be submitted for the Auxiliary Closed CDPHE to Incorporate Boiler. Item 5 New APEN will be submitted for the Cooling Tower. Closed CDPHE to Incorporate Permit Body Page Sect. Para. Changes Status Comments Cover Issued to: Change address from 4160 Dublin Closed CDPHE to Incorporate Blvd., Dublin, CA 94568 to 717 Texas Avenue, Suite 1000, Houston, Texas 77002 Cover Responsi Change from Mr. Jim Gooding to Closed CDPHE to Incorporate ble Mr. Jason M. Goodwin, P.E. Official Director—EH&S 713-570-4795 Cover Facility Gary Aron's Title is Operations Closed CDPHE to Incorporate Contact Manager General RMEC requests a 60 day compliance Open CDPHE to Review and window from date of issuance for Incorporate software revisions and testing. 1 I 1 The engine driving the emergency Open CDPHE to Review and 1.1 generator should be considered an Incorporate—RMEC has insignificant activity along with the fire attached vendor data pump engine and included in Appendix displaying the source is A. insignificant. 3 I Table ...a steam generator rated at 326 MW Closed CDPHE to Incorporate 6.1 CT-01 (at peak capacity) 3 I Table ...a steam generator rated at 326 MW Closed CDPHE to Incorporate 6.1 CT-02 (at peak capacity) 3 I Table ...and at rated 1810 hp and 6.51 Open CDPHE to review and 6.1 S005 mmBtu/Hr incorporate change -RMEC has attached vendor data displaying maximum hp rating of 1810. 3 I Table ..., 12 Cell Cooling Tower, Rated at Open CDPHE to review and 6.1 S006 176,000 gal/min. incorporate change—RMEC has attached a revised APEN. 4 II Table The rate should be 0.00293 lbs/mmbtu Open CDPHE to review and Sub. 1 "VOC" and compliance factor 7.3 x 10-4 for incorporate change S001 and 1.5 it 10-4 for S002 4 II Table Should there be a Compliance Emission Closed CDPHE to Review and Page 1 of 4 RMEC - Draft Operating Permit RRB-GMAComments R2 (2).doc 11/16/06 ROCKY MOUNTAIN ENERGY CENTER, LLC DRAFT OPERATING PERMIT 05OPWE279 COMMENTS Sub. 1 "5O2" factor of 0.0006 Lb/mmBtu? Incorporate 5 II Table Based off of the Title V Permit Closed CDPHE to review and Sub. "Natural application fuel consumption for each incorporate—RMEC accepts 1.7 Gas" CT/DB's and full operation the limit the 32,625 mmscf/yr fuel should be 38,305 mmSCF/yr. usage limit. 9 II 1.4.4 Typographical error insert"gas"behind Closed CDPHE to review and Sub. natural incorporate change 1.4 9 II 1.5.1.3 The last sentence should read"Setting Closed CDPHE to review and Sub. in operation for these turbines ends 30 incorporate change 1.5 minutes after the turbine reaches Stage- C Operation." 11 II 1.6.1.2 Typographical error: NOx should be Closed CDPHE to Incorporate Sub CO 1.6 19 II Heading The Emergency Generator is rated at Open CDPHE to review and Sub 2 1810 HP. With the HP less than incorporate change -RMEC 1840,RMEC will submit a revised has attached vendor data APEN showing no more than 100 displaying maximum hp rating hours per year of operation. As of 1810. mentioned previously this machine should be considered an insignificant source per the requirements of APEN Exemptions in Colorado Regulation No. 3,Part a Section II.D.1.ttt.(iii). 21 II Table Change Limit to read 0.039 Closed RMEC retracts comment and Sub 3 CO lb/mmBtu on a 3-hr rolling average accepts permit requirement as Change Monitoring Method to written. Continuous Emission Monitoring System and Interval to Continuously 23 II 3.41 Revise entire section to reflect a CO Closed RMEC retracts comment and 3 CEMS similar to the 3.3 NOx section accepts permit requirement as written 24 II 3.6 All natural gas used at the facility is Closed CDPHE to review and 3 sampled and analyzed through a Gas incorporate change Chromatograph on-site to determine HHV and logged in the DAHS. Please delete this requirement 26 II Table Change 91,595.3 to 92,505.6 Open CDPHE to review and 4 Water mmgal/yr based on design flow rate incorporate change—RMEC Circ of pumps. has attached a revised APEN. 26 II Table See discussion for paragraph 4.2 Open CDPHE to review and 4 VOC below incorporate change 26 II 4.2 The basis for the 2.4 tons/yr based on Open RMEC requests removing 4 VOC Micheletti letter is for once through VOC and Chloroform tower...RMEC is a recirculating emission limits system. If the Division must use this, the tons/yr will need to be increased Page 2 of 4 RMEC - Draft Operating Permit RRB-GMAComments R2 (2).doc 11/16/06 ROCKY MOUNTAIN ENERGY CENTER, LLC DRAFT OPERATING PERMIT 05OPWE279 COMMENTS to 2.5 tpy with the new flow rate. After reviewing the US EPA AP-42 emission factors for wet cooling towers neither Chloroform or VOC emission factors are in the document. 27 II 4.3 There is no way to monitor circ water Closed CDPHE to review and 4 flow. RMEC can record a value each incorporate change month of the GPD x days in month to get monthly total water recirc'd. 29 II 6.1.1.1 Add the CO monitor for the Closed RMEC retracts comment and 6 Auxiliary Boiler accepts permit requirement as written. 29 II 6.1.1.2 a These conditions should not be Closed RMEC accepts the conditions 6 & c included in the permit. CO monitors as they are currently written in are not subject to the requirements of the permit. 40 CFR Part 75. Nor is the existing DAHS system configured to accommodate these requirements. If the CDPHE is going to require Part 75 monitoring provisions for CO analyzers then it needs to be consistent across the board. It is confusing trying to figure out whether we need to do a Part 60 or 75 QA measure. 30 II 6.1.2.1 Add the CO monitor for the Open RMEC retracts comment and 6 Auxiliary Boiler accepts permit requirement as written. 30 II 6.2.1 Add the CO monitor for the Auxiliary Open RMEC retracts comment and 6 Boiler accepts permit requirement as written. 31 II 6.3 We need clarification of why the Closed CDPHE to review and 6 Para 1 condition is being required since CO is incorporate change not subject to Part 75. Shouldn't the last sentence state that the data acquisition system"shall"be programmed versus"is"programmed. The DAHS system is not presently programmed to perform Part 75 type substitutions for CO. 32 II 6.4.3 Do not understand the"span value of Open RMEC has attached an 6 500 ppm for NOx Applicability Determination by the US EPA documenting that a lower span value can be used by a facility as long as actual emissions fall within that range. Acid Rain Page 3 of 4 RMEC - Draft Operating Permit RRB-GMAComments R2 (2).doc 11/16/06 ROCKY MOUNTAIN ENERGY CENTER, LLC DRAFT OPERATING PERMIT 05OPWE279 COMMENTS Appendix Pa Table ...a steam generator rated at 326 MW Open CDPHE to review and B ge CT-01 (at peak capacity) incorporate change 5 Appendix Pa Table ...a steam generator rated at 326 MW Open CDPHE to review and B ge CT-02 (at peak capacity) incorporate change 5 Appendix Pa Table Delete if determined to be Insignificant Open CDPHE to review and B ge S005 incorporate change 5 Appendix Pa Table The cooling tower is a 12 cell tower Open CDPHE to review and B ge S006 with 176,000 GPM flow rate incorporate change 5 Appendix Table Same comments as for Appendix B CDPHE to review and C above. incorporate change Page 4 of 4 RMEC- Draft Operating Permit RRB-GMAComments R2 (2).doc 11/16/06 tv O co N co N \ O fi ; in . \ \ \ \ \ _ \ ) \ } \ \ . \ B ! ! Ox 43 '82 o 03 : 3abz 0iro @) E 0 7.11)0 ! co x 15 a 7 ) ! \ , ( cc 0 § 0 \ k k O 0 • aOE E f ( ! ; ; 0 2 od O ) ; f \ / \o. ) - ( ) ! § I ! k 2 \ 2 } K \ ; ; / 4 « CO CD & j ) | ° r , � , ] ,r. , cc 2 o 2 tam Co / /] ) , II II II § ! ! , , . , , o II f x k ] J §{ ! !J wgo ) Eri \] ! ) k ) § k � ` � - z 7 O � = : ; W J ! ; : ) 2y = ; § E ; ! ! tC j \ 0� � : 2 \ � } - ) O5D 0q O ! O G « N 0 0 rn N m O 2 C J co U 4 U a o C • d O L y u_ m a) t E t " .n, 2 N > (1) E O c n E m Jr a s « 0 a m U p C r p « ra O o E D O E E — c .8 o. °° Ti w o' o aci 5 O o` E c :O X y 'i U) O x R o U C O X III in CO a 0 W CDOZ U c , x ._ O I. 0 O @J y 0 O m m = E co O 0 N > CD to-Z J TL I- L N J W c m a c E 0 E oo r - ' oLT) U s L U IY p 3 3 E a E x x y o a r •oo) m E "� .E Q II II V00 a Z Zv .y a co m E w a a J c c m o `w o o m y vii a r o y in 0 cn co 'n m �" N C f' T N (.1 M C O O M Er N N LU O a m c WLU W C o E p •- N m E u ._ _ ,� m V o J 0 X N J a La O E m E w C1'- d w u a u n u II 3 W j u a a a II n n CD D co co x u3 C c 3 o (`1 co N N W p0 g u2 2 `. C -a . X ' D. EF— X 'cis O al ah. y O m f V. � Z o i— a) Zn � 0 a0 a p E n. c w U Y u. W W w o a t c o W I W O W W 2 E E 0 2 " 5 co o O � ' YmEa co -0E 4. � 0I V V 'Xr o W E N + o U d' O5n 0 = O mo.. 000 N 0 U U a 0 cn cn ^ § 15 z \ \ , `co 43 \ \ k \ \ \ E r2 o. ° ° E c \ \ } \ \ _ $ Ay B : ! * z a CO G ! & ` $ \ 0 ; a ) , r . 2 03 G { 4 ! ! f . r { - , o : 2 2od ) ` } cE - ` � f f tr 0 / k 2 ; } : , . , , , § , cc ° w , ! 2.3; : § J rn cc E ! 00a c § ! § >.� , ! , , , , I , co ; J , II II , In � -S \ � co E` 5� \! 0 ea - 2EE 95 : z = : ; ] } § 9w : _ � : , m u� 2 } ( ) ! + U— J02 ) ! ; oae JI ) cq 6 N \ § 15 s ` /a r7 u_ ) - t 0 Ea 022 « / Qt : 0 { _ . ! E09 ica z ! ) k � 2 ! ) o0 \ 0 o 2 0a O V =11 ! m ) w 0it a0 0 o0 - o e ( $ oa _ Ol : , O � a ) § \ : E k \\ kk ) ` O f \ bE o a) II II — / f\ f / ® Ece a Ill e- c71 . 3 „O cO co Lai _C , N e , ! & �f ] ! , . , , , II ! t , , . , . . ) S0 | \ } / � � ` / S. / \E 20 ° ; . o ` • , ! ® O co § oY = = } � 0C3 in Q ; § f ! ! 2 ; \ \ a .- ea a a. .a — J02D ow 2oab of EPA-Clean Air Act Applicability Determination Index Page 1 of 4 p 4Fa Fs. U.S. Environmental Protection Agency • r Compliance Assistance a Recent Additions I Contact Us I Print Version EPA Search: EPA Home>Compliance and Enforcement>Compliance Assistance>Applicability naott` Determinations>Applicability Determination Index>Search ADI Database Centers Search Applicability Determination Index Planning Sectors Search Return to Search Technical Recent ADI Related Stakeholder Outreach ADI I Results I Help I Support Updates Links Applicability Determinations • Determination Detail information Resources Control Number: 0000113 About Us Category: NSPS Newsroom EPA Office: Region 4 Where You Live Date: 06/01/1999 Tips and Complaints Title: Alternative Continuous Emission Monitor Span Values Training Recipient: M. D. Harley Author: R. Douglas Neeley Comments: Subparts: Part 60, Da Elec. Util. Steam Gen. Units (post 9/18/78) Part 60, Db Indust.-Comm.-Inst. Steam Gen. Units References: 60.474)(3) 60.47a(i)(5) 60.48b(e)(2) Abstract: Q: Will EPA accept alternative NOx and SO2 continuous emission monitor (OEM) span values currently in use for monitors installed on three boilers? A: Based on information provided by the source, EPA will accept the alternative NOx span values for the monitors. EPA cannot make a determination on the alternative SO2 span values until the source provides historical information regarding the maximum sulfur content of the coal actually burned at the facility. Letter JUN 01 1999 4APT-ARB EPA-Clean Air Act Applicability Determination Index Page 2 of 4 Mr. M.D. Harley, P.E., DEE P.E. Administrator Emissions Monitoring Section Bureau of Air Monitoring and Mobile Sources Department of Environmental Protection Division of Air Resources Management 2600 Blair Stone Road Tallahassee, Florida 32399-2400 SUBJ: Alternative Continuous Emission Monitor Span Values at Indiantown Cogeneration, L.P., Indiantown, Florida Dear Mr. Harley: The purpose of this letter is to provide you with a written determination regarding the acceptability of alternative continuous emission monitor(CEM) span values currently in use for monitors installed on three boilers at the referenced plant. Indiantown Cogeneration L.P. (ICLP) refers to these units as the aux boilers and the main boiler. The two aux boilers are subject to 40 C.F.R. Part 60, Subpart Db (Standards of Performance for Industrial-Commercial-Institutional Steam Generating Units), and the main boiler is subject to 40 C.F.R. Part 60, Subpart Da (Standards of Performance for Electric Utility Steam Generating Units for Which Construction is Commenced After September 18, 1978). Based upon our review of CEM data submitted by ICLP on March 25, 1999, we have determined that the alternative nitrogen oxides (NOx)span values for the monitors installed on all three units are acceptable. Since the March 25, 1999 letter from the company does not contain enough information for us to determine whether the span value for the sulfur dioxide (SO2) monitor on the outlet of the scrubber used to control emissions from the main boiler is acceptable, our letter identifies the relevant factors that should be considered when evaluating the current span value for this monitor. According to 40 C.F.R. Sec. 60.47a(i)(3), the required span value for the NOx monitor on the main coal-fired boiler is 1000 parts per million (ppm), and according to 40 C.F.R. Sec. 60.48b(e)(2), the required span value for the NOx monitors on the gas-fired aux boilers is 500 ppm. The NOx monitor span values currently in use on the main and the aux boilers are 250 ppm and 300 ppm, respectively, and based upon emission monitoring results from the first quarter of 1999, ICLP was able to quantify all NOx emissions from the main and aux boilers using these span values.The data submitted by ICLP consisted of hourly monitor results for the period of time between January 1, 1999, and March 17, 1999, and the maximum NOx concentrations measured during this time period (199 ppm and 130 ppm, respectively for the main and aux boilers)were well below the corresponding span values currently used by ICLP. Therefore, it appears that NOx concentrations in the flue gas from ICLP's boilers are considerably lower than those from the units the U.S. Environmental Protection Agency considered when it specified default NOx span values for boilers subject to Subpart Da and Db. Unless NOx concentrations in the flue gas from the aux and main boilers exceed their respective span values in the future, we recommend that ICLP be allowed to continue using the alternative NOx monitor span values for the monitors installed on these units. Data from the NOx monitoring systems at ICLP should be reviewed periodically to verify whether the current span values are still appropriate in the future. If the actual NOx concentration at the outlet of any of the three units at ICLP ever exceeds the current span values, it will be necessary to increase the corresponding span value(s) in order to ensure that the company can quantify all NOx emissions and potential exceedances of the applicable EPA-Clean Air Act Applicability Determination Index Page 3 of 4 emission standard. The current span value for the SO2 monitor at the scrubber exit on the main boiler is 140 ppm, and over the course of the nearly three month period for which ICLP submitted data, there was one hour during which the outlet SO2 concentration exceeded the monitor span. Over the time period for which ICLP provided data, the average SO2 concentration in the boiler outlet stack was 52 ppm, and the outlet SO2 level exceeded 75 percent of the monitor span for 17 of the approximately 1800 hours of operation addressed in the ICLP submittal. Therefore, even though ICLP was unable to quantify the magnitude of the SO2 emissions for one of the operating hours in the first quarter of 1999, the SO2 concentration was well below the current span value for more than 99 percent of remaining hours in the quarter. The March 25, 1999, submittal from ICLP did not contain the information that we would need to review in order to determine whether the current SO2 monitor span value on the main boiler has been set in accordance with provisions in 40 C.F.R. Sec. 60.47a(i)(5). Therefore, this letter identifies the factors that should be considered when determining the appropriate SO2 monitor span for the main boiler, and we can give you additional assistance with the resolution of span issues for this monitor if ICLP supplies historical data regarding the sulfur content of coal burned in the main boiler. According to 40 C.F.R. Sec. 60.47a(i)(5), the SO2 monitor span at the outlet of a control device on a boiler subject to Subpart Da should be set at a level equivalent to 50 percent of the maximum estimated hourly potential emissions of the fuel fired. Although ICLP does not have an upper limit on the sulfur content of the coal it burns, setting the outlet span value based upon the maximum sulfur content of the coal actually burned at the plant rather than basing the calculation on some hypothetical "worst case" coal is recommended. If a worst case coal is used for the calculation, the resulting span value will be high enough to ensure that nearly all outlet emission rates can be quantified, but the monitor resolution under ordinary circumstances will be poor if the sulfur content of the coal normally burned is significantly less than that of the worst case coal used to calculate the span. We can think of two possible reasons that the SO2 concentration at the outlet of ICLP's main boiler exceeded the span of the monitor installed on this unit. One potential reason is that the the sulfur content of the coal burned on the day when the span value was exceeded may have been higher than that used by ICLP to calculate the span value of 140 ppm. The other potential reason is that a malfunction may have caused the efficiency of the scrubber on the main boiler to drop below 50 percent. Under this second scenario, setting the outlet monitor span value equal to 50 percent of the maximum potential emission rate of the fuel fired would create the potential for exceedances of the monitor span whenever the efficiency of the scrubber drops to 50 percent or below. Since the data submitted by ICLP thus far does not contain historical information regarding the maximum sulfur content of the coal actually burned at the company's Indiantown facility, we cannot determine the exact reason for the one exceedance of the SO2 monitor span at ICLP during the first quarter of 1999. If the company set the span value of its outlet SO2 monitor based upon 50 percent or more of its estimated maximum hourly potential emission rate, and if a scrubber malfunction caused the outlet SO2 concentration to exceed the monitor span, Subpart Da would not automatically require that ICLP increase the span value of the monitor at the scrubber outlet. If the SO2 monitor span value at the scrubber outlet for the main boiler at ICLP is set at a level that corresponds to less than 50 percent of the estimated maximum hourly potential SO2 emission rate, the span value should be increased in order to reduce the likelihood that the SO2 concentration at the outlet will exceed the monitor span in the future. Although raising the SO2 monitor span will decrease EPA-Clean Air Act Applicability Determination Index Page 4 of 4 the monitor resolution and may reduce the accuracy of the monitoring results at the lower end of its range, using a higher span value will improve the ability to identify and quantify exceedances of the applicable emission standard. With respect to the two competing goals of obtaining better monitor resolution and being able to quantify all exceedances of the applicable standard, the latter is more important from an environmental standpoint. Therefore, the span of the SO2 monitor on the main boiler at ICLP should be definitely be increased if it is currently set at a level that is less than 50 percent of the estimated maximum hourly potential SO2 emission rate based upon coal that has historically been burned at the plant. If you have any questions about the issues addressed in this letter, please contact Mr. David McNeal of my staff at 404/562-9102. Sincerely, R. Douglas Neeley Chief Air and Radiation Technology Branch Air, Pesticides and Toxics Management Division Planning&Results I Compliance Assistance I Compliance Incentives&Auditing I Compliance Monitoring Civil Enforcement I Cleanup Enforcement I Criminal Enforcement I Environmental Justice I NEPA EPA Home I Privacy and Security Notice I Contact Us Last updated on Friday,November 10th,2006 URL:http://cfpub.epa.gov/adifindex.cfm? CFI D=69779&CFTOKEN=13710572&jsessionid=aa304519678039636620TR&requesttimeout=180 1250KW STANDBY 3512B EPA GEN SET PERFORMANCE -GKPGN1 TMI - ENGINE AND COMP PERF DATE: 01/10/03 09 - PACKAGE SET PERFORMANCE TIME: 20:05:39 3512B DI TA SC DRY MANF TURBO QTY 2 PARALLEL ADEM GOV DM6612-00 PGS STANDBY 60 HERTZ A/C TEMP: DEG F 140 GEN 1250.0 W/F EKW 1295.0 W/O F EKW W/F BHP 1810 W/O F BHP @ 1800 RPM CERTIFICATION YEAR 2000 CERT AGENCY EPA INFO CODE 01 - GENERAL PERFORMANCE DATA * * * * * * * * * * * * * * * * * * * GEN PER ENG ENG S FUEL FUEL INTAKE INTAKE INTAKE EXH EXH EXH W/F CENT PWR BMEP CONSUM RATE MANF T MANF P AIR FL MANF T STK T GAS FL EKW LOAD BHP PSI LB/BHP-HR GPH DEG F IN-HG CFM DEG F DEG F CFM 1250.0 100 1807 252 .346 89.2 168 70.2 4308 1101 799 10607 1125.0 90 1630 227 .348 80.9 165 63.7 4057 1063 777 9809 1000.0 80 1453 202 .349 72.5 161 56.0 3743 1026 760 8919 937.5 75 1366 190 .350 68.3 160 51. 8 3559 1009 753 8446 875.0 70 1278 178 .351 64.1 158 47.5 3379 991 746 7973 750.0 60 1103 154 .353 55.7 154 39.0 3019 956 732 7030 625.0 50 930 130 .358 47.5 151 30.8 2669 918 717 6119 500.0 40 760 106 .367 39.9 149 23.6 2348 868 697 5293 -GKPAC1 TMI - ENGINE AND COMP PERF DATE: 01/10/03 09 - PACKAGE SET PERFORMANCE TIME: 20:09:29 35128 DI TA SC DRY MANF TURBO QTY 2 PARALLEL ADEM GOV DM6612-00 PGS STANDBY 60 HERTZ GEN 1250.0 W/F EKW 1295.0 W/O F EKW W/F BHP 1810 W/O F BHP @ 1800 RPM A/C TEMP: DEG F 140 INFO CODE 06 - ALTITUDE CAPABILITY DATA * * * * * * * * * * * * * * * * * * AMBIENT OPERATING TEMPERATURE DEG F => 50 68 86 104 122 NORMAL ALTITUDE - FT * * * * MAXIMUM SET GROSS ENGINE POWER - BHP * * * * 0 1810 1810 1810 1810 1810 1810 984 1810 1810 1810 1810 1810 1810 1640 1810 1810 1810 1810 1810 1810 3281 1810 1810 1810 1810 1810 1810 4921 1810 1810 1810 1810 1810 1810 6562 1810 1810 1810 1810 1810 1810 8202 1810 1810 1810 1786 1731 1810 9843 1810 1792 1733 1676 1625 1810 -GKPHR1 TMI - ENGINE AND COMP PERF DATE: 01/10/03 09 - PACKAGE SET PERFORMANCE TIME: 20:09:47 35128 DI TA SC DRY MANF TURBO QTY 2 PARALLEL ADEM GOV DM6612-00 PGS STANDBY 60 HERTZ GEN 1250.0 W/F EKW 1295.0 W/O F EKW W/F BHP 1810 W/O F BHP @ 1800 RPM A/C TEMP: DEG F 140 INFO CODE 02 - HEAT REJECTION DATA * * * * * * * * * * * * * * * * * * * * * GEN PER REJ TO REJ TO REJ TO EXH RCOV FROM FROM WORK LHV HHV W/F CENT JW ATMOS EXH TO 350F OIL CLR AFT CLR ENERGY ENERGY ENERGY EKW LOAD BTU/MN BTU/MN BTU/MN BTU/MN BTU/MN BTU/MN BTU/MN BTU/MN BTU/MN 1250.0 100 31449 6711 71372 35942 9554 16379 76661 190116 202514 1125.0 90 29402 6369 64889 32131 8701 14161 69097 172714 183974 1000.0 80 27298 6085 58519 28264 7791 11943 61647 155312 165434 937.5 75 26160 5914 55334 26444 7336 10862 57894 146667 156222 875.0 70 25080 5744 52150 24625 6881 9782 54197 137966 146952 1 -GKGPE3- TMI - ENGINE AND COMP PERF DATE: 01/10/03 09 - PACKAGE SET PERFORMANCE TIME: 20:10:07 3512B DI TA SC DRY MANF TURBO QTY 2 PARALLEL ADEM GOV DM6612-00 PGS STANDBY 60 HERTZ EXH STK DIA 10.0 IN GEN 1250.0 W/F EKW 1295.0 W/O F EKW W/F BHP 1810 W/O F BHP @ 1800 RPM A/C TEMP: DEG F 140 INFO CODE 05 - EMISSIONS DATA * * REFERENCE NOTES * * * * * * * EMISSIONS DATA MEASUREMENT IS CONSISTENT WITH THOSE DESCRIBED IN EPA CFR 40 PART 89 SUBPART D & E AND ISO 8178-1 FOR MEASURING HC, CO, PM AND NOX. THIS ENGINE'S EXHAUST EMISSIONS ARE IN COMPLIANCE WITH THE FOLLOWING US EPA AND CALIFORNIA NONROAD REGULATIONS EXHAUST EMISSIONS LIMITS G/HP-HR HC CO NOX PM 1.0 8.5 6.9 .40 -GKGPE1- TMI - ENGINE AND COMP PERF DATE: 01/10/03 09 - PACKAGE SET PERFORMANCE TIME: 20:10:19 3512B DI TA SC DRY MANF TURBO QTY 2 PARALLEL ADEM GOV DM6612-00 PGS STANDBY 60 HERTZ EXH STK DIA 10.0 IN GEN 1250.0 W/F EKW 1295.0 W/O F EKW W/F BHP 1810 W/O F BHP @ 1800 RPM A/C TEMP: DEG F 140 INFO CODE 05 - EMISSIONS DATA * * * * * RATED SPEED * * * * STANDARD TIMING "NOT TO EXCEED DATA" 02 (DRY) GEN ENG NOX TOTAL PART IN EXH SMOKE BOSCH PWR % PWR (AS N02) CO HC MATTER (VOL) OPAC SMOKE EKW LOAD BHP * * * * * * * * LB/HR * * * * * * * * & % NO. 1250.0 100 1807.3 27.09 2.61 .90 .350 11.30 2.2 1.28 937.5 75 1365.7 19.44 2.63 .99 .370 12.00 2.9 1.28 625.0 50 929.7 14.00 2.11 .78 .300 12.70 3.4 1.29 312.5 25 499.8 7.60 1.60 .60 .170 14.00 2.4 1.28 -GKGPE2- TMI - ENGINE AND COMP PERF DATE: . 01/10/03 09 - PACKAGE SET PERFORMANCE TIME: 3512B DI TA SC DRY MANF TURBO QTY 2 PARALLEL ADEM GOV DM6612-00 PGS STANDBY 60 HERTZ EXH STK DIA 10.0 IN GEN 1250.0 W/F EKW 1295.0 W/O F EKW W/F BHP 1810 W/O F BHP @ 1800 RPM A/C TEMP: DEG F 140 INFO CODE 05 - EMISSIONS DATA * * * * * RATED CONDITIONS * * STANDARD TIMING "NOMINAL DATA" AT RATED: WET EXHAUST MASS 19716 LB/HR WET EXHAUST FLOW ( 799 DEG F STACK TEMP ) 10616 CFM WET EXHAUST FLOW RATE ( 32 DEG F AND 29.98 IN HG ) 4146 STD CFM DRY EXHAUST FLOW RATE ( 32 DEG F AND 29.98 IN HG ) 3757 STD CFM FUEL FLOW RATE 89.0 GAL/HR 2 SOUND LEVELS WITHOUT OUR SOUND-ATTENUATED ENCLOSURE -GKPSO1 TMI - ENGINE AND COMP PERF DATE: 01/10/03 09 - PACKAGE SET PERFORMANCE TIME: 20:10:44 3512B DI TA SC DRY MANF TURBO QTY 2 PARALLEL ADEM GOV DM6612-00 PGS STANDBY 60 HERTZ GEN 1250.0 W/F EKW 1295.0 W/O F EKW W/F BHP 1810 W/O F BHP @ 1800 RPM A/C TEMP: DEG F 140 INFO CODE 03 - SOUND (NOISE) DATA - EXHAUST @ 4.9 FEET * * * * * * * * * GEN PER OVERALL OBCF OBCF OBCF OBCF OBCF OBCF OBCF OBCF W/F CENT SOUND 63HZ 125HZ 250HZ 500HZ 1000HZ 2000HZ 4000HZ 8000HZ EKW LOAD DB(A) DB DB DB DB DB DB DB DB 1250.0 100 115 105 120 116 108 106 108 107 106 1125.0 90 114 104 119 115 107 105 107 107 105 1000.0 80 113 103 118 114 106 104 106 106 104 INFO CODE 03 - SOUND (NOISE) DATA - EXHAUST @ 49.2 FEET * * * * * * * * * GEN PER OVERALL OBCF OBCF OBCF OBCF OBCF OBCF OBCF OBCF W/F CENT SOUND 63HZ 125HZ 250HZ 500HZ 1000HZ 2000HZ 4000HZ 8000HZ EKW LOAD DB(A) DB DB DB DB DB DB DB DB 1250.0 100 95 86 103 97 88 87 88 87 85 1125.0 90 94 85 102 96 88 86 87 86 84 1000.0 80 93 84 101 95 87 85 86 86 83 INFO CODE 04 - SOUND (NOISE) DATA - MECHANICAL @ 3.2 FEET * * * * * * * * * GEN PER OVERALL OBCF OBCF OBCF OBCF OBCF OBCF OBCF OBCF W/F CENT SOUND 63HZ 125HZ 250HZ 500HZ 1000HZ 2000HZ 4000HZ 8000HZ EKW LOAD DB(A) DB DB DB DB DB DB DB DB 1250.0 100 111 113 123 113 105 100 100 98 102 1125.0 90 111 113 123 113 105 100 100 98 102 1000.0 80 111 113 123 113 105 100 100 98 102 INFO CODE 04 - SOUND (NOISE) DATA - MECHANICAL @ 49.2 FEET * * * * * * * * * GEN PER OVERALL OBCF OBCF OBCF OBCF OBCF OBCF OBCF OBCF W/F CENT SOUND 63HZ 125HZ 250HZ 500HZ 1000HZ 2000HZ 4000HZ 8000H2 EKW LOAD DB(A) DB DB DB DB DB DB DB DB 1250.0 100 92 94 103 94 86 82 83 80 84 1125.0 90 92 94 103 94 86 82 83 80 84 1000.0 80 92 94 103 94 86 82 83 80 84 3 -GKPID1 TMI - ENGINE AND COMP PERF DATE: 01/10/03 09 - PACKAGE SET PERFORMANCE TIME: 20:12:42 3512B DI TA SC DRY MANF TURBO QTY 2 PARALLEL ADEM GOV DM6612-00 PGS STANDBY 60 HERTZ GEN 1250.0 W/F EKW 1295.0 W/O F EKW W/F BHP 1810 W/O F BHP @ 1800 RPM A/C TEMP: DEG F 140 INFO CODE 07 - IDENTIFICATION REFERENCE AND NOTES * * * * * * * * * * * * * ENGINE ARRANGEMENT NUMBER 197-9040 GENERATOR ARRANGEMENT REF NUMBER GENERATOR SET REF NUMBER EFFECTIVE SERIAL NUMBER 1GZ00374 PRIMARY ENGINE TEST SPEC NUMBER OK-3109 PERFORMANCE PARM REF NUMBER TM5739 PERFORMANCE DATA REF NUMBER DM6612 AUX COOLANT PUMP PERF REF NUMBER DM1285 COOLING SYSTEM PERF REF NUMBER DM1298 CERTIFICATION REF EPA COMPRESSION RATIO 14.0 COMBUSTION SYSTEM DI AFTERCOOLER TEMPERATURE DEG F 140 CRANKCASE BLOWBY RATE CU FT/H 2030.60 FUEL RATE(RATED RPM) NO LOAD GAL/HR 11.8 LUBE OIL PRESS @ LOW IDLE SPD PSI 20 LUKE OIL PRESS @ RATED SPEED PSI 56 PISTON SPEED @ RATED ENG SPD FT/MIN 2173.2 MAX OPERATING ALTITUDE FT 10499 PEEC ELECT CONTROL MODULE REF NUMBER PEEC PERSONALITY CONT MOD REF NUMBER TURBOCHARGER MODEL REF GT604104B56/80/76-1 FUEL INJECTOR NUMBER 100-8774 TIMING - STATIC DEG TIMING - STATIC ADVANCE DEG TIMING - STATIC MM UNIT INJECTOR TIMING MM 64.34 POWER SETTING PL NO NUMBER GG0055 4 -GKPNO2- TMI - ENGINE AND COMP PERF DATE: 01/10/03 09 - PACKAGE SET PERFORMANCE TIME: 20:13:05 3512B DI TA SC DRY MANE' TURBO QTY 2 PARALLEL ADEM GOV DM6612-00 INFO CODE 08 - PERFORMANCE PARAMETERS REFERENCE * * * * * * * * * * * * * * TM5739 - 04 GEN SET - PACKAGED - DIESEL TOLERANCES: AMBIENT AIR CONDITIONS AND FUEL USED WILL AFFECT THESE VALUES. EACH OF THE VALUES MAY VARY IN ACCORDANCE WITH THE FOLLOWING TOLERANCES. ENGINE POWER +/- 3% EXHAUST STACK TEMPERATURE +/- 8% GENERATOR POWER +/- 5% INLET AIR FLOW +/- 5% INTAKE MANIFOLD PRESSURE - GAGE +/- 10% EXHAUST FLOW +/- 6% SPECIFIC FUEL CONSUMPTION +/- 3% FUEL RATE +/- 5% HEAT REJECTION +/- 5% HEAT REJECTION EXHAUST ONLY +/- 10% CONDITIONS: ENGINE PERFORMANCE IS CORRECTED TO INLET AIR STANDARD CONDITIONS OF 99 KPA (29.31 IN HG) AND 25 DEG C (77 DEG F) . THESE VALUES CORRESPOND TO THE STANDARD ATMOSPHERIC PRESSURE AND TEMPERATURE IN ACCORDANCE WITH SAE J1995. ALSO INCLUDED IS A CORRECTION TO STANDARD FUEL GRAVITY OF 35 DEGREES API HAVING A LOWER HEATING VALUE OF 42,780 KJ/KG (18,390 BTU/LB) WHEN USED AT 29 DEG C (84.2 DEG F) WHERE THE DENSITY IS 838.9 G/L (7.002 LB/nAT ) . THE CORRECTED PERFORMANCE VALUES SHOWN FOR CATERPILLAR ENGINES WILL APPROXIMATE THE VALUES OBTAINED WHEN THE OBSERVED PERFORMANCE DATA IS CORRECTED TO SAE J1995, ISO 3046-2 & 8665 & 2288 & 9249 & 1585, EEC 80/1269 AND DIN70020 STANDARD REFERENCE CONDITIONS. ENGINES ARE EQUIPPED WITH STANDARD ACCESSORIES; LUBE OIL, FUEL PUMP AND JACKET WATER PUMP. THE POWER REQUIRED TO DRIVE AUXILIARIES MUST BE DEDUCTED FROM THE GROSS OUTPUT TO ARRIVE AT THE NET POWER AVAILABLE FOR THE EXTERNAL (FLYWHEEL) LOAD. TYPICAL AUXILIARIES INCLUDE COOLING FANS, AIR COMPRESSORS, AND CHARGING ALTERNATORS. RATINGS MUST BE REDUCED TO COMPENSATE FOR ALTITUDE AND/OR AMBIENT TEMPERATURE CONDITIONS ACCORDING TO THE APPLICABLE DATA SHOWN ON THE PERFORMANCE DATA SET. ALTITUDE: ALTITUDE CAPABILITY - THE RECOMMENDED REDUCED POWER VALUES FOR SUSTAINED ENGINE OPERATION AT SPECIFIC ALTITUDE LEVELS AND AMBIENT TEMPERATURES. 5 COLUMN "N" DATA - THE FLYWHEEL POWER OUTPUT AT NORMAL AMBIENT TEMPERATURE. AMBIENT TEMPERATURE - TO BE MEASURED AT THE AIR CLEANER AIR INLET DURING NORMAL ENGINE OPERATION. NORMAL TEMPERATURE - THE NORMAL TEMPERATURE AT VARIOUS SPECIFIC ALTITUDE LEVELS IS FOUND ON TM2001. THE GENERATOR POWER CURVE TABULAR DATA REPRESENTS THE NET ELECTRICAL POWER OUTPUT OF THE GENERATOR. DEFINITIONS: STANDBY - MAXIMUM OUTPUT AVAILABLE FOR NON PROGRAMMED POWER OUTAGES. THE EXPECTED USAGE SHOULD BE APPROXIMATELY 30 HOURS PER YEAR AND THE AVERAGE DEMAND, DURING THE OUTAGE, SHOULD NOT EXCEED THE CORRESPONDING INDUSTRIAL ENGINE CONTINUOUS RATING. STANDBY RATINGS MAY BE USED IN PEAK SHAVING AND DURING INTERRUPTIBLE UTILITY SERVICE IF THE FOLLOWING CRITERIA ARE MET. 500 HOURS/YEAR OR LESS 60% MAXIMUM AVERAGE LOAD FACTOR 80% LOAD PEAK DEMAND 100% LOAD USED ONLY FOR EMERGENCIES PRIME POWER - OUTPUT AVAILABLE FOR PEAK DEMAND OF A VARIABLE ELECTRIC LOAD INCLUDING PEAK SHAVING AND PROGRAMMED OUTAGES. THE AVERAGE DEMAND DURING ANY 24 HOUR PERIOD SHOULD NOT EXCEED THE CORRESPONDING INDUSTRIAL ENGINE CONTINUOUS RATING. ALL PRIME POWER RATINGS, EXCEPT D SERIES, HAVE 10% OVERLOAD FOR EMERGENCY USE. CONTINUOUS - OUTPUT WHICH MAY BE UTILIZED CONTINUOUSLY WITHOUT LOAD CYCLING. ALL 3600 ENGINE CONTINUOUS RATINGS HAVE 10% OVERLOAD CAPABILITY. NO MORE DATA AVAILABLE, PRESS <ENTER> TO CONTINUE NEXT TRAM: INFO CODE ( 09 ) UNIT TYPE ( E ) HLP-F1 ACF-F3 PGM-F4 SEL-F5 IDX-F9 6 0,0.. I I N .491 0. o.¢ 7'V.`v ! \o'a °� EN o l m H W h O N 1 `" (1 �^ N U O aL E > 74 'c.) G ��YII P , a� G-,D Kl o o m ° o< `° r '� S) d m "OC mo ; N W O", 6 '� N F a `. Q, V0 Fd a r' 7 m0. q 4 d r C� ° rn d ,., ia d ".J 7 i- c0 .—iL c m o _ H E ._ m. d A z r- cr a py o in U 1� Q in 4 o>i T v n °� 0 b H o r. cip 41' �O of lV) o N .o ._ H o m o O U m WQ px', I e n y d z o'� 0"-u0 Q a)EL E CO.. 3 Q Y v .E X ,o.� T L el .0 E c > cW�� v� m '&.5 o v "' 'E T 3 > 0 �" N W 0. 2 N `� v.o r " v U. 0 (Le aU, Y W Q ° _ o. 0. 0 T `� v5 O w c v '� ° o o 0 ' o 0 3 m .s W N x Z + ° W >.,= E uzi "' ° rL m m on Z U h v G o c-'o 3 o U Z Q N .. O.-' F 0. T ~ O N v ° ° O o S 1 N p -0 gU ° E v °3o Q w n E ta. o T T.� v� ❑ 4 W .c 4` a o.N .E ° my o o d v 0 w 0 Ca L m 70 0 . {i Y 3 d .- V 3 °'L' , O.G I' F C ° O V 9 N �. P>� it Z C U t- Z O * Cn w° aUU$ .7 ❑❑❑❑®❑ O? o X t Z ''o^ _ u O m U `m H 3 o s— O d N a r" p Z U `0..0> F ... x .. v C Op ^� m U<-3 os Ts h.0 G Vt Q a F >0o• c HW ie ,n q a out-� ° C,, o 0 0 o 0 0 �.' - W vii W > 'C�;� O a u�] u aCi d C v v ,4 0 _G o o o T c m .-. gu > > > > > > O F a Zo v d p .. Pt()\ 0 CO m `� q w H . mry v o.� p w UCA ,� �r cy °G 5 N c I Z g y ,�".t— L a 6 m .o v G O [ z: 3 'WJ O �l o ¢ 2 go a°v > ¢ in O in ww co, W4 U ` ci 6 \-' °°vii ro— n T E.i:).-°4 H �n .v'. F u.Ur o Fr is s --.ry 4 .5 E ed n v U ' > z 0 b V E od0 Uoc dW z ,az v ch F co o m v >` U , md.� 0 F E. vU Ti u] v rF- . o e.. v c in Fj .. ad o m t°vi u m v COo; O tiW U o �ry z >. 0 o�� i in " " ' o`° tiP s " r yx u u > ri o o 2 zilL [UFe m= 4 �v, OH W .•'' Eli ry v m ul d,F„ e" 0.m E i'" 'y', ¶p1 Ud a' oa C) G o � A H oTZO 174 Y z �? L .L S .it ood 3h c4 t M ❑ ads � y FL 0 0 4 o a. v 0^ re, 3 Q PI �� h 3 o �j 'c W T. U .T OS N L F-+ � U F. U O v A- �4 N a n111111 11*¢ vco Uwkit : a 3 0 Iii'I \ 2E _ - 1•1 G)o ai'i 3 P i II C/1v ° E O' A L o'o 'n ' v _ m-- F E G o. o .a Wme H a ° 7 ° COc z U a m o z Z P y wc",;1 k7 Em H O j co W 4 i- 0 E F. o , `� m mid u �' r 0 c tiI , w wEd 4 -, .. E- < 0 '� CL m O a- Z 2.E v dU 18' Oci O A Q F2 F 0 z' [1] DO �. L tJ v o 'S x F O E 7 r O E , `o �, ? 0.E. o c a c ° c m ZZ.0O F_ Fv Z 4 U az QPLU z 3 N O O zVZa. o�'o: O Cv' 'n - O •]`�o u. °v v ow S '.o ' psi r.w n .. Z O n _ Z ._1gZ VI U rn 04 0. u'.. `-Em o '. 4 '' o v a ' _ ��' x H L' m Q u �' 4TC. � a m 2 U aH2 2 o o2 2 en ma F �v_r=r .� • V Tom CO Do 00 a a ck,--� v a a a a a a a a a a a a a ,yam _ 0 Z Z z z 2 Z Z Z 2 2 Z 2 2 i g N o UE -oii W (h CO 9 C y D ° 0 Ca C-Ci r y E@Z. O O O O O O o a Q O r N O) N N M CO ct N al aO 04 V a W —O o N- a� n r N CO O U re 0 o o p aZ o m a Z a) U N 2 N N N N N N N N N N N N a co C a) a) a) a) N d a) a) a) m a) m Z N— co O p LL N W N W N W N LL' N W N 11 In W In W In LL In W a) W N L W a} W a7 W a) al co W a7 W a) W N W co al co W co al co W co U O ,. m Ha Ha H .0H . HnHnHn H Hf Hf H _oFa L E ` ` .c k- < 0 < a3 am < COCCCCUCCaCV < a <C aloaa (n a 0 mom 0m0m0mOm0mUmOm0mUmOm C CD W 0 0 0 0 0 0 0 0 0 0 0 0 CO N E Eo 1L o 2▪ = = c el z z \ C1-6 W . a) 15 a)c x OU .- COM 0. 1 ot, N N N } F- a p Ii . LL j o o ' o o 00 0 0 0 0 o O o N Z E = C 0 w W E W W W W W W w W w w 'O Q� o � O -p COa M N C) 0 0) CO a7 OJ O C LIin = CO N I O N .) Co (O O r - r , N r V rC N @ J c O 3 0 W v U .J 43 • m t_. N 0O c -- .E. -- d ' c 3 Eo f ° 0 2 •2 0 5 o v aw Q N O) O c W g N 0 n O 13 W 15> C Vit CO o � J. L-:: W > 0 0 m C l""' N C N . 0o �° ° a a 0 a a 0 a 0 m a a 0 0 W o_m aa 0. N Et W O EY En IL a) Q N a O a) a N 7 N E v d c a a) x o et z c - E acct 5 a) .C cs co d O O c a) ('`� N c W Ws V 2 E c = a To x w = o ' N I— u a aE m O1 m r E`o z a o H x 2 L a W W a` o O o o I U co a) Z i N N C m O 0 E C C N a) CD W CO 0 0 a) a d U E n co Z 7 Z m U -c c�i CD E o m r N o - o CO m co o m ,� Z c o Q E � 2 o v m 0 0 o N (0 in o a� (O J c — a) ) (o CO O O Oo O) In Or Q 1 E o .- o '( r Ew N- o 0 r r a E E c a d 0 d n 03 o. W a U o J' n u° N 45 C T `- m ° >` o @ N N C co a 0 -A c O ° o ° r O O) E \P = Y a>> Co > > E .0 `o a o >, a m m m@ w a c c c ° ° a C Q o co E 2 ° ° @ 7 E m a° c N mcl_ 0 t m -c o 2 o x U) t o o c @ ° o 0 0 d w CI y ° ao o .° a U Q ° ) c ° ° E r 0 ° E a° E Z co ° CC °C a a O > 'O 0 0 C o W o ° Q r Q o r E E -a) > 0 C U ° @ciii O ° c C O a y0 2 0 L d L" a m U) Q a a o E �'c E E E o c dS 2 E N ° a m 0 _ a ri it= o E o a @ N 0 N I O o c y E m x ° v a@i c O o E E c � ° z 01 = O E o O u- O z N ° ° c @ Y N c co 0 0 a Co T) O j �' Y •E -° E -a a) o i a cC E ° 0co C D N = U mE 0 E N L O' -0 F N N to oa °in C o) '_ O a W N 0 ° c E Cl) Co Coai E@ C ° c o C OE ° @a. m @ ° ° W ° ° a o f a y a m E @ 6 o E a o LL Z m ° a ° ELF ° Co CO v a° Q U ccooco E c E L a) w o , w < a E ° co co r ° o n o a Q N „ @ z r 0 I— E ° a N c > ° N .L.. ° ° E - c o = O O) c E m ° - - N N C N N ^ 8 U ._ U O «p aO N J .0 c y DEC C ° @ O c I- N a 44-CO co U O -o X CO a .o -O E aE ° co c ° N �' r E o a so 0 0) d d 0 'x ° o a a) ° in ° a v r- .N .N Q o ° o c ° L c `Co E a) o _cC - — a a) c U co c N O a @_ ° N O • N N c ° E J ° LL r N 0 a >T O ? U o i- ll Q E c o E _ C c E r v E: C >_ Q- J 1O En.; O CO N O a ° o r O c a m ° r ° ° y O .3 Q H or cc 'o O N co C a ° o a d. N E N C .0a N -.-c- o_ -0 I a ° E ° E o E `m c o o ° o ° 0 O t1 EQ E a ° a =.0 2f CLa L a m ° � ° 0 ° r O d c 0 r LL LL E O CO ° ° ° co r @ E �'') 0 r L )0 co O Co N W a) @ Y C RI C ° >,V E C ° ° M c N C N 0° 0 0 O c < Q M @ a C U .D O N O O N ^ ° r" N N U a O 0 ° c N lc uU a L `@@o w .C > a) a) � a) '� a o Ze — 0 CO Ill o@ ° d N L a y ° ._ E E -. ° Q ° c y O Z J ° > L _ -O O G .O N O p O)N 0) O ° O O) c C cco CO a) UQ ° mmy ° c @ a `ow `o L C CO _NE o5 a Z N ' 0 O 0 o z 0 C c co co r O) L. co O y O' co L a) O D O _ ° a O ° a ° Co N Co5 C ° co O CO z W N U U aE 0 O) ° .c 41-1 C H O a O O 0 a) 2 Q YO a 0 m ° N � � .Q a ° N r co -O @ ° c C Sam° - .6 "'4. o Ec o m Q < z E °a °)Y c°i m@ a a a E °a 0 a) c 0 O W o E E Q N E p 0 ° O L y O 0 N 00 0 co co r co td _ -c _c N t0 a0 V E L- d a ° 0_45 V r.. E O) a-- 'al ° 0_ ° ° C ° ° U in y Co .O O Z Q � 3 c°iE v ° aaa 3 E a aL a o � ° S ° C O _ d N C O_ aJ co ° Z ` ° H OU c E ° C Q iZ ° Co ° CO a .0 C o O `O co co O ° 0 L -o • 'JO r N c°7 -El U N ° co c f.7 c E LL . 0 � .E d .'" c ° c = ' 0 . 0 w 0 c o Co 0 O G o E o c o o)Co 0 'o ca A rs w E o O o O ° )j E 7 _c a L m m .g ° 0 r Co N N co a o-a LL r ° W E c > 0 w °: C 7 Z >, 0 " c x C -° 0 ate) a C - C Cc C w O .` o ? Oa .0 '2 1E "0 r2c y o 'O o] 0 oC •y � II co E 0C o co E -° 0 a) o ° co a a - a c E o) (0 00L ya 0 .C p a) a ca 0 `a) ° O E a O U) Z Zo n. < 7i .(.1) Ua a' < a' ° ° -O ce Oa W co LL N 00.E r, C F Q r' "'L°` G y p CO 00 an N `3 . &v^ fy v.f. `o o o. �p 7 ao c_ E C :a- a '..ry 0 M m ��- onT a w rn o e-io E r� d o �¢� r ` �J� of €o N N en 0 ten o ',� Z N a QC� CT Q c �yj 5`r' - .-. v N' .. a p �O v '� 7.� c. o rn d E J C / ❑ '= m m A O (z\ e 2 / �n a v S d p, p O o CI �' \J o p N w — H o oa `o o t) c 'O g wM. a ^ m d W .° .. `o o Q °va aa) o O v T C_ X 9 K G T dA C. �— F > o a W Cr m v v o v N'- F L .° cil 0 04 oo to oop it O 1 dv — N d a o ° .'°. °F1 ''Y E q ❑, N Y R' Cl, �' Q v .o a G 3p y 'S m v! o x v x _ o N ' °- 3 O r r W p ow a or .� m u N .. X cz o .� a r w° ' 0 En °n''E °� 0 0 F 9- rn U ° E v o 6= m E W c T '�Y.'_')_ IC. x ac > - ° ° a t, ,b NO ❑ a. W Q .Q . E . o ma bV Q 4,X a❑ >ry C w r a` a aL vim, m Si w° j. W a oo00 2) c `o u m z >, O ab.w 54 0 N .z. \ E > 'EO ZO4UFZO Z° a° o.UUo Q \,o in A ,,mac, 0 W OODLES 0.= EU v F 0 5) i `i' o Y mio > F O 2 v 0 b o UQ00 A .. - 5 HO p 20 0 a �� y QF r ry o x cro o _ - `�' 'o -`°o ^`°p v�°o ° i,°o Q z 6 CJ a U W > p F a O W v m o u C C ', 0 ❑ .. 0 i r> o u4W ,T > > > > > > u k Z t4 ae _ o - o u W Q a°i cn Fc o F o En 1 w".' O ^ F a W .G W c m Ko Q 17, ° Z F Z W 3 v 00 0 _ C a 0 W U 5 cn = w V a -c'-,B' a -fT Z _� F F rip .o O p v > Q z x u m 0 E o ¢Q o A Q W O ,-a IZ :2 o U W F Cl H o n U \ m<3 o y. h o W'S".Le 0. z in o 7, n.o m c > Z i © 0 < to ) in 00 0 v.) ad y v o o N u =Oa'� e a en ? L4 o O v w ,;; > M 1' 0 ciN C4 p v\° E. 3 °' WHO '❑ o 'o an ry W, W � " o — li ° c. "9 V HQLLI ❑ Irj. N 0 �9 0 E U '“^ m 'o Q¢o Pl 'x Z d c` u `o Q ° o g �WO' a Y. O L.cL"u (, a 0 9G1 O p Nr 0 V cn in v W y o r 3 . c W F e U� �.a Y o o Z u n Z Z : e i °u 3 3 ld p .0 m o a N — V W a W Fj ;..,, - O K 3 C P ^ m y U ,, v P oN el a a > Y N Co V_ y o o` u�g Z' ❑ _�° e h — N n ❑ m O O C7 E ._ u. F4,," mg 7 3 1.e E 4 a)�, G h y y F 0.r — y h ; 0 O d v, n '�4 N ^\ E'd. - -J' aJ r+ 'n W F. N V `J G Zoo � 3 o c Cot a w Z.= C.z . G9 u Z Q� ° L V Fl Q .7 Q p C O �,W cor 3 V WVO + 2 ~ O C E o A f-0V�� L._ Q m n T v o F,FO u (�]W «DI 5 p, p Z p `° coT P. G F >. vi E e m alz 15 ao $au � 5 -0f o E p win <t-t LI.,F o y '7 V [1 Z ° o Q -o 0 a v F v� w E W [. `5)E O Z 'S'N 4 ... Z Q at d O p >i— m N 'teao E a, z �' WW a WEW • O r jcCi v,Z ~ O O E; b W.;Zz N X' {i E' > V �j n U m e Q U ° 7 0 ... �O4.d IX W C n a 5 F F O E ,n a m C U a ° Z` n z V-7 .., E 6i- 3;j v A Or p o o p Q z q _ � .E .E 5 m C C c zzo 3 ..Q 6c`"' cc 1.. z �i z H r. C c' v, z v. 0 a C W j = c > v'e Q r oQ o F a WO z U E O Z. a 0 o v' o Q 0-to O `°' F° w v a y To y � o rU/� -aa' p 0 OVN W Vi o o a� o yzz a yJ -,a R-a ,� O z nJi w w u cC aL c a v^i W o .. F p O`d o E r• °d o W m o "z '1 Uill oz 6 U .-Q _ 6 ; c = e vwi'�> ≥ Z N 4— g-74 el 3 6 ? w>' y Z LP] ~ m t.E Ti; a a C n 9 '? O U W..'.,] `� �=° �c u et' p FBI o a w w Le) W ;m o 'C ° u °' o m � 60 00 ,400 tt ! y' K ° it V S o. C7 Q G S U OFD m O 02 v� �j a 6 m m Z > U P.o�4 m r Hun N cr) J J C U OJ < 2 -° `- Q o N z z z z z z z z z z z z Q Q Q Q Q Q Q Q Q Q Q Q z C 5 �,^ O ° ,-Y C N m c‘ 12 a) U E 0 w Z NIU W « a C CI r IN 0 a N - Q N E m 0 0a 0 0 o 0 o a j w J. V N O Co 7 Nr N r. Q W o L U') ti Qm w � vOP) N v V N .o > co ov N CO CO O O CO QZ N Q w Z II a) o C`7 ` co (/) N N N N N N N N N N Q Z I� W O O LI- ° LL N LL y LL y W N LL y LL CD LL y LL y LL CD W y LL y L ° W co W 0 W co W co W co W co W cow co W (p W (p W Co W N 0 Q E cn E- .0F- a H _0H _0 H _0 H .° H a H d F a F a F- JD F a t Z.'. 'Er; < a < j < 0 < 0< mQmQmQm40Qm000 � (no O O 0coU (o 0m0co0mUco0 t0i 0cs0 o0co00 3 N w c fl f w Co 0 0 0 0 0 0 0 0 0 0 0 0 N E E W o -• -5t0 O ] D rn U Z Z a) LL C X O 'N—' a CO N N N } a L C CO (o — N CO N V' N `— O LL W -. o o w o o O o 0 0 0 o O o cE Z E L C y w E w w w w w w w w w w -o Qo d o m CO a co 0 o 0 m m CO o C ° .N Co v a m N (� i° c° (o u) O N 13 W 0 O , , , , N V R N U J = -I OU 3 o wv J . J -a o O m C O N E d) 0 0 C N o d o c Np E ... • a <j = v 9 0 o-w QN T C w 0 N 0 ,C p m ILI J ' C U -'a) CC ca 0 0 � m � O U c Q � m 0 r- ° • m C NC Li 0 'o C° 00 a CO C C 0 a CO < < 0 0 O W 2 am a N . tt W o o M Ce it Q O Q O N N co �/ co Tz .c a O N N N L N N O O C`7 O LL 2 N O O N N N N N c0 d O N C cq C O O W v ° ° E c a m ax 2 o Ni Z I- E t a E m m 5, E 2 m Q a H - 0 L ° Q w ° Z a ° re U Q LL a Oco ✓ t -C i U (U N Z L N . . N N co O E C C 7) N U E co O 0 a) (O cn Z 3 J. U O 'C U E Or N V CO 0 co o V 0Li, 0 (DCO N C > Z CO J C Q a0i v z 0 o- 0 v o 0 0 0 0 a a ct a o Fa C E � r ro m a E E E c ` E 0 y Q G) O O N Q 0 N d U d d W I — — d i N 46 C >. .__ co' a, T co co Tn m o ° P O O) N c E o a a, a 4,— I m > T d o `o E ° T a m @@ N O V C L. r L N aCC O C Q O E C O d O@ U V ! L°.. "O.,-)c). D w E m 3 �. c°i o a co @ N CO r 2 o N c ) x_ a) r N o c 4- C ° O E Z .0:T oCo o a T E r o E a° E C a L a O T -O O O CO c O 0 W D a>i Q L Q Y a E .soo' Q @ c T N 0 -O a C @ Cr) C > L C L U N C • O @ O m e E O N a - a r 03 t.-/, L.. a N cn a m a a a ° N o __ E COCD W = o o@ E o °a @ �. ° 'D N it O a a "o c - x ao a) a o @ o a N o N co W N - w co aa) a) o a C u w - .x c -c o N ` O o E E c a' .0 a@@ ° °o m ° O E ir r a ° O "• O Z N O N m C co .C L (IC C M — O o� 0 Z N a @ @ ₹ i 7 .9 ce U c O O O N « r N Z OC C n aj N N (0 c L c o @ -c N `� 0 N m v o m E d E m !, o- -o H N N D H o - N C@ m c 'ao L W co @ a) E — m o c a y @ E � c -OOY a c E N > @ _@ o ° c @ @ @ O O T @ O a) L W W 2 @ a o f a N ° E m s o f o ° a - U N N N L @ -O O @ d i- • T) N ° @ EL o D a CO -° co O m c E L d o c w m Z a) D Q a E @@ H @ C ) O L Q @ i— E a c • « ° ' T N w o E To • O a - - -° m j. -o r a) a T , C U C J c a a 1:1E @ O X n c a�ai a ° o 0 `o °° oc ov o ° ° N t"): a J N N N a) O L .-: N N L O O U C N W 'C C Cu E t O r N °) C • Q N N c E J co W C N °- a) V " U D N _ c N -c 7 C . W E m o O o d @ O coa) co N co o a 4 >- d J ox CO = ° a ° o :- ' .C c a cno @ a) NO c_ m .c1) 'a .0 w mI � = al o o .o a !a) ! a Ea E o • L O N@ CO O)-O O c a Cl ` N E N N •] a, 3 H a p •O N co c -O ld a) C c O _� O Q a, 0 c O 0 Ea E o a _0 d a aciw ~ a N r. @in a, ,n o c O O > U y U N c E C E @ d @ d a) LL W E D N N co N O) N E M Or co r Oin co o = J W a) @ • Y a7 C T 3 @ To M C C N U U 1 co C2 re a @ Z W .0 L Q N O EO N 7i cc 0 r N O To a_ O O Q Q ri m U y a) 7 N w o 4 U 0 Q1 C N a CO L N O .L.. ≥ N N D N a O --a 0 coW •o .� i > a) y C o - - E a) ai E. @ y - -O Q: C N @ a) Q a) co C N ° C d a `o " p -c N E O 'O V O d' N C C O N y ≥ N O N D C co O N YO 3 a) — U Ca L a N C N C ca . C p N O Y _ co _ O N ° w .r O N o O i_ a Z O O a) (° a) a .. @ I @ C @ a) C O CO O E a° - m m m @` La > E c° m ° o ° g CO Z W y �° U O O c C H o O O Q m @ N a E! 'N a) N C « a a Q) C N -O -. C @ @ C C C 0 ... .cCi N O E .C O CO U d O co• N Q Q Z E a a L "O U O) @ a °a a E a -o e a) a) N N _ O C a c O 'U W O J E ocr a) Q N O O a) O) -c co O y N Or N ° •-' 'L" 'y) cj a O a) U r a) a a C -O N @ @ @ r T N C) .� a a) Q- Y N O) a r N @ N a) a) c C @ 2n _m .— @ a O Q C � a 3 uo y a) a .2-f °a 3 «L• E � co� K o � � °) a) c C p �_ d m a3i Z •� " a) Hoc o m Q K aa)) ai e O - @ O Z O CO a) @ N 0 L ca ° r N t+7 a7 o a (° a N t o o W a .. = a) ° co " C a O O O 'V C@ J ii o C7 o LL O E a `mcaa) c > ? 'c 'c w m 4uit IY �. N d a .�+ a) C a m 7 .O m c c c Cu O E o O U C OCD CC - E E L Q m m • N N ct N 'C @ N in C.) a Q )i t 7 0 ;: C Z T CO ..- C X C - a7 a C 't O C a coco Z O p u a) c o m p .o m c o a •y @ a c E E 2 O a, co @ o a a` a - N a N � ° E O) N C° L y 0- K y a) p d a 0 L. CO a) a) o Q, E a C (n Z Z O a Q < a U a a' < a. co -o Z 0 a W@ u I O G S = �"y a.o ,. mo 2 y m ..\\02 OF, M a ae• c_ G O� k d O, J rn O tr,U o I o �y pp a HT.i > `� v.a, n� Q C„ cNI � � � N at E� a e a, o C ° N ¢ E o .4 a LL C — O V1/U�� Q V1 W y u O. O F uE F' o '� If) Ll y O G Fl 'O F v pp .5 O° W ~ �-+ G �' o n y v J .j O O a d N - N B Q' a °' m 0 b -K s 0 A z th m 0 �i o W ' t'' �' CO C m S o .. � F 3 .2 0 Pi No C fv o: J a c ° 2 c y o` q U Vi Y m . C ti co Z a a9 0 „ U a W W w °A 3 n r rt O - T t.5. O L" r, u, o F.. v' O V ° E E o E. c E 4. ° Z.>a�i n x o �! y' o o y. .o t ❑ o., w m r: z C P O op P. o Q v a .-6Q-. 't [t] m O-.0 al T. s .a o v mw � ? } ❑ o. . gym a OW o y 3 Q z 3 i.c n o ^' k o o vb N z,o, m 'E_❑ Z au Zzo taw° aUUo ZU c v ‘_°. o °E .23U H 01 ° 0 p N o x e G F z Si ai_ w m E FO O aa1 N Urv0 Ga � o: ° ¢5 y z W F V] CU o »�rv' n Z F W O O .. U Z 600 W .o CA 000000 zi.-40 W m z to ' v co m aa; -, o ❑ Z z ZD o tr)o ° > > > > > > U U a o OF. o v 7 m a W a0i ri 7 F y v'N ^ v p-" ❑ `z U' a ai W w c'," Tr) W O Q oQ " g v ova • o v et o �Po wW C m Q d U U ON a E� >, z �� Htn `� Q VF w w w E ^ .5 ° t° U > a. tiQ o g. o a v S U 4 i° ❑ ti tut v y — c Q FN- . F W ;°U E S ,1 Z ?4 C 2N 0 n'O a j C')0. O x)1,4 © r0iW OU , ° o v `� °? V.O 0 0 W ''' <cs. C./) a F m m m a3 Q� U m o _v d a on w - m a s ❑F� y hE"n g w¢_ y lav v, E u. c.'g U .< W O W Z E P9 O U n a S 7 J Tr ° m 4. U a ° Q ° 0 F. v H W µ dWi 0 ".� O E o._ W C } 3 cm m o vF K Oy U cn CliC a C co U m z a wz F 2 a ca ', a 2 _ a °uo MH U - O q >N .. PC Cy," ° 0 U - o - oo ❑ tr y k. a i C. cv O v 3 ❑ 6 n — N c c O l 00 a• 4 _ x�� ^ A ,,,.= Li Z oN •c' h . � m2Fm en a — ° c „, 0 O cn U v .y Oe N L° v m N 0 O o 3 s ❑SC O. a i o n L7 o urn Cu 4 .¢.W o0r 3 ` .W7 9Eo 1i1 0 ° • 3 E po rn 9. v C; V) ��W z ac o 0 o Fig �.i SE � 11 :: C g z O p .w'_' c c c o. >, v;E e R 7 0y sS o A ° n oa a • c� c A 7 u d t) c b F v o a 0 W W �;°C C N O K C Z. 2 N C. z N 4 Cc o o � °0 V W . o �' x ' w w GFZ an W .� c X Z z 0 _ > W N F' O G O W S F Gyl R �j o a U m F Z O N _ 2P4 s , O a.3 -G Z ... au - Uz.P Q ,°° 0Le� 0= • c FI.�4 F. .. C m • Z j tao O O O p c m O,`2.,„, 3 - i v r.V is p� p Ce w C O 22 0 .2 .5 22¢ 9 h- m c Z. O oRp ..� ens C. R 2 Z z F F ; ' a, Z 0- O q .2. ❑W P. y =,c > v < FBI u F u i 00. W `C 5a' 3 N O o U za v P.�O .oI Fa � 3n� C W ore u r- a > c' 4 0 ❑ o. o u Q m r a o W dvP. 'c O h tiS o u a0 0 LL C 0 c,1 N. o O ..1 a �' U)Z 7 a' `=°C7 (;`- c e.� 'w Z w C I-0 u z oS,`i' 0 U B.. 0 J v UFF v 01 E� Co 2 H Z w ,z, . Z 2 .. W 4t< .. _ Z O E.TI _ — m y e a 0 ' a ° Z'�A a .� ti m O m ?° .o s Y a . a a Y "d 0 = _ U W.7.] c �=° C yt Pp G u ° 2 O P v U a i U C N S - U 1-2 OH) C 2 4j a. a o. vi O O U P.P..a, vZ F ^ ax'^C' X � _ � 0 ( U a � -0 --=' < ' < « < < • « « « < " Z ZZZ ZZZ Z Z Z ZZZ o C .o c o UE 0w - Z N I a a - W I a To (.',3 . a co T U O N Q N O Q a O OCD- N N M c0 ct CO T co N Q W o L -0 LO r- `o U — d N N (I) XI ≥ N 0 U � O HRI E � � al O o � w Z a Z ' LC CO U C`') CV i ) co vi U) Cl) Cl) v n cnco n Q CO I C W al W a) LL 11 W �'W LL L1 a) CL)1L u07 u in LL S f� 00 O O i w 0 W w ca W co W CIO W ;rS L1I c, i W O w co.W Cp W cp W O U O � � � H _0 1— A I-- _0r _fll— _0i— _oF-- _oil— _0H _aI— _ol— _of— .a O Le) -- o Q mQ Q roQ Q Q Q Q Q aQ cpQ mQ :77 EU ≤p O m' U ro U TO U To 0 m U m U m U ill U coo U co U cp C _Q _D W co a; a ❑ a ❑ ❑ ❑ ❑ ❑ ❑ ❑ Q I O C E E L_ ! C � O 7 O RI LU � UZZ o - } a) c cu m N co = N Hr N r C") N N N 0. la LL 5 6 0 C) O O 0 ; 0 0 0 0 00 0 Z E C O ' W W E W W W W w W LL.I W W W 17 < O a_ C -p O C) O_ co ti , a) O C) CO O oo O C CJ V7 O i OJ d c`7 N N- r LC) (D a) 1_ 3 CD CD O — ,— �-- .— (Ni N- Ncts M a) E C 0 Jg _1 Uli -0 ( 5 D) O a) a) 0 O C c o O. o c _o CD Q E � ' N (,) _ (B a D a/ a) O cp 2 o a o c crY a `� m ai cu o wn O CI) W a) C 4-C-' C( I LLJ In O I U C O ' LL 7 i 0 0 az < Q U < , c m a) a) c -- • O O C a) 1.e N ZIli ci3 N a) O a) co N - x t la" co w aa) p Lc H' •E a��i Q E m m ' Eo os _ Q Q x a a� Q ' L `o Z a o cc w w o v < o II C a Z L a� U co O C C U) a U - co o U > ao Cl) Z U a - o O co ,- N 00 NN c - Zoz) J C Q CU U � uo) o oo o o co O o `� ^ o 0 t Q _ 0 .CO s cp � o CD N C) c 0 ` C ` E U - Q 'c - O. U CL W W QU CL u I c co m N '(9 c N in a) m a O O O 13 7 a E O _ O °) O O a Q N > L a) T p p ° E a) r y O co J Uas a o) m m y o V C L.. IL N L a L O co Q co E .- C O N w O O m m E m C LO C N al a) 1 . -- O N O N C —D .2 xci3 N N O a N C a W V 'U m C N a C L O C a) O 0 a3 CO O = 0 a E o Y Z Q o o a a o T -° o o U) o °� W o a>i 0 Q L Q -o y m E -oo to Q m 0 N a 6> C "� O a a al d N .L. d C N Q m 0 .4 «'c N ° - = E m 1� d o W z E @ a' E o o- i) a o °)c N w ° 7 a U O a O O 'X a 0 p m O N a) J N m -- 00 m aa)) a) ° a c " E x c L 0 ° E E c a� a�EL co 03 Z co O o m O E -C U a J c o I{ p Z E a - D E fi o I v 0 a E ° c 0 on P a - E c ,o r\ N Z Y _ O J Z C F O aj N_ N To C C p '°N lA `o a c a) O) E mO L E w w o o O a N ° d .O-. J Y a C E T .c N a) w N a) E T c D c O L co O -O C LL L W -o a a coi m a) w 3 ° E c o u o Q Z o tri.N. -0 a) a) E r y C a m e �° n con m Q Q n. "E E m c o o �° Q N m « m Z o a r ° a m m �' o c m N ;; o U ti J o) c E 9 o m .o a ° T 0 m ow -° O To Ja) E o C o -92 o c o o a m o O U O "i7)< X Co .- ° E`o m ° �° 50 `o o Na = "X m U a N .9 m m N J L 7 .N . < ,9)(- 0- N�y 0 O O Q c C O o C N m 0 O a = y. L O V O @ N N N O 2) N a) O N (6 O N N a) E J a) U. o o a) a « a) U a N E N c c N V C Q E m o o f o _ m a) r) u) co 0 C o ≥ Cl) • m Co 'O m co w — .O a) y O �- . C a co 16 0 o 1 N I P E N O V L C w O C 21 O O C a o o O' O' E d Q I- m .O 0 f00 CO y6 t7)L O a N E N C "J U C Q I- a o E O ` �O 0 "o N Y C c a y 0 N O o- a) O 0 > Q E o a m a a c a o m o� p a o c v ≥ O Q> u m E c E d o 0 0 cµ'6 LL V Q LE u- E E co N N O m L N E M O! co ON `° C N .= U W O (Q Y m c a`) >,'o E a 3 a) a) co C N C N U U C C fl 0 d c c z U) - L N N •3 E N m N m m p (6 a N O Q Q p') m N Q U O `n O ° O N ) � L.° N O O U U a) C L N a_ U 00 L m m o w C) > N 65 N ` a o c'ta m C = a « o 2 O ° £ w E ° c N a) .3 a) > `o � d m n m ° _ E o w m a) m N L : 0 Y a) "_ E 2 a) m N O f" Z C a) > L _ 0 (�6 N c w OL- at. co L 0 J o) O r. CA > m U Q T., N O C C 0a) O O G U '� O m m a) N p C N ° J L a O 0 L = E m '> w a) C C) O d' O N C C O N 03 5 N L ° O O m O co o 3 m '� N L C > a z N • c c o m ° O c w o) « a) i _ M _ O N Q r-- O a+ - z O a> m a) m 1 m c m a) C O Co o y 0 E m ° 21 a m m : 0 > E m y J o O m O J N CO Z W m c c c t- 0 0 0 o m a°i aPi a ° "N aiE v E ° m o o c N . o a) c a a ° 0 m -ooQ C m m c c a c d o o E c a) c .v a 0 :° a Q Z 'E o o) a) x aa)i m e a o "o E a c EL; U O N a C LL 7 7 Q u) a) a C y r N m a a -o m N CE 1J' ` (6 7 E Q N a " C L N C a) a) 0 N a) o — L_, O m if l/ O . f 1 d Q a) a U" Y °� a� N a> of a) a) C N V N "N W V "_ .D O Q Q a3i > o 4-, ,u •L ' O) m o '" aaE ) Zi K K W Q 7 a) aa) o u o CO Q al m 0 Z L a) I— OU C a) •> (6 .. N O ._ O A O Z O N N m N m O N O y - -o J = N M a-i a a a a C r a o w 4 m c ° 0 0 0 E c m 7 u) li CC• o m.0 `ma aE a c o 7'000)@ Q p CO c c O E ° ° 0 o c c/a cG 1 2 9 Q a .`0 z O 0a m D 0 m C (OJ U CO) O 'j A N IOa U N C > a) t mLL LL c cu / O C JE Z >, Ra L Cl m x C O D O d a) C • co coN U C W 4> OC C O m a J O O Z C L U C 'i-. 'p '€ 22 C O a) O` .O m 0 O C Zoo j0 m 0 O UC ... o _ .° •Em Cc 0a) m5 CC a a = a CO) m "_ •0) N £ _ CO ra o - da C4 m r o 0 a moo m o E a E m - (I) Z Z 8 a Q C .(' U a K Q d' 0 0 "o K U a W m W U V m c _CD (iiin C �,--� g.d^ V 0 .w. o 0j rl cc M u �l vci" O T .ci(9✓ ¢ €� O N o 00 `" a N a el a 0 p, v � t 1 i¢ o 2 o q '� ' �' o a o °' wv rd q a a .0 a a 0 �A tl a cn co o v, c�i 4 in a d H u a S Ges FO- ° b D—i O G N 2 _ F V 00 O . �/ L..' U dl C co Yiy tFii to, o .2 W O .C. O O a 9 V - b 0 � in u' o- W m o H r3 o o2 `m E ,i0> 0 N O w DOA .. ? N K m e tV` * m 3? U ° (i U N GL �._ w d '� � a'g. °CO X go C < O U O " L a ° u c „ ' _ 3 u s W U Z J z, o U ,n `U ≥, .N dw . v ° 44 vo �o 5o pZ6 CO N 0 E pOA0pO, wT GO O ,N '.r.e-i Jl� N O O '3 F w O U � E@off . nE w ° ≥u F. .oc m 'lc- .. v b a '° >� O ❑ a d, o° c .� ° m 2, o a d a 0'CN r a o. it v n V L°. T w a.°Qm c[ L o o'er `c 004;L >- 00 by 0- 3 4 o N v 3 m ° t. € € ° 000 n1 2: T 'c0 Z 70E= Z0 '' )-,;_,2 ia"Ua o cn u u O crU E-3 Z ) 4 k `s°8. o z A. o z z U °y8 • Q 0 o u p 0 'o u. 7-) PO O ma o U4o0 o O 00C 04 ¢W O o 'Q.Ci.j o x a G c 0. c., 8, o 7 m c c , c -°c 0 < O a o a o•: E(2 U W o m t O 0- u u u o 0 Z z e � m N ..ri > > > > > > U U o' n4 ae _aH ° a a = G ata E•4 tna 0 V v, o^w v a CC w 0.4 H ,, CON ^ U Lr" Q U F W Si b 0 00 I:4 E_ , Et) .. 4U 0 w °o y Z F ... W Q Q o Q 92 '° o - c- ≥ Q O O— `� Ik1'�U^ U .. O .6 N ram 114; ' 7) ti W V 11 `� T H F F F E^ W '� m ry o. aA El Q W C E .lZ o F 8CO u w U r? QQ O - v) 4.11 a y 4cu H > CGS co .0 F Z c'a o A ~ L Cy a v y4 O V_1 �iW 'u L ≥ z.1'i w H (n �i�ry c in, u O = q 07> Z 3 'it v y 12 c m s ?; mn0 op� O O e_Ta _ Cl V 4 �i Cd U '^ Y. V O v 00 > K c x b .- r b r 8 u 3 C wHO -) o o c v oN 4. S � Ri u n L. w ry y2 a F,F �] N at❑ 0- ON • o C4 way y 7 ° t L,.'° V H d w a O Z $Pu W O V 0 'am= I y c tG U mn °eh U K.2 `,� 4 N z =i G d V p 3 6 v L C y V ^ U U� C y 4. O ry e m ti b e _ r v C- d> HI C.) cv Oco Fah a, o o ENl'' O 6 .& oN ❑ 1 - uu Oa t7 C7 o u a 2 9F N 74.0 ca a t, -c3° 4 y O �'i y 1 Icio c] _ .n. -?:,,F,, d 9 era F y 0 =m c z'p F 3 .o �' Quo c•--E3--, (121 a w \ t:t r4 a^' t vac) Eo OU —,W gON 3 a, o .70" vy V u kg n Q0v ICI G Can CD 0C F o O Q p d cin = — a O IX o. O LA E W ed q y] P.0 ° oa V m H .° �' F m zSLt Wac W X v co o z •= w w 75 a N v �«` • o f a Z H 0 7 0. b F je Z , w 4. E i N fj` O a U F Q 6 a' ¢ 0 O o a F ' zi C • �k �. `v Z .. O'U a4.F, c o 04.mr 0 E...(. .)• v o F F. up. m c OH 0 O ° m ZO A o T _ O cj m r-� U h z p �' p a Z .J' n O .o a m Lti �' E zzo o w O -1.J2,,,..; F� O o `� z H H 1 Z 0- OqW°' j = c > u a �� 8 to'- ao 0 Z y 5 o L 00 aQo g 90 Waica ^j > cL V c< c o o iti .. E- v w' O p ti o ooZZ i aO Uva.n O " o w ¢ p v.' ° `w c .. F u Oda o F c'c e a z vmi 0 0 K .� Zu o a' w o 6 0 F E- COa O c u._ pLy > ❑ <, r w V _] ° O a .. Z .7 c n m 0 0 Z o Z'�o w zQ z m z a r w o. .. Z O .� .. v ._ A 0 Q,1,L ' .o . ,n c w '.{• o o ezi U in 5 0 w v n ° .� a aue)i n ° `v on o m i 0 0 0 0 .000 E ^ F$+a„�` �1 U a x a 0 Q Ili �? V p �. �. ti A Q ;4 ,:T. a 0- ,n Z > O 0.c.0- v� H - .C co '7 @m co O a7 co Q � �` N ¢ d ¢ d d d d ¢ d d ¢ 4 � z z z z z z z z z z z 2 Q a hi cc�i .F Q w �a Z o U W M O c Q N O co co\ ° a7 0 Q NE `a7 0 0 0 0 0 0 0 0 0 0 0 Q 4 Q a1 W j, W W W W W W W W LO W O CO Q W C "p LU Q CO T '0 O 00 OA ,— N 00 m 0 cn N ° o W O a) m -0 v3 c N rt 00 '. .r .� ri N I a U u) .O .[I- r-- it 0 O o LL it B Lf O aZ om a N o O Z ' I m w w w w w w w w w W w tl O „ N N w w w w w w w w w w w Q «_ M F F F F F F H F F F H r O p F' Z r o o < < < < < t < < < < < p Q m U U U U U U U U U U U o E . . � L o oE c WO < < < < < < <PPP o 2 _ _ _ m v z z a) W C y _ } N C CO 0 I a O LL ti 0 0 0 0 0 0 0 0 0 0 0 al Z E L co W Liz w Fi7 W W Ci7 W w W Ci7 -O QO 0- O O O o O o o O o o O O C O .N j O O o r fn F. w cn O a) O N C M N O\ DC rt vl N V1 r E _ 0 J c -I O 3 o w " J - J -oU ,_- otip0 C C do c EE y o_ C� CU o E. CZ (7) 222 aa) a wD .. c o a Y N 15 -103 0 W a c � -) Eft c J a', w to o 0 c0 m c ( o o N C > c O IX O O r oZ C U ¢ d d d d U U dV c O Lu 2 N 0 m °7 n a N Y co It O N w o fY V as < 0 E O d 0 co _ E b Z °�' � a v $ M ft m oN b g b T y m x p Y' O .v w is E a >t d pd, N F— E x u ¢ a7 t ° F X x a O m /N L z w ¢ w° C C, U U O a O C ... 'C . to p CO N 3 C hi d W O O a7 E c c Co d v O °- o Z E m o o 0) s an o O Q "O N 00 0 1. ® _ C_ z C O O Q E Z ry 0 0 ,r o in o 0 o C C - K c E J O L ` . c, r- , r- o N rri d o O E E E E = KE Uya a O d a. 111 ¢ v Et 'cn -) Z ii C m — mi O S /� 0 o V a Q = j• � 9 w G M 7 w O'er f C w ° Aa o A 9° � E c' N Cu'-�. N 8 Gam r JO v'� ¢ ae (2 colM O to 8U Z G 0 Jo. r AQ�{��q¢�� ..: z S ~ , 7 al 0\ ELi ` an ti Q E Uw a. p u c v a �¢ A. �- E 'a F F" •a �C41PIG5 ..7 °� w a o id ^� 3 0=0 O u Q C .� t a g O. yl Q o. '5 v a °� O 0. o .0 VW) o 0 b k. v O a v 2 0 H 3 e 0 04 00 \ o v m C` 7 m eel w 0�0 m J v o + a 3 U LLl ❑U N W -n k' d o _ dy o , , 0� c - Y o u ^r ° o 3 m zs 3 2 Z o i U W o . 2 , 0 N w 3 p w a cw ce 111*; U •86.T N E O❑ - W 4 4 T W a y ° c c`ti -t r 0 o.11- m N Z� A a '5° Z0OF Z 2 aw. aUUo x v' w ❑®❑❑®❑ 0.a �o X� Zda• - o u 2 Ut E-I3 - Co d N Z a U o Y 52-02 �' 0❑ O co 0 U¢a0 IM = A HO O C a , °° >aF x In Qw r O ) wZ 2a x, n. U CFW5 d o 'c o0 rn o v Q 2 ¢� C O N U W z S? 'moo as aQ = p ❑ o z a ae -F ° 8 a d M ?ti N O0 010 . Q w U a �i W L2 WGJ , ,- U ¢ ��+ 'v T4, C .a cr Z Z' t W ° Q o 7. L P ° p O U Q - O w tic...) t N I� ��ii pp m y O 0 H ^ L F NQ� OUN.mT. Qw yO 4J En F o > 2 U - A Q o ❑ ti Ici S m Gz.k1=i P. Z a2 m �`n. F w aoU E m o r �� 6 - ya O h O 0W o co o o '�., U U z °' o O p O ZO 'O 4 ril y v . a �n ,�/+,d.a� U O w a o .n � � > _ u No �,z Z r t4 o `a;' mo' 'F❑re W D .. w y .= O U. 22 F w ❑ W v; y aa 0 E U of d a SQ¢a.w] x Z ,,dcv W a Y m o v } U a: o Zoo n .0. Lily, S t aS ; U m t " v O 4 I"l oeu >.h Aa' m _ a UP m as O - N CD t v 3 � a totcs A s - ❑ - v u 0 .. m . .x m F a 1.21 4 v _ � c 4 0 tZlo 2° N � q Z' 3 m -0 aco _ 7 F -`>, — o CL 0Lm f-4 r'�rid+ O N T O U L�[] G'O� O V-� ,W o O0- ; v w C a g E con G ,— a > v 'v F i4 i° 'K‘ \ . P. >CI) OO Si s.ICI r o — ❑ ._ ° o, or g •o O w w o EZ W C w - H F F- r c g o .7 ; 4.2L C O 7 v z o c a .° o F .a y� v, w co'E R 0O0' o c ZZC'l C 0 m O ° Y- m i W �r a U 2 , ,r-,Z Vn weN ❑ q G. O v, 2 v w 0 ul v a n [ ^S '> ru f' 0 U a. 0 w 2° N S y u �/`�^ %Ki o Z :n U 1i ^ n Z r aU aL� Q O � RLJ C p O E ° Ey� 0 S y r FQ OLL m z F = p a m a a ZO 51,-4 = p i `j o Li c, o o u¢ c K O P O .o ¢ N a � .E .c. a ZZ0 i ❑ Q :�— y^ r- y Z F F `� Z 0 '' ' al,„,... .v1 ,°—;.d > v �d 6 O O D N w w U(�C E a Dim;l - F' w Q a O o O 01 0 c 'F 4, . m , t FM w j a >, 2 U_ z a= o Z z a4`n E 'c $ w vvy F. C. v J C O vC o m O ❑ �FF a: ea U� 'n." O^ � ¢ w 'J uw 00 O Z O V] 07 a.. .. F p G �. C-cn Z . la m ° Y w 9 d 0 v �.F. v m� pc o o�o Z m Z z ` w o. - Z O a . - J 0 a J <.. - u 2 0 Z.r 1- J w 0 y U in m ❑ 1 9 n y v,x c O _ ° U W J m v m S Y a emc IOIN CI O Q a 2' m J v m ° v u ° 6 2 0 0 0 0 ._“:)o �'^ a v I n S c. � a 0O Q q - e u ❑ 7 2 m O ❑2 � m Lt.; a a. a m Z > U a m a. .2 F v=a al iCO C 00 C 0 cl al 3 \ ! _ _2 0 _ «s ( \ ) •9 © Ef. _& � - ) \ \ ) - CZ _ , ( 0 7 ex b - � � 0 \ 0a0 \ 2 � ) k • � \\ \ ) \ \ \ § .. T._ } [ } j / t . }{: / ! / \ j { j {\© 7.1 ( CI - _ \ ( \) { ) \ / § ! / / / / = 2 ( t 0005o ol | f/// - \ \ 22 < " 0 U\ } ) / CUUUU } a00 « ES [ = , • 13.4 Wet Cooling Towers 13.4.1 Generals Cooling towers are heat exchangers that are used to dissipate large heat loads to the atmosphere. They are used as an important component in many industrial and commercial processes needing to dissipate heat. Cooling towers may range in size from less than 5.3(10)6 kilojoules (kJ) (5[10]6 British thermal units per hour [Btu/hr]) for small air conditioning cooling towers to over 5275(10)6 kl/hr (5000[1061 Btu/hr) for large power plant cooling towers. When water is used as the heat transfer medium, wet, or evaporative, cooling towers may be used. Wet cooling towers rely on the latent heat of water evaporation to exchange heat between the process and the air passing through the cooling tower. The cooling water may be an integral part of the process or may provide cooling via heat exchangers. Although cooling towers can be classified several ways, the primary classification is into dry towers or wet towers, and some hybrid wet-dry combinations exist. Subclassifications can include the draft type and/or the location of the draft relative to the heat transfer medium, the type of heat transfer medium, the relative direction of air movement, and the type of water distribution system. In wet cooling towers, heat transfer is measured by the decrease,in the process temperature and a corresponding increase in both the moisture content and the wet bulb temperature of the air passing through the cooling tower. (There also may be a change in the sensible, or dry bulb, temperature, but its contribution to the heat transfer process is very small and is typically ignored when designing wet cooling towers.) Wet cooling towers typically contain a wetted medium called "fill" to promote evaporation by providing a large surface area and/or by creating many water drops with a large cumulative surface area. Cooling towers can be categorized by the type of heat transfer; the type of draft and location of the draft, relative to the heat transfer medium; the type of heat transfer medium; the relative direction of air and water contact; and the type of water distribution system. Since wet, or evaporative, cooling towers are the dominant type, and they also generate air pollutants, this section will address only that type of tower. Diagrams of the various tower configurations are shown in Figure 13.4-1 and Figure 13.4-2. 13.4.2 Emissions And Controls! Because wet cooling towers provide direct contact between the cooling water and the air passing through the tower, some of the liquid water may be entrained in the air stream and be carried out of the tower as "drift" droplets. Therefore, the particulate matter constituent of the drift droplets may be classified as an emission. The magnitude of drift loss is influenced by the number and size of droplets produced within the cooling tower, which in turn are determined by the fill design, the air and water patterns, and other interrelated factors. Tower maintenance and operation levels also can influence the formation of drift droplets. For example, excessive water flow, excessive airflow, and water bypassing the tower drift eliminators can promote and/or increase drift emissions. 1/95 Miscellaneous Sources 13.4-1 Fill Water Inlet Taffientagind p. Air Air Inlet Outlet Water Outlet \ / Atmospheric Tower Air Outlet Air Outlet 1111 111111 Water III �npY Inlet Fill ill Inlet Air Asr \ J V�e AirInlet Inlet !ww� V�"� Inlet 4-- F— Water Water Outlet outlet Counterflow Natural Daft Tower Crossflow Natural Draft Tower Air Outlet Air Outlet Fm Fan Fill ill � v Au Air Air Inlet Air Inlet Inlet Inlet la-. 41--- F' 1 Fan Assist Crossflow Induced Draft Fan Assist Counterflow Induced Draft Figure 13.4-1 Atmospheric and natural draft cooling towers. Because the drift droplets generally contain the same chemical impurities as the water circulating through the tower, these impurities can be converted to airborne emissions. Large drift droplets settle out of the tower exhaust air stream and deposit near the tower. This process can lead to wetting, icing, salt deposition, and related problems such as damage to equipment or to vegetation. Other drift droplets may evaporate before being deposited in the area surrounding the tower, and they also can produce PM-10 emissions. PM-10 is generated when the drift droplets evaporate and leave fine particulate matter formed by crystallization of dissolved solids. Dissolved solids found in cooling tower drift can consist of mineral matter, chemicals for corrosion inhibition, etc. 13.4-2 EMISSION FACTORS 1/95 Air Outlet Fan Air Outlet I IIII II WaterWater /la ,eih rd. Inlet It d / Inlet Fill Fill Fan Air Inlet ------- rt_ Air Inlet Inlet ,r Water Water Outlet Outlet Induced Draft Counterflow Tower Forced Draft Counterflow Tower Water Fan Fill Inlet Air Outlet Water ttttt Inlet Water Inlet Fill A'v A 4 .net ■ Air F t iii 4 4i 4 n___4, 1 _ Water Outlet \ / Water Outlet \ / Forced Draft Crossflow Tower Induced Draft Crossflow Tower Figure 13.4-2. Mechanical draft cooling towers. To reduce the drift from cooling towers, drift eliminators are usually incorporated into the tower design to remove as many droplets as practical from the air stream before exiting the tower. The drift eliminators used in cooling towers rely on inertial separation caused by direction changes while passing through the eliminators. Types of drift eliminator configurations include herringbone (blade-type), wave form, and cellular (or honeycomb) designs. The cellular units generally are the most efficient. Drift eliminators may include various materials, such as ceramics, fiber reinforced cement, fiberglass, metal, plastic, and wood installed or formed into closely spaced slats, sheets, honeycomb assemblies, or tiles. The materials may include other features, such as corrugations and water removal channels, to enhance the drift removal further. Table 13.4-1 provides available particulate emission factors for wet cooling towers. Separate emission factors are given for induced draft and natural draft cooling towers. Several features in Table 13.4-I should be noted. First, a conservatively high PM-10 emission factor can be obtained by (a) multiplying the total liquid drift factor by the total dissolved solids (TDS) fraction in the circulating water and (b) assuming that, once the water evaporates, all remaining solid particles are within the PM-I0 size range. Second, if TDS data for the cooling tower are not available, a source-specific TDS content can be estimated by obtaining the TDS data for the make-up water and multiplying them by the cooling tower cycles of concentration. The cycles of concentration ratio is the ratio of a measured 1/95 Miscellaneous Sources 13.4-3 Table 13.4-1 (Metric And English Units). PARTICULATE EMISSIONS FACTORS FOR WET COOLING TOWERSa Total Liquid Driftb PM-10` Circulating EMISSION EMISSION Water lb/103 FACTOR lb/103 FACTOR Tower Typed Flowb g/daL gal RATING g/daLe gal RATING Induced Draft 0.020 2.0 1.7 D 0.023 0.019 E (SCC 3-85-001-01, 3-85-001-20, 3-85-002-01) Natural Draft 0.00088 0.088 0.073 E ND ND - (SCC 3-85-001-02, 3-85-002-02) a References 1-17. Numbers are given to 2 significant digits. ND = no data. SCC = Source Classification Code. b References 2,5-7,9-10,12-13,15-16. Total liquid drift is water droplets entrained in the cooling tower exit air stream. Factors are for % of circulating water flow (10-2 L drift/L [10-2 gal drift/gal] water flow) and g drift/daL (lb drift/103 gal) circulating water flow. 0.12 g/daL = 0.1 lb/103 gal; 1 daL = 101 L. ` See discussion in text on how to use the table to obtain PM-10 emission estimates. Values shown above are the arithmetic average of test results from References 2,4,8, and 11-14, and they imply an effective TDS content of approximately 12,000 parts per million (ppm) in the circulating water. d See Figure 13.4-1 and Figure 13.4-2. Additional SCCs for wet cooling towers of unspecified draft type are 3-85-001-10 and 3-85-002-10. ` Expressed as g PM-10/daL (lb PM-10/103 gal) circulating water flow. parameter for the cooling tower water (such as conductivity, calcium, chlorides, or phosphate) to that parameter for the make-up water. This estimated cooling tower TDS can be used to calculate the PM- 10 emission factor as above. If neither of these methods can be used, the arithmetic average PM-10 factor given in Table 13.4-1 can be used. Table 13.4-1 presents the arithmetic average PM-10 factor calculated from the test data in References 2, 4, 8, and 11 - 14. Note that this average corresponds to an effective cooling tower recirculating water TDS content of approximately 11,500 ppm for induced draft towers. (This can be found by dividing the total liquid drift factor into the PM-10 factor.) As an alternative approach, if TDS data are unavailable for an induced draft tower, a value may be selected from Table 13.4-2 and then be combined with the total liquid drift factor in Table 13.4-1 to determine an apparent PM-10 factor. As shown in Table 13.4-2, available data do not suggest that there is any significant difference between TDS levels in counter and cross flow towers. Data for natural draft towers are not available. 13.4-4 EMISSION FACTORS 1/95 Table 13.4-2. SUMMARY STATISTICS FOR TOTAL DISSOLVED SOLIDS (TDS) CONTENT IN CIRCULATING WATER' Range Of TDS Values Geometric Mean TDS Value Type Of Draft No. Of Cases (ppm) (ppm) Counter Flow 10 3700 - 55,000 18,500 Cross Flow 7 380 - 91,000 24,000 Overallb 17 380 - 91,000 20,600 ' References 2,4,8,11-14. b Data unavailable for natural draft towers. References For Section 13.4 I. Development Of Particulate Emission Factors For Wet Cooling Towers, EPA Contract No. 68-D0-0137, Midwest Research Institute, Kansas City, MO, September 1991. 2. Cooling Tower Test Report, Drift And PM-10 Tests T89-50, T89-51, And T89-52, Midwest Research Institute, Kansas City, MO, February 1990. 3. Cooling Tower Test Report, Typical Drift Test, Midwest Research Institute, Kansas City, MO, January 1990. 4. Mass Emission Measurements Performed On Kerr-McGee Chemical Corporation's Westend Facility, Kerr-McGee Chemical Corporation, Trona, CA, And Environmental Systems Corporation, Knoxville, TN, December 1989. 5. Confidential Cooling Tower Drift Test Report For Member Of The Cooling Tower Institute, Houston, TX, Midwest Research Institute, Kansas City, MO, January 1989. 6. Confidential Cooling Tower Drift Test Report For Member Of The Cooling Tower Institute, Houston, TX, Midwest Research Institute, Kansas City, MO, October 1988. 7. Confidential Cooling Tower Drift Test Report For Member Of The Cooling Tower Institute, Houston, TX, Midwest Research Institute, Kansas City, MO, August 1988. 8. Report Of Cooling Tower Drift Emission Sampling At Argus And Sulfate #2 Cooling Towers, Kerr-McGee Chemical Corporation. Trona, CA, and Environmental Systems Corporation, Knoxville, TN, February 1987. 9. Confidential Cooling Tower Drift Test Report For Member Of The Cooling Tower Institute, Houston, TX, Midwest Research Institute, Kansas City, MO, February 1987. 10. Confidential Cooling Tower Drift Test Report For Member Of The Cooling Tower Institute, Houston, TX, Midwest Research Institute, Kansas City, MO, January 1987. 1/95 Miscellaneous Sources 13.4-5 11. Isokinetic Droplet Emission Measurements Of Selected Induced Draft Cooling Towers, Kerr- McGee Chemical Corporation, Trona, CA, and Environmental Systems Corporation, Knoxville, TN, November 1986. 12. Confidential Cooling Tower Drift Test Report For Member Of The Cooling Tower Institute, Houston, TX, Midwest Research Institute, Kansas City, MO, December 1984. 13. Confidential Cooling Tower Drift Test Report For Member Of The Cooling Tower Institute, Houston, TX, Midwest Research Institute, Kansas City, MO, August 1984. 14. Confidential Cooling Tower Drift Test Report, Midwest Research Institute, Kansas City, MO, November 1983. 15. Chalk Point Cooling Tower Project, Volumes 1 and 2, JHU PPSP-CPCTP-16, John Hopkins University, Laurel, MD, August 1977. 16. Comparative Evaluation Of Cooling Tower Drift Eliminator Performance, MIT-EL 77-004, Energy Laboratory And Department of Nuclear Engineering, Massachusetts Institute Of Technology, Cambridge, MA, June 1977. 17. G. O. Schrecker, et at, Drift Data Acquired On Mechanical Salt Water Cooling Devices, EPA-650/2-75-060, U. S. Environmental Protection Agency, Cincinnati, OH, July 1975. 13.4-6 EMISSION FACTORS 1/95 a IF CALPINE `17 CENTER ® 717 TEXAS AVENUE SC1TE 1000 ® © HOUSTON,TEXAS 77002 713.830.2000 713 830.2001(FAX) �C of 6l/I7/06 November 16,2006 Attention: James A.King Colorado Department of Public Health and Environment Air Pollution Control Division Stationary Sources Program 4300 Cherry Creek Drive Denver,Colorado 80246-1530 RE: Rocky Mountain Energy Center,LLC—Keenesburg,Weld County,Colorado Draft Operating Permit Comments(Permit No.05OPWE279) Dear Mr.King: On behalf of Rocky Mountain Energy Center,LLC,Calpine Operating Services Company,Inc. (Calpine)is hereby submitting the attached draft Title V operating permit comments. Calpine appreciates your time and consideration with regards to our questions and comments. In addition Calpine would like to schedule a meeting with you and your staff,at your earliest convenience,to discuss in greater detail our questions and comments regarding the draft operating permit. Please contact Ryan Bowles at 713.830.8347 if you have any questions regarding the attached information,to coordinate a meeting and if you require any additional information. Sincerely, (__ca ?3 Op ating Services Company, Inc. ./Jason M.Goodwin,P.E. v Director—Environmental,Health&Safety Eastern Power Region On Behalf of Rocky Mountain Energy Center,LLC M:\Ryan Bowles\Rocky Mountain\Rocky Mountain-Draft Title V Comments Cover Letter.doc cc: Ryan Bowles,Calpine EH&S(Houston,TX) Jim Gooding,RMEC(Keenesburg, CO) Gary Aron,RMEC(Keenesburg, CO) File,RM-A180 ROCKY MOUNTAIN ENERGY CENTER, LLC DRAFT OPERATING PERMIT 05OPWE279 COMMENTS Cover Status Comments Letter Item 1 The definitions for startup should be revised per Open CDPHE to Review and comments in the Permit Body below Incorporate Item 2 New APENs to be submitted Open None Item 3 RMEC will submit a demonstration. Will clarify Open RMEC to submit demo and Divisions needs on this. CDPHE to Incorporate Item 4 New APEN will be submitted for the Auxiliary Open CDPHE to Incorporate Boiler. Item 5 New APEN will be submitted for the Cooling Tower. Open CDPHE to Incorporate Item 6 This item is addressed in the body of comments below. Permit Body Page Sect. Para. Changes Status Comments Cover Issued to: Change address from 4160 Dublin Open CDPHE to Incorporate Blvd.,Dublin,CA 94568 to 717 Texas Avenue,Suite 1000,Houston,Texas 77002 Cover Responsi Change from Mr.Jim Gooding to Open CDPHE to Incorporate ble Mr.Jason M.Goodwin,P.E. Official Director—EH&S 713-570-4795 Cover Facility Gary Aron's Title is Operations Open CDPHE to Incorporate Contact Manager General RMEC requests a 60 day compliance Open CDPHE to Review and window from date of issuance for Incorporate software revisions and testing. 1 I 1 The engine driving the emergency Open CDPHE to Review and 1.1 generator should be considered an Incorporate insignificant activity along with the fire pump engine and included in Appendix A. 3 I Table ...a steam generator rated at 326 MW Open CDPHE to Incorporate 6.1 CT-01 (at peak capacity) 3 I Table ...a steam generator rated at 326 MW Open CDPHE to Incorporate 6.1 CT-02 (at peak capacity) 3 I Table ...and at rated 1810 hp and 6.51 Open CDPHE to review and 6.1 S005 mmBtu/Hr incorporate change 3 I Table ..., 12 Cell Cooling Tower,Rated at Open CDPHE to review and 6.1 S006 176,000 gal/min. incorporate change 4 II Table The rate should be 0.00293 lbs/mmbtu Open CDPHE to review and Sub. 1 "VOC" and compliance factor 7.3 x 104 for incorporate change S001 and 1.5 x 104 for S002 4 II Table Should there be a Compliance Emission Open CDPHE to Review and Sub. 1 "SO2" factor of 0.0006 Lb/mmBtu? Incorporate 5 II Table Based off of the Title V Permit Open CDPHE to review and Page 1 of 3 RMEC-Draft Operating Permit RRB Comments R0.doc 11/16/06 ROCKY MOUNTAIN ENERGY CENTER, LLC DRAFT OPERATING PERMIT O5OPWE279 COMMENTS Sub. "Natural application fuel consumption for each incorporate 1.7 Gas" CT/DB's and full operation the limit should be 38,305 mmSCF/yr. 9 II 1.4.4 Typographical error insert"gas"behind Open CDPHE to review and Sub. natural incorporate change 1.4 9 II 1.5.1.3 The last sentence should read"Setting Open CDPHE to review and Sub. in operation for these turbines ends 30 incorporate change 1.5 minutes after the turbine reaches Stage- C Operation." 11 II 1.6.1.2 Typographical error:NOx should be Open CDPHE to Incorporate Sub CO 1.6 19 II Heading The Emergency Generator is rated at Open CDPHE to review and Sub 2 1810 HP. With the HP less than incorporate change 1840,RMEC will submit a revised APEN showing no more than 100 hours per year of operation. As mentioned previously this machine should be considered an insignificant source per the requirements of MEN Exemptions in Colorado Regulation No.3,Part a Section ILD.l.ttt.(iii). 21 II Table Change Limit to read 0.039 Open CDPHE to review and Sub 3 CO lb/mmBtu on a 3-hr rolling average incorporate change. Change Monitoring Method to Continuous Emission Monitoring A CO CEMS is in place for the System and Interval to boiler Continuously 23 II 3.41 Revise entire section to reflect a CO Open CDPHE to review and 3 CEMS similar to the 3.3 NOx section incorporate change 24 II 3.6 All natural gas used at the facility is Open CDPHE to review and 3 sampled and analyzed through a Gas incorporate change Chromatograph on-site to determine HHV and logged in the DABS. Please delete this requirement 26 II Table Change 91,595.3 to 92,505.6 Open CDPHE to review and 4 Water mmgal/yr based on design flow rate incorporate change Circ of pumps. 26 II Table See discussion for paragraph 4.2 Open CDPHE to review and 4 VOC below incorporate change 26 II 4.2 The basis for the 2.4 tons/yr based on Open CDPHE to review discuss 4 VOC Micheletti letter is for once through proposed change with RMEC tower..,RMEC is a recirculating system. If the Division must use this, the tons/yr will need to be increased to 2.5 tpy with the new flow rate. 27 II 4.3 There is no way to monitor circ water Open CDPHE to review and 4 flow. RMEC can record a value each incorporate change Page 2 of 3 RMEC-Draft Operating Permit RRB Comments R0.doc 11/16/06 ROCKY MOUNTAIN ENERGY CENTER, LLC DRAFT OPERATING PERMIT 05OPWE279 COMMENTS month of the GPD x days in month to get monthly total water recirc'd. - 29 II 6.1.1.1 Add the CO monitor for the Open CDPHE to review and 6 Auxiliary Boiler incorporate change - 29 II 6.1.1.2 a These conditions should not be Open CDPHE to review and clarify 6 &c included in the permit. CO monitors requirements are not subject to the requirements of 40 CFR Part 75. Nor is the existing DAHS system configured to accommodate these requirements. If the CDPHE is going to require Part 75 monitoring provisions for CO analyzers then it needs to be consistent across the board. It is confusing trying to figure out whether we need to do a Part 60 or 75 QA measure. 30 II 6.1.2.1 Add the CO monitor for the Open CDPHE to review and 6 Auxiliary Boiler incorporate change 30 II 6.2.1 Add the CO monitor for the Auxiliary Open CDPHE to review and 6 Boiler incorporate change 31 II 6.3 We need clarification of why the Open CDPHE to review and 6 Para 1 condition is being required since CO is incorporate change not subject to Part 75. Shouldn't the last sentence state that the data acquisition system"shall"be programmed versus"is"programmed. The DAHS system is not presently programmed to perform Part 75 type substitutions for CO. 32 II 6.4.3 Do not understand the"span value of Open RMEC requests clarification 6 500 ppm for NOx Acid Rain Appendix Pa Table ...a steam generator rated at 326 MW Open CDPHE to review and B ge CT-01 (at peak capacity) incorporate change 5 Appendix Pa Table ...a steam generator rated at 326 MW Open CDPHE to review and B ge CT-02 (at peak capacity) incorporate change 5 Appendix Pa Table Delete if determined to be Insignificant Open CDPHE to review and B ge S005 incorporate change 5 Appendix Pa Table The cooling tower is a 12 cell tower Open CDPHE to review and B ge S006 with 176,000 GPM flow rate incorporate change 5 Appendix Table Same comments as for Appendix B CDPHE to review and C above. incorporate change Page 3 of 3 RMEC- Draft Operating Permit RRB Comments RO.doc 11/16/06 FedEx I Ship Manager I Label 7922 4198 0604 Page 1 of 1 From: Origin tO: (713)830.2000 GGam� Ship Dale:18NOV08 Mary Anne Wiidhouse AdWgt1 LB • CALPINE CORPORATION 'hss Syslem#:1593289'INET2500 711 Texas Ave.,Suds 1000 - Account$•"••Mountain •••' N IINNII N II VII II rYpN HOUSTON,TX REF:IIIiIII1IIIIIIIII H nalenignarn IIII�I�I�I�Itl IIIIII1�11IRAIt1I�II..lY pull SHIPTO: (303)692-2000 BILL SENDER Delivery Address Bar Code James King Colorado Dept of Public Health 4300 Cherry Creek Dr. Denver, CO 80246 PRIORITY OVERNIGHT FRI �W TRK# 7922 4198 0604 F0201 D eliv By. EN 17NOV08 I+ Al 80246 -co-us AE B KFA Shipping Label:Your shipment is complete 1. Use the'Print'feature from your browser to send this page to your laser or inlet printer. 2. Fold the printed page along the horizontal line. 3. Place label in shipping pouch and affix it to your shipment so that the barcode portion of the label can be read and scanned. Warning:Use only the printed original label for shipping.Using a photocopy of this label for shipping purposes is fraudulent and could result in additional billing charges,along with the cancellation of your FedEx account number. Use of this system constitutes your agreement to the service conditions in the current FedEx Service Guide,available on fedex.com.FedEx will not be responsible for any claim In excess of$100 per package,whether the result of loss,damage,delay,non-delivery,misdelivery,or misinformation, unless you declare a higher value,pay an additional charge,document your actual loss and file a timely claim.Umltations found In the current FedEx Service Guide apply.Your right to recover from FedEx for any loss,Including Intrinsic value of the package,loss of sales,income interest,profit, attorney's fees,costs,and other forms of damage whether direct,incidental,consequential,or special is limited to the greater of$100 or the authorized declared value.Recovery cannot exceed actual documented loss.Maximum for items of extraordinary value is$500,e.g.jewelry, precious metals,negotiable instruments and other items listed In our Service Guide.Written claims must be filed within strict time limits,see current FedEx Service Guide. https://www.fedex.com/cgi-bin/ship_it/unity/1 CiSs2CeRv0HdRv0CaZv lEhRg4CbSy9Jc... 11/16/2006 • • Colorado Open Lands 274 Union Blvd.,Suite 320 4 Lakewood,CO 80228 Phone: 303/988-2373 Colorado Rpm Lands Fax: 303/988-2383 March 17, 2005 Ms. Mari Gillman Contract Landman CalPine Rocky Mountain Energy Center, LLC 1200 17th St., Suite 770 Denver, CO 80202 Dear Ms. Gillman, Thank you for your patience while we reviewed the revised mineral assessment and report completed by CTL Thompson and discussed it at our project review meeting this afternoon. In short, the implications of the mineral potential on this property are such that Colorado Open Lands is not comfortable accepting a conservation easement on the land we have discussed. The primary reason for this relates to the IRS Code that reads: (4) Retention of qualified mineral interest—(i) In general. Except as otherwise provided in paragraph (g)(4)(ii) of this section,the requirements of this section are not met and no deduction shall be allowed in the case of a contribution of any interest when there is a retention by any person of a qualified mineral interest(as defined in paragraph (b)(1)(i) of this section) if at any time there may be extractions or removal of minerals by any surface mining method. Moreover, in the case of a qualified mineral interest gift, the requirement that the conservation purposes be protected in perpetuity is not satisfied if any method of mining that is inconsistent with the particular conservation purposes of a contribution is permitted at any time. See also §1.170A- 14(e)(2). However, a deduction under this section will not be denied in the case of certain methods of mining that may have limited, localized impact on the real property but that are not irremediably destructive of significant conservation interests. For example, a deduction will not be denied in a case where production facilities are concealed or compatible with existing topography and landscape and when surface alteration is to be restored to its original state." Our concern lies with the statement that the mining will 'have limited and localized impact on the real property.' From the CTL Thompson report and a basic understanding of the Colorado Oil and Gas Commission regulations, the wells must be spaced fairly evenly across the property, contrary to a localized approach. It is also expected that not all the wells would be put in place at the same time, further extending the time period of impacts on the property and the conservation values, and contrary to a limited impact. Unfortunately, I do not know of other land trusts that operate in this geographic area that I would be able to refer you to. While government entities are also qualified holders of conservation easements, the IRS requires that, like a non-profit organization, they "have a commitment to • • protect the conservation purposes of the donation and have the resources to enforce the restrictions." The only other possibility might be the American Farmland Trust, but I don't believe it holds many conservation easements anymore, and their Rocky Mountain office has unfortunately closed. It might still be worth a call to determine whether they would consider holding the conservation easement, but I think you'd have to call their national office in Washington, DC. Please call me if there is anything else I may be able to assist you with. Sincerely, Christine Earley Land Protection Specialist & Development Assistant Cc: Jim Hines CALPINE �, Rocky Mountain Energy Center, LLC 120017"51.,Ste.770 DENVER,CO 80202 720.946.1338 ']20.359.9140 (FAX) February 8, 2005 Sent by Fed-Ex Ms. Monica Daniels-Mika Department of Planning Services 918 10`11 Street Greeley, Colorado 80631 RE: Partial Vacation—Rocky Mountain Energy Center, LLC Use by Special Review Permit No. 1339 Dear Ms. Daniels-Mika: Pursuant to the Resolution dated September 8, 2004, and recorded at Reception number 3221934, the Weld County Board of County Commissioners approved the Partial Vacation of a portion(approximately 107 Acres) of the Special Review Permit#1339. Under cover of January 21, 2005, I forwarded to the Department of Planning Services a Draft copy of the Amended USR Plat for your review. As you had no recommended changes to the Amended Plat, enclosed herewith,please find: • 1 (one)mylar Plat executed by Rocky Mountain Energy Center, LLC • check# 524 in the amount of$41.00 for recording fees Please record the Amended Plat and return a recorded copy to me a the letterhead address. If you have any questions,please call me directly at 720-946-1338. Thank you for your assistance in this matter. Sincerely, 1\a\\ �,\\\WO,\ Mari Gillman Project Development Enclosures 0 Jim Hines From: Mari Gillman Sent: Friday, January 28, 2005 9:08 AM To: Jim Gooding; Elizabeth Mitchell (E-mail) Cc: Jim Hines Subject: Conservation Easement; DOW All- As you know I have been talking to the Colorado DOW regarding the possibility of them acting as the Trustee for our Conservation Easement. The conversation began several months ago with Mike Smith, a technician at Banner Lakes for the DOW. He referred us to Eric O'Dell, the Area Conservation Biologist in Ft. Collins. After several conversations with Eric, he presented the idea to the Regional Manager. After discussions with his regional manager, Eric called today to say that although our property has some attributes for what they typically look for in property for a conservation easement - there are other properties that present better opportunities. They appreciate our interest - but they are going to pass. Mary Qcllvnam' Mari Gillman Calpine Corporation 1200 17th Street,Suite 770 Denver,CO 80202 720-946-1338(office) 303-748-3768 (cell) 720-359-9140(fax) 1 • CALPINE • Rocky Mountain Energy Center, LLC k 1200 1E" 02020 DENVER,C0C 80202 _ ■ 720.946.1338 720.359.9140 (FAX) January 21, 2005 Sent by Fed-Ex Weld County Planning Department GREELEY OFFICE Ms. Monica Daniels-Mika JAN 2 5 )00` Department of Planning Services RECEIVED 1555 North Seventeenth Avenue Greeley, Colorado 80631 RE: Partial Vacation—Rocky Mountain Energy Center, LLC Use by Special Review Permit No. 1339 Dear Ms. Daniels-Mika: Pursuant to the Resolution dated September 8, 2004, and recorded at Reception number 3221934, the Weld County Board of County Commissioners approved the Partial Vacation of a portion (approximately 107 Acres) of the Special Review Permit#1339, conditional upon the following: Pursuant to Section 23-2-200.G.5 of the Weld County Code, the applicant shall submit a revised Partial Vacation Use of Special Review Plat, conforming to Section 23-2-260.D of the Weld County Code. Enclosed herewith,please find: • 2 (two)paper copies of the revised Plat executed by Rocky Mountain Energy Center, LLC Please review the revised Plat and if you have any revisions,please forward them to me at the letterhead address for our correction. If you have any questions, please call me directly at 720-946-1338. Thank you for your assistance in this matter. Sincerely, NO-[1‘\\VM\ Mari Gillman Project Development i S Mari Gillman From: Mari Gillman Sent: Thursday, December 09, 2004 1:43 PM To: Jan Stewart Subject: RE: Calpine--Conservation Easement Question Jan- I think I have the answer to our question. One of the qualifiers for a Trustee to hold a Conservation easement is that it must be a Public Charity and not a Private Foundation. Since The CAlpine Foundation is a private foundation - I think you are off the hook and we will pursue our Conservation Easement with Colorado Open Lands as our Trustee. Thanks for all your help in this matter. Mari Original Message----- From: Jan Stewart Sent: Tuesday, December 07, 2004 9:33 AM To: Mari Gillman Subject: RE: Calpine--Conservation Easement Question Thanks Mari. Jan Stewart President and CEO Calpine Foundation 50 W. San Fernando St. San Jose, CA 95113 408-792-1180 FAX 408-975-4648 www.calpinefoundation.org Original Message From: Mari Gillman Sent: Monday, December 06, 2004 4:09 PM To: Andrew Schulz (E-mail) Cc: Jan Stewart Subject: FW: Calpine--Conservation Easement Question Andrew- Jan Stewart at The Calpine Foundation refereed me to you regarding a question we have as to whether The Calpine Foundation can be the Trustee for a Conservation Easement that Calpine wants to place on 400 acres in Weld County, Colorado. Can you review the e-mail string below and advise me of your opinion? Please call if you have any questions. Thank you in advance for your help in this matter. Mari Gillman 1200 17th Street, Suite 770 Denver,CO 80202 65 r vLx DEPARTMENT OF PLANNING SERVICES 918 TENTH AVENUE GREELEY, COLORADO 80631 WEBSITE: www.co.weld.co.us IIIID C . E-mail (97 0) 353-6100, EXT. FAX (970) 304-6498 COLORADO November 22, 2004 Mr. Gary Aron, Plant Engineer Rocky Mountain Energy Center 6211 County Road 51 Keenesburg, CO 80643 Subject: Flood Hazard Development Permit(FHDP-439) Reclaimed Lands associated with the Temporary Low Water Crossing Dear Gary: The Department of Planning Services has been notified by the Department of Public Works that their use of the heavy haul route to cross the Box Elder Creek has been completed. Weld County Government personnel inspected the site on November 4, 2004 for compliance with the terms of Flood Hazard Development Permit number 439. Visual inspection determined that the Box Elder Creek is silting in via overland flow of erosionary soils into the creek. Further, the banks, ledge and area surrounding this low water crossing have not been re-seeded thus contributing to this environmental calamity. Photographic evidence of this condition is attached via the scanned images of this area. For the record, the Department of Planning Services, as Floodplain Administrator for Weld County Government determined that the requested reclamation of this site, as required via Flood Hazard Development Permit number 439, has not met the intent of the permit. Failure to adhere to this requirement may result in action by the Board of County Commissioners. Should you have any questions or need further information, I may be reached at the above address, telephone number or e-mail address. Sincerely, A Kim Og��_ Planning Manager ec: M. Mika,Director Planning Services L.Morrison,County Attorney D.Renley,Building Inspection R.Vigil,Building Inspection D.Carroll, Public Works K.Meyer,Public Works File: FHDP-439 USR-1339 BCS-030064 BCS-020444 BCS-030070 word\ogle\wordperfect files\ogle\correspondence\year 2004\RMEC FH DP439 Reclaimed_6.wpd Page 1 of 1 Kim Ogle To: Keith Meyer Subject: RE: Calpine FHDP Thank you for the update. Kim From: Keith Meyer Sent: Wednesday, October 06, 2004 8:40 AM To: Kim Ogle Cc: Monica Mika Subject: Calpine FHDP Kim - FYI The temporary crossing at Calpine has been removed. I believe all that is left to complete is revegetation. You may want to send someone out to complete the final inspection of the permit. Thanks! Keith Meyer, P.E. Engineering Manager Weld County Public Works 970.356.4000 ext. 3758 970.304.6497 fax kmeyer@co.weld.co.us -B (La\6 -rex- Page 1of1 Gt5/Z - 133 ' Lin Dodge From: Phillip Brewer Sent: Friday, September 24, 2004 3:52 PM To: Lin Dodge Subject: RE: "Noise"at 7503 Hwy 85 I just got off the phone with Mr. Bachofer. I will be sending the noise regulations to him so he can review them. I think that is is going to talk with you again to see about getting a copy of the USR. PhilB From: Lin Dodge Sent: Friday, September 24, 2004 3:27 PM To: Phillip Brewer Subject: RE: "Noise" at 7503 Hwy 85 Thanks, Phil! I believe this is exactly what is needed for Mr. Bachofer. Again, thanks for your help. From: Phillip Brewer Sent: Friday, September 24, 2004 3:17 PM To: Lin Dodge Subject: "Noise" at 7503 Hwy 85 Lin: I was at this address today, and surveyed the area for what has been described as a noise annoyance. I left my card on the fence of 7503 as no one was at home. I talked with a Mr. Ewing who lives next door to 7503 and who owns the land on which the Calpine operation is leased. I talked with a son of a mother who lives direct north of and next to the Calpine site. Mr. Ewing said that for him and his wife there is"no" noise from the Calpine site. The son of the mother who is concerned said that he does not know of the noise that is the basis of the complaint. The mother is annoyed by the noise, per the son. I did measure the noise level 25 feet from the property line of the portion of land on which the Calpine operation is located. I measured a maximum noise level of 51.4 db(A). This level is within Colorado regulation for Industrial, Light Industrial, Commercial, and residential areas at that time of the day (12:30pm). I have not measured the noise level between 7pm and 7 am. The 51.4 db(A)would be a violation of statute if it were between 7pm and 7am if that is"zoned" residential. I don't know now how it is zoned, but I am guessing"Agriculture" since there are farms all around the Calpine site. If so, then the noise may be exempt. I will attempt to contact Mr. Bachofer now (it is 3:15pm on Friday the 24th). Philb er Attc12.060 -IZ�.» 130Ck n 1LTn- 3- 1 - Zs ‘S-- ,haLLICL LCOLL.t.) IC Baia_ O h -Co 'r ) ,u:V ALJ% D vlinttiO --� a. ck— �' 1 S u(- \ 11 e 1C'\ Ct (S 1C{ 111 111tCkd cc( b,LiO in yenHvD . • \ uocxx, 143 ‘NU\A.:Lb 414 / 367 3O 6ocb39 — wino 5E4 130I% 30 a 0o0 07 - t i PT scJ4 3 0 ("lit� a8 J3a t -3o Boa o IS aety-K6ce4/, R6 9 5:o5 Pl-/' 44 -66 Aum - hie-A-A-zrztti- Al - 13311 , ., . de. . -„,„,„1/4, ...a ...,.. . . _......,. a. ... .,..„ ., .. „.. . ., a r .. , Li. ` .- J I , ;}}� ! ♦1. o-- . ^. i r ' j ti,. hes r ,W'�,� ♦- # F •ley w / i .�.; 7 il -,. Lp r tiff . ..r ' `, ! .. n- f 4 `1, I 1 , IZ f .� •t� M rr, .��. tl .R rtd. •r : 1 J it 1 .♦ f T...iSd1 r i 4 1 _ •4- q, �'-M1. � c•rs . - . _ , 3' A7j ts' Iti I r f + r • ,a 4. /Ls- — age :: % •r . ti a- = 7525852RWE % _ r-- - �/ / - i ( '1:1 ,...--"1-ree--.." IL; rihree,.. . • • 7501 85 HWY WELD lifee , ra el /3e9 30Oabv31 . er- - ... • I t . I I 7 . . • ill a II . n I I tiI. � `�� t I - r '1 ?- -Z - - ' - - `� ' Ij --- — —• .r �• ' r l • , { ,I. la 7 t• r / i f f r ! - Bit,r-' ' / I ^S� tt — 1 - . - I: / t i 4 I - - • ifry , II / ,\\ _ , . ____ ll , ____ _____ 7525 85 CR WE D 7501 85 HWY WELD s- i / c i — t \.\\ / I I ) 1 g v ❑ Ol err Fi . (I_I II_r I �, II=r k • r_I EL, ............„..„:„........„,::.:.,:.:::.....:::::::.::: _ ._ . ... .. . ... .. Xi ZtS C•1 I'r lV - in p -b di i/+ ID C v CC -_j- -LI L.t- CC ,^^� a. r"1 ci u r ±_ ,y , Q) C •V. - - - 0 iy y i! L L f� I r�-, • fly1 {V T f Ti: HI U) .' �'"J . I .• (('J II. ,! II .J II •.J IC\J i • ( .,J (N G 1{ I"- • • .. w G J £ ,B � -1:i ,U (_1 ,v c_' .r?f a:, ,1) a> U) i y ` w j3 . ' 1 i t�'Jt 0 cc _ Cri rCt rJ O ; U C `0 •c NJ m ILA C1 ;yi 0 + la. Q = ' .,� ,= w f,J Q• u- G c -D 1p a r� 4i. (r+ • Liµ o •% a! -O I0, o O :Ti f� it) cr N r 1 , al ,� at U) .j w ID I CO -Cu u (� .• j; ••,. _y • :' I_t d is • - ._J LU c• • -,7: r _O -n; a - iJ CuI _ C -1 r-I II z�•' t'i ..f.,:. -y 117 I,' Eiciii,_,, bin.,...,: ...,.._, ,,." ..„, r_Lj in .:::-.: c . . ii tom! . • b •v �� J Q.7 , C rr T : } �1 I_I T— it 1 ' �_, pitiii:cic,, '- w la-) w II 1..� x u u �i fJ CE'€ 'lain JIx CC COC ?7 U) + a r, �� w w _I CL 0 = �i lV LL G A > 7 , I_ I_ NiI I_ h I L T C. t`J l `J tiV T �`J ▪J �`J _ W Wt- ci li.i L.L u- -J j r� c� C17 c] 1 j rat ii, 0 O L ci .2..; gig r-� g.. i L� iJ i f 't 3✓ t i ;., L �.�y w fit✓ �, .rJ; Q:' [J uJ r_� +�I `7- G C rii +.� MJ I— I O rrT•°�.� rn ` I— = >).i ��`.•J 0 6 I,Lr �- %- ti C' O _ al - "' a 5 ,2 0 ID ac— ,3) .0 cy, co la- i! •=. H 0 C l (.0C )- U E 0- G 4 _ :,,, r,, ,,,,,, ci ec a) m f J L'.--:...) O ID 1"5 �7 el O Cr.,v N 'z liV 0a. I IIE a .r�., m. Cry Q Ail •v .- t-1 -LEJ W O _ - , } �! p`'( "‹ - - CD 0j O et �^ U O O r, J L mj co w I® ca Q r v c..,-ri .E Eft CO U I—, ail I WI.k . . Qi I::::=M I a +p I ' .i./ �,� 4 - . > • I--Vt. - Y ._ — — -D ,l , 4i L D) ,—ci 'II w L � E if; alit - 0. }' E L an } w CL It", 1:75 i f:'::; L !` -c m 2 1,'-_ , Z (f Q . - o DI J J U O V J on o ... a--I `; � ° W . ;, • U 2 r�) . CO ,� { 1 Ek.-,. (o ` - o W 'a co U1 t • ME CL M 417 Z '4 CI • H h- Q I J I r LC) 41 J rr. V Q (, , I-1 � �� ; U w u� m ci -0 '.. {-- L m r-- ,, G 'eta c G •= CO G V _ = • O_ I '' u '•_ LL y Cf 8 C - .� O 6 G C13 O LI QQQY m .2 I - O sae up P7 C'7 c I EE f J N - r T- y I CO: : Z ab I/ * J T I r - <I"i Nottize : :, . •+� y tiln ocry: a Q ift �. �.f —7'd.), :r co I fA .L. G • I_n Crl C LL .i� cc o �!� In CD CI CV I® L J cri �U c m —' !"I r C.J v.I CO U rl; 'IIII • l:::: Q�•)y ki 7-1 `-' ii �_ P r•. - L� �' li :. . . . . . . . . _ . . ••t.♦'l.tititi'.SSl."el. ?r ' l' '✓. ti' '1. . ..' ' . 1.' 'l. !. V 't. f. ✓ '`' '✓. . . . .• ♦ 4 . . . . .✓ 1 '•. ••• • •� r��.. fl ' • •• . 1 • • • . . . . . . . . . . . . . . . . . . . . . " . . . . . (-1. 41% •. •'• y,../•S 4 • ' . • • • , I I t O . . . . . . • . .• • o•'•'• •. . 't•+. ... . . . . �f4 ."-:----e-:-µ rr Mx� . . Re illx ai r • I .... � . i 7 t CO C7 L G �7co tr.,. (.0 !— co fl Q Li o r)1 J w Li O w . Tw 0 i - LLI J J co 0 ,t CO ---3" — l— CC = r C� J U7 O < 1- J O o w ,+.4 LD O 0 co cc _ O ,r.; In Q F— z p a �R C J � Vy ^ OOil u) wW x . 4UJ 41:33 pri7130 w '67i LI� E :.: T •t CO J CC Q a ! �I aI L f , Q — , •- Int. 50 D I— Q .O J CO CC O - ?JJ w rC � co, O OU CC �� F— ~ 0- r ~ Cr) w =I= c 1— w F— L _2' Cr} C U7 { .1O LC)co { `I ,--I' y a li. J F- u_ D f O —',cis f in J J CC Li �' O v OWF- CV OO .. _ �- 0 COO r� Z a"-- a x i/ ' , i era? G ..sat L.0 -34. ! r-- Li w c�u' s t. -6 S �� j +��+ MI u a r•gl CL II I CO < +•i ` l G VI IN' co CO .. -. ... - m wl C . . mow! rs W V1 It' �. ('t J' P,I 0 o �� "" O c7) Ci COw 1 J I® 2` b J L m J J x.l ". -J C V __ t . mil ifi T CO ti � co ci I 'il • • I im Pe ( cu - 6 di ri a— ., - 0. :u_ .0 fl] _ - _.. �_ ..... . r� - X hi ., c c N. O Cp Lt'i C 1.6 1-rGTO O C O r" o U a Li• N U. m . I.X. III OCLOO � > O O tv G W W co O O 00U ''t � CJ Q WWZL0in Z I Q En N. 17 Sod C Z C V � CnNcn c h ti • .... � � � � F- a . cc 4 > CD k CG U = � UpZN Q Q• j UI � - S' O � a. J � J _ .C W O CD O fi'' CN O N � ZWz O � co '� O .. • _ r- M tt O CT Oo l~ J o N N O tv 11 MJNQW X 0 r r- >. CO O J "ri jZMW CM Q Q C >. >e. z 14-OOZ ~ Eit en o� .� c) W CD N. _ 0 7 LL Z 3Ly,� mJr- F-- a 0 0 0 U N � Cn = Lc 00 CO • J ? QLN 0 Q N L'' N J Ca F=- r r I '' . (f) C7 N Cr) W CJ, N O CC U I O L+- O 00 o a. Q CO r- CCUWZ ) > 13) 4 ha O O Q? tt CD = I-- O W M Z N` C. Cr ro C getc 0 J U 0) 01 Cl, —J � 0 Z CL ~ U CC Is) CD N ►- 0 Nuj a0 i 44 0) 0 ► ' U O `'C; 'V CA RD Co •• cal C 't 0. D, C p "dine — C 11:11 CI mo Cn IL. ID < = Q E o P y C y S .. *— I Q E N , 0 sc LLLLL L L L. Mme °° a C Z N0o N ' U G C 0 Z p • . `, 000 Otv J �] • O ad � W �' E ° °' o ' ° �I i a� W = ,� J C os ten C o3J z �— o L L L L L L Q, V iv 61.0 Ur° 0~C O E o » c� C C.J u L Q rr-- a �J O p -4 7 Cri .C C O r- I.A. CO CEO O _i LO V) ° C o CJ ,u C .. O (0 i9 rJ O v N Q o mir = C )- a.l l ►- X v LLI 1- ,�-� �, I = o 16o O o E ea L L L L L L L L L E c .y N .a o fv v y '� ,. O N E L.). z sl U7 s� -- �, co .c Z ca Z C O y �' o Jic n� u C O 0 •H O M .�sr) 0 O C t O _ 01 C (, '� 1. o C cc o 0.4 kj T I vN - N C 0o o � to U .... Zl 'on-1 Xi I--I U ml va X '`Z `�} U 0 n O a o m un o W Q o L L L L L L L L l• 1 tL a 0 } Q n. r co re-. J co co AUG-20-2004 FRI 03:43 PM SOUTHWEST WELD PLANNING FAX NO. 720 652 4211 P. 01 6 AO ak , SOUTHWEST WELD COUNTY DEPARTMENT OF PLANNING SERVICES BUILDING INSPECTION 4209 CR 24,5 LONGMONT, CO 80504 I'll WEBSITE:www.co.weld.co.us PHONE (720)652-4210, EXT.8740 C. FAX(120)652-4211 COLORADO FAX TRANSMISSION TO: i ; FROM: �k) riv DATE: FAX #. PAGES: l 1 • SUBJECT: C S 03 S' COMMENTS: CONFIDENTIAL This facsimile is intends o I or th use o t el dvidua or entit to which 't is addressed nd m contain in oration that is Me ed confide tia and ex m t from d'sclos re under a li b e I . If the reader of this of this communiction is facsimile is not the intended recipient nor the employee or agent responsible for delivering the facsimile to the intended recipient,you are hereby notified that any dissemination, distribution, notify copying medithis by telephone m and strictly prohibited. If you have received this communication in error, please rfY return the original message to us at the above address via the U.S. Postal Service. Thank you. AUG-20-2004 FRI 03:43 PM SOUTHWEST WELD PLANNING FAX N0. 720 652 4211 P, 02 se Sundem - Re: BCS-030285 CA-PINE JA NIFOLD BUILDING/EASEMENT ;, From: MONICA Mika To: Sundem, Elise Date: 6/30/03 2:37PM Subject: Re: BCS-030285 -CALPINE MANIFOLD BUILDING/EASEMENT Okay, I just spoke to Lee Morrison, Lee said we can not do a SE for a Major Facility of a Public Utility, because it is private. According to Lee,the only determination is whether or not this a substantial change to the USR. After review of this proposal, I find that this is not a substantial or a major change so just proceed with this, >>> Elise Sundem 06/30/03 01:18PM >>> Monica, Dennis has said in conversations with you that it is OK to release Calpine's permit for the Manifold Building. Please reference the following e-mail received from Kim on Friday afternoon and provide a written decision on the verdict to release this permit. I've tried to reach Kim and Sheri this AM and have not heard back. Thanks, Elise Elise I understand that you were given direction today regarding the Calpine lease agreement and the permitting of the on-site structure. There is one additional issue that requires addressing. For the purposes of permitting the on-site structure and support buildings, a Subdivision Exemption application should be submitted by the applicant for the placement of this structure on lands leased from a third party. It is suggested that the applicant contact the planning office for direction and to acquire the appropriate application. The SE application is handled Administratively and may take up to 45 days to process. CC: Drenley; Kogle AUG-20-2004 FRI 03:43 PM SOUTHWEST WELD PLANNING FAX NO. 720 652 4211 P. 03 Use Sunder Re. BCS-030285 CALPIF' 9ANIFOLD BUILDING Page 1 From: WENDIInloes To: Sundem, Elise Date: 6/30/03 8:23AM Subject: Re: BCS-030285 CALPINE MANIFOLD BUILDING no >>> Elise Sundem 06/30/03 08:12AM >>> ANY RIF'S FOR THIS MANIFOLD BUILDING? AUG-20-2004 FRI 03:43 PM SOUTHWEST WELD PLANNING FAX NO. 720 652 4211 P. 04 lise Sundem yCALPINE ,u.......�.,_ „w ., Page 1 From: LIN Dodge To: Sundem, Elise Date: 6/26/03 10:20AM Subject: CALPINE I just forwarded you Monica's answer— I will assign an address to this site- remember it will be considered a"temp address"and not attached to the parcel. You should have a copy of the actual ROW Option &Agrmt and the amendment, in the permit file, as well as specif access instructions for the inspectors. One more thing ... the description on the permit does not tell us how the building is built, so you need to add that. CC: Reif, Jeff; Sullivan, PAT AUG-20-2004 FRI 03:43 PM SOUTHWEST WELD PLANNING FAX NO, 720 652 4211 P. 05 ,,..,.�,. n mmn ...,,,.,.Mmm mm,r.. Elise Sundem Calpine Lease Agreement W W • Page 1 From: Kim Ogle To: Elise Sundem Date: 6/26/03 3:21 PM Subject: Calpine Lease Agreement Elise I understand that you were given direction today regarding the Calpine lease agreement and the permitting of the on-site structure. There is one additional issue that requires addressing. For the purposes of permitting the on-site structure and support buildings, a Subdivision Exemption application should be submitted by the applicant for the placement of this structure on lands leased from a third party. It is suggested that the applicant contact the planning office for direction and to acquire the appropriate application. The SE application is handled Administratively and may take up to 45 days to process. AUG-20-2004 FRI 03:43 PM SOUTHWEST WELD PLANNING FAX NO. 720 652 4211 P. 06 Elise Sundem Re: CALPINE page 1 From: MONICA Mika To: Dodge, LIN Date: 6/26/03 10:13AM Subject: Re: CALPINE As a private agreement unless it is identified on the USR wihic I do not believe it is. >>> LIN Dodge 06/26/03 08:31AM >>> Elise called for an address for a utility building Calpine submitted a permit for--it is described as a "manifold bldg for well field water pump controls for Calpine"- it is located on private property in the SE4 30-2-66 - is this part of the USR should the USR be referenced? There is a letter Elise faxed that references a right of way option&agrmt,Aug 2002 by& between the property owner& Rocky Mountain Energy Center w/an amendment to ROW option 3/03. So, should we handled this as a private agrmt or as a part of the USR? AUG-20-2004 FRI 03:44 PM SOUTHWEST WELD PLANNING FAX NO, 720 652 4211 P. 07 Elise Sundem Fwd: CALPINE Page 1 From: LIN Dodge To: Sundem, Elise Date: 6/26/03 8:35AM Subject: Fwd: CALPINE After talking w/Kim, he suggested we check w/Monica. Have you found anything in your Calpine file? Did you email Monica? AUG-20-2004 FRI 03:44 PM SOUTHWEST WELD PLANNING FAX NO, 720 652 4211 P. 08 ,z....,a..,.m .� wnrnrrn,ar n.mmmmv a,rmmr�-tee Elise Sundem CALPINE Page 1 • From: LIN Dodge To: Mika, MONICA Date: 6/26/03 8:31AM Subject: CALPINE Elise called for an address for a utility building Calpine submitted a permit for—it is described as a "manifold bldg for well field water pump controls for Calpine"—it is located on private property in the SE4 30-2-66— is this part of the USR/should the USR be referenced? There is a letter Elise faxed that references a right of way option &agrmt, Aug 2002 by&between the property owner & Rocky Mountain Energy Center wl an amendment to ROW option 3/03. So, should we handled this as a private agrmt or as a part of the USR? CC: Reif, Jeff; Sullivan, PAT; Sundem, Elise AUG-20-2004 FRI 03:44 PM SOUTHWEST WELD PLANNING FAX NO. 720 652 4211 P. 09 JUN-12-2003 THU 08:48 AM SOUTHWEST WELD PLANNING FAX NO. 720 652 4211 P. 02 Air(rrye WELD COUNTY BUILDING INS'r'E`,,,oN BUILDING PERMIT APPLICATIOPt . 0.,60 COUNTY BUILDING INSPECTION WORTH LOCATION l� I(ew SOUTHWEST LOCATION .. 0 1555 N. 17TH AVENUE 4209 CR 24.5 GREELEY, CO 80631 LONGMONT„CO 80504 (970)-353-6100 EXT. 3540 (720) 652.4210 EXT. 8730 PLOT PLANS AND WARRANTY DEED REQUIRED FOR ALL STRUCTURES PROPERTY OWNER CAL-PINE PHONE (3o 3)534 2500 MAILING ADDRESS (6,211 WELD C0LLN-TN RoAD 3Ycji JOB SITE ADDRESS LEGAL DESCRIPTION.%P4 l 1 % _rat+ ' {y SEC.—352_,T Z N, R W DISTANCE FROM LOT LINES OR SUBDIVISION LOT BLOCK N S E W GENERAL CONTRACTOR MAILING ADDRESS ID# PHONE ERS Cav1S-R2u..c.TnRS (0211 WELD canary{ BOAC 651 303 53(. 263I MECHANICAL CONTRACTOR • MAILING ADDRESS • ID# PHONE ELECTRICAL CONTRACTOR MAILING ADDRESS ID# PHONE Ti C- &z(I WELD on4Arr 1 EoAb, 5 I 303 S3c,, osra 3 PLUMBING CONTRACTOR MAILING ADDRESS ID# PHONE PURPOSE FOR PERMIT TYPE OF PROJECT TYPE OF CONSTRUCTION TYPE OF FOUNDATION I(f NEW BUILDING 0 DWELLING 0 WOOD FRAME 0 BASEMENT ❑ ADDITION 0 PRIVATE GARAGE JCSTRUCTURAL STEEL 0 FINISHED-SF; 0 REMODEL 0 ATTACHED 0 DETACHED ❑ MASONRY ❑ UNFINISHED-SF• ❑ REPAIR/REPLACEMENT 0 SINGLE 0 2 CAR a ❑ REINFORCED CONCRETE 0 CRAWLSPACE: SF ❑ ELECTRICAL 0 PUBLIC GARAGE ❑ BRICK VENEER $'SLAB ❑ MOVE-IN RESIDENCE ❑ STORAGE SHED 0 POLE FRAME ❑ CAISSONS OTHER }ir OTHER pis,C.NTWLPy2Y, ❑ OTHER _ ❑ OTHER HEIGHT OF BUILDING: MI 1 #OP STORIES:� #OF FIREPLACES MASONRY; O-CLEARANCE: _GAS LOG: ._AVA �CARPORT SIZE:_X. LP PATIO: 1ST SIZE: -X._ 2ND S12E_X, COVERED:❑YES 0 NO MA NUMBER OF BEDROOMS: N/A DECK: 1ST SIZE: -Y- 2ND SIZE:_-X_.. COVERED:O YES 0 NO A/44 -,'w BATHROOMS FULL: - 3/4:_ 112: ON FILE:,,WYES ❑ NO BLUEPRINT ON FILE!❑YES❑ NO TOTAL LAND AREA: Pond bete ACCESS; A EXISTING 4 NEW+❑NORTH OSOUTH❑EAST❑WEST 611y q24 S 0 SINGLE FAMILY 0 TWO OR MORE FAMILY MOTFUHOTEL#OF UNITS ,$OTHER ( area UTII_(r/ BLDG TYPE OF SEWAGE; / TYPE OF WATER: TYPE OF HEAT: ELECTRICAL SERVICE: PUBLIC-NAME:. esh 0 PUBLIC-NAME: MP? ❑ NAT. GAS-NAME: $NAME: Me 7 PRIVATE ❑ PRIVATE ❑ PROPANE-NAME: SIZE OF SVC;Ito AMPS PERMIT F. PERMIT #; *ELECTRIC-NAME: .aneaGP.CALCULATIONS: PERC-TEST DATE: ❑OTHER SQUARE FOOTAGE: VALUE S /10L000 BUILDING FEE 6 VAIN LEVEL: 424 SP ••00 NOT/NCLLJa THE FOLLOWING ITEMS IN THE ABOVE PRICE" 2ND LEVEL: µ/A ELECTRICAL COSTS S /0 000 PEE S =OUNDATION+ CONSTRUCTION METER: C YES Si NO FEE S GARAGE: PLAN CHECK: C YES 0 NO FEE S ]THER: OTHER : FEE S TOTAL FEES 6 NOIRE THAN ONE(1) RESIDENCE ON SITE? YES NO NM INCLUDE A BRIEF DESCRIPTION OP THE WORK BEING DONE LISTING THE IIVENDED USE NAIIWOI4 p2u.tt#D(14Ea Paa 142Q,CL. F1GL,D WAT R Ufl4 C,ot$T0.AI_S rA-c.P I A G (6 LEcf fL i4 till L%t4 3 HEREBY CERTIFY THE ABOVE AND ANY ATTACHED INFORMATION IS CORRECT AND ACCURATE TO THE BEST OF MY KNOWLEDGE: cir-w1ATnve ne aom IPAMT fATe AUG-20-2004 FRI 03 44 PM SOUTHWEST WELD PLANNING FAX NO 720 652 4211 P 10 �} r 4 e . f Rf .. E 7 § L xd R e u4. ?.aa w yF a va JR ..z..R .. i', 'u� L. An�'",,,,.:We Ln` s Odd' ifk }x ? ,4W4 +s�» x h*� i=ri nL: a ;f fkb + l�c * „3 { •7. x '",.,, fF f '+ * a , "'t r '�`y" y; s *u� ttit *" ` - c v ( c? SG 4.a.R ' 'i ,F �£ .� t {�f 49:, t ik*V`I'A " S xx ,t + C ..a, n iw ,µa nfrw >is n 6 r a +a/' f 2 s * .ate x c i"°\.r « r .d` a r' " q St ' s v ,e�wG.£x�w k .s .ae ° i :7,<;,::, c y ' R, `°„t+ * bq� sS�k , .f , vcyht 'i �. .v^ >a vx 7t 7a'� alc :,: ',, $ ,,m,:),,,,,E„,:44 L a• t t ;figg 7 :x£ z. • S R's> w $ �s`c^�; ..p. ;;•,:.,1.,:„ ar 3:f a S l C C +e +;, n e+ k+ �Gl * r?t 4 , �, u'r *R s. esc sR * {}.„ s`as `*' ,� s ;ar ss' a ''n c . »» 3 g R Y. y' „i ih .',cr t:i . t,i F's.. e ew ^ k r t ''4Rt$ ,s� * ;RA 4x ,' i e S r srh ; R i 4�ErA { *, , gM Ry4t4 r9 'is +* i 4 f : ^0 } i i .� ';R n Y �O3�r itif{ u S.d .,*i� i S a 'f k R r <sietiMiR'�. .si.,l i iri..,.w"3x" +:n S v *L .'L! ! lV ' ! L f : Yfi. 4*.'An' sl `."' 14 ^.iii . . bn'* �»b' R i '+ 4g/'m `Jt*1 ?g !' a�SY'F '11 S jZ iR4YF/M x c+ h a ',,� R ,,4 r E. s a t ,yt S t a: AY a 4 . L t + i" x.T�. *{ i x {i n p L'^ "a * yc'i.? $ * a l} r n"{4 ; s i sv i i n 4x ." Z4 RVz'l* s " rJ it 1.4 ,�k s : r * Ia k�. J tt '...F^"..i £ .- f rf' ' `ai' d{ i n , y $ nb h?:;p. > } s i ^R RY ! ii n* S i w s4 >;° *31`ir `'�" f rr"� +. s r� yr j R R' f > r i Lvw* R ts1 t'it. xi1 �n* *� s ,..Tj a Sn`na v` r i 'gz '^` `� , Sn e 4 R 4` ' S Ry Az: g�, r w* f i �s '9� r w " a 's E in b y l > r ! i .: r:sa >>. : ss 4"1 �ii �Y ^ :. 4i ^r f _ S!,* $ i ; k 2` M1 vv s .e" as r R '?e+' d R ,R£s s gv5q, * Nda > L ^ .6s d elk n 3 `Fs'r r R v a a sx: sn * ; f4 i?h 'nip „,4 4 '"T i sv� va<,°•:' ## s+ a ti i -R*� i * n s " rr 1 4 sr R cii y iiii i -#: �p s S s at s "t; F vi'it sta. e>C * e.. t * _ fin',,��,, r x ?s t si'R. i F` i &.S. n >>w € :.ata Frp� . rx 'r ›:i £ c nd + igis tvi: +: .. * : ( ^ ff' £ � tt +N, "r d' , k* i#s: . s,> 4 .f gyp, ERs yg i kik a �*� 5 W. ` '' Ts` : e# •4£i ;. t 411. vi•(^ } " r >f ..S ¢te ; .. ,y s as x rf '�' r?�. z* w' Eta '( .ih€ ` ,n.a..R i0 ✓T £ s, ii. f + a &v s : "r.y • , fr¢ 'ti"4.4 t yik tn1R 4 R *h,�s�: i ti' .. f ko R., t wk �•i 4 fR v i "7 S G£'':::;'1;'.5.014° s�'. cf L s�u , d"d '� afiv x i>>y " t>is ' 44:1 ,*J Y tie<rf * "° .1 r „-�d R A R * s j $ +ga v f�, Sy * 'F . 3_.,r { ✓ * ti ,a *!a r%R R* iv i Ct* S c i -!n .7 • R� Z '''+ i -!,4,04,,,,11:;?-,,,� ii :ry *s d wfz AT !- iY—,;,,,,,;:„..:4,,,..:=,,”4:„.,;:,,,,r.:::.,,:„..�} Y �5 ,�q, , ` M' iF fi �` YJ 1ff !� i di k i` y .. .. I I 1 —r,,,---- c --11111H 1 1' T (O , AUG.20-2004 FRI 03:46 PM SOUTHWEST WELD PLANNING FAX WI . 720 652 4211 P. 11 L...�Yt 1'tl�A r..,,1 i !IM ! r V .1' 9 1.. XI , 1Y�) 'N 1 yk ' b ;,-;-...5,::',,,,,,,,. I + •.: ,ts . . N°' r 1 1 • r x �,I d , ,. ., r1 1 n' �yy Sf+; v i,'. 9 it I • -,02,,,,::::.0.' a ,/i..,44,4.-,1,;..7,:v. ra 1 x'rh Y6' a ,Br•kJ Y ♦" r r 4 4'rV r m° r fp{•,"ick pi' �,�✓°� btu � � A 1 µ• 1 . �h y/ 1 I . • ''x,,•21,4\ 1 Itl rn..l. [1x'•, Nrt1 r n "r •. f4 F' .) f .i Y Fli,, 4 nt �1 o- i 4''Mr. ;V ,,,,,,Hr,. ,:v4,9-,,::r�J� y� k .r�,,,f. �� r r ! •6q +, ; *,,'N, .�•t 1 � �I y � 1 .,;;,),:4v,• .x�� w� 's �f i AJ' :,,,t,..2.:,,;‘,", 'N' ,1 e t7,,,, �, y J t r! {`S AI .Yv. .✓�' 1p F ' rIt•xrr C r l /) 1 , I!„ 'A A MY �'� Y rA i V T 1 : i }!' . : L I $.J 1 , q d ' ./'...14: 1 I _ rrtlyW � v r 1 'fib<, g Jr a � ". 1 x9 p tr n f a ,r j °'irp7 ✓ qg �nnt .:;. I I '.'y t� pM I 4 R{ 1 V� EIDENOMMEiY � J3 f ; ₹V I � ?•I w. : Y'tlw ,': r � II:,•'r` �kM . �Y r l '44 i. F,' I I i + �rti 4' u r :I h l _ F tl� r ,N l x b4 , t* c r. 111* 4P + I l t ti , [ 1 i h `1 ! ; til A, yx, a y yYl° � P'4`at w alua 1'�� 1` ft.' til 1 1 ' w,,L, {,•tg.,x. � I i !l u i rlw?,,uc �..i.40'w • tl^' r ' I ' rlam ' e I t 1 "'l ■ (aJ�C' �,J.0 1 rl t I I „Ir ; � Ji K., �Yf k{ F I 1 .:I k',,,V re }/jrV / r ?» k:'44444:7. 444 •a 1b , •••pNl ,ii I Al 'Y O®,lI,,, 'I/ , tv)i 3' ' mm L ( ' S 01 M J f 's J1 `ye ! �Vr b p a a J rt ,,1 ° I ' 214`,''.,..,4,,,{ d � ! 'h. t UhulluuiI i Ip' - : 1 n1 1 fx IAv • :4,,,.l �� eY:4,,yi ' t :^M 4 Noll 4 ... .2,,,,,,,,J, I 1 ^ 'r `o M.n t{ !I' �I V� it l'..1 1 'f h YrN f 1�� IY t M n 1 II oI . �1 I ....;,:,..§:„„,i,'. �IbY ® J r 4 I I� I+ nl r ! f� 5 'i ��'i, r i fJJ x 1 I Hull, . ii:',.:,,,,: ' ,,. . OF , I 110 fC ,, q II E'I pF , „`1 „II Iri 1+ kr h I tiGyl/1 Ptl'` I� ,4j Illi lk.,,, ' ,r. tlxi4 II, Il Ill A n I 1 Itl X1 I�� }� t.,,,, r, .dt t q „Lir I?.? ( 9: t 1, F :a1 ° 1r rl 1' l x + f,,iyy i 11 r 1 i1V bl• I 1 1i !. pI1 � l VVl flllyi fr1 ,l1 II }• ISI t ,,1 , V�'f ;. ,, 'IV ,IR+ I � I �w��l,'� ar..'Ir 'l.�. t I ��I �' p f. t II I ,�� 1 1 I I q tlh�, d .t ill Illi 1,1i 1..`ItJ„ 11 kft; DEPARTMENT OF PLANNING SERVICES 1555 N. 17i° AVENUE GREELEY, COLORADO 80631 W IWEBSITE:`D�. : kogl@CO. eld.CO.USE-mail address: www.co.weld.co.us wd.CO.US PHONE (970) 353-6100, EXT. 3540 FAX (970) 304-6498 COLORADO May 10, 2004 Mr. Gary Aron, Plant Engineer Rocky Mountain Energy Center 6211 County Road 51 Keenesburg, CO 80643 Subject: Flood Hazard Development Permit (FHDP-439) Request for Extension Granted Dear Gary: The Department of Planning Services, in correspondence dated February 2, 2004 ,granted your request for an extension of the temporary low water crossing over Box Elder Creek. Applicati m materials stated that this crossing was designed and constructed to accommodate the transportation o! heavy components associated with the power plant. As stated in the February 2, 2004 letter, Weld C:runty Government granted an extension of the existing Permit until June 1, 2004, as requested in tht December 23, 2003, letter from Aron to Ogle. In discussion with the Department of Public Works, the use of the heavy haul rot to to cross the Box Elder Creek will be utilized by the County to remove soils from the RMEC property. ll s expected that the use of the road will be completed early to mid August 2004, thus providing a 30-day w. idow for RMEC to complete the reclamation process as required via Flood Hazard Development I armit number 439. Should you have any questions or need further information, I may be reached ; t the above address, telephone number or e-mail address. Sincerely, I1 KirtrOgl Planning Manager ec: M.Mika, Director Planning Services L. Morrison, County Attorney D.Renley,Building Inspection R.Vigil,Building Inspection D.Carroll, Public Works File: FHDP-439 USR-1339 BCS-030064 BCS-020444 BCS-030070 wordAogleAwordperfect OlesVogleAcorrespondenceAyear 2004,ftl,EC FHDP439 Reclahned_2 wpd Offit ‘? DEPARTMENT OF PLANNING SERVICES 1555 N. 17`h AVENUE GREELEY, COLORADO 80631 WEBSITE: www.co.weld.co.us E-mail address: PHONE (970) 353-6100, 9 OE T. 3540 FAX 3540 COLORADO April 20, 2004 P. . Gary Aron. Plant Engineer Rocky Mountain Energy Center 6211 County Road 51 Keenesbcrg, CO 80643 Subject: Food Hazard Development Permit (FR DP-432) Request for Extension Dear Gary: The Department of Planning Services, in correspondence dated February 2, 2004 granted your request for an extension of the temporary low water crossing over Box Elder Creek. Application materials stated that this crossing was designed and constructed to accommodate the transportation of heavy components associated with the power plant. As stated in the February 2, 2004 letter, Weld County Government granted an extension of the existing Permit until June 1, 2004, as requested in the December 23, 2003, letter from Aron to Ogle. As required by the Department of Building Inspection. prior to obtaining the Certificate of Occupancy for the Rocky Mountain Energy Center staff will require that the temporary low water crossing over Box Elder Creek be removed, the surrounding lands reclaimed to their original condition and all evidence of disturbance be eminated. Please contact this office of a request for inspection a minimum of thirty days prior to the Certificate of Occupancy inspection. Should you have any questions or need further 'in inform I be reacheul et the abov ; P ;ss. telephone number or e-mail address. Sincerely, Kim Ogle Planning Manager Enclosures ec: M. Mika, Director Planning Services L. Morrison,County Attorney D. Renley, Building Inspection R.Vigil, Building Inspection D. Carroll,Public Works File: FHDP-439 USR-1339 BCS-030064 BCS-020444 • BCS-030070 ward' lerwordperrect Resloglercorrespondencelyear 2004\RMEO FHDP439 Reclairnec.wpC • r ,,,, ,.... , ,,„,„, .0 DEPARTMENT OF PLANNING SERVICES 1555 N. 17th AVENUE GREELEY, COLORADO 80631 W I www.co.weld.co.us E-mail address: kogle@CO.WeId.CO.US PHONE (970) 353-6100, EXT. 3540 FAX (970) 304-6498 COLORADO February 2, 2004 ._.ary Aran. Piart EncOneer c Cc .._, 5! r _s ir_ _ 305,13 Suipicot.: Foss: , r`. . _ tiF-i Request for E:tensic;r. Dear Gary: The Department of Planning Services is in receipt of your letter dated December 23, 2003 requesting an extension of the temporary low water crossing over Box Eider Creek. This crossing was designed and constructed to accommodate the transportation of heavy components associated with the power plant. In previous correspondence dated December 12, 2002, RMEC stated that the road would be in place from the end of December 2002 through the month of May 2003, for a period of six months. By Code, this is considered a temporary condition based on length of time the low water crossing is in piece. Given that there has been a failure of equipment at the plant, and the transport of the failed equipment will utilize this heavy heui route, Weld County Government will grant an extension of the existing Permit until June 1, 2004, as requested in the December 23, 2003, 4..-on to Ogle. Of continuing concern is the possible effects of :he snow pack. Sncoy pack on he from haricie tales naang the months of Fetruary, March and - rr'il. cf r sn .,7 '.❑tO gall, May Spring flows if v. e- may st.ha.to,-,:,aaly im t tt'.:s crcc t . roc,: __ a i-- . � ., _ conceon of p'- i± Co Gooecfment. as tne .l ooc D. tuttt Leek to the fa is - cried d for early ,. 2004. That br' r' stated, ,+ _ u 'Su i4 GJ'/er ', ..lt;7ii i regbife the d.pic __0aUhI:t an amendment to the existing Flood Hazard Development Fermi:. Should the schedule of the reclamation of the existing creek bed not be met, based on the extension of the low water crossing, please notify this office in writing. Should you have any questions or need further information, I may be reached at the above address, telephone number or e-mail address. Sincerely, Lb' Ki Og! Planning Manager cc: M. Mika. Director Planning Services L. Morrison, County Attorney • D. Carroll, Public Works File: FHCP-439 use-1339 uora\ogie'wordpertect fl'.es\cgletcerresocndence\yeer 2004\RMEc=MDP490 Extension woo CALPINE 46 al AI Rocky Mountain Energy Center 6211 WELD COUNTY ROAD 51 KEENESBURG CO 80643 • 303.536.2500 303.536.0606 (FAX) December 23,2003 Mr.Kim Ogle Department of Planning Services Weld County 1555 N. 17`h Avenue Greeley,Colorado 80631 Subject: RAE('Flood Hazard Coe•,eio~meat Permit.Case No.F1-1DP-4 3'.) Dear Mr.Ogle. This letter is to request an extension to the,above referenced Flood l la and Development Permit. As was discussed in the basis for the previous extension. RHEC wanted to maintain the viability of the heavy haul route in case of a failure of a step-up transformer follow ing the back-feed of power from Xcel Energy. Unfortunately,this failure has occurred. We are developing a recover plan that will include the removal of the damaged transformer,shipping to a repair facility and the return of the transformer to RMEC. As it appears now,the earliest the transformer will arrive back to RIvIEC is toward the end of April.2004. With this in mind,RMEC is requesting an extension of our existing FHDP permit to June 1, 2004. This will give us time to replace the transformer, verify its operation and recover the road bed. The design of the heavy haul route will remain the same as previously submitted: Please contact me at your earliest convenience,as this is a time.critical event in our support of Xcel Energy's power needs.For any questions,please contact me at(303)536-2518 or my cell at(303)710-3363. Sincerely. Rocky Mountain Energ Center I Gary M.Aron,PE Plant Engineer Cc: Larry Vondrak Andrew Whittome Monica Daniels-Mika RMEC Project File Rocky Mountain Energy Center, LLC 26 West Dry Creek Circle, Suite 600 Littleton, Colorado 80120 Weld County Planning Department GREELEY OFFICE JUN 14 2002 June 11, 2002 RECEIVED Ms. Monica Daniels-Mika Department of Planning Services 1555 North Seventeenth Avenue Greeley, Colorado 80631 RE: Use By Special Review Permit No. 1339 — Rocky Mountain Energy Center, LLC Dear Ms. Daniels-Mika: The Resolution of the Board of County Commissioners adopted on February 6, 2002 ("Resolution"), granting a Use By Special Review Permit (No. 1339), requires Rocky Mountain Energy Center, LLC ("RMEC") to provide certain information to the Department of Planning Services. Condition I. of the Resolution requires RMEC to submit to the Department of Planning Services, a Use by Special Review Plat. Enclosed are two (2) paper copies of the Plat for your review. Sincerely, David D. Perkins Director- Project Development Rocky Mountain Energy Center, LLC Enclosures cc: Bruce T. Barker, Esq. (w/o enclosures) Lee D. Morrison, Esq. (w/o enclosures) Roy ;' Mountain Energy Centt . LLC 26 W. Dry Creek Circle, Suite 600 • Littleton, CO 80120 Tel: 720.283.4155 • Fax: 720-283-4154 May 6, 2002 Weld County Planning Department GREELEY OFFICE Ms. Monica Daniels-Mika MAY 8 2002 Department of Planning Services 1555 North Seventeenth Avenue RECEIVED Greeley, Colorado 80631 RE: Rocky Mountain Energy Center, LLC — USR Permit No. 1339 Dear Ms. Daniels-Mika: I write to clarify one aspect of Trevor Jiricek's April 30, 2002 e-mail to you relating to the status of Rocky Mountain Energy Center, LLC's ("RMEC") well permit submissions to Weld County. While the e-mail message can be read as suggesting otherwise, RMEC has complied in full with Condition 2, F of the February 6, 2002 Resolution approving RMEC's USR Permit No. 1339. Condition 2, F of the Resolution required RMEC to provide evidence to the Weld County Department of Public Health and Environment that any "existing or constructed well(s) have been appropriately permitted/registered with the Colorado Division of Water Resources" (emphasis added) prior to recording the plat. In its April 5, 2002 letter to Ms. Charlotte Davis, RMEC provided the Colorado Division of Water Resources permits for all existing or constructed wells currently used at the Power Plant Site and the Wellfield Site. As stated in the letter to Ms. Davis, the domestic well at the Wellfield Site is no longer used, as the Central Weld County Water District provides water to the residence. RMEC has no plans to use the existing well for domestic or other purposes. No other wells currently exist or have been constructed at the Wellfield Site. Therefore, RMEC has no additional evidence of well permits to submit to the Weld County Department of Public Health and Environment. Thank you for your continuing assistance with these matters. Please let me know if you have any questions. Sincerely, avi D. Perkins Director- Project Development Rocky Mountain Energy Center, LLC cc: Charlotte Davis Trevor J. Jiricek Bruce T. Barker, Esq. Lee D. Morrison, Esq. � r` Weld Coin; g Department �n :� ` ,D �ri�, ,,.-r 'UILDING UNITED STATES BANKRUPTCY COURT SOUTHERN DISTRICT OF NEW YORK JAN 7 2002 R a tirED In re: ) Chapter 11 Calpine Corporation, et al.,' Case No. 05-60200 (BRL) Debtors. ) Jointly Administered NOTICE OF ENTRY OF ORDER CONFIRMING THE SIXTH AMENDED JOINT PLAN OF REORGANIZATION OF CALPINE CORPORATION AND ITS DEBTOR SUBSIDIARIES PLEASE TAKE NOTICE that on December 19, 2007, the Honorable Burton R. Lifland, United States Bankruptcy Judge of the United States Bankruptcy Court for the Southern District of New York, entered an order [Docket No. 7256] (the "Confirmation Order") confirming the Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code [Docket No. 7237] (as confirmed by the Confirmation Order and as may be amended in accordance with the provisions thereof, the "Plan"). This notice is sent to you as required under paragraph 82 of the Confirmation Order. The Confirmation Order and the Plan can be viewed at http://www.kccllc.net/calpine. [THE REMAINDER OF THIS PAGE IS INTENTIONALLY LEFT BLANK] A complete list of the 274 Debtors in the above-captioned cases and their respective case numbers can be found at http://www.kccllc.ncticalpine. PLEASE TAKE FURTHER NOTICE that the Plan and its provisions are binding on the Debtors, any entity acquiring or receiving property or a distribution under the Plan, and any holder of a Claim (as defined in the Plan) against or Interest (as defined in the Plan) in the Debtors, including all government entities, whether or not the Claim or Interest of such holder is impaired under the Plan and whether or not such holder has voted to accept the Plan. Dated: January 4, 2008 Respectfully submitted, New York, New York A/David R. Seligman Richard M. Cieri (RC 6062) Marc Kieselstein (admitted pro hac vice) David R. Seligman (admitted pro hac vice) Edward O. Sassower (ES 5823) KIRKLAND & ELLIS LLP 153 East 53rd Street New York, New York 10022-4611 Telephone: (212) 446-4800 Facsimile: (212) 446-4900 Counsel for the Debtors 2 Hello